ML20138B279
| ML20138B279 | |
| Person / Time | |
|---|---|
| Issue date: | 04/23/1997 |
| From: | NRC COMMISSION (OCM) |
| To: | |
| References | |
| REF-10CFR9.7 NUDOCS 9704290115 | |
| Download: ML20138B279 (182) | |
Text
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Title:
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_g DISCLAIMER This is an unofficial transcript of a meeting of the United States Nuclear Regulatory Commission held on April 23, 1997 in the Commission's office at One White Flint Nort,h, Rockville, Maryland. The meeting was open to public attendance and observation. This transcript has not been reviewed, corrected or edited, and it may contain inaccuracies.
The transcript is intended solely for general informational purposes. As provided by 10 CFR 9.103, it is not part of the formal or informal record of decision of the matters discussed. Expressions of opinion in this 4
transcript do not necessarily reflect final determination or beliefs. No pleading or other paper may be filed with the Commission in any proceeding'as the result of, or addressed to, any statement or argument contained herein, except as the Commission may authorize.
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1 4 1 UNITED STATES OF AMERICA I
2 NUCLEAR REGULATORY COMMISSION 1
3 3 ***
- 4 BRIEFING ON ELECTRIC GRID RELIABILITY 5 ***
l
) 6 PUBLIC MEETING 7 ***
8
- j. 9 Nuclear Regulatory Commission j 10 One White Flint North 11 Rockville, Maryland 12 Wednesday, April 23, 1997 13 l i
). 14 The Com'ission m met in open session, pursuant to 4
15 notice, at 1:30 p.m., Shirley A. Jackson, Chairman, i 16 presiding.
I 17 COMMISSIONERS PRESENT:
l 18 SHIRLEY A. JACKSON, Chairman of the Commission ;
l 19 KENNETH C. ROGERS, Commissioner i
! 20 GRETA J. DICUS, Commissioner i
- 1 l 21 NILS J. DIAZ, Commissioner i i
22 EDWARD McGAFFIGAN, JR., Commissioner j 23 i
24 i 1
25 1
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2 1 STAFF AND PRESENTERS SEATED AT THE COMMISSION TABLE: .
2 JOHN C. HOYLE, Secretary 3 KAREN CYR, General Counsel 4 DAVID MEYER, Electricity Team Leader, Office of 5 Policy & International Affairs, Department of 6 Energy 7 DENNIS EYRE, Executive Director, Western Systems 8 Coordinating Council 9 ERLE NYE, President and Chief Executive, Texas 10 Utilities Company 11 JOSEPH CALLAN, EDO 12 ASHOK THADANI, Associate Director for Inspection 13 and Technical Assessment, NRR 14 RONALDO JENKINS, Electrical Engineering Branch, 15 NRR 16 MARY WEGNER, Reuttor Systems Engineer, AEOD 17 DENWOOD ROSS, Director, AEOD 18 ROBERT WOLFF, Chief Executive, New England Power 19 Pool 20 MICHEHL GENT, President, North American Electric 21 Reliability Council 22 JOSE DELGADO, Director of Electric System 23 Operations,' Wisconsin Electric Company 24 25 ANN RILEY & ASSOCIATES, LTD.
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, 1 PROCEEDINGS l
2 (1:30 p.m.] l 3 CHAIRMAN JACKSON: Good afternoon, ladies and' 4 gentlemen, this meeting is the first of two Commission l 5 meetings dealing with electric utility deregulation and 6 related issues. This first meeting will focus on electric 1 7 grid reliability and how it may be impacted by electric 8 utility restructuring -- deregulation and restructuring.
9 The second meeting will address deregulation l 10 issues in general with representatives from several federal 11 agencies involved.
12 The Commission will hear presentations today from 13 both the NRC staff'and invited industry representatives, 14 along with a representative from the Department of Energy, 1
15 I'm told.
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16 Specifically at this first meeting, the Office for 17 the Analysis and Evaluation of Operational Data, or AEOD, 18 will present information-from its study of grid performance 19 factors. The study was initiated to collect operating I
20 experience where grid disturbances had an impact on nuclear 21 power plants and other background information on grid 22 performance. -!
23 Last year, two electrical disturbances within a 1
24 five-week period on the western grid caused 190 plants to 25 trip off line, including several nuclear units.
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1, i These events occurred after AEOD had released its , '
2 draft report -- after it had released its draft report ,
3 concluding that the grids are basically stable.
1 4 A stable and reliable grid was an assumption in '
- 5. the NRC's report on unresolved safety issue A-44, the i 4
6 evaluation of station blackout accidents at nuclear power
! 7 plants dated June 1988. '
8 The reliability of off-site power is important to i 1
9 nuclear safety since accident sequences initiated by loss of l 10 off-site power are important contributors to risk for many i 11 nuclear plants.
12 The Office of Nuclear Reactor Regulation also will-13 address licensing requirements for electric power systems, f 14 station blackout, and' potential safety concerns with recent i 4 .
j 15 grid events. !
l 16 The Commission understands that grid reliability 4
l 17 is a voluntary function under the North American Electric '
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,! 18 Reliability Council and the regional councils, and that- I l 19 federal oversight is currently located at the Federal Energy
- 20 Regulatory Commission and at the' Department of Energy.
21 DOE has created a working advisory committee on i+
- 22 the reliability of the U.S. electric system, which is 23 considering whether efforts to date to maintain reliability
- 24. are sufficient to provide assurance of reliability in the I
- 25 future and whether there may be a need for increased federal
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authority over reliability in the future.
j 2 NRC, we understand, has been coordinating with DOE !
j 3 and will continue to keep abreast of this effort. This is a !
- 4 long introduction.
5 Following the NRC staff presentation, industry :
i 6 representatives chosen to represenc several different 4 1
7 geographical areas and grids will discuss the strengths and j 8 vulnerabilities of their grids.
1 9 Additionally, a representative from the DOE will l 10 describe the department's current activities regarding 11 electric grid reliability.
12 And so the Commission is interested in a number of' I 13 things and I'll tell you a few.
14 First, insight on what effects electric utility j 15 deregulation will have on grid reliability as far as we 16 understand, a discussion of the independent system operator j 17 concept, and an assessment of what governments or 18 operational specifications need to be built into the ISO 1
19 process to ensure a stable' grid. !
20 I personally have discussed the issue of electric 21 grid reliability with numerous utility executives over the 22 .past year. It was not possible to invite to the panel today 23 all of the industry representatives who have been active on 24 this issue, so I apologize to you in advance. But if there 25 is, toward the end of the meeting time, I may invite other ANN RILEY & ASSOCIATES, LTD. !
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6 1 utility or state representatives to offer any additional -
2 brief comments they would have to the Commission as 3 appropriate. .
4 I understand that copies of the various -- the 5 presentation, at least the staff's, is available at the 6 entrance to the meeting, and so unless there are any further 7 comments, Mr. Callan, please proceed.
8 MR. CALLAN: Thank you, Chairman, and good 9 afternoon, commissioners. WITH me at the table a-9 Dr.
10 Denwood Ross, the director of AEOD, and to his right, Mary 11 Wegner, who is a reactor systems specialist who works for 12 Dr. Ross in AEOD. To my left is Ashok Thadani, who is an 13 associate director in the Office of Nuclear Reactor 14 Regulation, an'd to his left is Ronaldo Jenkins, an 15 electrical engineer who works for Mr. Thadani.
16 Chairman, you've covered all the points I was 17 going to make in my preamble, so I will at.this point turn 18 the discussion over to Dr. Ross who will begin the 19 presentation.
20 DR. ROSS: If we go to slide 2, the reliability of 21 the grid to which the nuclear plant is connected can' affect 22 the safe operation of the plant. And because of several 23 events on grids around the country, AEOD performed a study 24 which is the basis for the first part of this Commission 25 briefing and Mary Wegner is the author of that study.
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. 1 The study identified several grid performance 2 factors, such as demand growth, capacity margin, and plant 3 age, which she will talk about. And.on the basis of this 4 study, AEOD developed a recommendation that all licensees l l
5 should confirm and maintain their licensing basis with 6 respect to stability.
7 Mary will discuss her study in more detail, and 8 then following that, NRR will discuss the original licensing 9 basis concept and NRR's plans for addressing grid 10 reliability. Mr. Jenkins will provide the NRR comments, 11 along with Mr. Thadani. I l
12 Slide 3. I 13 CHAIRMAN JACKSdN: And before you go, in terms of 14 the recommendation from this study for licensees to confirm 15 and maintain their licensing basis, I think the memo you 16 sent also states that several licensees reviewed their grid 17 analyses. Was this voluntary on their part?
18 DR. ROSS: Yes. In fact, Mary will have the 19 specific discussion on that point. Sometimes it was in 20 response to an event, such as the Virgil summer event 21 prompted a Virgil summer reconsideration, but I think we'll I 22 discuss that in more detail in the middle of her 23 presentation. But I'm not aware of any regulatory
, 24 requirement that dictated or required reexamination of it.
25 Now, it is true that this concept is embedded in d
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1 their 5054 letters thac went out last year with resp,ect to -
I 2 licensing basis in general, of which this is just a part. '
3 CHAIRMAN JACKSON: Now, are you going to talk 4 about agency actions that are generic -- any generic agency ,
1 5 actions that came about as a result of the summer event you 6 mentioned at the summer plant?
! 7 DR. ROSS: I don't think we were.
8 MS. WEGNER: The only action I know of was the 9 issuance of an information notice and that led to another 10 utility doing -- '
11 DR. ROSS- But I don't believe there are a 12 specific licensing action if that's the question. ,
13 CHAIRMAN JACKSON: Okay. Even though at the time, 14 the.FSAR stated for that plant that the grid should be able 15 to absorb the loss'of a generating unit, but in that 1 16 particular case, it couldn't and 16 other units tripped off 17 line. You didn't feel that any --
18 DR. ROSS: Let me check.
19 MR. THADANI: I think my understanding also is 20 that, as you say, an information notice was issued as a l
1 21 result. Any other actions we may have taken, I don't know l 22 of, but we can check on that.
i 23 DR. ROSS: Slide 3. Certainly, reliable power is l 24 needed for safety equipment, and we see this at several 25 places in the Commission's regulations.
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. For example, GDC-17 has the notion or the idea i 2 that an off-site electric power system shall be provided to 7
3 permit functioning of structure systems and components 4 important to safety.
3 I 5 It has a number of statements and provisions i i
- 6 relative to off-site power as well as on-site power. .
7 Further, GDC-35 states that for ECCS, system .
8 safety function must be accomplished using the off-site 9 electrical power system assuming the on-site power system is 10 not available,'and conversely, and also, assuming a single ,
11 failure.
12- And other rules have links to off-site power. For 13 example, 10 CFR 50.63, loss of all AC, has requirements 14 linked to the expected frequency and loss of off-site power 15 and duration of the loss.
16 Risk assessments also considered a loss of off-17 site power, and if in the modeling you also. lose the on-18 site power from the emergency diesels, you would be in a 19 condition referred to as station blackout, or SBO.
20 This event in many-risk assessments is the 21 dominant contributor to core damage frequency.
22 At present, the contribution of grid reliability 23 to loss of station power is relatively small and it's more 24 likely the origin of loss of station power would be within 25 the station, sometimes called plant centered, such as a s ANN RILEY & ASSOCIATES, LTD Court Reporters 1250 I Street, N.W., Suite 300 Washington, D.C. 20005 (202) 842-0034
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10 1 circuit breaker or tran:sformer faults, or weather related, -
2 such as winter ice st'ortis, strong winds, possibly an 3 earthquake, and Hurricane Andrew is a good example of a 4 weather-related loss of station power..
5 And from this you can see that adequate safety is 6
based on a combination of both, on site and off-site power.
7 'And while at present,. grid reliability is not a dominant 8 contributor to the risk factor such as core damage ;
9 frequency, it seemed important to us to provide assurance 10 that this would continue to be the case in the future i
11 consistent with the licensing basis.
12 What I want to do now is turn over a discussion of 13 the grid performance factor study to Mary Wegner. l 14 CHAIRMAN JACKSON: Let me just ask you a couple 15 questions before you do.
16 Do we have confidence that the assumptions 17 supporting the staticn blackout rule remain valid in light 18 of some of the more recent data? And what would be the 19 significance if such events -- the loss of off-site p.ower 20 were more' frequent that what had been assumed at the time?
21 DR. ROSS: From what we've seen -- we don't have a 22 published study -- that the frequency, especially related to 23 grid stability and loss of station power, is less.
24 Now, I'd say the definitive study is in a NUREG-25 1032 which is good up to 1985. It's a 20-year study from, I ANN RILEY & ASSOCIATES, LTD.
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. 1 think, 1966 through '85, and it counts the number of, events 2 and categorizes them into the three bins that I mentioned, 3 which is grid centered, plant centered, and weather, severe 4 weather.
5 We are in the process of updating that study, so 6 we will have a new Sub 1 or Rev 1 to 1032. .Actually, it 7 will have a different number. l 8 There was about, I think, 12 grid stability events i 9 at the time of that study, but most of them were in the 10 Florida Peninsula area and it was a hardware alignment 11 situation which was corrected and there's been essentially 12 no subsequen't grid centered -- or grid stability problems I 13 beca'use of the way,they rearrange'd their interties.
14 So from what we can tell, the data would support a 15 lower frequency of occurrence.
16 Now, what we would have to do is put in the 17 duration, which is part of the blackout rule also.
18 The other half of your question would deal with 19 the reliability of on-site facilities. AEOD just finished a 20 publication on.that study, almost all the diesels in all the 21 plants, and it showed in general that the reliability is 22 tracking about what it was assumed to be, and there is a 23 statistical spread. And I think we have made this available 24 to the Commission.
25 We don't have any information now that would put ANN RILEY & ASSOCIATES, LTD.
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- l. 1 50.63 in a new and different light, but we are working.on .
2 it.
3 CHAIRMAN JACKSON: Do we require a certain 4 reliability of on-site power sources that is referenced to 5 assumptions about the grid?
6 MR. TRADANI: In most cases, as a result of the 7 station blackout rule requirements, licensees came in and ;
8 make certain commitments about reliability of on-site AC 9 power source. In this case, it might be diesel generators.
10 So we do have licensee commitments on site, AC power source 11 reliability.
12 If I may just add to it --
13 CHAIRMAN JACKSON: I guess what I'm -- let me just 14 ask you this. Are they referenced to assumptions about the -
15 duration --
16 'MR. THADANI: Yes.
17 CHAIRMAN JACKSON: -- and the extent of the loss?
18 MR. THADANI: In fact, I was going to touch on 19 that. That's exactly the issue, is the station blackout 20 rule, the real controlling factors are not just the 21 frequencies themselves, loss of off-site power, but also 22 duration.
23 Duration is a very critical issue, and in many 24 cases, the resolution on a plant-specific basis was that 25 they could cope with station blackout for a certain time ANN RILEY & ASSOCIATES, LTD.
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, 1 period. In most cases, it was on the order of four hours, 2 because the expectation was that off-site power could be 3 recovered during that time period.
4 And there are a number of -- as you noted in your 5 introduction, that this rule went into effect in 1988, and a 6 number of issues have developed in the intervening years.
7 Dr. Ross mentioned the IPEs are showing station 8 blackout to be still a dominant contributor, and in some i 1
9 cases it's quite significant still.
10 And there have been some new issues that have I I
11 developed over the last eight or nine years, one of which i 12 has to do with the behavior of reactor pump seals, and their 13 performance could be significantly degraded in the absence 14 of cooling to the' pump seals.
15 What we're doing in the Office of' Nuclear Reactor 16 Regulation is we are collecting and looking at all the new 17 information, grid rel'iability being one of the issues. We 18 are collecting all the information and we're planning to 19 reassess the whole issue of station blackout, integrating.
20 all this new knowledge that we have now, and would expect to 21 complete that evaluation by the end of 1998. l 22 That was' going to be Mr. Ronaldo Jenkins' -- part 23 of his presentation, so excuse me for having -- I think it's 24 important to recognize that we're trying to integrate all 25 these issues and reevaluate station --
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14 1 CHAIRMAN JACKSON: So we'll wait.
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2 DR. ROSS: I think many of the commitments are 3 found in the companion reg guide to the blackout rule, which 4 is -- Mary, i
5 MS. WEGNER: Slide 4, please.
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6 In 1989, an event occurred at the Virgil summer 7 nuclear plant that resulted in a major grid disturbance. I 8 AEOD began an inquiry to identify other grid-related events' t
9 that impacted the operations of nuclear plants, naturally l l
10 the availability of off-site power.
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11 It was necessary to learn about the grid in order- l 12 to evaluate the findings of the study and to communicate 13 them. My presentation is divided into three parts. .'First I
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14 will address the. organ'ization of the North American Electric 15 Reliability Council and some important characteristics of .
16 the grid.
17 Secondly, I will describe some events involving i
18 grid perturbations or the potential for a grid instability. ,
19 Finally, I will close with the conclusions I have 20 drawn.
/r 21 Slide 5, please. The North American Electric 22 Reliability Council was formed in 1968. Its mission is to 23 promote the reliability of the electricity supply for North l 24 America. It is made up of ten regional councils and one 25 affiliate council. The local utility is connected to other >
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. 1 utilities in its reliability council and to other s 2 reliability councils which form the North American Electric 3 Reliability Council.
4 The entire Continental United States, most of 5 Canada, and part of Mexico are interconnected in order to 6 provide reliable electric power to' consumers.
7 Membership in the regional councils is voluntary 8 and is open to all individual electric systems from all 9 ownership segments of the electricity supply industry.
10 This map shows the location of each reliability 11 council. The acronym and the names of the councils are 12 listed in the study.
13 In 1997, adherence to the North American Electric.
14 Reliability Council standards was made mandatory. Each -
15 reliability council has a set of operating criteria that 16 were base'd upon the North American Electric Reliability 17 Council criteria, but modified to allow for regional 18 differences.
19 The operation of each reliability council is not.
20 uniform, that is, the Mid-Atlantic Area Council operates as 21 a single entity, while the Southeastern Reliability Council 22 is composed of four subregions which are virtually 23 autonomous.
24 Slide 6, please. .
25 CHAIRMAN JACKSON: When you said that the s ANN RILEY & ASSOCIATES, LTD.
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16 1 adherence to the operational requirements was made .
2 mandatory, made mandatory by whom?
l 3 MS. WEGNER: The board of trustees of the North 1
4 American Electric Reliability Council, and I believe the 5 members have completed their voting on the acceptance of it.
l 6 But Mr. Gent could answer more detailed questions on that I i
7 than I could.
8 CHAIRMAN JACKSON: Mr.?
9 MS. WEGNER: Gent of the North American Electric j 10 Reliability Council.
11 COMMISSIONER ROGERS: Just before we go on, does 12 every electric generator or generator of electricity for 13 sale belong to an electric reliability council?
14 MS. WEGNER: I would say probably not since it's a 15 voluntary organization, but I would say most of them do, if 16 they wanted to be interconnected to other utilities to 1
17 provide their electricity to others and to receive aid from 18 them when they need more additional power. There's nothing 19 requiring them to be.
20 MR. JENKINS: Independent power producers would 21 not fall under this. This was mainly for utilities.
22 MS. WEGNER: Well, they can. It's voluntary.
23 CHAIRMAN JACKSON: So membership is voluntary?
- 24 MS. WEGNER
- Yes.
25 CHAIRMAN JACKSON: But decisions are binding on ANN RILEY & ASSOCIATES, LTD.
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. 1, the members, provided the members accept them?
2 MS, WEGNER: I presume. Mr. Gent can answer the 3 question more adequately, that there are business contracts 4 written up to enforce these decisions.
5 CHAIRMAN JACKSON: Okay.
6 MS. MEGNER: Peak demand and capacity margin !
7 projections are important grid parameters. On this chart, 8 the peak demand projections for the Mid-Atlantic Area I 9 Council, our council, are shown in the upper left-hand 10 graph. The lower left-hand graph shows the peak demand 11 projections for the New England Region of the Northeast l 12 Power Coordinating Council'.
i 13 All reliability councils project a yearly increase j 14 in peak demand over the next ten years from about 1 percent i
15 to about 2 percent per year. {
16 Capacity margin is a planner's tool to deal with '
17 unexpectedly high demand, demand forecast error, and so 18 forth. Capacity margin projections for the Mid-Atlantic 19 Area Council are shown in the upper right-hand graph.
20 Capacity margins for the New England Council -- the New 21 England region of the Northeast Power Coordinating Council 22 are shown in the lower right-hand graph.
23 System response to a developing situation is 24 affected in part by the availability of unloaded generation.
25 Unloaded generation is related to capacity margin. A !
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18 1 continuing decrease in capacity margin will eventually .
2 impact system response.
3 Slide 7, please. Power plants are aging. The 4 plants that are expected to produce the electricity needed 5 during the 1997-2005 period have already been built. The 6 chart shows the total numbers of plants started up and their 7 total capacity by decades'. Both the number of plants coming 8 on line and their capacity declined sharply after the 1970s.
9 40 percent of the electricity is generated by 10 plants which may be 26 years old or older. According to the 11 East Central Area Reliability Coordination Agreement, ECAR, 12 the aging of generating capacity necessitates the increased
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13 maintenance and lengthened outages.
1 14 The Virgil Summer 1989 events report named the age 15 of nearby plants as a contributing factor. Age has the l 16 potential to become a factor in grid reliability, l
17 Slide 8, please. I have talked about the i
18 organization of the North American Electric Reliability 19 Council and some characteristics of the grid. Now I will i 20 address some operational aspects of the grid as demonstrated 21 during events.
22 There are two kinds of grid emergencies. The 23 first is the outcome of excess demand / That is, demand 24 above expected peak demand that may exceed reserves. As 25 this kind of emergency develops, there is usually time for ANN RILEY & ASSOCIATES, LTD.
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l 1 human intervention to mitigate the transient.
2 The second emergency type develops very rapidly as l 3 a result of a fault. Automatic systems protection must cope l 4 with the situation.
1 5 The third type of situation is a discovery of the )
6 potential for grid instability due to an existing nuclear 7 plant condition.
8 Slide 9, please.
9 CHAIRMAN JACKSON: I'm looking at the fault issue 10 with the summer event, and particularly the western grid
'11 disturbance of last year, and I recall that your draft 12 report at that time concluded reliability just weeks before 13 this western grid disturbance --
14 MS, WEGNER: Yes.
15 CHAIRMAN JACKSON: -- on August 10th.
16 Now, had that report specifically looked at the 17 potential of the kind of fault that caused those two events, I
18 that caused the western grid disturbance?
19 MS. WEGNER: T'ere h were previous faults, the July 1
20 2nd one, the December 14th, 1994 in which a seemingly 21 innocuous situation occurred far across the country from the 22 nuclear plants and caused a disturbance, and I looked at it i
23 to the point in which I determined to the best of my ability 24 what transpired during these events and wrote them up in 25 technical review reports, and they were summarized in the 9
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1 report. ,
l 2- That is, I believe,.as far as I could say that we !
3 have reviewed the events, but --
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l j 4 CHAIRMAN JACKSON: I guess I'm really:more ]
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5 interested not so much in ringing your bell relative to that 6 particular event, but more to understand is whether the way l
7 we track the status of the grid was such or is now such that 8 we would be sensitive to the potential for the kind of event 9 that occurred last summer.
10 DR. ROSS: Other than expose what happened in the 11 reports, I'm not sure of any specific action --
12 CHAIRMAN JACKSON: I guess I'm saying, what do you 13 measure to make a conclusion that a grid is stable and l l
14 reliable? What do.you measure? What do you look at? How
~15 do you reach that conclusion?
16 DR. ROSS: Okay, I understand your question now.
17 The specific event, and I think Mary's going to get bottled.
i 18 -- segmented the western area to a number of little ad hoc 19 islands, and within the islands, certain actions took place, j l
20 And if the plant -- some of them tripped, most of -
21 them tripped, some did not -- it was such that you still !
22' have reliable off-site power to the plant, even though the 23 plant may trip, then I think that's relevant.
24 CHAIRMAN JACKSON: I guess I'm wondering, are we 25 sensitive to whether there may be operational conditions ANN RILEY & ASSOCIATES, LTD.
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. 1 that are occurring, or do we know enough even about the s 2 maintenance of the grid to know whether the loading -- or 3 whatever factors, to know when a potentially problematic 4 situation is' developing?
5 MS. WEGNER: That, I believe, would be DOE's 6 Office of Emergency Management's job.
7 CHAIP. MAN JACKSON: Okay. And I guess this goes 8 back again to something we had talked.about in an earlier 9 stage, and the issue becomes then the interface.
10 If DOE's Office of Emergency Management -- and l l
11 we're going to hear from them -- tracks certain things, what '
12 communicatio'n is there then to us that we fold into in any 13 kind'of a trending database that would trigger us to be more i l'4 sensitive or transmit information to the regions, to have 15 our folks be more sensitive to the potential for some --
l 16 MS WEGNER: DOE has been sending me weekly l 17 reports, which I've been transmitting to a number of people I 18 in DOE and NRR, discussing a potential situation in a few 19 weeks in areas where there may be problems or where there 20 have been problems.
21 Don't know about any databases other than the 22 study --
23 CHAIRMAN JACKSON: But nothing that would allow 24 any response on a real-time basis or anything that 25 approaches that?
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l 22 I 1 i MR. CALLAN: Chairman, I think in all candor, I'm - 1 2
speaking as an ex-regional administrator, the insights the 3
region gets regarding grid reliability they get from 1 1
4 industry sources, typically through the resident inspectors 5
who are -- attend several operational meetings every day 6 that the licensee holds at site.
