ML20205C726

Reactivation of Nuclear Power Plant Construction Projects. Plant Status,Policy Issues,And Regulatory Options

ML20205C726
Person / Time
Issue date:	07/31/1986
From:	Spangler M Office of Nuclear Reactor Regulation
To:
References
NUREG-1205, NUDOCS 8608120699
Download: ML20205C726 (140)

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NURsI1205 1

Reactivation of Nuclear Power Plant Construction Projects Plant Status, Policy issues, and Regulatory Options 4

l U.S. Nuclear Regulatory >

Commission Offico of Nuclear Reactor Regulation M. B. Spangler 0RE;GbO731 PDR

s.

1 NOTICE Availability of Reference Materials Cited in NRC Publications Most documents cited in N RC publications will be available from one of the following sources:

1. The NRC Public Document Room,1717 H Street, N.W.

! Washington, DC 20555

, 2. The Superintendent of Documents, U.S. Government Printing Office, Post Office Box 37082, Washington, DC 20013 7082 l

3. The National Technical Information Service, Springfield, VA 22161 Although the listing that follows represents the majority of documents cited in NRC publications, it is not intended to be exhaustive.

Referenced documents available for inspection and copying for a fee from the NRC Public Docu-ment Room include NRC correspondence and internal NRC memoranda; NRC Office of Inspection i and Enforcement bulletins, circulars, information notices, inspection and investigation notices;

! Licensee Event Reports; vendor reports and correspondence; Commission papers; and applicant and licensee documents and correspondence.

The following documents in the NUREG series are available for purchase from the GPO Sales Program: formal NRC staff and contractor reports, NRC-sponsored conference proceedings, and N RC booklets and brochures. Also available are Regulatory Guides, NRC regulations in the Code of Federal Regulations, and Nuclear Regulatory Comminion Issuances.

Documents available from the National Technical Information Service include NUREG series reports and technical reports prepared by other federal agencies and reports prepared by the Atomic Energy Commission, forerunner agency to the Nuclear Regulatory Commission.

l Documents available from public and special technical libraries include all open literature items, such as books, journal and periodical articles, and transactions. Federal Register notices, federal and state legislation, and congressional reports can usually be obtained from these libraries.

Documents such as theses, dissertations, foreign reports and translations, and non-NRC conference proceedings are available for purchase from the organization sponsoring the publication cited.

Single copies of NRC draft reports are available free, to the extent of supply, upon written request to the Division of Technical !nformation and Document Control, U.S. Nuclear Regulatory Com-mission, Washington, DC 20555.

Copies of industry codes and standards used in a substantive manner in the NRC regulatory process are maintained at the NRC Library, 7920 Norfolk Avenue, Bethesda, Maryland, and are available there for reference use by the public. Codes and standards are usually copyrighted and may be purchased from the originating organization or, if they are American National Standards, from the American National Standards Institute,1430 Broadway, New York, NY 10018.

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NUREG-1205 Reactivation of Nuclear Power Plant Construction Projects Plant Status, Policy issues, and Rcgulatory Options Minuscript Completed: June 1986 Dits Published: July 1986 M. B. Spangler Offico of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission W:shington, D.C. 20666

ABSTRACT Prior to the TMI-2 accident on March 28, 1979, four nuclear power plant units that had previously been issued a construction permit were cancelled, princi-pally because of reduced projections of regional power demand. Since that time, tn additional 31 units with cps have been cancelled and eight units deferred.

On December 23, 1985 one of the deferred units (Limerick-2) was reactivated and construction resumed. The primary objective of this policy study is to identify the principal issues requiring office-level consideration in the event of re-activation of the construction of one or more of the nuclear power plants falling into two categories: (1) LWR units issued a construction permit whose construction has been cancelled, and (2) LWR units whose construction has been deferred. The study scope is limited to identifying regulatory issues or ques-tions deserving analysis rather than providing, at this time, answers or recom-mended actions. Five tasks are addressed: a tabulation and discussion of the status of all cancelled and deferred LWR units; an identification of potential safety and environmental issues; an identification of regulatory or policy issues and needed information to determine the desirability of revising certain rules and policies; an identification of regulatory options and decision cri-teria; and an identification of decision considerations in determining staff requirements and organizational coordination of LWR reactivation policy and implementation efforts.