7 But we don't have a mechanism, a reliable 8 mechanism internally to disseminate that kind of 9 information.
10 DR. ROSS: And I think also to the point we talked 11 about, the sudden, rather than the slow drop in capacity.
12 There's some inner workings amongst the councils about how 13 to, given a trauma of some sort, to separate into islands, 14 and we don't review that. We don't have access or --
15 CHAIRMAN JACKSON: You have the issue of sudden 1G dinturbadces.
17 DR. ROSS: Yeah.
18 CHAIRMAN JACKSON: And then you have the issue of 19 degraded voltage, right?
20 DR. ROSS: Right.
21 CHAIRMAN JACKSON: And I noted that your report, 22 and I'm going to quote from it in discussing a particular 23 plant that had a degraded voltage event stated, that "the 24 degraded voltage analysis accepted by the NRC in 1979 was 25 not updated because no requirement for periodic update ANN RILEY & ASSOCIATES, LTD.
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23 l
. 1 existed." ,
2 And so what's the status with respect to that? Do !
3 licensees adequately monitor degraded voltage concerns, if 4
the licensee's data is updated with respect to that when 5 they perform their IPEs or their PRAs now?<
{
6 And I guess my -- I'm told that degraded voltage ;
7 weaknesses were routinely identified when we did these i
8 electrical system SSFIs some years ago. What staff actions I 9 came out of those and do we have any current concerns? i 10 DR. ROSS: Let me answer the first part and I'll }
11 turn to Mr. Thadani for the second part. We don't know the 12 extent to which utilities have updated their stability, 13 hence our recommendation. We just don't know.
14 As far as what came out of the SSFIs, I'll ask Mr.
15 Thadani to answer, but I'll expect we're into the plant 16 centered rather than the grid centered area now. !
17 MR. THADANI: Yes. By and large, the. findings ;
. 18 were more on plant-centered issues and there were follow-on 19 activities as a result of that. But two parts. Let me go 20 back to this point to a question you raised.
4 21 IPEs are -- at least it's my view that they do not '
22 look at degraded conditions. They look at failures, actual 23 experiential database, and that's how they come up with j 24 frequencies of events. i 25 In addition to that, Mr. Jenkins will be talking j i
l l
e .
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l 24 i 1 about an effort that were initiating at Oak Ridge National .
2 Laboratory, and one element of that is going to be -- focus 3 attention on the issue you raised just now. ,
4 CHAIRMAN JACKSON: I keep coming to Mr. Jenkins. ;
5 DR. ROSS. He's the last speaker so we're all --
6 CHAIRMAN JACKSON: I will try to be good for the 7 next three minutes.
8 MS. WEGNER: Slide 9, please.
9 The first example is an event in which weather-10 driven excess demand affected grid operations locally. The 11 event occurred on January 18th through 20th, 1994. Cold 12 weather affected most of the Midwest, .~uth, northeast, and 13 Mid-Atlantic areas'of the United States. The figure shows 14 the relationsh'ip of temperature at the Washington National ,
15 ' Airport to electricity demand for the region.
16 On the 18th in the Mid-Atlantic area, the 17 temperature began to drop from 35 degrees Fahrenheit at 5 18 a.m. to 8 degrees Fahrenheit at midnight. In the evening, 19 electricity demand increased inversely with the temperature 20 when it was expected to drop with the change in usage from 21 commercial to residential. ,
22 Weather conditions not only increased customer 23 load, but also disrupted fuel supplies. Generation was 24 increased to the maximum. Transmission lines were loaded to 25 their maximum.
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1 25
. 1 Slide 10, please. Emergency measures for reducing 2 the load as shown on slide 10 were instituted. The Mid-3 Atlantic Area Council and Virginia Power had to resort to 4 rotating blackouts to maintain the reliability of the grid.
5 Florida, New York and Canada provided power to the Mid-6 Atlantic. Load reduction measures as shown in slide 10 were 7 instituted and utilities, government entities, the business 8 community, and the private sector all cooperated to reduce 9 load.
10 The system frequency never decreased to the point 11 where step 8, actuation of automatic underfrequency load 12 shedding relays occurred.
13 The second kind of emergency, a fault driven 14 transient, occurred in 1989 at the Virgil Summer Nuclear 15 . Plant. At Virgil Summer, a loss of cooling signal was 16 generated', the turbine tripped, and the reactors scrammed.
17 Nearby plants attempted to make up the load but tripped 18 because their generator protection was set high because of 19 their age.
20 A cascading failure resulted during which 16 units l
21 tripped off line and caused a severely depressed voltage 22 throughout South Carolina and the neighboring states.
l 23 Virgil Summer's 20 buses saw the degraded grid 1
24 condition and isolated from the grid. The emergency diesel 25 generators started and loaded the running buses. They ran l ANN RILEY & ASSOCIATES, LTD.
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I 26 1 for one hour and 35 minutes. Subsequently, the licensee .
2 determined that his grid analyses had to be periodically 3 updated.
4 Slide 11, please. Another important event was the 5 western grid disturbance of August 10, 1996. The weather in 6 Los Angeles was hot. Relatively inexpensive hydropower was I
7 available from the northwest. Large amounts of power were 8 flowing southward when voltage problems in the northwest 9 became evident.
10 A line sagged into a tree at Oregon. Lines 11 tripped; generating plants tripped. The system separated 12 into four islands as shown o,n the slide outlined in heavy i
. 1 13 black lines.
l 14 Frequendy in the Northern California island 15 dropped. All five sets of load shedding relays actuated 1
16 causing about 50 percent of Northern California load to be I
17 shed. 1 18 Many power plants tripped, including Diablo Canyon 1
19 units 1 and 2-- units 1 and 2. Southern California, Arizona 20 and New Mexico were part of the southern island. Frequency 21 dropped there also, triggering load shedding.
22 Palo Verde units 1 and 3 in the southern 4.sland j 23 tripped. Neither nuclear site lost all off-site power as a 24 result of the event. A transient resulted in the loss of i 25 over 30,000 megawatts of load, 25,000 megawatts of ,
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I 27 j
. 1 generation, and the tripping of 190 generating units shown y 2 in dots on the slide, which came from the western grid i
3 disturbance report of WSCC. , I 4 Included in those dots are the Diablo Canyon units 5 in California and the Palo Verde units in Arizona. The 6 Western Systems Coordinating Council concluded that the 7 system operation was not in compliance with WSCC minimum 8 operating criteria prior to the beginning of the transient.
9 That criteria requires that the system be operated 10 so that cascading failures which can cause system collapse 11 do not occur. Cascading failures did occur. However, the 12 structure of the system and the responses of the operators 13 controlled the situation to prevent grid collapse and 14 equipment damage, allowing rapid recovery.
15 Besides events, several potential grid ,
16 instabilities based on licensees' analyses have been 17 reported. For example, the licensees for PQint Beach units 18 1 and 2 in Kewaunee have identified scenarios involving 19 transmission line outages with the potential to cause loss 20 of all off-site power to Kewaunee.
21 Slide 12, please. My conclusions are these. On 22 the whole, the grid is stable and reliable, even in the face 23 of events as serious as the August 10 disturbance. However, 24 problems described in the study, ine uding decreased 25 capacity margin, plant aging, reanalyses which have ANN RILEY & ASSOCIATES, LTD.
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1 1
28 1 identified problems, actual events, and uncertainties .
2 introduced by restructuring of the electric industry, 3 indicate the reed to monitor grid conditions on a regula'r .
4 basis.
5 And that's the end of my presentation.
6 COMMISSIONER DIAZ: .Are you sure on the Palo Verde 7 trip?
8 MS. WEGNER: I'm sorry, sir.
9 COMMISSIONER DIAZ: Are you sure that Palo Verde 10 tripped?
11 MS. WEGNER: Palo Verde units 1 and 3 tripped.
12 MR. CALLAN: Let me clarify that. There's a 13 distinction here that's important. Palo Verde can withstand 14 a loss of load without a reactor trip and, in fact, I was 15 regional administrator at the time. My recollection is that' 16 the unit withstood the loss of load transient turbine trip 17 without a reactor trip.
18 MS. WEGNER: The reactors trip on a low TNBR.
19 COMMISSIONER DIAZ: But-only one was actually --
20 information was only 2 and 3 you're talking about.
21 MS. WEGNER: ' Units 1 and 3 tripped from 100 22 percent power.
23 COMMISSIONER McGAFFIGAN: 2 didn't?
24 MS. WEGNER: 2 did not. It's because of -- I 25 presume, and it looks like it's because of the direction of ANN RILEY & ASSOCIATES, LTD. .
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29 1 power flow out of the plant.
2 COMMISSIONER DIAZ: But unit 1 was not on line.
3 Unit 1 was --
4 MS. WEGNER: Unit 1 was in 100 percent power, and 5 unit 3. Unit 1, I believe, just came out of an outage.
6 COMMISSIONER DIAZ: Mr. Callan, would you like to 7 figure that out, please?
8 MR. CALLAN: I don't recall exactly the units that 9 were up or and down, Commissioner, but we'll get back to you 10 on that. I've forgotten.
11 CHAIRMAN JACKSON: There's an AEOD recommendation?
12 DR. ROSS: Let's go to slide 13. We had a single 13 recommendation from the study. NRR, which is our usual 1 14 receiving office -- well, sometimes it's NMSS, but we 15 requested -- NRR should request licensees to confirm that 16 they continue to meet their licensing bases with respect to 17 stability and reliability, and further, have a process for 18 ensuring they meet this licensing basis on stability for the 19 rest of their license.
20 CHAIRMAN JACKSON: That's a natural segue'into 21 NRR's part of the presentation.
22 Mr. Callan.
23 DR. ROSS: Now I believe it's Mr. Jenkins.
24 COMMISSIONER DIAZ: I think I'm actually very 25 proud of it. I guess the SONGS unit, SONGS 2 and 3 did stay ANN RILEY & ASSOCIATES, LTD.
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30 1 on line. .
2 MS. WEGNER: They did stay on line, yes.
3 CHAIRMAN JACKSON: We have Mr. Ray here.
4 MR. JENKINS: Good afternoon, I would like to 5 briefly discuss first the licensing basis for reliable power 6 to safety systems and components, and then those NRR actions 7 which we believe are appropriate in light of the ongoing 8 changes in the electric power industry.
9 Slide 14, please. General design criteria 17 10 details the electric power requirements for nuclear power 11 plants. The on-site and the off-site power supplies 12 together assure reliable power for safety-related functions.
13 Each power type, independent of each other, have 14 different' characteristics. The on-site power source must 15 meet the scene-of-failure criteria. As a minimum, the off-16 site power source consists of two independent circuits.
17 Each must be capable of safely shutting down the reactor.
18 In addition, GDC-17 also states that provisions 19 must be included to minimize the loss of off-site power.
20 As part of the staff's review of the licensee's 21 design, grid stability analysis which were performed by the 22 licensee must verify that the local grid remains stable in 23 the event that the nuclear unit generator is lost or the 24 largest other generating unit is lost, or the loss of the 25 most critical transmission line occurs.
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. l 31 l l
, 1 With that short overview of the licensing
., 2 perspective from off-site power, the next slide describes l 3 our ongoing or near-term actions.
i -
j 4 CHAIRMAN JACKSON: Let me just ask you two 5 questions. The Virgil Summer event of 1989, tell me where 6 that stood with respect to any of these three factors.
I 7 MR. JENKINS: The Virgil Summer event reflected 8 the fact that they had not updated their grid analysis and 1
9 taken the appropriate action with respect to ensuring that 10 the loss of that particular unit would create a local grid j 11 disturbance.
I
- 12 So technically they were not consistent with that,
{
13 but the problem is'that that's not a hard requirement. At i .
J 14 the time plants are licensed, the staff looked at the grid j 15 analysis and basically verified that, in fact, that had been 16 done.
4
- 17 But over the course of time, and this showed up in 1
j 18 the ANO event, or the licensee event, the disconnect between 19 the transmission departments and the nuclear generati.ng l 20 units sort of led to a disconnect between them. But the ANO 21 event which was: led by the fact that they were going to have i
22 an ESFI inspection' forced them to look at their grid I 23 analysis, and then of course they reported it.
a
! 24 CHAIRMAN JACKSON: So have all of our licensees 25 systematically verified?
j j
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32 1 1, MR. JENKINS: I could not state that. The -- st .
2 one time, if it's stated in their SCR that they performed a 3 grid
- analysis, they did do that, but.over time, conditions 4 change. There's no requirement at this point. I 5 MR. THADANI: Let me comment. When we issue 6 information notices, we're not explicitly calling for 7 licensees to do specific analyses that they need to report 8 back to us, but there is an expectation that they need to go 9 back. Given the information in that notice, they need to 10 assess the information and its applicability to the 11 requirements that they need to meet.
12 So there is that expectation. When we find 13 information in one plant that could potentially be .
14 applicable to other piants, we issue the information notice 15 that those plants will in fact look at the information 16 notice, make a conscious decision whether there is 17 information there that may be applicable to their plant and 18 their requirements that they need to go back and verify it.
19 DR. ROSS: Chairman Jackson, a typical FSAR ;
20 statement will be the stability of off-site power systems is 21 in compliance with the branch technical position. That's an-22 NRC branch, concerning stability, and that they have --
23 steady state and transient studies show that the loss of 24 both units, which happens to be south Texas, or the loss of 25 one unit with the other unit either on line or off line ANN RILEY & ASSOCIATES,'LTD.
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l 33
. I would not impair the ability of the system to supply power I
N 2 to the ESM electrical system.
3 Then it goes on and talks about stability. That's
, 4 a typical SFAR commitment.
E CHAIRMAN JACKSON: So given that, thcie's no ,
6 specific requirement that if some event like.this western
]
7 interconnect situation occurs, that they have to go back and 8 assess what's in their FSAR against what has occurred? Is I
1 9 that what you're telling me? '
10 MR. JENKINS: They would have to look as part of l l
3 11 -- being a member of the reliability council --
l l 12 CHAIRMAN JACKSON: No. I'm talking about in terms' l
l 13 of us.
l 14 MR. JENKINS: From our perspective, there's no l l
15 requirement that they would have to do any grid analysis. l j 16 DR. ROSS: I do note that the -- l l'
17 CHAIRMAN JACKSON: What is -- go ahead.
18 DR. ROSS: The FSAR is written in the present j
.: 19 tense. I l
20 CHAIRMAN JACKSON: So you're saying that to say ;
21 what, Mr. Ross?
1 22 DR. ROSS: To me, that means whatever is true then 23 is true now. It didn't say at a certain point in time, I 24 could do this. It says it is.
25 MR. JENKINS: Certainly it would be actionable on ANN RILEY & ASSOCIATES, LTD.
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1 I
i 34 1 our part if we determined that there was deficiencies. They -
i l
1 2 would have to go and correct those deficiencies, either the 3
FSAR, or they would have to correct the plant in response to 4 the grid.
5 CHAIRMAN JACKSON: Commissioner Diaz.
6 COMMISSIONER DIAZ: I'm trying to understand the 7 role of the house power or the -- you know, our -- the 8 reactor and, you know, the power plant running.
9 If I remember correctly, when TMI happened, we 10 actually required that whole power plants will trip -- I 11 mean all the reactors will trip when the turbine trips, 4 l
12' that's correct, and then at the same time, those power 13 plants that had an integrated' control system and.had i
14 actually bought a power run-back were authorized to 15 ' disconnect the power run-back.
16 And how many plants are affected like that? How 17 many plants actually had a power run-back option that would 18 allow them to trip and then restart and pick up 10 percent 19 of the load? Do we have an idea?
20 DR. ROSS: Let me comment a little bit on that 21 because at that time, the BMW plant had a -- well, of' course I 22 it still does -- had a pilot-operated relief valve, and on a 23 typical load separation where the primary pressure is going 24 up , the PORV would be electrically commanded to open first, 25 and then if the pressure kept on going higher, the reactor's !
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1
35 1 trip signal would be generated. This was built in so thdt 2 the ICS could run by power before they tripped on high 3 pressure.
One of the more immediate things that happened 4 -
5 after TMI was an emergency bulletin that reversed these set 6 points such that you got the trip first, and then the PRV 7 was challenged next.
8 That really more or less invalidated the run-back 9 feature of BMW.
1C COMMISSIONER DIAZ: It also affected the 11 Westinghouse plants that don't have the problem with the 12 power grid relief valve, will have an integrated control 13 system; is that correct? ,
14 DR. ROSS: 'm not sure about that, but the 15 feature did come into mind on one of the European plants 16 that had a precursor PRV stuck open years before, so I think 17 that was true, that the valve opened first and stuck open.
18 The whole idea of reversing it was to quit 19 challenging the PORV. -
20 MR. THADANI: That was also the pressure trips at 21 a point were modified for reactor trip versus opening of the-22 PORV. That was all.
23 COMMISSIONER DIAZ: I was trying to determine 24 whether the power plant -- you know, the turbine trips, 25 there's an overload, the actual trips, and then we get into ANN RILEY & ASSOCIATES,'LTD.
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'36 i 1 a situation in an hour or two, you know, how we access the . l 2 capability of the nuclear power plants to come up and pick
' )
3 up the house load itself and I've seen that missing from the 4 analysis. {
5 MR. JENKINS: As I understand it, there's no I 6 provision for picking up house loads once the plant trips. l 7 CHAIRMAN JACKSON:
l I want to go back and try to 8 -close the loop here between what your statement -- your.
9 statement about FSARs being written in the present tense and 10 your statement that there's no specific requirement in the 11 -- if' there is some major grid disturbance relative to 12 what's in th'e license'-- related to the licensee, is to go 13 back and assess their grid stabil'ity analyses relative to 14 these factors that are laid.out here. !
15 And I don't understand. I mean, what are you i 16 trying to tell us, they do or they don't -- that they are or 17 they are not required to update their analysis? !
18 MR. JENKINS: I think we're saying the same thing, 19 which is that apparently a licensee has an FSAR and that
- 20. indicates that,it includes not only a licensing basis but 21 the design basis, and if they find a condition which --
22 that's no longer true, then they're going to either have to 23 adjust one or the other, and -- -
24- CHAIRMAN JACKSON: Right. But I guess I'm trying 25 to get at this issue of, they find that something is no ANN RILEY & ASSOCIATES, LTD.
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37
! . 1 longer true. The issue is, what triggers that judgment?
2 MR. JENKINS: Discovery either by the staff or the 3 licensee. .
4 CHAIRMAN JACKSON: Okay. So then if something l 5 happens like the WSCC events, okay, and/or the Virgil Summer j 6 event of '89 and/or the ANO event, is that a discovery that 7 triggers a need for reanalysis?
8 MR. JENKINS: The western grid disturbance, given 9 its regional nature, will not necessarily force licensees to 10 look at their particular control area and say that we need l 11 to reanalyze. I h
12' In other words, the central problem, as Mary l 13 discussed with the western grid disturbance, was.the fact 14 that some parties were not meeting their minimum operability 15 reliability criteria which was established by the council, 16 and the corrective actions would have to work through that 17 voluntary organization. I 18 If the WSCC found that there was a problem with 19 that -- with a particular control area and it centered on 20 that plant, then that would be something that the licensee i
21 or the utility would have to address. !
22 But none of the conclusions I saw were that '
23 specific.
24 DR. ROSS: Chairman Jackson, what I meant by the 25 present tense is that when NRR proceeds, like they said, on l ANN RILEY & ASSOCIATES, LTD.
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j i their third bullet to implement this recommendation, they -
l '
2 certainly, when they' communicate, this say this is not a new ,
3 requirement; remember, your plant was licensed that.way.'
4 So it's not like we're reinventing something. It 5 just we're saying, are you still doing what you said you I
6 would do 15 or 20 years ago?
7 COMMISSIONER ROGERS: Well, I'm troubled by the i 8 whole way this thing is being discussed because it seems'to 9 me that our responsibilities and our licensees' 10 responsibilities are between the two of us, and now we're 11 talking about a grid that's out there, and it seems to me !
t 12 that what we have a responsibility for is to see that the 13 licensee can function safely in the event that something 14 happens on the grid but we can't control that grid.
15 And so we're talking about -- you know, we keep 16 talking about grid stability considerations as if we can 17 control the grid through some licensing action of our own, 18 and to me that -- you know, that's never-never land. We 19 don't do that.
- 20 'And so there's an analysis that says -- I mean the 21 statement here, the analysis must verify that the grid 22 remains stable in'the event of these sorts of things, that's 23 a presumption that the' licensee makes in developing their
- 24. coping requirements, I'll call them, and how they handle 25 those sorts of things. !
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'39 1 But that's not a requirement on the grid because
, 2 the grid's out there and it's whatever it is. And so, you 3 know, I think that the issue which we've been ducking here, 4 I think, is that things are changing or could change out in 5 that grid that are different from the way the historical 6 record will show. That's what we're concerned about.
7 And what are the implications of that with respect 8 to our requirements on our licensees?
9 CHAIRMAN JACKSON: Exactly. That's all I'm trying l 10 to get you to say. Thank you. Thank you.
11 COMMISSIONER ROGERS: We can talk until the cows 12 come home about what the reliability councils have to do.
l 13 We don't control the reliability' councils. I 14 MR. JENKINS: If we can go to slide 15, please.
15 Okay, and slide.15, this is a part of the ongoing actions, 16 future actions that we plan to take in light of these 17 changes in the industry.
18 First, we plan to monitor industry developments.
19 We met with utilities, Commonwealth Edison, government 20 authorities, such as FERC and DOE, and also with the North '
21 American Electric Reliability Council. I would say that 22 this particular matter is a new area for the staff to enter 23 into before we consider the grid reliable.
24 We still consider the grid reliable and sthble 25 based on the evidence that we have, however, we are trying ANN RILEY & ASSOCIATES, LTD.
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1 to look ahead and identify if there are any problems . )
)
2 approaching on the horizon. j 3 The next bullet, we're proceeding in securing a
]
4 contractor to assess the risk significance due to potential 5 grid instability as a result of deregulation, and this will 6 address some of the points that you are mentioning.
7 We can't control the -- what's happening in Iowa 8 as how it affects a plant at Palo Verde, but we can assess 9 whether or not changes in the industry require us to take 10 additional actions to compensate for any grid instability.
1 11 As recommended by the AEOD report, we plan to I l
12 issue a generic communication to licensees to reemphasize to s
them the need to maintain their design basis with respect to 13 i 14 off-site power requirements. ,.
15 There is no change here. The equipment has to 16 have adequate voltage and frequency in order to operate, and 17 the preferred source is the off-site power system.
18 Lastly, as part of the PRA implementation plan, we 19 plan'to reassess the risk from the SBO perspective.
20 Overall, we are taking a look at this brand-new world as it 21 develops, and I think in the past, the line for us was the 22 capacity to switch. Some of the grid stability 23 considerations on the previous slide dealt with when a plant 24 was initially licensed and we were concerned with the local 25 grid operation. But that was all assuming that the grid was ANN RILEY & ASSOCIATES, LTD.
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41 l 1
1 reliable and stable. I I
2 COMMISSIONER ROGERS: It's out there. Whatever it
)
1 3 was was not going to change. 1 1
4 MR. JENKINS: Right. I 1
5 COMMISSIONER ROGERS: And that in the event of any 6 of these three things on -- these challenges on slide 14,
)
7 that the plant could handle that.
8 MR. JENKINS: Right.
9 COMMISSIONER ROGERS: See, we're using the term 10 stability and reliability. We're coupling the two together, 11 and I wonder whether there's a distinction between them or l 12 if there is no distinction between them, then we ought to 13 use one term, not two. But I suggest that there might be a 14 . distinction between them in that it seems to me that when 15 we're talking about stability, we really are talking about I 16 certain deterministic considerations, and when we're talking l 17 about reliability, we may be talking about more 18 probabilistic considerations out in the grid someplace, 19 whereas the stability analyses tend to be related to very 20 specific types of events which could then be handled through 21 a deterministic'fix of some sort.
22 So I dont know what your thinking on this is, but 23 I would suggest that in the interest of clarity, either we 24 use one term, reliability, and not two, unless we really do 25 want to draw a distinction between stability and reliability ANN RILEY & ASSOCIATES, LTD.
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- 1. and how they affect licensees and how we think about the ~ .
i 2 grid, in which case we have to be, I think, clearer than we l 3 are right now.
I 4 CHAIRMAN JACKSON: Dr. Thadani, you want'to j 5 comment?
I 6 MR. THADANI: I just want to say, I completely 7 agree with your comments and we do want to draw a '
l 8 distinction and just as you described it. So we'll make a l 9 point of making -- i l 1
10 CHAIRMAN JACKSON: So there are two terms.
11 MR. THADANI: Two issues, yes, and we'll make sure 12 that we characterize them properly. .
13 . COMMISSIONER DIAZ: I just wanted to make,sure 14 that when Mr. Jenkins'was talking about the brand-new world, !
15 are you talking about daylight time or nighttime?
16 MR. JENKINS: We have to find out exactly which it 17 will turn out to be.
i 18 COMMISSIONER ROGERS: Which time zone? l 19 CHAIRMAN JACKSON: Well, I. guess my only question 20 has to do with the.following: why is it going to take until 21 the end of 1998 to do these things? And if we're going to 22 utilize contractor expertise, have we placed a contract?
23 MR. JENKINS: We're in the process of placing a i
24 contract. i 25 MR. THADANI: Mr. Jenkins, he was down at Oak ANN RILEY & ASSOCIATES,'LTD.
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43 1 Ridge about two weeks ago.
2 MR. JENKINS: We wanted to assess the capabilities 3 of the contractor, and that was part of the delay in order 4 to have a good fit between our -- what we're interested in 5 what they can provide.
6 CHAIRMAN JACKSON: Well --
7 MR. THADANI: If I may.
8 CHAIRMAN JACKSON: Please.
9 MR. THADANI: There are a number of issues that 10 we're trying to make sure we take into consideration. I 11 mentioned reactor coolant pump seal issue. Some of the 12 inspections ~have identified concerns about the so-called 13 alternate AC power source at some plants, Millstone in 14 particular, there were the problems there; questions about 15 . availability of the alternate AC source if there'is delayed i 16 loss of 6n-site power.
17 That.is, if you don't have simultaneous loss of 18 off-site and on-site AC power, it could be, the way the 19 station blackout rule is written, it could be that an hour 20 later, and that's what happened at Millstone, an hour later, 21 because the battery charger has gone from the alternate AC 22 power source, but that alternate AC power source may not be 23 available.
24 There are a number of issues. We're trying to 25 make sure. The whole idea of trying to go to Oak Ridge and ANN RILEY & ASSOCIATES, LTD.
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l 44 1 trying to get additional information on this issue, the .
2 potential impacts in terms of grid reliability, it would be 3 very difficult for us to move an issue at a time, 4 particularly if we're in the realm of backfits. We need to 5 be able to integrate, understand what the risk significance 1 1
6 is, and be able to support whatever actions we want to take. {
7 CHAIRMAN JACKSON: Of course we have to support 8 whatever actions we want to take. Of course we have to 9 worry about backfit. Of course we have to do the cost-10 benefit analysis. Nonetheless, the train is leaving the '
'll station.
12 And the issue, to me, they're twofold, there are 13 two pieces. One has to do with, as Commissioner Rogers 1
14 says, all we can control is what we can control.
15 Nonetheless, we're a public health and safety agency. If we 16 know that there's a larger issue out there, even if it's'in 17 the realm that we don't control, but the industry is 18 organizing itself, and it's not that they're not thinking 19 about it themselves, relative to certain kinds of 20 requirements, whether some agency needs to have some ability 21 to enforce certain things, et cetera, we might be asked to 1
22 speak to it.
l 23 We need to be in a position to speak to it in a l- 24 time frame that is timely. relative to what's going on. And j 25 that's why I'm asking the question about why is it taking us
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. 1 two years to get to this when there could be legislation'or 2 there could be actions that go on this year that relate to 3 these kinds of things. So that's number one.
4 And number two, again, we're here, you know, going 5 around the barn more generally on issues having to do with 6 licensees maintaining their current licensing bases, and we 7 have things in the FSAR that relate to assumptions or 8 analyses about, you know, grid stability and, you know, in 9 terms of coping capabilities in plants, and the Commission 10 is being asked and in the process of making decisions, you 11 know, with respect to that, and the issue again of being 12 able to inform that process in a way that makes sense.
13 And so again, we can't just kind of lull along 14 , because we say, well,'you know, that's DOE's Office of 15 Emergency Management, we've got to get this contracting, 16 we're going to take two years to do our thing, when the ;
i 17 train's leaving the station. l 18 And that's all I'm really trying to say. We don't 19 do what we don't have the regulatory authority to do. And 20 we don't want to overstep the bounds, but at the same time,
'21 if there's an issue, we need to clearly identify it, 22 identify it in a timely way, and even if it's not in our 23 regulatory purview, if there's a public health and safety 24 issue, we have to be prepared to speak to it.
25 And that's what -- I mean, I think you have to ANN RILEY & ASSOCIATES,'LTD.
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'46 1 develop a little bit more of a sense of urgency with, respect .
2 to this.
3 Is that the end of your presentation?
4 MR. THADANI: Yes.
l l 5 CHAIRMAN JACKSON: All right, we'll hear from the 6 next panel. Thank you.
7 Well, gentlemen, I want to thank you for coming
'8 'and I think -- I'm assuming that -- who's the lead of the 9 discussion here? The gentleman from DOE, Mr. Meyer.
10 Okay, so why don't you give us the organizat, ion of 11' your discussion.
12 MR'. MEYER: Good afternoon, and thank you for the.
13 oppo'tunity r to present the Department of Energy's views on 14 . matters related to the reliability of the Nation's fault-15 electric system.
l 16 I am David H. Meyer, electricity team leader in.
17 the Office of Policy and International Affairs at the 18 department.
19 The department strongly supports the restructuring 20 that is new occurring in the e10ctric industry because we 21 believe that it can lead to redur,ed electric costs and 22 enable consumers to choose among a wider range of energy 23 products and services. -
24 However, the transition to competition will 25 require changes in the institutional infrastructure that has ANN RILEY & ASSOCIATES, LTD.
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47
. 1 been developed over the past several decades for maintaining 2 grid reliability.
3 We believe that competition and reliability can be 4 compatible, but we also believe that that result will not be 5 achieved automatically.
6 Ensuring continued reliability must be set as a ,
7 design requirement and taken into account as a critically 8 important policy objective by the legislators, regulators, 9 industry executives, and others who are presently concerned 10 with the overall architecture of the new electric industry.
11 I'm pleased to say that in my personal opinion, i 12 this concern has been generally accepted as a critical 13 design requirement and that in one fashion or another, 14 strong mechanisms'for preserving reliability will be built 15 into the new industry.
4 16 That, however, I have to add immediately that 17 there may be some bumps in the road before we get the design 4
18 set exactly right.
i 19 Let me turn to the department's current activities 20 related to reliability, and there are several activities 21 that come under this heading.
22 The first, and perhaps the most important to you 23 in today's context, is reliability as it rela'tes to the 24 proposed federal legislation, that is, not DOE's own ideas 25 or views on the legislation, but more generally by others.
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48 1 The department believes that the existing legal framework .
2 for the industry is out of date and needs to be modified to 3 be relevant to a competitive industry.
4 Legislation is needed that will resolve 5 jurisdictional ambiguities, eliminate obstacles in federal 6 law to competition, and provide policy. guidance and 7 direction on a wide range of issues raised by the prospect 8 of competition.
9 We have developed some concepts and draft 10 materials for such legislation as a basis for interagency 11 discussions, and we hope that these discussions will lead in 12 due course to a legislative proposal that the President will' 13 recommend to the Congress.
14 CHAIRMAN JACKSON:
Now, do you have this working 15 on a particular track where you developed a specific l 16 interagency process and have it tracked to a recommendation 17 or set of recommendations to the President by a. proposed 18 date?
19 MR. MEYER: Our proposal is in a -- has gone into 20 an interagency review process. That's not a process that we 21 can control, so we are not able to give you any particular 22 date.
23 CHAIRMAN JACKSON: And the NRC is part of that?
24 MR. MEYER: I am not sure who is and who is not in l
25 on that process.
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'49 1 CHAIRMAN JACKSON: Is the NRC part of that? Can j l
2 anybody speak to that? I i
3 MS. CYR: People on my staff have been meeting 4 with a group of people at least from DOE on' issues on j 5 restructuring legislation. I don't know if it's a different 6 set than this, but --
7 CHAIRMAN JACKSON: You do suggest that there's an j 8 actual document that's undergoing interagency review?
9 MR. MEYER: The interagency review process was put l 10 on hold pending Secretary Pena's confirmation. I 11 Now, Betsy Moler has been nominated as deputy and l 12 my personal' expectation is that she will want to take a very 13 acti've role in that process, so it may be that that process l 14 will be delayed yet further to allow her to be in place and 1
15 then take an active role. '
16 CHAIRMAN JACKSON: So let me make sure 1 17 understand. There is or is not a draft document that's 18 undergoing interagency review?
19 MR. MEYER: There's a draft document that awaits
- 20. an active interagency process.
21 Reliability is one area that we think needs to be 22 addressed in this legislative debate. The existing 23 infrastructure for maintaining reliability has been 24 developed on an as-needed basis by the industry and has 25 little or no explicit basis in federal law.
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50 1 Legislation may be needed to express an explicit .
2 federal interest in reliability and provide support to the '
3 industry concerning the setting of reliability standards, 1
4 operation of the bulk electric systems, monitoring of 5 compliance with the standards, and enforcement of the 6 standards when necessary.
7 I will return to this subject in more detail in 8 another section below.
9 Let me speak very briefly to the task force on ,
10 electric system reliability that the Secretary of Energy, 11 Hazel O' Leary established last year.
12 This is a subcommittee of the Secretary of 13 Energy's Advisory Board and the task force is chartered to 14 address technical, institutional, and policy issues .
15 . pertaining to reliability. It is chaired by former 16 Congressman Phillip Sharp, now of Harvard.
17 We were pleased that a member of the Commission's 18 staff attended the task force's March meeting, and I suggest
~
19 that the Commission consider writing to Mr. Sharp to express 20 its principal concerns in the reliability area so that he 21 and the other members of the task force can take your views 22 into account as they do their work.
23 CHAIRMAN JACKSON: Now, we may indeed do that, but 24 I also would ask that you make -- take the NRC's concern on 25 this issue to the task force.
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51 1 MR. MEYER: Yes, yes. We would welcome more y 2 frequent dialogue with you and others as appropriate here to 3 -- so that we have a very clear appreciation for your 4 concerns.
5 We have federal reporting requirements for major ,
6 system incidents. That is, that the department, in order to ,
7 meet its national security requirements and responsibilities 8 contained in the federal response plan, has established 9 mandatory reporting requirements for electric power system 10 incidents or possible incidents.
11 These incidents are to be reported to the 12 department through its Emergency Operations Center and the 13 type of incidents to be reported on include load shedding 14 actions or loss of firm loads, system voltage reductions, 15 public appeals for short-term reductions in electricity 16 usage, acts of actual or suspected physical sabotage or 17 terrorism, add fuel supply emergencies.
. 18 CHAIRMAN JACKSON: Have you been actually trending 19 this data? How recently has this reporting started?
20 MR. MEYER: That reporting requirement has been in 21 place for quite some time. We are in the process of 22 . preparing a new summary which we will distribute to all 23 transmission owning and operating entities.
24 The plan is that that would be distributed under a 25 cover letter signed by the Secretary and we wish to -- the ANN RILEY & ASSOCIATES, LTD.
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52 1 thought is that this wou'1d demonstrate the Secretary's keen _
1 2 interest in reliability issues.
3 Once an incident is reported to the depart, ment, 4 the department then alerts other agencies as appropriate and 5 works with them to develop a coordinated response to the 6 problem, if a response is needed.
7 Let me speak briefly about our participation in 8 disturbance reviews. That is, when significant outages or 9 other disturbances occur, the industry examines the data 10 pertaining to the disturbance in minute detail in order to 11 learn as much as possible from the incident about its causes 12 and how similar incidents might be prevented.
13 Last summer, as one of the 24 recommendations in 14 our report to the President on the western outage of July 15 'nd and 3rd, the department determined that henceforth, it 2
16 would participate in the reviews of all major system 17 disturbances, and our reasons for participat.ing in these 18 reviews are to demonstrate our continuing commitment to 19 maintaining reliability ~and to learn, along with the 20 industry, all that we can about the causes and 21 preventability of such incidents.
22 Finally, let me speak briefly about our activities 23 related to systems under -- or regions under stress.
24 From time to time it becomes apparent that the 25 bulk electric system in one or another region is under ANN RILEY & ASSOCIATES, LTD.
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e j 53
. 1 stress, even if no actual disturbance or incident has i l j 2 occurred, due to severe weather, outage of one of major l 1
3 generation or transmission facilities, or some combination 1
4 of such factors.
i 5 In these cases, an electricity staff group at the
) '
6 department monitors the state of affairs in the region l 7 closely and provides at least weekly status reports to the I
8 secretary and other senior department officials.
9 In some cases, we have been able to send technical 10 staff to the affected region before incidents occur. These 11 people have worked with their counterparts from industry and I
12 State and local governments to identify and execute 13 preventive -- or preventive or mitigating actions.
l 14 Let me turn to involvement of industry, State, and l
15 . federal regulatory agencies in these activities. '
16 We endeavor to maintain an active dialogue, as 17 appropriate, with other parties, and we would be pleased to 18 work more closely with the Commission on matters of common 19 inte'est.
r 20 One of your questions in the letter of invitation 21 concerned activity on our part with respect to nuclear 22 safety issues in the context of reliability, and so far as I 23 am aware, the department has not as yet found occasion to 24 give explicit attention to nuclear safety issues in relation 25 to its reliability activities, but we would be happy to work ANN RILEY & ASSOCIATES, LTD.
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54 1 with you to find a way to focus those. -
2 CHAIRMAN JACKSON: Well, a beginning would be if 3 we are clearly in the interagency process.
4 MR. MEYER: I appreciate that. If you want to 5 play a role, I cannot believe that there wouldn't be an 6 opportunity to do that.
7 Let me turn to our interest in the independent 8 system operator concept.
9 The department has a keen interest in the ISO 10 concept in general, although we do not wish to be understood 11 as endorsing any particular one of the many ISO designs and 12 proposals now in circulation.
13 The ISO concept became popular as it became 14 apparent that in the competitive wholesale market, it will 15 be necessary to ensure that regional transmission networks 16 are run without discrimination against any participants in 17 the market's commercial transactions, and that utilities 18 that own both generation and transmission could avoid 19 conflict of interest problems by acceding the operation, if 20 not the ownership of their transmission facilities to an 21 independent party.
22 But secondly, it also has become apparent that 23 there is a need to ensure that the regional transmission 24 networks would be run without stressing them beyond their
-25 physical limitations, but also without allowing those ANN RILEY & ASSOCIATES, LTD.
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. 55
. 1 limitations to be used as a pretext for discrimination to f 2 the advantage of some market participants and the 3 disadvantage of others. ,
4 Both of these concerns imply that there will be a 5 strong and enduring need for independent regional scale 6 transmission entities. As federal legislation to update the 7 legal framework for the industry takes shape over the coming 8 months, consideration should be given to provisions 9 pertaining to ISOs.
10 Like reliability itself, ISOs appear to be too 11 important, too critical to the successful function of the 12 new industry not to warrant explicit coverage in the new 13 legal framework.
14 Let me conclude then by going back to the subject 15 'of reliability provisions in proposed federal legislation.
16 The department has not yet offered its proposal, but -- and 17 so here I can only mention ways that reliability might be 18 addressed in federal legislation.
19 One approach would be to authorize a federal i t
20 agency, such as the FEEC, to approve reliability standards '
21 developed by affected parties through a membership-based 22 organization.
23 The agency that is -- possibly the FERC could also 24 be empowered to approve procedures proposed by a reliability 25 organization for the organization's own activities, h
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56 1 including monitoring and enforcement of the standards. -
2 Finally, the legislation can provide the agency 3 with the authority to enforce the standards itself if 4 necessary, although the initial responsibility for 5 enforcement might reside with an industry organization.
6 That concludes my statement and I would be happy 7 to answer questions at.your convenience.
8 CHAIRMAN JACKSON: Okay, I think we'll go through 9 -- I think what we'll do is start with you, Mr. Gent. Is 10 that the correct pronunciation of your name?
11 MR. GENT: Yes, it is.
12 CHAIRMAN JACKSON: And then we'll go through the 13 different regional, and we'll let you Mr. Nye, last but 14 certainly not least, tell us the real deal from the 15 industry.
16 MR. GENT: Thank you, Madam Chairman. Good 17 afternoon, commissioners. I'd like to thank the Commission 18 for extending this opportunity to the North American 19 Electric Reliability Council for us to talk about what we.'re 20 doing in the way of reliability and how deregulation might 21 affect reliability.
22 I'd like'to start by saying something that's not 23 in my prepared remarks. I've notiged while sitting in the 24 audience that you have this desire to participate in this 25 process and I'd like to offer that invitation for the NRC to 4
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Y 57 1
. 1 participate in any, all, some, or none of our processes at )
g 2. any time you would like immediately without going through
+
3 NERC processes, peer review.
4 We would welcome your attention. Your staff has 5 visited our offices and I'd like to invite them back because 6 I think a lot has happened since they were there when they 1
7 were preparing this report that served as a basis for this 8 discussion.
j J
9 As you know, NERC's responsibility is the high-
, 10 voltage grid that interconnects generators and load centers.
11 We have three major grids in the United States and Canada. ,
l 12 Some say four. It depends on how you count Quebec. That
] l 13 would be the fourth.
14 We call'them in our terminology interconnections 15 and I understand what Commissioner Rogers is saying about 16 the terminology. We have some very strict terminology that 1
17 probably conflicts with.your very strict terminology in many f 18 cases.
19 So as we have defined reliability, we break it 2
i 20 into two parts. We talk about adequacy and we talk'about l 21 security, and I've learned that security means something to 22 everybody a little bit differently than it means to us.
I 23 In this case, it means that we must' be able to 24 withstand a large contingency outage. Your staff has listed 25 a number of examples in their report, transmission lines, ANN RILEY & ASSOCIATES, LTD.
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58 1 corridors, generating plants and the'like. -
2 Our initiatives dealing with security and 3 standar'ds relate directly to your interests in grid 4 reliability. We require that there has to be enough 5 spinning reserve to be able to withstand those 6 contingencies. We need to ensure that_these. units that have 7 the spinning reserve are strategically located and we have 8 to ensure things like transmission lines have enough room 9 left to withstand these losses.
10 The public in general doesn't understand why we 11 can't load transmission lines right up to the maximum 12 thermal rating, and I think after listening to this, I'm 13 sure you understand that there is a stability issue. There 14 is also a contingency issue.
15 To help us reliably handle the increasing number 16 of transactions, NERC is establishing a network of 22 17 security coordinators graphically and electricity 18 distributed across North American. And many of the other 19 speakers that fol' low me will be addressing those security 20 coordinators.
21 This is the real key to instantly providing a 22 . reliable network. These coordinators are going to have 23 their own dedicated communications network, we call it 24 interregional security network, or ISN and it will begin 25 operation as soon as June of this year with some limited ANN RILEY & ASSOCIATES, LTD.
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59
. 1 functionality.
2 Today, our security coordinators are implementing 3 several interim procedures and processes so that the more j 4 sophisticated tools that they'll need to make definitive 5 judgments, and, yes, even run stability studies, are fully t
- 6 developed. The ISN is going to ramp up to. full 7 functionality later in.1997 and we hope will be totally on 8 line in the early part of 1998. I 9 These 22 security centers will be responsible for 1
10 conducting security analysis of the grid with on-line data, 11 and will have the authority to take the actions necessary to 12 prevent or relieve overloads or prevent potential risk to i 13 the grid.
14 This very elaborate system should allow many 1
15 multiples of additional transactions to take place in this :
16 new deregulated open access world that we are surely fac'ing.
17 You've asked in the notes that I received. earlier 18 about how the governance that would involve an independent 19 system operator concept --
20 CHAIRMAN JACKSON: Before you go on, let me just 21 ask you this question. Do nuclear plants receive any 22 special recognitios in protecting their off-site power, 23 their access to off-site power?
24 MR. GENT: Yes, they surely do.
25 CHAIRMAN JACKSON: Could you tell us how that
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60 1 works? ,
2 MR. GENT: Yes. In an operational sense, if you 3 look at what I have attached to my material, you'll see that 4 I have excerpted what's called a NERC operating manual.
5 This is just a cover sheet.
6 If you look a little bit deeper at the table of 7 contents, you'll see something I've highlighted in yellow.
8 It's called operating policies. And then I've gone a little 9 bit deeper. Policy number 5 on the next page, for instance, 10 refers to emergency operations, and then the number E item 11 there is called system restoration.
12 I realize this is a lot of detail, but if you will 13 shift with me now to a page that's numbered at the hottom 14 PS-7, there will.be a' reference to system restoration. l 15 There's something called requirements. This is something ;
16 that's required. These are must-do things. 1 17 In this case, when you're restoring the system 18 from some system collapse or an outage such as we had in the 19 Western Systems Coordinating Council on August 10th, under 20 the requirements, you see steps one through five. The fifth 21 step in this process is off-site supply for nuclear plants.
22 This is the first thing that happens after the 23 system is brought back together, resynchronized and judged 24 to be functioning. This is before we bring back any other 25 loads or generating plants. The first thing we do is try to ANN RILEY & ASSOCIATES,'LTD.
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< 4
. i 61 1 bring back the nuclear plants. !
1 2 CHAIRMAN JACKSON: Well, as part of that, do you 4 l a
l l ,
3- have specific information as to the coping capabilities of !
l 4 the nuclear units in a particular region to -- relative to j i
i 3
a 5 how long the unit or~ units can go without off-site power, !
- 6. the provision of off-site power? )
j 7 MR. GENT: I don't have information of how long '
' 1
- 8 they could go without off-site power.
- 9 CHAIRMAN JACKSON
- So that's not readily available l 10 to those who would be in the position of working to restore j 11 the provision of off-site power?
i 1 j
12 MR. GENT: I don't know that that's the case.
- I l
t 13 MR. DELGADO: That information is available in the !
14 EMS screen. "We have figures built into the energy ;
l 15 management system that address the needs of our plants. l j 16 There are written and screen procedures similar to this. ;
l 17 And of course we also monitor the plant, for example, the 18 alarm, so that the operator -- even when the plant is out, i
j 19 the operator can do something about voltage levels that is 4
4 20 required to meet the requirements of the power plant.
l 21 CHAIRMAN JACKSON: I'm asking a slightly different
'l j 22 . question. That is,'let's assume there's been, you know, 1
23 some loss of the grid, and now you're working to restore the l
I' 24 power. I guess what I'm trying to understand, you know that i
4 25 there the different stations have different coping N
4 i
i e .
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l l 62 1
1 capabilities depending upon their own on-site power sources .
2 and design of the plant. And the question is, is there --
3 as part of this grid management and restoration you,say ,
4 should be given high priority, but that has to be informed 5 by what the actual status is of the given plant.
6 MR. GENT: We have actual real-time communication 7 with the plants, and if they were to have specific problems, 8 my operators and the plant operators would be in 1
9 coordination. We generally know of their requirements and !
i 10 they know of the status.of the grid in preparation for these I 11 events, and in real time, we can tune the situation by 12 direct telephone communication with ring-down circuits.
13 CHAIRMAN' JACKSON: 'Do you have a worked-out 14 protocol relat've i to the nuclear plant?
15 MR. WOLFF: I'm struggling with the word protocol 16 but we have a worked out, ongoing daily relationship of 17 talking with the plants, and if you will acpept that as a 18 protocol, yes,, we have a protocol. It may not be written in 19 a document somewhere. ~It is a general agreement to operate 20 and communicate.
21 MR. DELGADO: Maybe I can address it. From'our 22 perspective, we do have the procedures which have been 23 written in conjunction with the power plant, so our plant 24 staff.has -- in preparation for this meeting, I checked and l l l 25 the last one I saw was revised in April of this year, so I'm l
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63
. 1 satisfied that we're keeping.up with it.
l ,
2 Whether or not -- and I cannot answer your l 1 3 question, whether or not the~ operator knows how long the 4 power plant can be black. By giving it top priority, I can 4
5 assure you that it's getting it as soon as the operator can, l 1
! 6 in other words, getting first priority.
- 7' So -- and besides that, the communication is f
- 8 pretty solid from the perspective of dealing directly with j 9 the power plant by. hands off operating and communication is j 10 not required. Line communication can be done hands off.
i .
2 11 So by having a top priority issue, it assures us 12 -- it assumes the system is energized with the black start 13 plants. The nuclear power plant will be given the first 14 priority in getting access'to it.
15 Besides, since they are connected to a backbone 16 345, which is the highest voltage we have, in any 17 restoration of the system, you begin with the black plant 18 and you go right to the backbone. So those plants naturally 19 will receive priority because you right away want to get to the backbone.
20
'21 CHAIRMAN JACKSON: You don't have any 765 kV?
22 MR. DELGADO: Sometimes I wish we did, but : tght 23 now we don't, no, and I don't expect we will in the near 24 . future, but 345 is quite ample for us.
25 COMMISSIONER ROGERS: Would that be true in all ANN RILEY & ASSOCIATES,~LTD.
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64 i
1 the regional coordinating councils? . .
2 ,MR. DELGADO: I have a map here of Maine and I can 3 assure you if you look at it, the thick lines join all 4 nuclear power plants.
5 COMMISSIONER ROGERS: No. I'm talking about the 6- whole country now. I'm not talking about a regional. I'm 7 talking about now every regional, whether that's the case.
8 MR. GENT: I'm not sure this will answer your l 9 question, but virtually every plant has a procedure and f 10 protocol for being restored to the network and there is an 11 order in which they're called in to do that depending on the 12 situation, but everyone has a plan that includes that.
13 COMMISSIONER ROGERS: See, the question that I -
14 haven't heard a direct answer to is whether there is 15 something different about how a power pool treats nuclear 16 plants from how the regional coordinating council treats 17 nuclear power planta. i l
18 Because you may have a -- you know, a larger I 19 problem than just one that is in a particular power pool i
20 grid that extends well beyond that, and then the question is' I 21 whether the coordinating council has a particular way of 22 dealing with nuclear power plants in the broader region.
23 That's the question I think that we haven't had an answer 24 to.
25 MR. WOLFF: I brought with me two paragraphs that ANN RILEY & ASSOCIATES, LTD.
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i
, . j 65 -
, 1 indicate that we do have a formal procedure for ensuring 2 that nuclear plants receive the highest priority. That is 3 in conjunction with NERC requirements and I can assure you !
4 that the New England Power Pool and New York Power Pool and i 5 PJM do it that way. We're known as the three tight pools.
i 6 I have no reason to believe it's not done that way in other l
7 areas. I'm sure it is, but I know for a fact it is done in ;
j 8 the whole northeast region.