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CONTENTS

.P, age ABSTRACT........................................................... iii SUWlARY............................................................ ix

1. STUDY SCOPE AND 0BJECTIVES.................................... 1

2. DETERMINANTS OF STAFF REQUIREMENTS AND ORGANIZATION C00RDINATION..................................... 3 2.1 The Number of Reactivations and Their Timing............. 3 2.2 Reactivation Options chosen and Plant Status Considerations.................................... 3 2.3 The Number and Difficulty of Safety and Environmental Issues..................................... 3 2.4 NRC's Choice of Rerulatory Options for TreatingReactivatfonIssues............................. 3 2.5 Organizational Coordination.............................. 5

3. STATUS AND OUTLOOK FACTORS OF CANCELLED OR DEFERRED PLANTS............................................... 7 3.1 Status Summary of Units with Cancelled Construction...... 7 3.2 Status Summary of Units with Deferred Construction........ 14

3.3 Limerick-2

The Case of a Reactivated Plant Whose Construction Had Been Deferred............................ 22

4. IDENTIFICATION OF POSSIBLY RELEVANT SAFETY AND ENVIRONMENTAL ISSUES ARISING FROM SIGNIFICANT NEW INFORMATION.............. 29 4.1 Safety Issues........................................... 29 4.2 Environmental Issues.................................... 33

5. IDENTIFICATION OF REGULATORY OR POLICY ISSUES OF POSSIBLE RELEVANCE TO THE ADEQUACY OF EXISTING RULES AND POLICIES OR THEIR NEED FOR REVISION...................................... 37

6. REGULATORY OPTIONS AND DECISION CRITERI A. . . . . . . . . . . . . . . . . . . . . 43 6.1 Decision Criteria and Regulatory Purposes Guiding LWR Reactivation Policy Development......................... 43 6.2 Regulatory Options for Dealing with Reactivation Issues. 48 6.3 Potential Impact of Research Programs on the Choice of Regulatory 0ptions................................... 54 6.4 The Image Problem of Identifying and Choosing between Alternatives to Deal More Effectively with a Complexity of Regulatory Issues......................... 58

7. REFERENCES................................................... 63 i l

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CONTENTS (Continued)

P_ age APPENDIX A - FORECASTS OF ELECTRICAL ENERGY DEMAND AND NEED FOR ADDED PLANT CAPACITY................................................... 67 I. Exp l a na to ry Note . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 II. Ten Year Projections and Analyses by the North American Electricity Reliability Council of U.S. Electric Power Supply and Demand Plus Need for Added Plant Capacity............... 71 III. Ten Year Projections by the U.S. Department of Energy /EIA of Domestic Energy Consumption and Supply by Sector and Fuel Type........................................................ 91 IV. Excerpts from the Report of the Edison Electrical Institute on the Outlook for Reopening the Nuclear Option............. 101 APPENDIX B - ORDERS OF THE PENNSYLVANIA PUBLIC UTILITY COMMISSION BEARING ON THE DECISION PROCESS BY WHICH THE LIMERICK-2 NUCLEAR GENERATING STATION WAS REACTIVIATED ON DECEMBER 23, 1985......... 111 vi

FIGURES Figure P3 1 A conceptual model of interrelationships between factors and events impacting utility choice of LWR reactivation options and NRC choice of regulatory options and staffing requirements............................................. 4 2 lhe analytical model developed by the Philadelphia Electric Company in evaluating options for meeting regional electri'-

city demand for the period 1985-2020 and employed as an exhibit in the PUC show cause proceedings for Limerick-2 (Direct testimony of V.S. Boyer and W. H. Hieronymus)..... 26 3 A preliminary framework of industry and government initia-tives that would serve an implicit national goal of improv-ing the U.S. outlook for maturation progress in nuclear reactor safety technology and the resumption of industry growth.......................................... 62 TABLES Table g 1 Status of LWRs granted Construction Permits whose construction has been cancelled.......................... 8 2 Status of LWRs granted Construction Permits whose construction has been deferred........................... 15 3 Key information on the current status and plans regarding preservation costs and other data related to the pos-sible reactivation of the deferred nuclear WNP-1 and WNP-3. . . . . . . . . . . . . . . . . . . . ...............