9 COMMISSIONER ROGERS: Yeah. Well, it's a question f 10 -- it's a national based question rather than a regional
, l 11 based. ;
- 12 COMMISSIONER DIAZ
- Is the NRC notified when i .
13 something like this happens and you're actually trying to 14 restore'the lo'ad? Is our incident response seen on the t
15 ^ network?
16 . CRAIRMAN JACKSON: I think our information comes 17 through our licensees. Okay.
1 18 MR. GENT: I mentioned the NERC operating manual.
19 There are a number of other~ issues in there that you may be 20 interested in and I'd be happy to provide your staff with a 21 copy or as many copies as.you'd like and answer as many.as 22 questions as you might have.
23 Regarding the governance issue, whether governance 24 of ISOs is going to affect reliability, we think that that 25 is not going to be the case and I'd like to explain why.
I ANN RILEY & ASSOCIATES, LTD.
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66 1 Our initiatives are based on separating transmission .
2 operations and reliability from a marketing fcnction. We're 3 trying to do that right now.
4 If an ISO is a means to achieve this separation of 5 market and operating function, then certainly it will be 6 successful in creating the separation and. independence and '
7 they will enhance reliability.
8 What we're doing now with our security 9 coordinators is getting out in front of this. We think that 10 eventually they'll probably evolve into ISOs if that truly 11 is going to be'what the industry will be shaped like.
12 Today, however, we need to move on, and so to mak'e
~
13 sure that our security coordinators, these 22 locations 14 around the United States and Canada, are truly acting 15 independently, we've asked them all to sign data 16 confidentiality agreements, l 17 This is necessary because some of the data they 18 need for reliability purposes and analysis can be used to 19 somebody else's commercial advantage, and I think you can 20 understand how they're fairly skittish at doing that.
21 So we think that the best way to handle this, 22 without it taking'an awfully long time, is to have them sign 23 data confidentiality agreements. That's in the process 24 right now.
25 Our security coordinators will then be independent ANN RIL,EY & ASSOCIATES, LTD.
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'67
, 1 of the marketing function and will not be affected by any 1
2 decision made by the governance of an ISO. l 3 I've mentioned our operating standards. I need to )
4 4 talk about our planning standards, which you may have some l
5 interest in as well. These are not nearly as well-defined I i
6 as our operating standards. We're now approaching the issue j 7 of elaborate planning standards. It's under way and I would 8 invite the Commission to participate.
I 9 I'm personally going to take the issues I've heard i l
10 here today back to the groups working with this and see that I 11 there is a consideration of the stability issue, viewing 12 with me your licensees to see that that's an updated process l l
13 and'done fairly often. )
14 I think that as soon as we get into this, we'll l l
15 see that it is a process that's now considered. I just 16 can'.t testify to it.
17 I hope from the comments that you'll hear from l l
18 those that follow me and from me, we believe that'NERC's !
19 interest here is really in seeing that the grids are not 20 only reliable today, but they remain reliable through the
]
21 coming years during the restructuring and after.
22 We agree in large measure with the conclusions of l
23 the report that was presented to you earlier, and then I 24 said earlier, I think we need to revisit not only the report 25 but have the staff revisit with NERC staff to learn what ANN RILEY-& ASSOCIATES, LTD.
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1 68 l 1 changes have been made since they visited this. .
x 2 I thank you again for this opportunity and I'm !
3 sure that there will be other questions. I'll try to answer 1
l 4 them along with the others on the panel.
1 5 CHAIRMAN JACKSON: Well, I'd like to ask you a 6 question couples rele. Live to the submission that you've 7 made. You were talking about your processes for developing 8 operating and planning standards have been accelerated and 9 are being changed to include more opportunity for input by 10 all affected parties.
11 And you talked about ways of enforcing standards, 12 and you said regarding that enforcement, one possibility is 13 that we will end up with what are generically called a 14 reliability -- calling a reliability compact, which will i i
15 .probably consist of a series of contracts that specifically 16 obligate'the policies to abide by the NERC standards.
17 Does this need some kind of a federal backing or 18 legislative undergirding? And when the industry 19 representatives speak, I'm going to ask them to address that 20 issue separately. But I want to hear from you.
21 MR. GENT: You'll probably get four or five 22 different answers. This is currently the issue under debate 23 now. We know what the rules are, we know what they should 24 be. How do you enforce them when somebody says I'm just not 25 going to do it?
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69 1 We currently have a process that has worked, but 2 we're anticipating that as competition gets heavier and 3 heavier, we're going to have some people that refuse to' obey 4 by the rules.
5 The best way we have right now is with contracts, 6 and to the extent the contract law works,,this will. work.
7 But we are debating whether we do need some federal 8 backstop. We're a little bit timid in asking for it because 9 we often get more than we ask for. And I think that was 10 evident from a previous presentation. j 11 CHAIRMAN JACKSON: Also, I note that you claim 12 that with respect to the last issue we had asked you to 13 discuss in terms o'f factors and considerations used in i 14 establishing reliability governed structures vis-a-vis loss I 15 of off-site power events for nuclear power plants, that you 16 say that language is being included in some ISO agreeme'nts 17 that requires ISOs to operate the grid in accordance with 18 special operating criteria established by NRC operating 19 licenses.
- 20 Do you think that's a good idea in general?
21 MR. GENT: I'think we absolutely must visit that 22 issue to make sure that it has been considered. I'm certain 23- it has, I just can't testify to that. But.I will be able 24 to soon.
l 25 CHAIRMAN JACKSON: And you also were talking about ANN RILEY & ASSOCIATES, LTD.
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70 1, that NERC is the home of the generating availability .
2 -database, and you say you're primarily interested in, these 3 days, in the types of data that would allow us to model a 4 nuclear unit during a transient or slightly slower' dynamic 5 disturbance event.
6 That kind of modeling doesn't go on today? I'm 7 going to ask the --
8 MR. GENT: Yes, it does.
9 CHAIRMAN JACKSON: -- industry people to speak to 10 this too. So if it does, what's the issue?
11 MR. GENT: The issue is one of size. Before, most 12 of this type of modeling has been done by your licensees, 13 and we've learned very recently that these outages spread 14 over entire regions, l'ike the entire western United States, 15 and we need to extend our modeling to include more than just 16 your licensee's area, and having the rest of the world as an 17 equivalent, we need to get into huge modeling, and that's an 18 issue with planning people in NERC.
19 CHAIRMAN JACKSON: Do you have the resources and 20 capability to do that?
21 MR. GENT: We're not sure that we have the 22 resources and capability to do that. We need to find out.
23 It's never been done before.
24 CHAIRMAN JACKSON: Is this a path you're 25 definitely planning to go down?
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- 71 1 MR. GENT: Yes, it is.
2 CHAIRMAN JACKSON: All right. Any questions?
I 3 COMMISSIONER DIAZ: I have just a piggyback on the 4 Chairman's question on that next to last paragraph where it j 5 says, " language being included in some ISO agreements." Is 6 there any reason why some is selected or are we going to try >
7 to -- everyone is using it?
- i. 8 MR. GENT: There's only one ISO agreement now in 9 force and that's in Texas. What's being proposed in 4 10 California will also honor the agreements of the licensees i !
' 11 in that ISO agreement. So that was the reason for the ;
12 reference to some.
]
13 But I think that you can expect, especially after '
14 this process today, I think you can expect they will all be 15 . aware that there n'eeds to be a consideration in the i 16 agreement. ;
1 ;
, 17 CHAIRMAN JACKSON: Let me hear from Mr. Wolff. 1 i 1 18 MR. WOLFF: Thank you, Chairman Jackson. I'm
- 19 pleased to be here to give you some feeling for what it's 20 like to be an ISO.
i 21 First, by way of background, I've been in the i
4 l
22 industry for about 39 years in charge of distribution, in
{
4 23 charge of station plant design for Indian Point 1 and 2 when 24 I was at Con Edison, in charge of the control room at Con 25 Edison, which is an 8,000 megawatt control area, so I know i
1 ANN RILEY & ASSOCIATES, LTD. ;
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72 1 what it's like to operate a control area as an individual ,
2 company.
3 I have had grid planning and construction 4 experience and now four years as the CEO of the New England i
5 Power Pool so I know what it's like to operate a grid from a 6 power pool standpoint.
7 We are effectively an ISO and have been for some 8 25 years. The term has come to mean new things now, but we 9 have been an ISO for those people that supply the electric 10 industry during that 25 years. That group of people has 11 expanded and the term ISO now means you're dealing with not I 12 only utilities, but marketers and the rest.
13 But we will do very little different in the 14 management of the'New England Power Pool from what we have l
15 done, and I'd like to give you a feeling for that.
16 We were formed as a result of the 1965 blackout in 1
17 order to ensure reliability in that area. What will change 18 as we become an official ISO? Our governance will change. ,
19 We like to think that we are very fortunate. We 20 are, at least at present, the only ISO in the nation that 21 will have an independent board of directors. They have been 22 selected and are about ready to be put into place. It is 23 not a sector board of various interests. It'is a single 24 monolithic board dedicated to reliability, dedicated to the 25 ISO, and dedicated to supplying nuclear plants and ensuring '
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73 1, that the facilities are built into the system to make it 2 happen. They have no other vested interest than our 3 interest of reliability. So we're quite fortunate.
4 As a matter of fact, this meeting is my last 5 official duty before going into retirement. This whole 6 thing is getting ready to move and so I do cherish the 7 opportunity to talk to you just before retirement.
8 But I can say that I am quite pleased with the
- 9. excellent board members we have, names you might be familiar 10 with is Charles Stalen and other people with fairly 11 reputable reputations. I think that they will back the 12 interests --
13 CHAIRMAN JACKSdN: Is this the'Stalen who,was at 14 FERC?
15 MR. WOLFF: Yes, it is. And we have people in the 16 regulatory markets and in the marketplaces in reliability 17 and in the industry. So we are positioned to move forward.
18 What else is going to change? Our method of 19 dispatch will change. We have for 25 years been dispatching 20 the system every five seconds on'the basis of least cost.
21 That has been very effective. We have huge computers that 22 capture the data, make the dispatch, and monitor the entire 23 system to make sure economy is in place.
24
~
What else is going to change? I project that we 25 will have additional power now that we have a board. The ANN RILEY & ASSOCIATES,'LTD.
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1 regulators in New England, an organization known as NEPURG, .
2 the New England Public Utility Regulatory Group, are very j 3 much behind the process. They were involved in the 4 selection of the board.
5 They have, as Mike said, actually given me a 6 little more power than I feel comfortable with at times. I i 7 think a limited amount of power is good. I think too much #
8 could be dangerous, but barring that possible problem 9 sometime in the future, we have been reasonably well i 10 empowered to enforce the reliability rules.
11 Now, how do we address reliability? I'm very l 12 interested in'the questions you asked about reliability and 13 stability and that sort of thing.
14' They do mean different things and they're more or 15 less in the eye of the beholder, but reliability means how t 16 much of the time are the lights going to be on? Now, they ,
17 can go off for different reasons. They can go off because 18 we have a slowly growing load and we've had to go to load 19 shedding in order to balance load and generation when we run 20 out of generation.
21 First we ask for voluntary appeals, and then we 22 get the involuntary appeals if things get bad enough. We 23 have not had to do that in New England.- The last incident 24 that I'm particularly familiar with when it was consciously 25 done was in this area in January 19th, I believe, and it was ANN RILEY & ASSOCIATES, LTD.
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4 75 r 1 conscious rolling blackouts. '
i :
2 CHAIRMAN JACKSON: Is it well -- within a'given 3 power pool, is it well understand how low the voltage and/or 4 frequency margins can show before you have a potential for '
] 5 some instability?
6 MR. WOLFF: Yes, it's extremely well-known and we '
l '7 do the studies, we model the system, and we actually 1
8 practice voltage reductions during the spring time of each 9 year in order to see that they work and give us what we want 10 and they're not excessive, so the answer to your question is 11 quite clearly, it is known.
12 CHAIRMAN JACKSON: And that is automatically 13 coordinated with the actual plants or the utilities that 14 , operate the plants?
15 MR. WOLFF: Yes, it is. We coordinate directly
)
i 16 with Millstone and have a voltage schedule based on 17 Millstone's needs and they determine those needs and we 18 follow that schedule and drive the base points at the !
19 substations around Mills'one t to make sure they do not go i 20 below those voltage requirements. !
i 21 So we, in fact, do meet your requirements very 22 specifically in coordination with the utilities, and we have 23 some voltage schedules throughout New England to make sure 1
24 we don't have a voltage collapse.
25 Now, getting back to the area of stability, once ANN RILEY & ASSOCIATES, LTD.
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, 76 1 we.have ensured the reliability by balancing load and . i 2 generation, using both sources, load and/or generation, we 7
3 have to worry about the stability issue, which is the issue l
4 that is taken care of by what we call security constrained ,
l 5 dispatch. !
6 .
In other words, we will not dispatch the system to 7 a load level or to a transmission line loading level which 8 will result in a problem for the loss of any generator or 9 any major system. f 10 So we are already looking in advance. The t
11 computers are constantly monitoring, what happens if this i
i 12 generator goes out, what happens if I lose a Canadian power '
13 source, what happens here? They will make that study, check 14 the stability, determine if we can survive that event, and 15 if we can't survive that event, we will dispatch additional 16 generation, change the dispatch, go off economics, make a }
17 contract with New York to import additional power. There
. 18 'are many, many ways to. solve the problem. This is a cat 19 that can be skinned in many different ways, and it is the 20 job of the operator to determine which way is the most 21 reliable, which is the quickest way, and which will achieve 22 the desired result.
23 So when we do'a security constrained dispatch, we 24 take care of the stability issue. That's how we do that, 25 because stability is something you have to prepare for ANN RILEY & ASSOCIATES, LTD.
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'77 1 before it happens.
2 The same as voltage collapse, is something you 3 have to prepare for before it happens, possibly even the day 4 before. If you're not ready for a voltage collapse, it's 5 too late to do anything about it. Once it starts to sag, 1
6 you're in a worse position than before it sagged.
7 So that all will remain exactly the same in the 8 -Ikne England Power Pool . We're quite fortunate. For the 9 last 25 years, the New England power utilities have allowed l
10 us to operate that grid as if we owned it, and they have '
11 . charged us with operating it as if we own'it in order that 1
12 they could g'ain the relief necessary for knowing somebody is 13 looking at the farm and making su~re everything is done 14 properly.
l 15 We look at the whole system in a coordinated way.
1 16 We coordinate with the New York Power Pool, we coordinate 17 with Quebec, we coordinate with PJM. We even are limited by 18 certain flows across the central portion of Pennsylvania 19 that limit our Canadian imports, so there is the ability and !
1 20 it is done every day in practice to coordinate across 21 regions, and it is done by the operators in real time and is 22 in no way in conflict with what Mr. Gent is suggesting, a 23 broader and greater scope of this coordination, and I 24 wholeheartedly support that additional scope as part of an 25 answer to one of your questions.
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i 78 1 I mentioned the security constrained dispatch. We .
2 . continue to support all of the NERC criteria. We as 3 operators find it very consoling to have that criteria in a 4 time of competition. There's no question that the members, 5 the players in the market, have fiduciary responsibilities 6 to their stockholders and they will have to make. tough 7 decisions, but I am sure they won't directly conflict with 8 reliability, but having a set of standardized rules and ISOs 9 who are empowered to take care of the reliability aspect is 10 very consoling.
11 If you stop to think of it, there are only three 12 people that'are interested in reliability: The customer 13 most assuredly is, the regulatory bodies, and the ISOs. I. :
i 14 don't believe it is proper to charge the individual players .
15 totally with reliability because they have a direct 16 conflict *. ,
17 We are prepared to set the system up and make sure 18 that the incentives are there for all the players to bring 19 to the table the assets that we need, transmission, !
20 generation, and the like.
21 In the past, we have monitored reliability by 1
22 looking at reserve levels and doing a statistical analysis, 1 23 Monte Carlo type outage analysis on generators, lines and 24 the like.
25 In the future, since we don't have direct control ANN RILEY & ASSOCIATES,.LTD.
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79
. 1 of that, we in New England have decided to go toward other 2 incentives, such as operable capacity.
3 If you remember when Pilgrim was out for several 4
years a couple years back, that plant received capacity 5 credit and was in the planning criteria even though it had 6 been out for two years. The owning utility got capacity 7 credit because statistically it works. There were other 8 plants that were in.
9 In the world of the future, we will not be able to 10 give capacity credit for two years for a plant that is not 11 operating. So we have changed our criteria. We are 12 insisting that all the players go to operable capacity to 13 take care of reliability.
14 What I'm saying to summarize is, we can take care 15 of reliability several different ways, and in this new 16 marketplace, we will have to find those new ways to take 17 care of reliability. There are ways. If we do it right, 18 there's no reason for reliability to suffer and there's no 19 reason for anybody to have interests that conflict with DOE, 20 your Commission, or anybody else.
21 CHAIRMAN JACKSON: Do we need any kind of federal 22 legislative backing?
23 MR. WOLFF: Well, I think NERC is in a position to 24 require these things. I think the good faith and support of 25 the Federal Government is always good. A limited ANN RILEY & ASSOCIATES, LTD.
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80 1 involvement. I'm one of those people who believes that .
N 2 limited involvement is probably good. Complete ignoring the 3 situation certainly is not good. ,
4 Too much involvement, my personal opinion, is not 5 necessarily good either. That's just my personal philosophy l
6 on things.
7 CHAIRMAN JACKSON: But a system where some agency, 8 whether it's FERC or whatever, might lay out some baseline 9 criteria but that the NERC has the primary responsibility I 10 but the ability to enforce it based in some statute is not a 11 problem?
12 MR. WOLFF: No, that's not a problem.
13 CHAIRMAN JACKSON: Okay, let me hear from Mr. Eyre 14 from Western S'ystems.
15 MR. EYRE: Chairman Jackson, I'm sure you're aware 16 the WSCC is the largest and most diverse of the ten regional 17 reliability councils of America. WSCC has ,99 members 18 ranging from 71 traditional utilities to 10 independent 19 power producers and 18' marketers. So we have all segments 20 of the industry involved in the council's activities.
21 It also includes three regulatory represent'atives 22 that serve on WSCC's Board of Trustees. .
Let me cake a 23 moment just to review with you who is responsible for 24 reliability today and where it should be in the future.
25 As the industry restructuring occurs and we ANN RILEY & ASSOCIATES, LTD.
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81
. 1 implement competition, it is imperative on all of us to make 2 sure that we maintain a reliable electric system.
3 For over 30 years, NERC and the regional 4 reliability councils have been the caretakers of reliability 5 through the cooperative development of NERC and regional 6 council policies, procedures, and criteria.
7 There is no reason to doubt the ability, the 8 appropriateness and the resolve of NERC and the regional 9 reliability councils to continue to serve as self-regulating 10 organizations.
- 11. CHAIRMAN JACKSON: Now, you're telling me this in 12 spite of the two events that happened in the summer of 1966 13 -- I mean 1996?
14 MR. EYRE: Absolutely. .
15 CHAIRMAN JACKSON: And why should I have that 16 comfort?'
17 MR..EYRE: Why should you have that comfort? I 18 think what you see happening as of the disturbances that 19 happ'ened last summer is a resolve that the councils are 20 doing right now, to make sure that everything is in place, 21 everything will be administered, and as I go on through my 22 presentation, you'll see, at least in the west, we're moving 23 rapidly to implement a reliability compact that calls for 24 mandatory compliance with sanctions, incentives, financial 25 penalties as may be appropriate.
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82 1 CHAIRMAN JACKSON: And that did not occur before? . !
2 That did not exist before?
3 MR. EYRE: We did not have the sanctions and l 4 penalties provisions available to us prior to those 5 disturbances.
l 6 CHAIRMAN JACKSON: So you're saying that you've i
7- gotten religion now and that's the reason -- ;
8 MR. EYRE: That's a good way to put it. It was a j 9 wake-up call to the whole industry to see what can occur.if i
10 in fact we do not have the mechanisms in place to make sure 11 we have compliance with the rules of the road.
l 12 CHAIRMAN JACKSON: Okay, go on.
13 MR. EYRE: WSCC and NERC are committed to l 14 enhancing accountability for reliability and improving 15 compliance with reliability standards. WSCC strongly favors 16 an industry self-regulating organization approach with a 17 federal and/or state regulatory backstop as may be 18 appropriate.
19 Let me take a'few minutes just to outline to you 20 some of the activities that are being taken in the west to 21 ensure reliability.
22 CHAIRMAN JACKSON: Let me back you up. Elaborate 23 on that sentence a little bit.
24 MR. EYRE: As far as the backstop is concerned?
25 CHAIRMAN JACKSON: Correct. l 1
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1 83
. 1 MR. EYRE: I think I would support the earlier 2 comments, that I think a limited involvement would be 3 appropriate. I think it is also necessary. There is one 4 thing that the industry cannot do by itself. It can design 5 programs for mandatory compliance. It can design a program 6 for sanctions, incentives, and penalties, but it has no way 7 of assuring that it can get everybody at the table and 8 that's where we need support from the regulatory community, I
9 to make sure that everyone is at the table helping design 10 those mandatory criteria and making them accountable and 11 also subject to the penalties or incentives that we feel is 12 appropriate.
13 CHAIRMAN' JACKSON: So would this kind of backstop 14 be some kind o'f federal action, say, mandating NERC 15 ~ membership?
16 MR. EYRE: There are several ways that that could 17 be done. That is one way it could be done. It could be 18 done through licenses by the Public Utility Commissions of 19 the various states. It could be done with -- through FERC 20 mandating to the jurisdictional utilities who they do
-21 business with those types of things. Those are just various 22 options.
23 WSCC is continuously and expeditiously j 24 implementing new protocols and mechanisms to ensure 25 reliability is not sacrificed as we restructure the ANN RILEY & ASSOCIATES, LTD.
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i l 84 1 industry.
f
. l 2 In 1996, the WSCC Board of Trustees unanimously 3 endorsed a reliability compact that reaffirms the council's )
j
\
4 mandatory compliance requirements and which will result in l l
5 the enforcement of established reliability protocols in the 6 west.
l 7 The compact. recognizes,that to ensure continued 8 reliability, all market participants must adhere to the 9 established reliability protocols.
10 A policy level group has been formed to develop 11 incentives and sanctions for ir.plementing the reliability 12 compact. These recommendations will be submitted to the
.13 WSCC membership by'the end of 1997.
i 14 The WSCC agreement states that all control areas, 15 which includes the ISOs, must be members.of WSCC. And as 16 such, they must comply with all WSCC and NERC protocols'and 17 sanctions.
18 Also, and of importance to you as we've already 19' discussed, the most recent filing of the California ISO 20 filing includes a transmission control agreement which 21 requires the ISO to meet the WSCC and NERC protocols and the 22 provisions of NRC' plant licenses.
23 In addition, system operators are-required to give 24 a high priority to nuclear plant restoration, as already 25 mentioned in the NZRC policy 5. I believe, however, that we ANN RILEY & ASSOCIATES, LTD. .
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, l' must make a careful review of this policy to make sure that !
l i 2 this issue is properly addressed, and therefore, I will be t
recommending that NERC and WSCC criteria and procedures be 3 l i !
! 4 reviewed and revised as necessary to meet the nuclear plant i
' i 5 requirements.
i 6 Second, mandatory compliance does not stop with !
l 7 WSCC. As you've heard, NERC also made compliance with its l 8 . protocols mandatory. By establishing a system of mandatory I 9 compliance, all market participants will be accountable for 10 adhering to established protocols and result in a level !
i 11 playing field.
l 12 Within WSCC, we have another reliability program 13 which has been established and is called our compliance I 14 monitoring program, which reviews members' compliance with 15 WSCC minimum operating reliability criteria, WSCC opsrat'ng 16 policies, procedures, and guidelines, and NERC operating 17 policies.
18 In addition, WSCC and NERC are in the process of ,
19 enhancing their operating protocols to make them more 20 specific and measurable as possible. They will have to be i 21 measurable and specific to be enforceable under a mandatory ,
22 compliance program which requires the application of l 23 sanctions and penalties. !
24 WSCC and other regional councils are implementing ,
25 additional security measures. These measures will enhance ANN RILEY & ASSOCIATES, LTD.
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l 86 '
1 interconnected system reliability through the exchange of y 2 information required to assess system security and
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3 reliability, including on-line power flow and security 4 analysis and increased system monitoring. ;
5 These measures will enhance the operator's ability 6 to identify potential reliability problems and promptly take 7 proactive corrective actions to ensure system reliability. '
8 The council has approved a regional security plan 9 that is intended to convey both the responsibility for 10 overall system reliability and the authority needed to carry 11 out the responsibility successfully.
12 This plan was developed and is currently being 13 implemented in response to one of the four strategic 14 initiatives for reliability established recently by NERC.
15 The regional security plan empowers the security I 16 coordinators to take the actions necessary to preserve >
17 reliability. The California ISO will be one of,the security 18 coordinating centers,,and it is envisioned that as the other 19 ISOs are formed in the west, they will also become the 20 security coordinating centers for their section of the 21 interconnected system.
22 WSCC has also established a successful training 23 program that has been carefully structured to provide system r
24 dispatchers and other operating personnel with the necessary 25 skills to deal with the ever increasing complexity of 1
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87 1 interconnected system operation.
2 In addition, a schedulers / contract writers 3 training program was implemented in 1996. This training 4 program familiarizes schedulers, contract writers and energy 5 accountants with system operations and increases their 6 understanding of how their actions impact. interconnected 7 system operation and system reliability.