. . . . . . . power pl 18 ants 4 Proposed schedule by WPPSS for the treatment of safety issues relating to interfaces with NRC during the period of shutdown for the deferred nuclear plants, WNP-1 and WNP-3................................................ 20 5 Documentary sources of information to understand the nature and importance of new LWR safety experience.............................................. 30 vii

SUMMARY

This policy study is both exploratory and limited in scope. Its primary objec-tive is to identify the principal issues requiring Office-level consideration in the event of reactivation of the construction of one or more of the nuclear power plants falling into two categories: (1) LWR units issued a Construction Permit whose construction has been cancelled, and (2) LWR units whose construc-tion has been deferred. The study scope is limited to identifying regulatory issues or questions deserving analysis rather than providing, at this time, answers or recommended actions. Five tasks are addressed: a tabulation and discussion of the status of all cancelled and deferred LWR units; an identifi-cation of potential safety and environmental issues; an identification of regulatory or policy issues and needed information to determine the desirability of revising certain rules and policies; an identification of regulatory options and decision criteria; and an identification of decision considerations in determining staff requirements and organizational coordination for LWR reacti-vation policy and implementation efforts.

Regarding the last of these tasks, it is shown that a very large network of analytical factors and decision considerations are involved that imply large uncertainties in estimating the level and timing of staff requirements. Indeed, there is an interlocking Catch-22 aspect of such a task. The particular choices made by the NRC of its regulatory options could have either a discouraging or encouraging impact on utility decisions to reactivate or not their cancelled or deferred LWR project and other decisions related to equipment preservation programs and design change options. The latter might involve a switch to a new standard plant design for some of the 22 cancelled projects that, for example, have less than $100 million of equipment onsite. Likewise, the actual utility decisions that will ultimately be made regarding reactivation options--and especially staff estimates of the aggregate effect of these deci-sions on NRC resource requirements--is a significant factor conventionally i used in making decisions on regulatory options. Another factor involved in I staff requirement estimates is the number and type of safety and environmental l issues resulting from significant new information since the units were deferred l or cancelled and the possibility of site-related developments not anticipated l that would contribute to staff re-review in the event of project reactivation.

On the other hand, utilities facing reactivation decisions must cope with the uncertainties of the cost impacts of dealing with these issues as well as the possible construction delays and potential cost implications of NRC's severe l accident research programs and regulatory decisions yet to be made regarding policies, rules, and the resolutions of safety issues currently being addressed by the staff. Sections 6.3 and 6.4 address these utility concerns over the stability and predictability of NRC's regulatory framework and outcome of i

research programs as these might affect investor confidence that weighs heavily in any reactivation decisions.

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Although there is a complexity of regulatory options and research projects 1 affecting these cost uncertainties, a conclusion of this study is that, on balance, these programs and options have substantial potential for improving regulatory stability and predictability, especially as these might hold impli-cations for cost escalation of reactivated LWR projects. Many of these research efforts and regulatory developments and options are, or would be, directed to the objective of improving regulatory stability and predictability as well as limiting future design changes to those which yield a substantial increase in the overall protection of the public health and safety and that meet the cost-effectiveness criteria of NRC's new Backfit Rule and revised Regulatory Analysis Guidelines. Moreover, staff efforts are in progress to review technical speci-fications and other regulatory rules or procedures to eliminate or modify those which make only marginal, if any, contribution to safety.

The preliminary, reconnaissance-level information assembled on the stat a of deferred or cancelled plants indicates that all seven deferred unite and thir-teen cancelled plants have major amounts of equipment onsite (i.e., o excess of $100 million acquisition value per unit). NRC needs to define its policy -

and clarify its review guidelines and procedures for equipment preservation programs for such equipment to maintain quality assurances in the event of their use in future project reactivations or resale to other project use. All of the sites for deferred units and a majority of sites of the cancelled units are still available for future construction of a nuclear, coal, or other base-load unit, although some have undesirable features for a coal-fired plant.

Most importantly, the status review indicated that the owners of many deferred and cancelled units are beset by financial difficulties and need-for plant issues that clearly must improve befo/e more than a handful of these can reach a decision to reactivate these projects. Accordingly, it would be premature for NRC to make a survey of utility reactivation intentions as a basis for LWR reactivation policy decisions. Improvements in the political and investment climate for utility reactivation decisions will depend, in large measure, on the cooperative and separate initiatives of industry and government, only some of which have been identified in this preliminary study effort.

Moreover, the recent worldwide political fallout of the Chernobyl nuclear acci-dent in the Soviet Union, that began on April 26, 1986, has further clouded the near-term prospects for construction of new or reactivated nuclear power plants in the United States and other Western countries. Because of differences in plant design and safety regulations and practices between the United States and the USSR, it is not practical at this time to assess what lasting effects the Chernobyl accident will yield for nuclear construction project reactivation decisions of U.S. utilities. Considering the several billion dollars of invest-ment (past or future) required to construct a nuclear power plant, a Reactiva-tion Policy Statement would be purposeful even if only a single deferred or cancelled LWR unit were reactivated in the next several years.

Need for generating capacity additions is expected to strengthen over the next 10 years (see Appendix A) and of course lead-time for plant construction must be reckoned with. The Energy Information Administration of the U.S. Department of Energy projects the demand for electricity to increase at an average rate of 2.7 percent per year for the period 1985-1995 and further estimates that x

obsolete units equivalent to 15 gigawatts of capacity will be retired during this period.1 Moreover, the North American Electric Reliability Council expects that by the mid-1490's, electric generating capac * / margins will be near minimum acceptable i-vals in some parts of the United States, even if electricity demands grow no faster than their present forecast rate of 2.2%

per year. Thus, many utilities will need to contemp1'+e scheduled additions .

to their generating capacity and what type of fuel s-+ .'d be used. In view of .

acid rain legislation under consideration and mountin3 concern over the green-house effects from the use of fossil fuels 3, it is not wholly clear that nuclear additions are out of the running despite current concerns over safety and cost factors.

I 1 Annual Energy Outlook 1985 with Projections to 1995, DOE /EIA-0383(85).

2 1985 Reliability Review: A Review of Bulk Power System Reliability in North America, North American Electric Reliability Council.

3 S. Seidel and D Keyes, Can We Delay a Greenhouse Warming? U.S. Environmental Protection Agency, September 1983.

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REACTIVATION OF NUCLEAR POWER PLANT CONSTRUCTION PROJECTS:

PLANT STATUS, POLICY ISSUES, AND REGULATORY OPTIONS

1. STUDY SCOPE AND OBJECTIVES This policy study is both exploratory and limited in scope. Its primary objec-tive is to identify the principal issues requiring Office-level consideration in the event of reactivation of the construction of one or more of the nuclear power plants falling into two categories: (1) LWR units issued a Construction Permit whose construction has been cancelled and (2) LWR units whose construc-tion has been deferred. The study scope is limited to identifying regulatory issues or questions deserving analysis rather than providing at this time answers or recommended actions. Specifically, the following tasks are regarded as appropriate:

(1) A preliminary tabulation of individual nuclear units whose construction has been deferred or cancelled, but with construction quality preserved, and their status relative to current NRC policies and regulations.

(2) An identification of special safety or environmental issues that might require (updated) analyses and staff review (or re-review), the need for which arises because of significant new information.

(3) An identification of regulatory or policy issues and related information useful to a determination of whether existing rules or policies are ade-quate or whether new or changed ones are desirable, especially regarding the differential situation of a reactivated CP application versus a still valid CP, but one possibly in need of extension or updated re-review.