8 Although WSCC currently has an operation training 9 program, we are currently working with NERC to implement a 10 certification program.
11 Moving on, you have often heard the question or 12 maybe asked the question yourself: is the transmission 13 system being used ' differently than originally designed and 14 will it impact reliability? The answer to the first part of 15 the question, is it being used differently than originally 16 intended? And the answer in most cases is yes.
17 Will it impact reliability? As long as 18 established operating protocols and those implemented by the 19 industry are followed, transmission reliability should be !
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'20 preserved'. Industry and regional reliability councils 21 recognize the changing competitive nature of the industry 22 and the impact this may have on system operations.
23 As such, and as we speak, new protocols are being 24 developed to address changes occurring and being forecast !
25 for electric system operation in the future.
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1 As we restructure -- -
2 CHAIRMAN JACKSON: Let me ask you a question. ,
3 These new protocols that are being developed as we speak, 4 how are they going to be verified to be adequate? I 5 MR. EYRE: Mell, number one, in our compliance 6 program, they will be part of our protocols criteria that 7 must be followed. As part of our compliance program, we 8 will be monitoring those to be sure they're complied with, 9 number one, and through that compliance process and review 10 process, we will identify the needed changes that will be 11 needed.
12 As we restructure the industry, there are a few f 13 implementation issues to consider. We must make certain 14 that interconnected system reliability is preserved. As 15 time frames are established for restructuring the industry, 16 we must all bear in mind that these time frames must be 17 realistic and prudent, and that they may have to be revised 18 to maintain reliability.
19 The regulatory community, especially the Federal 20 Energy Regulatory Commission and'the state regulatory i
'21 agencies will need to serve in a backstop role, providing !
22 NERC and the reliability councils with the required tools to 23 maintain and ensure reliability. The regulatory community 24 should then hold NERC and the reliability councils l 25 accountable for ensuring reliability.
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89 1 We must ensure that all entities that own, operate 2 or use the interconnected transmission system are complying 3 with th'e established criteria, guidelines, and policies. To 4 ensure compliance, NERC and the reliability councils must be 5 able to monitor those involved and correct those in non-6 compliance.
7 Where financial or business incentives cannot be 8 developed to ensure compliance and accountability, the 9 regional reliability councils and NERC, working with the 10 ISOs and others, must have the ability to impose sanctions 11 or fines on non-complying members, so that one participant's 12 non-compliance does not degrade reliability or increase '
13 costs for other market participants.
14 Federal or state action mandating membership in 15 reliability councils and NERC or some other federal or state 16 mechanism will almost certainly be needed to equitably 17 administer the costs of maintaining reliability,and ensure 18 compliance with the rules of the road.
19 In conclusion, restructuring will impact the 20 electric industry. That impact can be positive if all of us 21 involved in the restructuring process do it right the first I 22 time. -
23 Commercial pressures may stress the reliability of j 24 the electric system. Consequently, we will need to ensure 25 that balance between competition and reliability is ANN RILEY & ASSOCIATES, LTD.
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. l 90 l 1- maintained. .
2 We need to move through restructuring in a prudent i 3 and timely manner. However, we must manage this transition 4 with a critical eye if we are to be sure that there are no 5 complications that develop which will not impact our I I
6 objective of preserving reliability.
7 The ISOs being formed in the west will hrve a 8 responsibility to maintain system reliability, and as 9 members of WSCC, will play an important and essential role 10 in administering interconnected system reliability.
11 NERC and the regional reliability councils, as l
12 self-regulating organizations, having the support of the 13 regulatory community must have the appropriate tools and 14 therefore abil'ity to continue to effectively manage electric 15 ' system reliability.
i 16 No matter how dramatically the industry changes 17 and evolves, the public will expect and demand reliable 18 service. Mandatory compliance, reliability monitoring, 19 enforcement capability'and accountability will be essential 20 for ensuring the public's desired level of reliability.
21 Thank you.
22 COMMISSIONER ROGERS: Yes, I was particularly 23 interested in your note that you're working to implement a 24 certification program. I wonder what your thoughts are .
25 there with respect to what the significance of that j ANN RILEY & ASSOCIATES, LTD.
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91 1 certification program might be.
2 It sounds to me like a very good idea and one that 3 might help to really ensure some uniformity in handling very 4 complex situations as they might develop any place in the 5 country.
6 Is this a program that you would think would be 7 applicable to all of the coordinating councils or just your 8 own?
9 MR. EYRE: No. In fact, my comment was that we 10 are working with NERC, with Mr. Gent's organization, to put 11 in place both a program which would accredit training 12 programs and certify system operators throughout the 13 country. ,
14 COMMISSIONE'R ROGERS: It sounds like a very good 15 idea. This is something -- the type of thing which we've 16 been very concerned about with respect to nuclear power 17 plant operators' training, and there are some good models, I 18 think, within the nuclear industry that -- NPO for instance, 19 Mr. Nye is very familiar with, that might be helpful to you 20 there in carrying that out.
'21 CHAIRMAN JACKSON: Commissioner Dicus?
22 Commissioner Diaz?
23 Commissioner McGaffigan?
24 Mr. Delgado.
25 MR. DELGADO: Thank you very much, Dr. Jackson, ANN RILEY & ASSOCIATES, LTD.
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92 1 Commissioners. I am director of electric system operations .
2 for Wisconsin Electric and I would like to tell you what 3 that means. I'm responsible for every aspect of 4 transmission service, the control center, construction, l 1
5 planning, protection. My background is power plant !
6 operations, all fossil though.
1 7 I would like to begin with a rather 8 uncontroversial statement. I would say that deregulation 9 will not impair transmission security. In my brief comments 10 here, I hope to be able to --
11 CHAIRMAN JACKSON: You say that was a 12 controversial statement?
13 MR. DELGADO: No. I said uncontroversial but I l
14 suspect that you might not totally agree. I hope to be able.
15 to back up the statements to give you a sense that this is 16 not. genetic optimism, but in fact there are very valid 17 reasons to believe so.
18 First, let's begin with two provisions. The first 19 one is that the consequences of unreliable electric supply 20 -- incidentally, I appreciate Commissioner Rogers' comments 21 regarding the terminology, and I did select the terminology 22 very carefully here because I think it will add clarity to 23 the subject and I think it will help the Commission identify 24 its objective.
25 As I was saying, the consequences of unreliable ANN RILEY & ASSOCIATES, LTD.
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93 1 electrical supply which are -- you can conceive are frequent j 2 burnouts and rotating blackouts, are not acceptable to the 3 North American customers. This is, to us, assurance that 4 there will be a continuous motivation and incentive and 5 that, in fact, will be powerful.
6 Second, the physical reality of an interconnected 7 electric network will not be changed by either deregulation 8 of the industry or by the growth of competition. The' power 9 plants will move, and frankly, from the perspective of 10 physics, it wil1 look very much the same.
11 I will add to it that from every aspect, I would 12 predict that transmission service will continue to be a 13 regulated monopoly'. I do not think that anybody can 14 conceive of building a parallel competitive system, and to 15 ' me , that's the definition of a natural monopoly.
16 Besides., there is, I would say, a very solid 17 consensus in the industry about the necessity to maintain 18 reliability. To a greater or lesser degree, all portions of 19 the transmission network support each other.
20 At a transmission level, all users using an 21 interconnected network share the same reliability. No 22 individual transmission owner can choose to build, maintain 23 or operate its system to a lesser reliability level without 24 affecting other entities within the interconnection.
25 There is no alternative to keeping a high degree NN RILEY & ASSOCIATES, LTD.
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94 1 of transmission network reliability. Practically speaking, .
2 the reliability of the network is the highest reliability 3 available to any single user. Obviously at a distribution 4 level, other things can be done.
5 Security and adequacy are two aspects of 6 , reliability which will help to explain the issue here. The 7 NERC definitions are at the end of the document but I would 8 like to rephrase them.
9 A transmission network is secure if it operates 10 within adequate voltage and frequency margins and survives 11 w contingencies'ithout cascading failures. It is adequate, 4
12 however, if it.in fact is able to meet the needs of the 13 customer with the' level of assurance the customer thinks 14 they need.
15 The electric system operation is the epitome of {
16 real time. Either generation matches the electrical demand 17 or the demand must be reduced to match the generation by 18 taking delivery. Any major mismatch of generation and load 19 will result in localized' equipment overloads and low voltage
- 20 operation that could lead to equipment damage and cascading l
l 21 system failures. This is like a primer in transmission l 1
22 operations. If I' drag you through it, I'm sorry. l 23 If the whole interconnection, and.you realize we 24 have three interconnections in North America, is overloaded, 25 system frequency would decay and that would lead even to ANN RILEY & ASSOCIATES, LTD.
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{ 95 j 1 more sudden and wider disruptions of network operations l
f 2 unless it is arrested, and of course we have the mechanics 4
3 to de so.
4 When a transmission system cannot deliver i
5 sufficient generating capacity to meet the l'oad demand, 6 system security will be maintained by disconnecting load as j' 7 necessary to balance the remaining demand with the 8 generating capacity so the transmission system can deliver 9 reliably at any particular moment.
10 Load reduction is achieved through the exercise of 11 curtailable contracts with customers, and I would say also 1
12 with appeals to,the customers incidentally, which in fact'it 13 can become very, very effective, and by rota. ting blackouts 14 .after the demand' side programs and appeals have been 15 exhausted. !
i 16 From this-perspective, ::ctating blackouts are' 17 . controlled actions of.the operator in order to match load to 18 generation when generation is not enough to meet the load.
l 1
19 These are not failures of the transmission system. Such 20 actions are directed at the prevention of equipment damage 21 and black plant ~ shutdowns which have a high potential of 22 costing our plant' equipment damage, and of course that means 23 that we would have then long-term problems.
24 Unfortunately, the distinction would seem 25 irrelevant to the end user, but it's extremely significant ANN RIL,EY & ASSOCIATES, LTD. ,
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96 1 for the-maintenance of long-term adequacy. It is also at ,
2 the heart of this Commission's concern with electric 3 reliability's impact on the safety of nuclear power plants.
4 So electric system operators have the means to
- 5 assure security even when the system is not adequate. These
, 6 means include computer-based controls and communication 7 systems which all control areas have. These are the energy 8 management systems, or EMS, whose procedures, the training 9 and the necessary authority to take appropriate actions, and 10 I would like to just on the side say that once a year, the l 11 chief operating officer of each company in Wisconsin sends a l 12 letter to the operators reminding them that they have all l 13 the authority required to keep the system secure, including i 14 dropping firm loa'd. They do not have to request permission 15 to do so. And it is renewed. We try to renew it once a 16 year, make sure everybody knows about it.
- 17 All of the more persuasive scenarios being
. 18 proposed for deregulation of the industry recognize the 19 imperative necessity of' retaining the system operator's 20 focus on electrical security. An adequate system, cn1 the l 21 other hand, must secure by necessity, because there's no j
l 22 adequacy if the system cannot stay on. l l
23 Long-term system reliability, both adequacy and 24 security, are the result.of appropriate transmission and I 25 generation planning. Generation planning is directed at l a
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1 meeting the projected demand growth in the most economic 1 l
2 fashion.
l 3 Transmission planning, in turn, is traditionally -l 4 intended to connect generation to load and.it has been said 5 already here several times. It also is intended'to increase 6 reliability at the least cost by promoting the sharing of 7 generation resource margins across the interconnection.
8 In a competitive electricity market, the entities 9 with contractual or regulatory obligation to serve end load, 10 and I'm not specifying what that might be because there is 11 no need to specify it -- there are many possible outcomes --
12 they will provide the necessary generation, and I say 13 transmission resources through firm contracts. In other 14 words, they will assure that there is sufficient firm .
15 services in order to meet the obligations of the load that 16 -- meet the load that they're obliged to serve.
17 If those resources are not sufficient to meet the 18 demand obligation, system operators.will be able, as they 19 are today, to maintain the system energy balance with the.
20 traditional means already noted using curtailable contracts l
21 and ultimately implementation of rotating blackout. l 22 As I repeat, rotating blackout is in fact the 23 ultimate goal. .I do not want to give you the impression 24 that we look forward to using it.
25 I say that regional transmission planning will ANN RILEY & ASSOCIATES, LTD.
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98 l 1 improve long-run adequacy and security by removing ,
2 constraints. Two of~the most widely expected developments 3 for the near future of the electric industry are original i
4 transmission planning and the establishing of grid wide l l
5 tariffs that eliminate the stacking or pancaking of 6 transmission costs for generation located.for most of the 7 load. .I would say of. course that we also expect regional 8 operations is very much in the near future.
9 Regional planning will facilitate the elimination 10 of transmission congestion, even though the most economic 11 solutions often span jurisdictional and property lines, and 12 I can assure you that the transmission limitations affecting 13 the state in which I live, Wisconsin, are not in Wisconsin.
14 I had to explain that to the governor last Monday because he 15 wanted to do something in a hurry, and 'I'm sorry. Actually, 16 they're outside of Wisconsin, so we had to work through the 17 region in order to remove them.
18 Grid-wide tariffs, in turn, should promote the 19 shifts and deciding of new generation locations that expand 20 rather than constrain transmission facilities. This would 21 improve the effectiveness of the existing transmission 22 system.
23 And of course proper location of transmission can 24 expand transmission capability -- I mean, proper location of 25 generation can expand transmission capability, and of course ANN RILEY & 7.aSOCIATES, LTD.
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99 1, the fact that the cost is in different locations for 2 transmission service will improve the -- will motivate the 3 proper location of generation.
4 In varying degrees, all regional councils have 5 achieved some coordination of the operation and planning of 6 transmission systems. Obviously if the council involves a 7 pool, there is more coordination.
i 8 The main area, of course, is not a pooled area.
9 However, there is coordination.
10 The push for greater integration of regional 11 operation's is urged by the rapidly increasing number of 12 entities transacting the transmission network.
I 13 Let would say that before the EPACT of 199,2, we 14 probably transacted with'six entities, which we were 15 directly connec'ted'to. Right now the list is probably 16 upwards of 50 or 60 of them.
17 Many of us are convinced that regardless of the 18 process of deregulation, there's already a need for 19 independent regional system operators with real time -
20 information and authority over la'rge areas of the 21 transmission ~ network. And I could illustrate that if you 22 had any questions about it.
23 Wisconsin Electric, me personally, is 24 participating with other Wisconsin and Minnesota utilities +
l 25 in information of what we call the upper Midwest ISO. This l
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100 1 was an ISO filed with the FERC last October by the Primergy ,
2 applicants, but it was put together with the assistance of a 3 variety of Wisconsin and Minnesota companies.
4 We also are participating with 25 other 5 transmission owners in forming the Midwest ISO which should 6 be filed with FERC this year. The structures of the ISOs 7 are compatible. The Midwest ISO goes from West Virginia 8 through Ohio, Pennsylvania, all of Indiana, Illinois, 9 Missouri, Wisconsin, Michigan. I don't want to forget 10 anybody.
11 The efforts should result in one very large entity 12 responsible for transmission operation and planning over a 13 vast portion of the Midwest.
14 Some of the key features included both in the
-15 upper Midwest and the Midwest ISO proposals, and just to 16 refer to some of the comments I already made here, it will 17 have real time information over the broad area of the 18 network. The whole area will have information on it.
19 It will have authority over all transmission 20 operations including the dispatch of generation to assure 21 network security, would produce a regional transmission 22 plan, will operate within rules set by reliability councils 23 and regulatory entities.
24 So the ISO will not set its own rules. It will 25 operate within the rules that are given to it by the ANN RILEY & ASSOCIATES, LTD.
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101 1 councils and by the regulators.
2 Transmission owners will maintain responsibility 3 over local system conditions, over hands-on maintenance and 4 operation of their equipment under the authority of the ISO, 5 and I would say these last two features, the fact that the 6 rules given to it, and they do not -- and the ISO will not 7 develop its own rules, and the fact that the transmission 8 owners under the ISO will still remain in control of the 9 hands-on operation should give some comfort to this 10 Commission.
'11 The ISd will uphold all special reliability 12 requirements and priorities of generating plants and large 13 load centers, and there are a variety of them and I would 14 assure you that the text we are working on in the Midwest 15 ISO does say that and in fact it will refer specifically to 16 nuclear power plants. '
17 This would include the technical specs of the 18 nuclear power plants. These requirements will be identified 19 with plant owners and/or operators and it will become a part 20 of the ISO procedures.
21 I would like to address just briefly the training 22 -- the basis of system operations just to illustrate a 23 little bit of what goes on in system operations.
24 Electric system operations for Wisconsin is 25 ' typical of transmission groups throughout the Midwest. ;
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- 102 - -
i
- 1. There are 13 systems supervisors. These are fairly well-
- 2 paid, highly trained individuals, t
3 3 -
These employees perform the transmission ,
4 operations and generation dispatch functions around the j
5 clock seven days a week from the system control center that
) 6 we have west of Milwaukee. There is an on-line backup 7 center in Appleton, so all the computer software, all the 8 communication is doubled up so in case there's a failure, 4
9 the backup can in fact take over operations.
10 The energy management system monitors special
- 11 reliability requirements. Nuclear plant requirements are
, 12 built into the EMS display. There is volt' age monitoring and 13 there's voltage alarms that allow the operator to know, and ;
14 those are set to the' limits within which the power plant has 15 to be. Likewise, there are operating procedures which are 16 built into the computer displays so that the operators in 17 fact bill them out for consultation as necessary. There are 18 also paper procedures that back that up.
19 The system supervisor is selected from a variety 1
20 of work backgrounds that include plant operations, both )
i 21 fossil and nuclear. We have them from the military, but j l
22 also from the nuclear power plant, electrical design l 23 employees, protection, planning, and startup. l 24 This variety is put to use in the development and 25 revision of operating procedures and in the process of ANN RILEY & ASSOCIATES; LTD.
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103 l ,
1 cross-training the group, which is an ongoing effort.
2 On the job training, with the use of procedures 3 under the supervision of an experienced employee -- and this 4 is the way we bring the new employee -- forms the core of 5 the training program.
6 However, the Wisconsin companies perform joint 7 training of system operators through the WUMS, what's called 8 WUMS, Wisconsin, Upper Michigan System, system operator-9 training, and the purpose of this is that it in fact allows 10 that all the operators in fact work together even though 11 they're in different companies to learn the same basis and 12 it's a lot of practical information they learn together.
.13 We are in the process of revising that and we 14 should have that coming up this year and be able to restart 15 that whole effort.
16 And I would say that future NERC operator 17 certification would provide greater nationwide uniformity to l 18 train system operators, and we look forward to.it. In 19 addition, NERC and Maine, though NERC has requested it, has
- 20. completed the certification of control rooms to make sure i 21 the control rooms in each control area have the adequate 22 elements to be able to do the job.
23 You asked, if you want to, for a legal background.
24 Would you like me to comment on it?
25 CHAIRMAN JACKSON: Sure.
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104 1 MR. DELGADO: We think there is a need for some ,
i 2 legal backdrop or some legal action. For one thing, we 3 think it's very important to finally clarify among the l
4 agencies of the government who has the authority over 5 reliability, and as we stated earlier, that is somewhat l
6 vague. l 7 We think it is important to make very clear that 8 all entities using the network must follow the same rules, l 9 and that means jurisdictional as well as non-jurisdictional, 10 and that is not clear to date, even though I will have to 11 add that non-jurisdictional entities by and large do belong j 12 to the NERC regional councils.
13 We.also have to keep in mind that we're talking 1 14 about the Nort'h American grid. Canada and Mexico are an l 15 integral part of it, and it is important that whatever rules 16 we agree to, and of course they participate in NERC, that 17 they do too, and so the sense of obligation and 18 participation is something that may require government to l 19 government dealing. It has to be clarified.
20 And then ultimately, we are of the opinion that 21 regional operations in fact is a necessity and ultimately, 22 even though it should not be specified as how to do.it, it 23 should be a very strong indication, either through law or 24 regulation, that all entities must participate in regional 25 operations, and that of course is controversial, I have no 1
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105
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1 doubt.
t 2 CHAIRMAN JACKSON: Thank you. I think I'm going 3 to go on to Mr. Nye and then we'll take any commissioner 4 questions.
5 MR. NYE: Thank you, Chairman Jackson. I would 6 say in view of the lateness of the hour and our physical 7 physique is maybe affecting our mental acuity, I will seek 8 to try to summarize as best I can and not try to repeat what 9 has been said here today.
10 I am president and CEO of Texas Utilities Company, 11 a large integr'ated utility in Texas. That is the 12 owner / operator of a large nuclear power plant, and I am also-13 currently vice chairman of NERC and a member of the DOE 14 Reliability Study which has been referenced previously.
15 If I could simply ask you to refer to the remarks 16 that I've provided you previously, and I'll seek to try to 17 sort of summarize from some notes I've made as I sat here.
18 I think it's clear that restructuring, and in some 19 degree deregulation, can impact reliability of the grid 20 negatively. Restructuring will likely change the 21 traditional way the grid is used. That is, more users, more 22 . heavily loaded circuits and the like. If we are to maintain 23 traditional reliability of the grid, it will require some 24 vigilance, various steps and some precautions.
25 Markets offer many benefits, but markets also may ANN RILEY & ASSOCIATES, LTD.
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106 1 operate in dynamic stress with reliability. Grids are not ,
i 2 perfect and we should keep that in mind. They have not been f
3 perfect in the past, nor will they be perfect in the future, 4 but the record today, particularly over the last 30 years, 5 is pretty exceptional.
6 My view is that the current reliability of grid is 7 good, and I will say that recognizing that as we leave this 8 meeting, there may be an incident, and so notwithstanding 9 the fact that there will be from time to time operating 10 circumstances that are and will be of concern.
11 The question really is the question that the 12 Chairman asked at the very outset, and that is, will the 13 reliability of the grids be maintained as the industry 14 changes?
i 15 In that connection, I think it is helpful, at 16 least I found it helpful, to divide this issue into two 17 halves, the one-half being the supply and what we've tended 18 to think of as an infinite supply of electricity always 19 available to everybody who wishes it on short notice.
20 I think as to the supply, we've got to depend on 21 the market. I think markets do provide adequate responses ,
I 22 to consumer needs, but when I studied economics 101, there- j 23 was a proviso there. It said, markets respond to consumer i i
24 demands over time. And so that at any one time, the supply j 25 may or may not be adequate under a market condition, and I ANN RILEY & ASSOCIATES, LTD.
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107 1 think some customers will choose to buy under less than 2 optimal conditions, some customers will choose to secure 3 supplies that are very reliable, very dependable, and in 4 connection with their particular need.
5 So if we can set the supply on one side and the 6 grid on the other side. The grid is reliable. The grid can 7 be maintained, very reliable in the future, providing that 8 we ensure certain provisions.
9 As a part of that reliability, I think it is clear 10 that security coordinators, and they.are variously referred 11 to as ISOs and RTGs and councils and what have you, but 12 there is a function that must be performed someplace that 13 sets the security of the grid above all other considerations 14 that does not deal with the market considerations and that 15 does not deal with'the equity of someone's economic 16 position,'and that is the essence of what I thnJ. e- when I 17 talk about an ISO or security coordinator, that I'm looking j 18 for and I am seeing. ,
19 My view is that NERC, reconstituted and renewed, !
20 provides the best vehicle for securing the reliability of l
21 the system. I do believe that NERC and NERC standards can 22 be developed by full participation by all players in the 23 industry, all the new players, as well as the traditional 24 players, and that those protocols, reliability standards and 25 so forth will require either governmental or regulatory --
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A 4 - 2 Lt a w A, 108 1 legislative or regulatory backup. .
2 I think there's precedent for that sort of thing 3 in the way we operate the securities markets in this 4 country. The government has seen fit to allow the market to 5 work to its fullest extent and to allow self-help agencies 6 to conduct very serious and critically important activities, 7 commercial activities, and yet the government always 8 provides some backup and some assurance that the sanctions 9 and the incentives that are provided by the commercial 10 market do have a backup in the event that there is a failure 11 in that regard.
12 I am. anxious to make the point that the work that 13 NERC is doing is more in the nature of renovation. It is 14 not in the nature of basic construction, aad you asked 15 earlier, Chairman Jackson, what confidence do we have that 16 these new standards will be all right. I think we've got 25 l
i 17 or 30 years of experience under generally those kinds of i 18 standards, those kinds of protocols, those kinds of 19 expectations, and the changes that are being made are 20 changes that are being made to accommodate more players 21 under a more rigorous circumstance.
22 In that' connection, I do think that the ISOs are 23 developing along the right lines in this country, that is, 24 the security coordination function, and I do think we need 25 to be careful about the definition when we talk about what ANN RILEY & ASSOCIATES, LTD.
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109 1 an ISO is.
2 I'm pleased to report that ERCOT has a broad 3 governance-based ISO, and in connection with all of ,the 4 ERCOT standards, I'm very pleased to tell you that as has 5 been traditionally the case in all the regions with which 6 I'm familiar, the nuclear power plant needs and criticality 1
7 is treated as the first and foremost consideration.
1 8 I think as we develop improved ISOs or improved I 9 security coordination agreements, that nuclear power plant 10 needs will be recognized as a high priority.
11 I think there are six key elements for I
12 transmission grid reliability and I'll speak to them very-l i
13 quickly. Mandatory reliability prctocols applicable to all i 1
14 market participants with sanctions for non-compliance.
15 Security coordinator oversight for the big picture 16 on the regional or broader basis.
17 Monitoring of operations in real time to ensure 18 compliance. l 19 Authority of an ISO or a security coordinator to 20 be responsible for security to implement corrective measures 21 as needed to ensure reliability.
22 Complete sharing of reliability analysis and data 23 around the market, and competent system operators, and 24 that's been referred to previously. l 25 I think that everyone must recognize the ANN RILEY & ASSOCIATES, LTD.
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1 potentially serious consequences of core damage due to loss ,
2 of off-site power. I do believe that the NERC reliability 3 criteria focuses on keeping the grid reliable, operating 4 above security and contingency limits and always leaving 5 margins available to assure grid reliability.
6 Nuclear power plant reliance on secure 7 transmission grids is recognized by owner / operators and it's 8 important that everyone involved with the industry 9 restructuring be extraordinarily sensitive to this 10 requirement.
11 I do believe that regulatory and legislative 12 bradies must give priority attention to the reliability needs 13 of. nuclear power plants, to the many rel'iability-dependent 14 customers, and to the importance of a highly reliable 15 electric supply system to the Nation's economy.
16 I think I would conclude simply by saying that I 17 think we can manage this well. I think we can accommodate 18 the new market players, and I think.we can accommodate a 19 majo'r paradigm change in the traditions of the industry, but 20 I don't think it will happen unless we are vigilant about 21 it, unless we take-the precautions that are appropriate.
22 CHAIRMAN JACKSON: Thank you. What I'd like to do 23 is I have a couple of questions and you can tell me in 24 answering them if in a certain sense they have been 25 addressed already.
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111 l 1 I'd note that you were saying the best prospect r
l 2 for assuring reliability is the enhancement of the NERC .
l 3 organization. Do you mean along the lines that have been i
l 4 already discussed or are there some other' specific? )
l 5 MR. NYE: There are probably shades of gray l 6 between the speakers I heard today as to what they would 7 expect with concern to NERC. I think there is perhaps on 8 the part of DOE, and I won't speak for David, but I think 9 there is perhaps a concern and I think probably so, that !
10 there not be a continuation of some narrow focused group of 11 players that dete'rmine standards, and I think NERC is in the 12 process of delivering a governance which will assure that 13 all the players have full participation in not only the l 14 enhancement of the existing standards, but the confirmata.on 15 that those standards are appropriate, and I do believe they 16 are appropriate and I do believe they will stand the test of 17 time.
18 But with that one qualification, and understanding 19 that it is natural, give'n that the players who have run the 20 reliability system, the grid system in this country for so 21 long have come principally from the traditional electric 22 utilities, the investor owned, the federal agencies, the co-23 ops, the munis, but not the IPPs and not the' marketers, and 24 those folks have to have an equal participation.
25 Given that in the governance, I think the l
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112 1 reliability standards that come out of NERC give us the best .
2 shot. We've been at that for 30 years. It doesn't stand to !
l 3 reason that we would start over trying to establish a whole ;
. 4 4 new set of standards and practices, but rather to fix the 5 ones we've got to ensure that everyone is treated fairly and l 6 that the market is not encumbered by the absolute necessity 7 to maintain the reliability of the grid.
8 CHAIRMAN JACKSON: You think by having this l
restructuring and empowerment of NERC, that would also l 9
10 address the question about movements of power between grids?
l 11 Because there is an issue, you can take care of your own i 12 regional network, but you'could have internetwork movement l 13 of power wheeling.
14 MR. NYE: Yes, Dr. Jackson. I do believe that the 1
15 only hope for interregional conduct is through some national 16 organization, some national standards, such as NERC, and 17 certainly we have all the experience with NERC and I can't 18 imagine that we would seek as a nation, uhrough changing the 19 public policy, the way we run our utilities to start over 20 with a system that essentially is prepared to handle that
'21 problem.
22 CHAIRMAN JACKSON: And do you think that NERC's 23 reliability criteria should have a direct linkage to NRC 24 ~ criteria or not?
25 MR. NYE: I think that the NRC has to be satisfied ANN RILEY & ASSOCIATES, LTD.
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-1 that whatever system is put in place that the public policy, i.
2' the Congress, and the state legislators will evoke, that-j 3 they have to be satisfied that it works.
4 Whether or not the NRC needs to be an active j ,
5 player in each of those activities, I would rather doubt, i 6 I'm a little bit back to what Dr. Rogers said, which is, we i .
, 7 have to, at the NRC, take for granted what is out there.
t 8 Now, certainly we ought to -- we. You all ought
, 9 to be a party to the public policy debate and it seems to me 10 that holding up reliability as a critically important 11 element in nuclear safety is likewise parallel to the equal 12 concern that many high, high reliability customers that 13 require critical reliability or are depending on -- I'm not 14 saying this very'well, but the concern you have about I
15 nuclear power plants having adequate off-site power is 16 shared by.a number of electronics and computer and othdr ;
i 17 manufacturers that must have a high degree of reliability ]
18 all the time.
i 19 And it is also'necessary for the economy of the !
20 nation. I don't think we're about to jettison the feeling 21 that we need to have the most reliable electric power system 22 in the country, and I'm sure DOE doesn't intend that, nor 23' does FERC. We're all working towards accommodating a new 24 market consideration consistent with the traditional 25 reliability that we have come to enjoy.
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1 CHAIRMAN JACKSON: Thank you. .
2 Commissioner Rogers.
3 COMMISSIONER ROGERS: Well, just I listened very 4 carefully to your remarks and read them. I wasn't sure 5 though whether you felt that some kind of federal 6 legislation was desirable here or not.
7 MR. NYE: Well, it's probably against my interest I
8 to say so. But I do believe in due course some sort of 9 federal legislation as it relates to regulatory sanctions 10 may be necessary.
1 11 I do believe that states and local governments 12 should act first, and generally I'm inclined to think that 13 government closest to the people is best, but this is a 14 national issue. It involves a national market, perhaps an 15 international market, and therefore I think some sort of 16 minimal enforcement standards that does not intrude upon the 17 market or does not try to conduct a command and control type 18 philosophy will be necessary.
19 I don't think'that's imminent. I think that can 20 happen in three or four years, once this plays out and we 21 really understand what sort of a market we have and what 22 sort of a problem we have.
23 I do believe that it's better to have a self-help 24 industry group composed of all the players bring forward 25 standards that do the least damage to the market, that ANN RILEY & ASSOCIATES, LTD.
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1 inhibit the market the least amount, and yet absolutely 1
2 ensure for all the players, not only the NRC but others, l 3 that this will deliver a highly reliable grid system upon 4 which we can rely.
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5 COMMISSIONER ROGERS: Thank you, '
l 6 CHAIRMAN JACKSON: Commissioner Dicus. '
I 7 COMMISSIONER DICUS: One quick question, please. I l
8 And this is a question that Mr. Wolff responded to from the !
9 Chairman. It had to do with whether we know with some 10 reasonable certainty what the floor is with regard to grid 11 voltage and frequency or any combination of the two below 12 which we shouldn't go because we know at that point that we 13 would have some grid instability situations, and you said 14 yes, and for your council, you knew what the number was and' ,
15 you were prepared to deal with it.
16 So.my question is probably to you. Is this the
{
17 case across all the councils across the entire systems? Do 18 we know what that is and are we prepared to deal with it?
19 MR. WOLFF: It's generally coordinated in the 20 three interconnections. It's different in each one. I 1
21 think you can see the reason why, Texas being smaller than 22 the east.
23 CHAIRMAN JACKSON: But Texas is its own country.
24 MR. NYE: Great nation, Texas.
25 MR. GENT: There are uniform requirements in the i
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l 1 various interconnections for different levels of frequency, ,
2 unit response. This goes right down to the basic individual 3 generating unit, how it responds to the load, where load is 4 shed under frequency, how low the different' voltage steps 5 should be, how it's tested. This is all very uniform.
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6 MR. NYE: If I could offer an alert, an alarm or a 7 concern as a long-disqualified engineer, there's one thing 8 to say we know what the standards are and what the limits 9 are and what the conditions are that we need to seek.
10 It's quite different to imply by that that we 11 understand all we need to understand about the concepts of
'1:2 voltage collapse which have developed in some of these 13 dyn'amic situations. It's quite a different matter to talk 14 about a steady state condition for which we can plan and 15 which we seek to control and it's quite another to try to 16 anticipate the myriads of millions of different operating 17 conditions that may fall upon Bob or anyone else at any one 18 time and tell you or assure to you that voltage collapse is 19 not a problem, because it is sort of the current concern in 20 the industry, I think. And the more we load the lines and 21 the more we expose the system to unanticipated flows, the 22 more likelihood it is that we're going to have some 23 conditions that we did not anticipate. .
24 So we need to be able to control even under the 25 circumstances of unanticipated demands, and I think that's ANN RILEY.& ASSOCIATES, LTD.
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117 1 perhaps the backup we need to all assure ourselves of.
2 CHAIRMAN JACKSON: Commissioner Diaz.
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COMMISSIONER DIAZ: No questions.
i 4 CRAIRMAN JACKSON: Commissioner McGaffigan.
5 COMMISSIONER McGAFFIGAN: No questions, but it 6 looks like Mr. Wolff wants to get in the last word.
7 MR. WOLFF: I was just going to make one comment, 8 that I can understand the concern of the Commission about 9 how seriously we take the nuclear plants and their supply, 10 but when you stop to think of it, all the operators out j
< i 11 there have wives and children in the area and all the ;
12 operators - . speaking from an area that is relatively short 13 of nuclear power right now, I can tell you that we've missed 14 nuclear power and we would'do nothing to jeopardize it in 15 the long run.
16 The other thing I thought I might leave you with 17 is the cost of an ISO, our ISO costs the ratepayer in New 18 England on average 16 cents a month. So it's too cheap to 19 meter to use in the whole place. -
20 CRAIRMAN JACKSON: No. I thank you, I thank all 21 of you. I appreciate that your wives and children live in 22 the area. So do we all, as do our nuclear operators. We 23 regulate them any way.
24 But I would like to thank the NRC staff, the DOE 25 representative, the coordinating council, reliability
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1 council representatives, and the industry representatives ,
2 for a very informative briefing to the Commission on this 3 subject of electric grid reliability and security and its 4 potential impacts coming out of electric utility 5 deregulation but potentially -- particularly with respect to 6 the security and safety of the nuclear plants.
7 As I stated in a speech to the National 8 Association of Regulatory Commissioners in January, from the 9 NRC perspective, we've said that deregulation has to proceed 10 with a sensitivity to and an understanding of the 11 vulnerability of nuclear plants to loss of off-site power, 12 and that grid reliability governance structures and -
13 operating criteria must reflect this, and it's an important 14 issue to be considered in the formation of independent
~15 system operators.
16 And that this implies again that the standards of 17 performance, operational criteria, and the training of 18 personnel, which we've all spoken to today, are critical 19 oversight issues that have to be factored in and properly 20 addressed as deregulation goes forward.
21 ~ I hope that in bringing you gentlemen here,'that 22 we have sensitized you to the NRC's issues and concerns, and 23 those of you who are our direct licensees understand that 24 and are as sensitive to it as we are to start with.
25 But I'd like to make a couple of comments relative ANN RILEY & ASSOCIATES, LTD Court Reporters 1250 I Street, N.W.,' Suite 300 Washington,.D.C. 20005 (202) 842-0034
119 1 to each presentation that we've heard today.
2 With respect to the staff presentation, I think 3 it's very important that we understand how the issue is to 4 be addressed within our current regulatory context, 5 understanding where we are and what we control versus what 6 we do not, but how it is to be addressed in these issues of 7 licensing basis, et cetera, and I've already spoken to the 8 issue of the timeliness and the expeditiousness of your 9 reviews, and I'm also going to be asking the AEO to arrange 10 for each region to have someone come - go to a power pool 11 and a reliability council for that region to get themselves 12- more informed than I think our staff currently is today.
13 On.the federal level more broadly, it strikes me 14 that there are' parallel paths for the NRC and the 15 ' interagency process doer.n't always work as well as it 16 should, and typically, when one agency goes to see another 17 -- and we do the same thing -- we would say, well, of 18 course, you know, if you want to be in, you're weleome to be 19 in, but the way to really be in is to make the interagency 20 process work and to have all the players, just as we've 21 spoken about it in the broader context, at the table as.the 22 discussions go on.
23 And I'm going to be meeting with the Secretary at 24 any rate and I'm sure we'll talk about this point.
25 I think that we will be prepared and I will be 1
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- 1 prepared to speak to any legislation as appropriate within 2 the context of our concerns that reinforce the ability to 3 ensure that the issues are. appropriately. dealt with, 4 including testifying if it comes to that.
5 And with respect to NERC and the other regional 6 councils, I think the issue of -- the path that you're 7 proceeding down seem oriented, but it all has to address 8 these issues, but it really does have to be pulled together, 9 and that your operating protocols and the training of people 10 are, to us, very serious issues, and the compatibility of 11 what you lay out in terms of operational criteria to nuclear 12 power plant requirements and having some enforceability of 13 that, I think, is a very important issue to us. l 14 And then with respect to the industry, I think 15 .it's important that we have a clear understanding with 16 respect to the extent to which you feel the various 17 operating protocols that are being developed in fact are ,
1 18 compatible with the requirements on the nuclear plants, as I
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19 well'as getting input from you on how you think the issues l l
20 can be addressed within the licensing basis or FSAR space 21 since that is something that the Commission has under 22 consideration at any rate as we go along.
23 And so.unless there are further comments or 24 questions from fellow commissioners, adjourned.
25 [Whereupon, at 4;25 p.m., the briefing was ANN RILEY & ASSOCIATES, LTD.
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CERTIFICATE 1
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This is to certify that the attached description of a meeting j of the U.S. Nuclear Regulatory Commission entitiled:
},
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l TITLE OF MEETING: BRIEFING ON ELECTRIC GRID RELIABILITY i
- PUBLIC MEETING '
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i 4 PLACE OF MEETING: Rockville, Maryland i
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DATE OF MEETING: Wednesday, April 23, 1997 l !
l was held as herein. appears, is a true and accurate record of-i i
i the meeting, and that this is the original transcript thereof j taken stenographically by me, thereafter reduced to 3
6 j
typewriting by me or under the direction of the' court
! reporting company 1 e
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i Transcriber: N Adu Neb b U
J dy Goettlich Reme i
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_ _ _ . _ . - - . . . - _ . . .. _- . _ = _ _ _ - . . - ..
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Electrical Grid Reliability Comments to the
- Nuclear Regulatory Commission by 1
Erle Nye, President of Texas Utilities Company April 23,1997 i
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! Electrical Grid Reliability Comments to the NRC by Erle Nye 4
! April 23,1997 i'
Good afternoon. My name is Erie Nye and I am president and CEO of i
. Texas Utilities Company, a large electric utility holding company, which j .
owns and operates the Comanche Peak nuclear plant. I also am currently serving as vice-chairman of NERC and as a member of the DOE Reliability l . Task Force and the eel.CEO Steering Committee on System Reliability.
l l appreciate being asked to provide comments to the Commission regarding electrical grid reliability. I commend Chairman Jackson and the
- commissioners for calling this meeting. Thank you for the opportunity to l
- assist the Commission in formulating its views regarding industry i
i restructuring.
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!e i Restructuring, and to some degree, deregulation potentially could.
Impact grid reliability. Maintaining the current high standards of i interconnected grid reliability in the industry will require attention.
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Restructuring of the industry will change the traditional way of delivering electric energy. As the industry transitions:
1 m The traditional vertically integrated electric utility industry will tend to
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- disaggregate. i i
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m Generation in many jurisdictions will be provided by a market (vs. l regulation) on either a wholesale or retail basis and generation options will continue to change as more independent power suppliers enter the evolving wholesale markets.
l e Transmission will continue to be regulated, as will the delivery portion of distribution. However, transmission grids will be used differently 1
than the purposes for which they were originally designed and built. l 9
m Energy supplies'and purchases will have different degrees of i reliability according to customer requirements.
m The security function related to controlling the transmission system typically will be operated separately from the energy marketing function.
These anticipated changes need notjeopardize service reliability nor )
impact the traditional reliance of nuclear power facilities on the grid, provided steps are taken to-ensure the security of the transmission system. The electrical transmission grid can retain its traditional reliability provided several measures are taken. ,
4 4
=
s The best prospect for assuring reliability is the enhancement of the NERC organization.
m NERC must change to accommodate participation by all key participants in the restructured industry on a fair basis.
m All users of the transmission system must be obligated to conform to operating practices that secure the system.
m Regulatory bodies n1ust support uniform policies, standards and practices promulgated by NERC.
Traditional NERC reliability policies, standards and compliance measures are being reconstituted and developed.
m NERC has created a requirement that Regional Security Coordinators have responsibility for the security and reliable operation of the grid. The model allows flexibility as to which entity in the restructured industry is responsible for carrying out the function.
m Functional responsibility for grid reliability is being established within a structure of governance that ensures compliance with established reliability policies and standards.
. m Voluntary compliance with NERC Transmission Grid Reliability 3
l Policies and Requirem'ents are changing to mandatory compliance for all market participants with incentives and/or sanctions to ensure compliance.
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a NERC oversight will involve real-time monitoring of system
)
operations for compliance with reliability protocols / standards. )
m NERC is developing training and certification programs for system operators.
l The independent System Operator (ISO) concept is evolving to meet different needs and criteria as the industry restructures. .
m In ERCOT, the newly formed ISO incorporates the NERC security coordinator function providing oversight for interconnection reliability.
Control and dispatch of the transmission grid remains the responsibility of the transmission owners. Governance affirms adherence to NERC Policies for Grid Reliability. ERCOT Operating Guidelines adopted by its Board and administered through the ISO !
1 establish criticality of nuclear plants relative to off-site power. The Control Area's emergency plans and black start plans incorporate l
. ERCOT's Guide ill which also addresses the criticality of nuclear plant off-site power. " Independent" in the ERCOT ISO does not mean indeoendence of grid operations from the transmission owner, but rather means indeoendence of the wholesale merchant functions 4
from grid operation.
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m The ERCOT ISO is working well, with full participation by all economic interests. All players are participating in its governance and advisory structures. Reliability remains the highest priority.
i a The governance structure of the California ISO specifically addresses the criticality of nuclear plant off-site power. I am confident others
- also will address this priority in their governance.
1 i
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- The FERC is committed to maintaining high standards of reliability.
m A number of the ISO principles directly support the concept of system reliability. In Order No. 888, FERC expressly notes that the ISO's role in reliability matters "should be well-defined and comply with applicable standards set by NERC and the regional reliability council."
a FERC has signaled that it is not likely to relax Order No. 888 principles for ISOs to permit a lower priority on system reliability than exists today.
a It is my sense that Chair Moler and the' other FERC commissioners
< 5
would desire an industry self-help organization like NERC, with full participation of all market segments, to provide a mechanism for ensuring reliability of the transmission grid while accommodating market requirements.
Nuclear plant safety requires reliance on a secure transmission grid.
m As the owner-operator of a nuclear plant and as the owner of a large interconnected transmission system, we recognize that the NRC General Design Criterion 17 (requiring an acceptably-designed nuclear power facility to include both an on-site electric power system and an off-site electric power system "to permit functioning of structures, systems and components important to safety") is of critical importance.
I a Given the serious consequences of potential core damage due to a l 1
loss-of-offsite-power initiated event, all agree that high standards of !
grid reliability must be maintained. NERC's Reliability Criteria l focuses on keeping the grid reliable - operating above security and contingency limits and always leaving margins available to assure grid reliability.
m Nuclear plant reliance on a secure transmission grid is recognized by owner-operators and it is important that everyone involved with industby restructuring be extraordinarily sensitive to this requirement.
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J m In considering actions to restructure the industry, regulatory s.1d legislative bodies must give priority attention to the reliability needs of nuclear plants, to the many reliability-dependent customers and to the importance of a highly reliable electric supply system to the nation's economy.
m The Public Utility Commission of Texas has recognized the importance of a reliable transmission grid to nuclear facilities in the development of the ERCOT ISO.
m I am encouraged by the FERC and DOE sensitivity to the importance of transmission grid reliability.
m All market participants have responsibility for maintaining reliability of the transmission grid. However, we realize the ultimate judgments for nuclear plant safety reside with this Commission.
It is clear that initiatives to restructure the electric utility industry create uncertainty regarding the reliability of the transmission grid. However, I believe that we can and must maintain a highly reliable transmission ,
system. That can be accomplished through a strengthened NERC organization with the sanction and support of state and federal agencies. ;
I appreciate the Commission's concern and attention to this matter. i l
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Nuclear Regulatory Commission ;
i . Electric Grid Reliability l Jose M. Delgado -Wisconsin Electric Pow.er Company 1
Deregulation Will Not Impair Transmission Security 1 A controversial statement? I think not, based on two observations:
First, the consequences of an unreliable electrical supply -- frequent brown outs and rotating blackouts -- are not acceptable to the North American electric customers. j
, . Second, the physical reality of an interconnected electric network will not be changed by either deregulation of the industry or by the growth of competition.
'
- Maintaining Reliabilityis One Of The Few Areas Of Solid Consensus In
- The Industry To a greater or lesser degree, all portions of the transmission network support each
- other. At the transmission level all users within an interconnected network share the same j reliability. No individual transmission owner can chose to build, maintain or operate its !
system to a lesser reliability level without affecting all other entities within the ;
, interconnection.. There is no real alternative to keeping a high degree of transmission network reliability because practically speaking, the reliability of the network is the highest reliability available to any end user. )
i
- Security & Adequacy Are the Two Basic Aspects Of Grid Reliability We need to talk about two, distinct aspects of reliability, namely: system security and system adequacy'(see NERC definitions').
Paraphrasing the official NERC definitions, a transmission network is secure ifit 4 operates within adequate' voltage and frequency margins, and. survives contingencies without cascading failures. Adequacy, on the other hand, is the ability of an electric energy delivery system to meet the needs of the end users with the high degree of assurance that end users expect.
- The Transmission Network Can Be Secure Even if Not Adequate but it Cannot Be Adequate Without Security Electric system operation is the epitome of"real time". Either generation matches the electrical demand or the demand must be reduced to match the generation that can be delivered. Any major mismatch of generation and load will result in localized equipment overloads and low voltage operation that could lead to equipment failure and cascading system failures. If the whole interconnection is overloaded, system frequency will decay and lead to even more sudden and wider disruptions of network operations.
When the transmission system cannot deliver sufficient generating capacity to meet the load demand, system security will be maintained by disconnecting load as necessary to balance the remaining demand with the generating capacity that the transmission system
- can deliver reliably at any particular moment. Load reduction is achieved through the NRC423E. DOC 473/97
Nuclear Regulatory Commission Electric Grid Reliability .
s Jose M. Delgado -Wisconsin Electric Power Company exercise of curtailabl> mntracts with customers, and by rotating blackouts after the demand side progra as have been exhausted.
From this perspective, rotating blackouts are control actions of the operator, not failures of the transmission system. Such actions are directed at preventing transmission equipment damage and black-plant shut downs which have a high potential of causing power plant equipment damage. Unfortunately, this distinction may seem irrelevant to the end user, but is extremely significant for the maintenance oflong term adequacy. It is also at the heart of this Commission's concern with electric reliability's impact on the safety of nuclear plants.
- Transmission Operators Will Assure System Security So, electric system operators have the means to assure security even when the system is not adequate. These means include computer based control and communication equipment (Energy Management Systems - EMS), procedures, the training and the necessary authority to take appropriate actions. I All of the more persuasive scenarios being proposed for deregulation of the industry recognize the imperative necessity of retaining the system operators' (local as well as regional operation proposals) focus on network security. An adequate system, on the other hand, must be secure by necessity.
- Market Participants Will Assure Adequacy Long term system reliability -- both adequacy and security - are the result of i appropriate transmission and generation (supply) planning. Generation planning is l directed at meeting the projected demand growth in the most economic fashion. l Transmission planning in turn is traditionally intended to connect generation to load. It l also is intended to increase reliability at the least cost by promoting the sharing of -
generating reserve margins across the interconnection.
In a competitive electricity market, the entities with contractual or regulatory obligation to serve end load will provide the necessary generation and transmission resources to meet their obligations to serve endload. If those resources are not sufficient to meet the demand obligation, system operators will be able to maintain the system energy balance with the traditional means already noted by using curtailable contracts and ultimately the implementation of rotating blackouts.
- Regional Transmission Planning willImprove Long Run Adequacy and i Security by Removing Constraints Two of the most widely expected developments for the near future of the electric industry are regional transmission planning and the establishment of grid wide tariffs that eliminate the stacking (pancaking) of transmission costs for generation located remote from the load.
NRC423E. DOC 4'23/97
Nuclear Regulatory Commission Electric Grid Reliability l Jos6 M. Delgado -Wisconsin Electric Power Company Regional planning should facilitate the elimination of transmission congestion, given that the most economic solutions often span jurisdictional and property lines.
Grid wide tariffs, in turn, should promote the siting of new generation at locations that expand, rather than constrain transmission transfer capacity. This will improve the effectiveness of the existing transmission system.
Grid Reliability Will Be Enhanced By Regional Operation And Planning In varying degrees, all Regional Reliability Councils of NERC have achieved some coordination of the operation and planning of transmission systems.
The push for greater integration of regional operations is urged by the rapidly increasing number of entities transacting in the transmission network and the complexity of monitoring transactions across large distances and many participants.
Many of us are convinced that regardless the~ process of deregulation, there is already a need for Independent System Operators (ISO) with real time information and authority over large areas of the transmission network.