(4) An identification of regulatory options for dealing with the above issues and decision criteria by which to judge their relative merits.

(5) An identification of decision considerations essential to a determination of staff requirements and organizational coordination.

One important aspect of this study is the identification of those determinants of NRC staff requirements and organization coordination needs associated with the reactivation of nuclear power plant construction projects. As will be seen in the discussions to follow, the level of staff requirements is one of the de-cision criteria by which the regulatory options of item 4 above should be eval-uated. Staff requirements, in turn, are related to many of the factors addressed in performing study tasks 1-3.

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2. DETERMINANTS OF STAFF REQUIREMENTS AND ORGANIZATION C0 ORDINATION Because of its interrelationships with other task elements, the identification of decision considerations essential to a determination of staff requirements and organizational coordination (task 5) occupies a focal role in the study design. The following is an identification of the relevant decision considera-tions or determinant factors of staffing or organizational requirements essen-tial to the effective performance of NRC's regulatory responsibilities asso-ciated with the reactivation of nuclear power plant construction of cancelled or deferred units.

2.1 The Number of Reactivations and Their Timing To a significant degree, NRC staff requirements will be greater (all other things being equal) the larger the number of LWR units being reactivated. The timing of any reactivations is also important to NRC decisions on staffing re-quirements which must be allocated over future years and budgets. For example, if analysis should reveal that few reactivations will likely occur over the next 3 or 5 years among the population of 35 units with construction cancelled and the 7 units with deferred construction, this would hold considerable import for staffing decisions even though the number of reactivations over a longer period may prove to be substantially greater.

2.2 Reactivation Options Chosen and Plant Status Considerations The number and timing of LWR reactivations is determined by the utilities' choices of reactivation options. As seen in Figure 1, these choices, in turn, are impacted by a host of factors and events. Not the least of these is what choices NRC makes in the way of regulatory options that may tend to encourage or discourage a given utility's decision to reactivate, or not, nuclear plant construction and the timing of such decisions. Also important is the status of cancelled or deferred plants, including such investment-related considerations as financial factors, electricity demand growth (need for plant), other regula-tory factors at the state or federal (non-NRC) level, socio political factors, and near- or long-term advances in technology and scientific knowledge. A number of these factors are discussed below in Section 3.

2.3 The Number and Difficulty of Safety and Environmental Issues In addition to the number and timing of LWR reactivations, NRC staff require-ments (including types of needed skills) will be affected by the number and difficulty of safety and environmental issues requiring staff review in the event of LWR reactivation. This is discussed in Section 4.

l 2.4 NRC's Choice of Regulatory Options for Treating Reactivation Issues l

The choice of regulatory options for the effective treatment of reactivation issues includes, among other cost-benefit considerations, the costs of regula-i tory staff (or contractor technical assistance) associated with the various options (see Section 6). By the same token, the particular choice actually made will then impose the estimated staff requirements.

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7. 8. 9. 10. 11. 12.

STATUS OF + FINANCIAL + ELECTRICITY + OTHER + SOctO. + ADVANCES IN:

CANCELLED C FACTORS T DEMAND t REGULATORY I OR DEFFERRED FOLITICAL 4 4 g GROWTH FACTORS FACTORS , 2 TECHNOLOGY SCIENTIFIC PLANTS INon NRC) KNOWLEDGE

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's . o' . o' ' . o' ' ... ge 1

3. + or - i UTILITY 5. 2 CHotCE OF ^

i RE ACTIVATION l -[+ or- ADEQUACY OF CURRENT l

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l CH OF l l REGULATORY OPTIONS S o f 3

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NO. & NO. & TYPE i l TIMING OF l 3r l OF SAFETY I i

LWR REACTI. & ENVIR'L VATIONS ISSUES ve,I.6/, gM.

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I NRC STAFF REQTS h

TIMING i

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+ or -  :

MBS v.ri.bi.  :

1-15-86 Figure 1 --A conceptual model of interrelationships between factors and events impacting utility choice of LWR reactivation options and NRC choice of regulatory options and staffing requirements.