9
- ISOs Being Developedin the Midwest:
-Wisconsin Electric is participating with other Wisconsin and Minnesota utilities in the formation of the Upper Midwest ISO. It was filed with FERC last October by the Primergy applicants. We also are participating with 25 other transmission owners in forming the Midwest ISO, which should be filed with FERC this year. The stmetures of these two ISOs are compatible. These efforts should result in one very large entity responsible for transmission operation and planning over a vast portion of the Midwest.
- Some of the key features included in the Upper Midwest and the Midwest ISO proposals:
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- Will Have Real Time Information Over Broad Areas of the Network
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- Will Have Authority Over All Transmission Operations Including the Redispatch i Generation to Assure Network Security
- Will Produce a Regional Transmission Plan
'Will Operate Within Rules Set By Regional Reliability Councils and Regulatory Entities
' Transmission Owners WiH Retain Responsibility Over Local System Conditions and i Over the Maintenance, and Hands-On Operation Of Transmission Equipment, Under the Authority of the ISO These last two features a're of special interest to this Commission. The ISO will uphold all special reliability requirements and priorities of generating plants and large load centers.
NRC423E. doc 4'2397
Nuclear Regulatory Commission Electric Grid Reliability .
Jose M. Delgado -Wisconsin Electric Power Company This willinclude the technical specifications of the Nuclear Plants. These requirements will be identified by plant owners and/or operators and will become ISO procedures. j System Operations In Wisconsin !
The Electric System Operations group of Wisconsin Electric is typical of other I transmission operations groups in the Midwest. !
There are thirteen " System Supervisors"in the operations groups. These employees perform the transmission operations and generation dispatch functions, around the clock, seven days a week from the System Control Center in Pewaukee, Wisconsin. There is an on-line, back up center in Appleton, Wisconsin that can take over the operating functions in case of any emergencies disable the primary site.
The Energy Management Systems (EMS) Monitor Special Reliability Requirements.
Nuclear Plant Requirements and Procedures Are Built Into the EMS Displays.
- System Operators Have Wide Variety Of Background and Experience,
- Including Fossil And Nuclear Plant O&M The System Supervisors are selected from a variety of work backgrounds that include plant operations, (both fossil and nuclear), electrical design, protection, planning, construction and start-up. This variety is put to use in the development and revision of operating procedures and in the process of cross training among the group.
- Operator Training willinclude the following:
On the job training with the use of procedures under the supervision of an experienced employee forms the core of the training program Wisconsin companies performjoint training of system operators through the WUMS (Wisconsin Upper Michigan Systems) system operator training Future NERC Operator Certification will provide greater nation wide uniformity to the training of the system operators.
MAIN Has Recently Completed the Certification of Control Rooms i
Reliability: The degree of performance of the elemermf the bulk electric system that results in electricity being delivered to customers within accepted standa.ds and in the amount desired. Reliability may be measured by the frequency, duration, and magnitude of adverse effects on the electric supply.
Electric system reliability can be' addressed by considering two basic and functional aspects of the electric system Adequacy and Security.
Adequ..a.cy: The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements.
Security The ability of the electric system to withstand sudden disturbances such as electric short circuits _or unanticipated loss of system elements.
4
' NRC423E. DOC #23/97
~
Nuclear Regulatory Commission Electric Grid Reliability Jos6 M. Delgado -Wisconsin Electric Power Company l
(from the Glossary of Terms, Prepared by the Glossary of Terms Task Force, North American Electric Reliability Council, August 1996) 1 NRC423E. DOC 4/23/97 )
4 f.' Response of Michehl R. Gent I -
President i North American Electric Reliability Council '
i
- - Before 1
i Nuclear Regulatory Commission j Meeting on Electrical Grid Reliability-1
! April 23,1997 i Washington, D.C.
l- The following bullet items are points the Nuclear Regulatory Commission staff asked j that I address. My responses follow:
Provide insight on what effect(s) deregulation will have on grid reliability.
NERC's purview extends to the entire interconnected bulk electric system - the high voltage grid that interconnects generators with load centers. NERC does not deal with the distribution system, which is
- typically the point ofinterface with the ultimate customer.
i
- Our primary motivation to address the, rehability impacts of deregulation comes from the Federal ;
i Energy Rp=*~y Commission's Orders 888 "Pmmotag Wholesale C==a**i tion 'Ihrough Open
- l Access Non-discnmmatory Transnussion Services.by Public Utilities; Recovery of Stranded Costs by i i . Public Utilities and Transmitting Utilities" and 889 "Open Access Same-Time Information System and i Standards of Conduct." As part ofour response to the Comnussion's No
- ice of Proposed Rulemaking, i
NERC presented a six-pomt action plan to ensure continued bulk electric system reliability. That -
! action plan formed the basis for NERC's four Strategic Initiatives for Reliability, which'are being implemented throughout North America.
l l l Of most interest to this Commission would be NERC's Strategic Initiatives deshng with Standards and
- with grid security. Secunty in NERC parlance means the ability of the grid to withstand sudden
, disruptions without losing its integrity. This requires maintaming a continuous balance between supply j and demand and operstmg the system such that the loss of any one element (a generator, transmission line, or transformer) will not cause any other element to become overloaded NERC has recently committed to establishing a network of 22 Security Coordinators, geographically I and electrically distributed across North America. They will have their own dedicated frame-relay i
communications network, called the Interregional Security Network (ISN). 'Ihe ISN will begin j i
operation in June of 1997 with limited beimlity. Several interim procedures will be put in place to
- handle any potential summer problems. "Ihe ISN will ramp up to full funniaanlity later in 1997. Full j t include near real-time data flow between control centers and Security Coordinators, fu=~i-li y will j and among Security Coordinators. These 22 Security Coordmators will be responsible for conducting 4
- _ _ _ _ _ _ - - - - -- -- - - . . .- - -~ ------.---- -
, routine secunty analyses of the grid, on-line, and have the authority to take any actions necessary to
- prevent or relieve overloads or potential risks to grid security. This elaborate system should allow many multiples of additional transactions over the existing transmission grid in a non-discrimmatory manner while mamtainmg and improving rehability.
Discuss the Independent System Operator concept in the establishment of grid reliability governance structures.
NERC's Initiatives are based on separating transmission +iidkes and reliability functions from the wholesale electncity merchant functions. For instance, the previously mentioned Security Coordmators are required to sign '" data F* E--::=13+y agreements " Some of the real-time data that will be avadable to the Security Ceci?.m.is could be considered comme.cially sensitive. lIhese data will be used only for security analyses and it must mmam in the hands of those p.Li.s.g that function. In this sense, our " Security Coordmators" will be ie Many believe this on-line security kes will eventually migrate to the emergmg i% system operators (ISO). Most ISOs are now in the fledgling state, but one purpose common to all will be to maintam grid reliability in accordance with establishing NERC, Regional Council, and other applicable reliability standards and entena *Ihese spridvis will be i% of the marketmg bac*iaa, as well as i bg En from any market participant. We do not expect the governance ofISOs to adversely affect on-line decision makmg for grid reliability. In fact, the lines of authonty for maintaimag grid rehability should be clarified and
&-#=4 with the advent ofISOs.
Discuss the use of performance standards, operational criteria, training for individuals and ,
systems established to maintain grid reliability as deregulation progresses.
Another of NERC;'s four Strategic Initiatives deals with Standanis. Standards, the' way we desc. ribe them, cover system performance, planmng and operatmg criteria, and training Activities in all these areas have been dramatically increased in preparation for the deregulation of electricity markets We believe that a truly open market requires clearer Standards, Standards that can be quickly adapted to the needs of the market participants while ==ia+=iaia: rehability. For instance, in the area of traimng, we have recently committed to certification of" grid" er. 4visand accreditation of Regional traimng programs NERC-wide, that is the United States, Canada, and Baja Cahfomia, Mexico. 'Ihis means that all " grid" operators will be certified as to their knowledge of reliability criteria and that all tramers of operators and their programs will be accredited so that we, and you, can be assured that their trainmg courses will be sound relative to reliability. This project is in the development phase. We have just awarded contracts. If you would find it useful, we can provide you with all of this material that includes deadlines and check points.
Our processes for developing Operating and Planning Standards have also been accelerated and are being changed to include more opportunity for inpot by all affected parties. Our Standards are t+x-m% much more specific and measurable. We are also establishing uniform ways ofjudgmg performance to those Standards and have under way projects to detemune how these Standards are going to be enforced. Regarding that enforcement, one possibility is that we will end up with what we
. are generically calling a " Reliability Compact," which will probably consist of a series of contracts that specifically obligate the parties to abide by the NERC Standards.
- Discuss ~what factors and considerations are made in establishing grid reliability governance structures with respect to understanding nuclear power plant vulnerabilities to Loss-of Off-Site-Power events.
Modeling groups in the Texas, Western, and Eastern Interconnections continually update databases to be used by Responal groups that run network studies. At the NERC level, there are general
~
requirements for what these studies must consider. Locally, where nuclear power plant licensees have special reliability requiranants, these criteria are included in the study parameters. Also, language is being included in some ISO agreements that requires ISOs to operate the grid in a--dics with special operatmg criteria established by NRC operstmg hcenses.
You may also be interested in knowing that NERC is the home of a C-.Gug Avadability Database
'Ihis Datahaw houses the giormance and outage event records of the major gg 4=g units in the United States and Canada At last count, we housed over 3,600 units includmg most of the nuclear units. Over the years, the requirements for the licensees to submit data has changed, so our data collection process for nuclear units has also changed. We are primarily interested in the types of data that will allow us to model a nuclear unit during either a transient or a slightly slower d>mmic disturbance event.
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Op3 rating Manual- Tablo of Contonts l Introduction - -
NERC History Notice Map of the Regional Councils Release ofInformation Policy Operating Policies Preamble Introduction Policy 1 - Generation Control and Perfonnance Policy 2 -Transmission Policy 3 -Interchange Policy 4 - System Coordination l
Policy 5 - Emergency Operations l
Policy 6- Operations Planning Policy 7 -Telecommunications Policy 8 - Operator Personnel and Training -
l Training Documents Area Interchange Ermr Survey Training Document Control Performance , Criteria Training Document l ' Frequency Response Characteristic Training Document Inadvertent Interchange Accounung Trammg Document f Data Control Areas Control Area Names and Abbreviations Control Area Diagrams La Values Bias Settings Time Notificatign
. References Transmission Transfer Capabilitp System Restoration Monitoring Review Questionnaire Backup Control Centers Demand-Side Management Operating Committee Roster Organization l
MTOC-1 May 23,1995
1 .
Oparating Policioo - Tablo of Contents
- m. u.o m 1:1-7 May 23,1995 Preamble and Introduction December 3,1996
- l Terms Used in the Policies lT
- 1-4 P1:1-13 December 3,1996 j Policy 1 - Generation Control and Performance j A. Operating Reserve B. Automatic Generation Control j C. Frequency Response and Bias D. Time Control E. Performance Standard - Effective begmmng 2/1/97 j Compliance expected 2/1/98
- F. InadvertentInterchange i G. Control Surveys 4
H. Controland Monitoring Equipment P2:1-3 October 18,1996 Policy 2-Transmission A. Transmission Operations B. Voltage and Reactive Control P3:1-11 October 18,1996 Policy 3-InterchanQe
- A. Interchange Coordination - Effective until 12/31/96 A. In'terchange Transactions - Effective beginning 1/1/97 B. Control Area and Purchasi'ng-Sc!!ing Entity Obligations - Effective until 12/31/%
- B. Transfer Capability - Effective until 12/31/%
C. Schedule Specifications . Effective beginning 7/1/97 D. Interconnected Operations Services - Effective beginning 1/1/97 E. Transfer Capability - Effective beginning 1/1/97 Policy 4- System Coordination P4:1-7 May 23,1995 ;
A. Monitoring System Conditions B. Coordination With Other Systems - Normal Operations
.C. Maintenance Coordination D. System Protection Coordination P5:1-9 October 18,1996 Policy 5 - Emergency Operations A.. Coordination With Other Systems B. Insufficient Generating Capacity C. Transmission Overload -- Effective until 12/31/96 C. Transmission System Relief- Effective beginning 1/1/97 -
D. Separation From the Interconnection E. System Restoration ,
F. Disturbance Reporting G. Sabotage Reporting P6:1-9 August 21,1995 Policy 6 - Operations Planning A. Normal Operations B. Emergency Operations C. Automatic Load Shedding D. System Restoration E. Control Center Backup
.. TOC-1 December 3,1996
Operating P:licies - Tcble cf Centents' .
P7:1-2 December 3,19%
Policy 7 -Telecommunications -
A. Facilities - Effective until 12/31/97 A. Facilities - Effective beginning 1/1/98 B. System Operator Telecommunications Procedures C. Loss of Telecommunications _
P8:1-3 October 18,1996 Policy 8 - Operator Personnel and Training A. Responsibility and Authority B. Selection C. Training A1A:1-4 December 3,1996 Appendix 1 A - The Area Control Error Equation A. The ACE Equation B. Jointly-Owned Units
- 1. Pseudo-Tie
- 2. Dynamic Schedule C. Supplemental Regulation Service D. Load or Generation Tmnsfer by Telemetry E. Summary January 1,1992 l Appendix 1D -Time Error Correction Procedures l A1D:1-1 A1F:1-3 September 1,1996 Appendix 1F - Inadvertent Interchange Energy Accounting Practices-A. Introduction B. Relation to NERC Requirements C. Schedules D. Accounting Procedures E. Adjustments for Error F. On-Peak and Off Peak Periods A1H:1-3 December 3,1996 Appendix 1H - Minimum Data Collection Requirements for Use in Monitoring NERC Control Performance Criteria A. Required Data Records '
B. Recording Chart Speed and Width C. Digital Collection D. Range for ACE Chart Recorder E. Range for Frequency Chart Recorder F. Range for Net Tie Deviation from Schedule Recorder G. Range for Net Interchange Recorder .
H. Measure Accuracy I. Data Retention A3A:1-2 February 27,1996 Appendix 3A - Scenarios of Interchange Schedules and Parties to interchange Schedules A3B:1-3 October 18,1996 Appendix 3B -Interchange Party and Transaction Identification A. Parties to Interchan'ge Transactions B. Transaction Identification TOC-2 December 3,1996
Operating P li:le3-Trble of Centents
< ~ u.s en May 1989 Appendix 5F - Reporting Requirements for Major A5F:1-2 Electric Utility System Emergencies A. Loss of Firm System Loads B. Voltage Reductions or Public Appeals C. Vulnerabilities that Could Impact Bulk Electric Power System Adequacy or Reliability D. Reports for Other Emergency Conditions or Abnormal Events E. Fuel Supply Emergencies A7A:1-16 December 3,1996 Appendix 7A - Instructions for Interregional l
Emergency Telephone Networks '
A. Eastern Interconnection B. WesternInterconnection C. ERCOT Interconnection D. Interregional Security Network - Effective beginning '
1/1/98 A7B:1-16 December 3,1987 Appendix 78 - Notification of Solar Magnetic Disturbance Wamings Appendix 8C - Suggested items for System A8C:1-9 May 24,1994 Operator Training Courses and Strategic issues Part 1 - Suggested Items for inclusion in a System Operator Training Course PartII- Outline o3 Strategic Issues Area Interchange Error Survey. Training Document ale:1-6 January 1,1992 A. Effects of Area Interchange Error on the Interconnection B. Area Interchange Ermr !
C. Survey Procedures j D. Survey Review Control Performance Criteria Training Document CPC:1-14 August 22,1994 A. Area Control Error B. Control Performance Criteria C. Calculation of Compliance D. Survey Procedures FRC:1-4 January 1,1989 Frequency Response Characteristic Survey Training Document A. Frequency Response B. Survey Procedures C. Survey Review inadvertentInterchange Accounting Training INAD:1-6 May 24,1992 Document A. Intmduction B. Inadvertent Accounur C. Inadvertent Interchange 1;nergy Accounting Practices D. Definitions TOC-3 December 3,1996
- l Operating Pelicies - Tr.ble cf Centents '
- n .,.i.i. st.I, :< m it.i. aw j l
Control Performance Criteria Survey Monthly ControlPerformance I
Cnteria Training l Document l Area Interchange Error Survey As needed Area Interchange l Error Survey Training Document inadvertent Interchange Monthly Inadvenent j Interchange l Accounting Training i Document {
Frequency Response Characteristic Survey As needed Frequercy Response {
Characteristic ;
Training Document Section Pages Revision Date 1 References Transmission Transfer Capability May 1995 Electric System' Restoration KESR:1-22 April 1993 RMWG:1-18 January 1992 l Monitoring Review Questionnaire Backup Control Center RBUCC:1-18 July 1993 ,
1 Demand Side Management RDSM:1-16 December 1993 I
TOC-4 December 3,1996
Policy 5 - Emergency Operations ;
Policy Subsections Effective A. Coordination With Other Systems '
B. Insufficient Generating Capacity C. Transmission Overload Effective December 31,19%
C. Transmission System Relief Beginning January 1,1997 D. Separation from the Interconnection E. System Restoration -
F. Disturbance Reporting C. Sabotate Reporting General Criteria When an operating emergency occurs, a prime consideration shall be to maintain parallel operation throughout the Interconnection. His will permit rendering maximum assistance to the system (s) in trouble. )
Each system and control area shall promptly take appropriate action to relieve any abnormal conditions which jeopardize reliable Interconnection operation.
Each system, control ama, and Region shall establish a program of manual and automatic load shedding .
which is designed to arrest frequency or voltage decsys that could result in an uncontrolled failure of components of the interconnection. He program shal! b coordmated throughout the interconnection to '
prevent unbalanced load shedding which may cause higb msmission loading and extmme voltage ,
deviations.
A. Coordination with Other Systems. ;
l
[Appendiz 7A - Instructions for Interregional Emergency Telephone Networks] .
Criteria A system, control area, or pool which is experiencing or anticipating an operating emergency shall !
communicate its current and future status to neighbcring systems, control areas, or pools and throughout i the interconnection. Systems able to provide emergency assistance shall make known their capabilities.
Requirements 1, Notifying other systems. A system shallinform other systems in their Region or Subregion, through predetermined communication paths, whenever the following situations are anticipated or arise:
1.1. System is burdening others. De system's condition is burdening other systems or reducing the reliability of the Interconnection.
P5-1 October 18,1996
l l P:licy 5- Emergency Operatirn1 -
A. Coordinati:n With Other Sy:tems 1.2. Insufficient resources. He system is unable to purchase capacity to meet its load and reserve requirements on a day-ahead basis or at the start of any hour.
{
{
1.3. Lack of single contingency coverage. He system's line loadings and voltage / reactive
! levels are such that a single contingency could threaten the reliability of the
- Interconnection.
4 i
! 1.4. Emergency actions for inability to purchase capacity. He system anticipates 3% or
! < greater voltage reduction or public appeals because of an inability to purchase emergency
, capacity. l 1.5. Emergency actions for other reasons. He system has instituted 3% or greater voltage ;
- reduction, public appeals for load reduction, or load shedding for other than local l 3 problems.
j 1.6. Sabotage incident. He system suspects or has identified a multi-site sabotage ;
occurrence, or single-site' sabotage of a critical facility.
- 2. Hotline use. When a condition is identified that could thmaten the reliability of the Intsrconnection or when 6rm load shedding is' anticipated, the affected control area shall . utilize the Interconnection-wide telecommunications network in accordance with Appendix 7A - Instructions for Interregional Emergency T'elephone Networks, Section 2, " Disseminating Infonnation," to convey ;
that information to others in the Interconnection. (Approved February 28, .1995)
B. Insufficient Generating Capacky .
. Criteria A control area which has experienced an operating capacity emergency shall promptly balance its generation and interchange schedules to its load,,without regard to financial cost, to avoid prolonged use of ,
the assistance provided by Interconnection frequency bias. He emergency reserve inherent in frequency !
deviation is intended to be used only as a temporary source of emergency energy and is to be promptly restored so that the intesconnected systems will be prepared to withstand the next contingency. A control area unable to balance its generation and inteichange schedules to its load shall have the responsibility to l remove sufficient load to permit correction ofits Area Control Error. ,
A control area anticipating an operating ' capacity emergency shall bring on all available generation, postpone equipment maintenance, schedule interchange purchases well in advance, and prepare to reduce i load. l Requirements l l
- 1. Returning ACE to acceptable levels. In the event of a capacity deficiency, generation and transmission facilities shall be used to the fullest extent practicable to promptly restore normal system frequency and voltage and retum ACE to acceptable performance criteria as defined in Policy lE. .- -
P5-2 October 18,1996
-- - ----- _ _ _ ---____.-_r
Policy 5- Emergenty Operatirns
- B. In
- uffi: lent Generating Ccprity
- 1 .
1.1. Schedule assistance. The deficient system shall schedule all available assistance that is
- . requimd with as much advance notice as possible. ,
- .. J 1.2. Using Interconnection's bias. The de6cient system shall use the assistance provided by l l the Interconnection's frequency bias only for the time needed to accomplish the following
- 1
- 1.2.1. Operating reserve. Utilize its readily available operating reserve.
1.2.2. Own resources. Analyze its ability to recover using only its own resoun:es.-
4 1.2.3. Assistance from others. Ifnecessary, determine the availability of assistance from other systems and schedule that assistance.
4 j 2. Emergency action. If all other steps prove inadequate to relieve the capacity emergency, the
- system shall take immediate action which includes, but is not limited to, the following:
l
, 2.1. Schedule all available emergency assistance from other systems.
2.2. Implement manualload shedding. .
- 3. ' Unilateral action. Unilateral adjustment of generation to retum frequency to normal' by systems not experiencing capacity deficienicies, beyond that supplied through frequency bias action and interchange schedule changes, shall not be attempted. Such adjustm'ent may jeopardize overloaded transmission facilities.
Guides
- 1. ' Notification of emergency. If a capacity or energy emergency is foreseen, contact neighboring systems as far in advance as possible to assess regional conditions and arrange for whatever relief is available or required.
- 2. Notifying other systems. Control areas should continue to. apprise the interconnected systems of the level of generstmg capacity or energy supply and future needs.
- 3. Voltage reduction on distribution system. Voltage reduction for load relief should be made on the distribution system. Voltage reduction on the subtransmission or transmission system may be '
effective in reducing load; however, voltage reduction should not be made on the transmission system unless the system has been isolated from the Interconnection. .
4 P5-3 October 18,1996
P?licy 5- Em roency Operati:ns
- C. Transmission Overload Effective until December 31,1996 Criteria When line loadings, equipment loadings, or voltage levels deviate from nonnal operating limits or can be expected to exceed emergency limits following a contingency, and reliability of the Interconnection is threatened, those control areas expenencing and those control areas contributing to the condition shall take immediate steps to relieve the condition. These steps include notifying other systems, adjusting generation, changing schedules between control areas, initiating line and equipment load relief measures, and taking j such other action as may be required.
Requirements
- 1. Dealing with transmission contingencies. Each NERC Region shall ensure that policies and procedures are developed and specified for dealing with transmission contingencies that threaten ;
I the reliability of the Interconnection, coordinating equipment ratings and outages, coordinating switchmg, monitoring and controlling voltage levels and MW and MVAr flows, and implementing line and equipment loading relief procedures:
- 2. ' Procedures. Where specific transmission reliability issues have been identified,those systems ;
I affected by and those systems contributing to the problem shall develop joint procedures for maintaining transmission reliability. .
- 3. Overloads caused by other system. If an overload on a transmission facility or abnormal voltageheactive condition persists due to operations of another system, the affected system shall notify the neighboring or remote system (s) of the severity of the overload or abnormal voltagehenctive conditions and request appropriate relief.
- 4. Disconnection of overloaded equipment. If the overload on a transmission facility or abnormal voltageheactive conditiori persists and equipment is endangered, the affected system or pool may ,
disconnect the affected facility. Neighboring systems impacted by the disconnection shall be notified prior to switching, if practicable, otherwise, promptly thereafter.
- 5. Action shall not reduce reliability. Action to correct a transmission overload shall not impose unacceptable stress on intemal generation or transmission equipment, reduce system reliability beyond acceptable limits, or unduly impose voltage or reactive burdens on neighboring systems. If-all other means fail, corrective. action may require load reduction.
- 6. Action to keep transmission within' limits. Systems shall take all appropriate action up to and including shedding of firm load in order to keep the transmission facilities within acceptable operating limits, prevent imminent separation from the Interconnection, or to prevent voltage ;
collapse.
Guides
- 1. Data for loading relief. On-line, real-time values should be used as much as possible in the implementation ofline and equipment loading relief procedures. .
PS-4 October 18,1996
4 Policy 8 - Emergency Operatirns i
-C. Transmission System Relief Effective beginning January 1,1997
- Introduction
- This policy
4 i 1. Summarizes the authority, infonnation and tools required by SYSTEM OPERATORS responsible for i the security of the INTERCONNECTION 1 9
- 2. Identifies the accountability for developing and implementing procedures to alleviate OPERATING l
- SECURITYLIMIT violations.
! 3. Describes the requirement to develop procedures for the curtailment and restoration of
- transmission service.
- Requirements .
1
- 2. Relieving secuiity limit violations. Each CONTROL AREA experiencing or materially contributing i to an OPERATINO SECURITY LIMIT violation shall take immediate steps to relieve the condition.
( ,
j
- 3. Operator authority and responsibility. SYSTEMOPERATORS having responsibility for the i security of the transmission. system within a CONTROL AREA, pool, etc. shall be given and shall '
exercise specific authority to alleviate OPERATING SECURITY LIMIT violations. "The authority shall enable the SYSTEM OPERATOR to take timely and appropriate actions including curtailing j transmission service or energy schedules, operating equipment (e.g., generators; phase shiflers, '
. breakers), shedding load, etc.
! 3.1. Action shall not reduce reliability. Action to correct an OPERATING SECURITY LIMIT l
- violation shall not impose unamy;.ble stress on intemal generation or transmission i
equipment, reduce system reliability beyond acceptable limits, or unduly impose voltage or reactive burdens on neighboring systems. If all other means fail,' corrective action may l require load reduction.
i Disconnection of overloaded equipment. If the overload on a transmission facility or 3.2.
abnormal voltage / reactive condition persists and equipment is endangered, the affected system or pool may disconnect the affected facility. Neighboring systems impacted by the disconnection shall be notified prior to switching, if practicable, otherwise, promptly thereafter.
.4. Security violation assessment. Sufficient information and analysis tools shall be provided to the SYSTEM OPERATOR to determine the cause(s) of OPERATING SECURITY LIMIT violations. This information shall be provided in both real time and predictive formats so'that the appropriate corrective actions may be taken. Effective Jan.1,1998 i Transmission service and energy schedule prioritization. Each CONTROL AREA shall develop 5.
prioritization procedures for the curtailment of transmission service and energy schedules.
i PS-6 October 18,1996
Policy 5 - EmergencySperations
- C. Transmission Systm R: lief 5.1. Effectiveness. Rese procedures shall provide for the curtailment of only those energy
, and transmission service schedules that effectively alleviate the OPERATING SECURITY
. VIOLATION will be intenupted.
5.2. Coordination. Rese procedures shall be coordinated with adjacent control areas in accordance with the REGIONAL SECURITY PLAN.
. 5.3. Curtailment and restoration sequence. He curtailment and restoration sequence shall be consistent with the approved tariffs and regulatory requirements of the transmission service provider (s).
Guides
- 1. . If the SYSTEM OPERATOR can project a curtailment requirement adequately, the transmission service customer should be notified. However,if time is not available, the SYSTEM OPERATOR will take whatever actions are necessary as specified in Policy SC, Requirement 2.
D. Separation from the Interconnection Criteria ,
Because. the facilities of each system may be vital to the secure operation of the Interconnection, systems ,
and control areas shall make every effort to remain connected to the Interconnection. However, if a system or control area determines that it is endangered by remaining interconnected, it may take such action as it deems necessary to protect its system.
If a portion of the interconnection becomes separated from the remainder of the interconnection, abnormal frequency and voltage deviations may occur. To permit resynchronizing, relief measures shall be applied by those separated systems contributing to the frequency and voltage deviations.
Guides
- 1. Load shedding to prevent separation. In those situations where it will be beneficial, manual load shedding should be used to prevent imminent separation from the Interconnection due to transmission overloads or to prevent voltage collapse.
- 2. Generator shutdown. If abnormal levels of frequency or soltage resulting from an area disturbance make it unsafe to operate the generators or their support equipment in parallel with the system, their separation or shutdown should be accomplished in a manner to minimize the time required to re-parallel and restore the system to normal.
2.1. Separating generators with localload. If feasible, generators should be separated with some local, isolated load still connected. Otherwise, generators should be separated carrying their own' auxiliaries. First sentence is a duplicate ofGuide 2 above.
- 3. AGC. AGC should remain operative if practicable.
PS-6 October 18,1996
i l
Policy 8- Emirgency Operations !
D. Sep rati:n from the interc:nnectisn f I
N
- 4. Instructions for plant operators. Plant operators should be supplied with instructions specifying l the frequency and voltage below which it is undesirable to continue to operate generators connected f -
to the system.
- 5. Generator protection at high and low frequency. Protection systems should be considered for automatically separatmg the generators from the system at predetermined high and low frequencies.
E. System Restoration -
(Policy 6D - Operations Planning-System Restoration]
[ System Restoration and Blackstart Frocedures Reference Document]
Criteria AAer a system collapse, restoration shall begin when it can proceed in an orderly and secure manner. 5 Systems and control areas shall cooniinate their restoration actions. Restoration priority shall be given to the sianon supply of power plants and the transmission system. Even though the restoration is to be expeditious, system operators shall avoid premature action to prevent a re-collapse of the system.
Customer load shall be restored as generation and transmission equipment becomes available, recognizing -
i that load and, generation must remain in balance at normal frequency as the system is restored.
Requirements ;
- 1. Returning to normal operations. Following a disturbance in which one or more system areas become isolated, steps shall begin immediately to retum the system to normal:
I 1.1. Extent ofisolated system. He system operator shall determine the extent and condition of the isolated area (s). ,
1.2. Frequency restoration. He system operator shall then take the necessary action to ;
restore system frequency to normal, including adjusting generation, placing additional l generators on line, or load shedding.
1.3. Interchange schedule review. Interchange schedules between control areas or fragments of control areas within the separated area shall be immediately reviewed and appropriate l adjustments made in order to gain maximum assistance in restoration. Attempts shall be made to maintain the adjusted schedules whether generation control is manual or automatic.
1.4. Resynchronizing. When voltage, frequency and phase angle permit, the system operator may resynchronize the isolated area (s) with the sunounding area (s), properly notifying adjacent systems, and considering the size of the area being reconnected and the capacity of the transmission lines effecting the reconnection.
l 1.5. Off-site supply for nuclear plants. Restoration of off-site power to nuclear stations shall be given high priority. , l l
l l
P5-7 October 18,1996 l l
P7l icy 5 - Em rgency Operations E. Sy; tem Rxtaratirn Guides
~
- 1. Isolating loads to help restoration. In order to systematically restore loads without overloading the remaining system, opening circuit breakers should be considered to isolate loads in blacked-out areas.
- 2. Restoration. Load shed during a disturbance should be restored only when doing so will not have an adverse effect on the system or Interconnection.
2.1. Manual restoration. Load may be restored manually or by supervisory control only by l direct action or order of the system operator as generating and transmission capacity j become available.
2.2. Automatic restoration. Automatic load restoration may be used where feasible to minimize restoration time.
2.2.1. Coordination. Automatic restoration should be coordinated with neighboring systems, coordinated areas, and Regions.
2.2.2. Must not bu'rden others. Automatic restoration should not aggravate system frequency excursions, overload tie lines, or burden any system in the Interconnection. !
l
- 3. Oil-filled cables. Reenergizing oil fdled pipe-type cables should be given special consideration, especially ifloss of oil pumps could cause gas pockets to form in pipes or potheads.
- 4. Maintaining transmission voltage. 'Ihe following should be considered when trying to maintain normal transmission voltage during restoration:
4.1. Preventing excessive voltage. Removal of shunt capacitors or addition of reactors or l
' addition of small blocks ofisolated load to prevent excessive voltage when energizing long transmission lines.
4.2. Energizing cables. Effects of energizing high-voltage cables at the end of a long, lightly-loaded system.
4.3. Reactive considerations. The capability of the generators to provide or absorb reactive power flows.
F. Disturbance Reporting (Appendix 5F - Reporting Requirements for Major Electric Utility System Emergencies]
Criteria ;
Disturbances or unusual occurrences which jeopardize the operation of the interconnected systems, that result, or could result, in system equipment damage, or customer intermptions, shall be studied in sufficient depth to increase industry knowledge of electrical interconnection mechanics so that similar events can be l
I
. P5-8 October 18,1996 1
P?licy 5 - Emirgency Operations I
prevented. He facts surtounding a disturbance shall be made available to system and control area ,
operators, system managers, Reliability Councils, and regulatory agencies entitled to the information. l Requirements i l
- 1. Analyzing disturbances. Bulk system disturbances affecting two or more systems shall be i l
promptly analyzed by the affected systems. !
- 2. Disturbance reports. Based on the magnitude and duration of the disturbance or unusual occurrence, those systems responsible for investigating the incident shall provide oral, and if '
appropriate, written reports.
2.1. Oral report. An oral report shall be made to the systems' Regional Council staff within twenty-four hours after the disturbance. His oral report is in addition to the reporting requirements of any regulatory agency havingjurisdiction over the systems.
- 3. Notifying DOE. De-U.S. Department of Energy's most recent Power System EmerBency Reporting Procedures, shown in Appendix 5F are the minimum requirements for reporting disturbances to NERC. ,
Guides
- 1. Reporting operating problems. If an operating problem cannot be corrected quickly, the probable duration and possible effects should be reported.
- 2. Written reports. He system should provide written reports following a disturbance.
2.1. Report timing. If appropriate, a preliminary written report should be available within several days of the disturbance.
2.2. Report review. If appropriate, a fmal written report should be available for review according to system policies.
~
. 3. Reporting " unusual occurrences." If, in the judgment of the system (s) involved, such an .
" unusual occurrence" would be ofinterest to the electric utility industry, the incident should be j reported to NERC whether or not it is reported under DOE Reporting Procedures.
4.~ Assistance from NERC OC. When the're has been a disturbance affecting the bulk system, the Region's OC representatives should make themselves available to the system or systems immediately affected in onier to provide any needed assistance in the investigation.
i
- 5. Reports from other systems. Information conceming bulk system disturbances in other parts of the world can be of value in furthering the objectives of NERC. To the extent that relevant information can be obtained, it should be appropriately utilized.
P5-9 October 18,1996
- ._- __ .. _ . . _ _ . ~ . _ _ - _ . . _ . _ _ ~ _ .__.._ . __. _ ____ . _ _ _ . _ _ _ _ . _
l J
Prlicy 8 - Emirgency Operations -
G. Srbotage R:p rting G. Sabotage Reporting Criteria Disturbances or unusual occunences, suspected or determined to be caused by sabotage, shall be reported to the appropriate systems, govemmental agencies, and regulatory bodies.
Requirements
- 1. Recognizing sabotage. Each control area shall have procedures for the recognition of and for making its system operators aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection. Procedures shall also be established for the communication ofinformation conceming sabotage events to appropriate parties in the Interconnection.
- 2. Reporting guidelines.' System operators shall be provided with guidelines including lists of utility contact personnel, for reporting disturbances due to sabotage events.
\
- 3. Contact with FBI and RCMP. Systems shall establish communications contacts with local j Federal Bureau ofInvestigation (FBI) or Royal Canadian Mounted Police (RCMP) officials and l develop reporting procedures as appropriate to their circumstances.
Guides I
- 1. Information to media. Systems should establish procedures for supplying sabotage-related I information to the media. Release of this information must be coordinated with the appropriate i FBI or RCMP personnel, i i
1 4
1 4
l j .
P5-10 October 18,1996 t
- 1
.n.. ,. ,. - - --
e Nuclear Regulatory Commission Briefing on Electric Grid' Reliability April.23,1997 Av k w
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. W XMM Jose M. Delgado MMM Director, Electric System Operations Wisconsin Electric Power Company .
' i
4 Deregulation Will Not Impair Transmission '
Security t
- Maintaining Reliability Is One Of The Few Areas Of So.l id .
Consensus In The Industry .
- Security & Adequacy Are the Two Basic Aspects Of Grid Reliability The Transmission Network Can Be Secure Even If Not ,
Adequate but It Cannot Be Adequate Without Security
- Transmission Operators Will Assure System Security
- Market Participants Will Assure Adequacy
- F egional Transmission ~ Planning will Improve Long Run Adequacy and Security by Removing Constraints 2
Joss Delgado - Director ofElectric System Operations - IVisconsin Electric Power Company - April 23.1997
Grid Reliability Will Be Enhanced By Regional Operation And Planning ]
- ISOs Being Develop.ed in the Midwest:
.- Will Have Real Time Information Over Broad Areas of the Network
- Will Have Authority Over All Transmission Operations Including the Redispatch Generation to Assure Network Security
- Will Produce a Regional Transmission Plan' Regional Planning Will Enhance Local Planmng
- Will Operate Within Rules Set By Regional Reliability Councils and Regulatory Entities Special Requirements and Priorities of Generating Plants (e.g.
Nuclear Plants Requirements) Will Be Identified by Plant Owners / Operators and Maintained by the ISO
- Transmission Owners Will Retain Responsibility Over Local System.
Conditions and Over the Maintenance, and Hands-On Operation Of ~ !
Transmission Equipment, Under the Authority of the ISO 2
Joss Delgado - Director ofElectric System Operations - Wisconsin Flectric Power Company - April 23,1997 l
. i i
System Operations In Wisconsin . .
- System Operators Have Wide Variety Of Background and Experience, Including Fossil. And Nuclear Plant O&M ..
Operator Training -
~
- On the Job Training - Use ofProcedsres & Simulators ,
- Joint Training Throngh WUMS System Operator Training
- Control Room Certification by MAIN Has Been Completed
- Future NERC Operator Certification
- Energy Management Systems (EMS) Monitor Special.
Reliability Requirements .
- Nuclear Plant Requirements and Procedures Are Built Into the.
EMS Displays Jost Delgado - Director ofElectric System Operations - Wisconsin Electric Power Company - April 23.1997
. i
, m 4
Western-Systems Coordinating Council k
N I i
Briefing on Electric Grid Reliability Comments by the Westem Systems Coordinating Council
.Before the Nuclear Regulatory Commission April 23,1997 By Mr. Dennis E. Eyre i Executive Director, Western Systems Coordinating Council 1
Thank you, it is a distinct honor to appear before you today to discuss restructuring and electric system reliability.
I am Dennis Eyre, executive director of the Western Systems Coordinating
, Council (WSCC).
Overview of WSCC WSCC is the largest and most diverse of the 10 regional reliability councils of the North American Electric Reliability Council '(NERC). WSCC's service territory extends from Canada to Mexico, an area of nearly 1.8 million square miles. It includes the provinces of Alberta and British Columbia, the northern portion of Baja California, Mexico, and all or portions of the 14 western states in between. The interconnected transmission system within the WSCC region is known as the Western Interconrfection. It is one of the four major electric grids in NERC.
WSCC has 99 members ranging from 71 traditional utilities to 10 independent power producers to 18 marketers. Three state regulatory representatives serve on WSCC's Board of Trustees.
Who is Resoonsible for Reliability?
As industry restructuri.ng occurs and we implement competition, it is imperative that each of us continue to do our part to maintain electric system reliability. For over 30 years, NERC and the regional councils have been the caretakers of reliability through the cooperative development of NERC and regional council policies, procedures, and criteria. There is no reason to doubt the ability, appropriateness, and the resolve of NERC and the regional councils to continue to serve as "self-regulating organizations" responsible
'for establishing and monitoring compliance with the required reliability standards and for administering the appropriate incentive, sanction, and financial penalty programs. WSCC and NERC are committed to enhancing accountability.for reliability and improving compliance with reliability standards. WSCC strongly favors an industry "self-regulatin'g organization" approach with a federal and/or state regulatory backstop as may be appropriate.
Actions Beine Taken by WSCC to Ensure Reliability WSCC is continually and expeditiously implementing new protocols and mechanisms to ensure reliability is not sacrificed as we restructure the industry.
In 1996, the WSCC Board of Trustees unanimously endorsed a reliability compact that reaffirms the Council's mandatory compliance requirements and which will result in the enforcement of established reliability protocols in the West. The compact recognizes that to ensure continued reliability, all market participants must adhere to the established reliability protocols. A .
policy level group has been formed to develop incentives and sa.nctions for
f implementing the reliability compact. These recommendations will'be submitted to the WSCC membership by the end of 1997. j t '
The WSCC agreement states that all control areas, which includes :
l independent system operators (IS0s), must be members of WSCC, and as such,
- i. they must comply with all WSCC and NERC protocols and sanctions. Also, and of i importance to you, the most recent California ISO filing includes a Transmission Control Agreement, which requires the 150 to meet the WSCC and j i NERC protocols and the provisions of the NRC Plant Licenses. In addition, >
a NERC's Operating Manual Policy 5 - Emergency Operations presently calls for
, system operators to give a "high priority" to nuclear plant restoration. I s believe, however, that we need.to further clarify this policy to make sure
~
thic issue is properly addressed; and therefore, I will be recommending that the NERC and WSCC criteria be reviewed and revised as.necessary to meet nuclear plant requirements.
Mandatory compliance does r.ct stop with WSCC. NERC also made compliance with its protocols mandatory. By establishing a system of mandatory
. compliance, all market participants will be accountable for adhering to '
established protocols and will result in a level playing field.
Another reliabi1 H " program WSCC has established is the compliance monitoring program, wh M reviews membe'rs compliance with the WSCC Minimum Operating Reliability uiteria; WSCC operating policies, procedures, and
, guidelines; and NERC Operating Policies for Interconnected Systems Operation.
.In addition, WSCC and NERC are in the process of enhancing their operating protocols to make them as s,pecific and measurable as possible. )
WSCC, and the other regional councils, are implementing additional security )
measures. These measures will enhance interconnected system reliability !
through the exchange of information required to assess system security and reliability, including on-line power flow and security analysis and increased system monitoring. These measures will enhance the operators' ability to identify potential reliability problems and promptly take proactive corrective actions to ensure system security.
The Council has approved a Regional Security Plan that is ' intended to ,
convey both.the responsibility for overall system reliability and the authority needed to carry out that responsibility successfully. This plan was developed and is currently being implemented in response to one of the four l Strategic Initiatives for Reliability established by NERC. The Regional Security Plan empowers the security coordinating centers to take the actions necessary to preserve reliability. The California ISO will be one of the security coordinating centers, and it is envisioned that the other IS0s being formed in the west will also become security coordinating centers.
WSCC also has an established and successful training program that has been carefully structured to provide system dispatchers and other operating personnel with the necessary skills to deal with the ever-increasing complexity of interconnected system operation and to ensure interconnected
. electric system reliability. In addition, a ned Schedulers / Contract Writers Training Program was implemented in 1996. This training program familiarizes schedulers, contract writers, and energy accountants with system operations and increases their understanding of how their actions impact interconnected
\
- 4 f system operation and reliability. Although WSCC currently has an operation i training program, we are also working with NERC to implement a certification j program.
I i .
i In the Transmission System Beine Used Differently than Oriainally Desianed and i t il It Innact Reliability?
! This question has been posed by the public, the regulatory community, !
i and members of industry. As long as established operating protocols and those '
being implemented by the industry are followed, tran~smission reliability will
- be maintained. _ Industry and the regional reliability councils recognize the j ,
changing,. competitive nature of the industry and the impact this may have on system operations. As such and as we speak, new protocols are being developed j to address the changes occurring and being forecast for electric system ,
- operation.
i Implementation Issues to consider As the electric industry becomes more competitive, we must make certain
- that interconnected system reliability is preserved. As time frames are I
- established for restructuring this industry, we must all bear in mind that
- these time frames must be realistic and prudent, and that they may have to be j revised to maintain rel.iability. 1
.The regulatory community, especially the Federal Energy Regulatory Comission (FERC) and the state regulatory agencies, will need to serve in a backstop role, providing NERC and the regional councils with the required tools to maintain and ensure reliability. The regulatory community should ,
then hold NERC and the regional councils accountable for ensuring reliability j is maintained. i 1
. We must ensure that all entities that own, operate, or use the interconnected transmission system are complying with the established criteria, guidelines, policies, and procedures of WSCC and HERC, To ensure compliance, NERC and the regional councils must be able to monitor those involved and correct those in noncompliance. Where financial or business incentives cannot be developed to ensure compliance and accountability, the regional reliability councils, working with the IS0s and others, must have the ability to impose sanctions or fines on noncomplying members, so that one participant's noncompliance does not degrade reliability or increase costs for other market participants. -
Federal or state action mandating membership in the reliability councils and NERC or some other federal or state mechanism will almost certainly be needed to equitably administer the costs of maintaining reliability and ensure compliance with the " rules of the road" that have been 0stablished to preserve reliability.
l
. l l
i Conclusions .
Restructuring will impact the electric industry ... that impact can be positive if all of us involved in the restructuring process do it right the l first time. Commercial pressures may stress the reliability of the electric 1
system. Consequently, we will need to ensure that the balance between competition and reliability is maintained. We need to move through restructuring in a prudent and timely. manner. However, we must manage this
. transition with a critical eye if we are to ensure that any complications that develop wil1 not impact our objective of presarving re. liability. The IS0s being formed in the West will have a responsibility to maintain system
- reliability, and as members of WSCC, will play an essential role in
- administering interconnected system reliability. NERC and the regional i
reliability councils, as self-regulating organizations having the support of
- the regulatory community, must have the appropriate tools, and therefore the i
ability to continue to effectivcly manage electric system reliability. No
, matter how dramatically the industry changes and evolves, the public will
' expect and demand reliable service. Mandatory compliance, reliability monitoring, enforcement capability, and accountability will be essential for ensuring the public's desired level of reliability.
This concludes my comments.- I would be pleased to address any questions
- you may.have.
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Electric Grid Reliability Office for Analysis and Evaluation of Operational Data Office of Nuclear Reactor Regulation April 23,1997
1 OVERVIEW .
t i
- Electric grid reliability can affect the safe operation of nuclear power plants. ;
i
- AEOD performed an electric grid study because of several grid events. .
i
- The study identified various grid performance factors.
- Recommendation from this study is for licensees to confirm and maintain licensing basis.
l t
- NRR will discuss original licensing basis and i actions being considered to address the grid reliability issue.
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SAFETYISSUE j
- Reliable power needed for safety equipment.
i
- Severe Accident Study, NUREG-1150, determined station i blackout a major contributor to core damage frequency.
- IPE Insights, Draft NUREG-1560, determined station blackout continues to be a significant factor for some plants. j
- Offsite power is the preferred source.
i
- Adequate safety based on combination of both offsite and onsite power.
- Changes in the industry could affect future reliability of ,
electrical grid. -
i
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, O NORTH AMERICAN t ELECTRIC RELIABILITY COUNCILS Figure supplied by the North American Electric Reliability Council
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Mid-Atlantic Area Council Peak Demand for 10 Years Capacity Margin MW (X 100 Q Pct 58 35 30 5 53 -
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= 4, 43 ,- 15 - - - - - - - - - - - - - - - - - - - - - - - - -
l 8 Summer *- Winter l l 9 Summer 4- Winter l 38 10 ' '
1996 1997 1998 1999 2000 20L1 2002 2003 2004 2005 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Year Year Northeast Power Coordinating Council- New England Peak Demand for 10 Years Capacity Margin MW (X 1000) Pct 23 30 W '
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l 0 Summer *- Winter l 'l 9 Summer -m- Winter l 19 5 ' ' ' '
1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 1996 1997 1998 1999 2000 2001 2002 2003 2004 200$
Year Year 6 - -
h PLANT AGE Number of Plants Total MW (X1000) 2000 '
300
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OPERATING EVENTS I
- Excessive Demand The Mid-Atlantic Cold Spell of 1994
- Fault Virgil Summer Event of 1989 Western Grid Disturbance of August 10,1996
- PotentialInstabilities Found by Analysis i
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TEMPERATURE EFFECTS ON LOAD Cold Spell of 1994 Mid-Atlantic Area MW (X 1000) . Temperature 60 40
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12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 am I pm Hours 9
a MID-ATLANTIC AREA COUNCIL 4
LOAD REDUCTION MEASURES
. 1. Curtailment of non essential power company station light and power ,
- 2. Reduction of controllable interruptible/ reducible loads
- 3. Voltage reducti.ons
! 4. Reduction of nonessential load in power company buildings i
- 5. Voluntary customer load reduction
- 6. Radio and television load reduction appeal I 7. Manualload shedding
- 8. Automatic actuation of underfrequency relays which shed '
10% of load at 59.3 Hz,10% at 58.9 Hz, and 10% at 58.5 Hz 10 - -
A J
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i WESTERN GRID DISTURBANCE 1 1
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August 10,1996 q% . - .
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i CONCLUSIONS l
l
- On the whole, the grid is stable and reliable l
l
- Problems described in the Regional Reliability Council assessments as well as uncertainties introduced by
- restructuring of the electric industry. indicate the need l to monitor grid on a regular basis .
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AEOD RECOMMENDATION
- NRR request licensees to confirm'that they l continue to meet their licensing bases with respect to the stability and reliability of offsite electric power.
- Licensees should further be requested to -I maintain a process for ensuring they continue to meet their licensing . bases in this area for the remainder of their license.
i l
j 1
13 -
LICENSING BASIS
- GDC-17 REQUIREMENTS !
= An onsite power system and offsite power system .
shall be provided, each independent of the other and capable of providing power for all safety functions.
= Onsite electric power supplies must meet single failure criterion and provide power for the minimum required safety functions.
= The offsite power system shall consist of two physically -
independent circuits connecting the grid to the safety buses.
Each of the two offsite ~ power circuits shall be available in f sufficient time to shut the reactor down.
= Provisions shall be included to minimize the loss of offsite power.
- GRID STABILITY CONSIDERATION
, = Analyses must verify that the grid remains stable in event of:
A Loss of the nuclear unit generator i A Loss of the largest other unit on the grid A Loss of the most critical transmission line
^
14 ' -
i t
NRR ACTIONS - GRID RELIABILITY
- Continue to monitor industry deregulation developments and its -
impact on offsite power to nuclear power plants.
i
= Staff has met with Connecticut Valley Exchange, Comed, NERC, NEPOOL', DOE, and FERC in order to gain insights regardmg future changes in the industry.
- Assess the risk significance of potential grid instability ;
due to deregulation.
l
= Utilize contractor expertise (Target Completion Date: 9/98).
- As recommended by AEOD, we plan to issue generic '
communications which will reemphasize the need for licensees to maintain their design basis with respect to the stability and reliability of offsite power, and to maintain a process for ensuring that they i continue to meet their design basis for the remainder of their hcense !
(Tacget Completion Date: 1.0/97). !
- Plan to reassess the risks from S.BO (Target Completion Date: 12/98).
b 15 -
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