2.5 Organizational Coordination It is envisioned that most of the regulatory options will require coordinated efforts of the Office of Nuclear Reactor Regulation, the Office of the Executive Legal Director, and the Office of Inspection and Enforcement. For those options involving rule changes or standards development, the Office of Nuclear Regula-tory Research and several offices of the Commissioners' staff may also be involved.

__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . 1

3. STATUS AND OUTLOOK FACTORS OF CANCELLED OR DEFERRED PLANTS

Direct contact was made with utility organizations that are the principal owners

, of the cancelled or deferred plants to obtain reconnaissance-level information on the status of these units and certain outlook factors of possible relevance to any reactivation decisions. This factual information was obtained even though, in a number of cases, it was quite clear there was zero or miniscule possibility of construction reactivation in order that a reasonable perspective on the full spectrum of closed or open (though undetermined) possibilities might be reflected by the factual data assembled.

For example, negative factors in the outlook for project reactivation would include: the sale of a site or its commitment to use in the construction of other buildings or major facilities; the planned conversion of the unit to other fuels such as coal, gas, or refuse; the installation of peaking units; and the cancellation, sale, or scrapping of major and minor equipment or its use as parts, or spare parts, for other nuclear and non-nuclear units owned by the com-pany. However, in those cases where very limited equipment is still available for project reactivation, the possibility might not be foreclosed that, depend-ing on the strengthening energy demand and financial (among other) factors, the 1;

utility might ultimately decide to put a new nuclear unit on the site, possibly a plant of standard design having a Final Design Approval or Design Certifica-

! tion in accordance with NRC's new Severe Accident Policy (NUREG-1070).1 Accord-ingly, preliminary information was obtained of the site's availability for a

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future plent installation, either coal, nuclear, or some other type of unit.

t 3.1 Status Summary of Units with Cancelled Construction There are presently 35 LWR units on 21 different sites whose construction has been cancelled. However, the NRC has not taken action on withdrawing the Con-struction Permit (CP) of 24 LWR units whose construction cancellation has been announced by the utility owner. After July 1, 1986, only four of these units I

will not yet have passed the iriitial CP Expiration Date: Marble Hill-1 (1-1-88), ,

Marble Hill-2 (9-1-89), Harris-3 (6-1-90), and Harris-4 (6-1-88).

4 Factual data regarding the regulatory, physical, and (quite limited) financial data on the status of these 35 units is shown in Table 1. It should be noted that in this exploratory effort, basically reconnaissance level information was assembled which has only partially been validated. Data on the first five col-i umns including construction progress was obtained initially from internal NRC sources. However, for the purposes of this study, precision of data is not es-

sential to provide a general, overall perspective. For example, the date at which construction was cancelled is imprecise since a variety of reference i points were used for different units: (1) the date of the press announcement i of construction cancellation, (2) the date of the utility's letter to the NRC requesting cancellation of the CP, or (3) the date at which NRC provided noti-

! fication of CP cancellation. The separation of these respective dates ranged .

i from a few days or months to upwards of a year c' more.

The principal relevance of the CP issue date is that it provides a crude indi-t cation of the plant's vintage. The oldest CP issue date for these units is l 10-27-72 (Zimmer) and the most recent is 1-4-79 (Jamesport 1 & 2). The mean CP l

issue date for this population of units is January 1977, or 9 years ago. Thus, i 1The titles and dates of NUREG citations are found at the end of this paper.

Tabl2 I. Status gf LWRs granted Construction Permits whose construction has been cancslied O (Based on reconnaissance level information; data not validtted)

Reactor Reactor CP Cancel "comu, . uW Ord m d hs M Me Nwnt w h Site Disposi*n PUC or State-Level Issues / Actions Reactor Unit Type vendor issued Date ns r Disp sed Value t* Nintenan:e Ifi Monit-

"*$I I or Future Use-N555 l TG l CME S-Mellions Program oring At Time of Cancel Status Change Vogtle 3 WR We 6 - 2s - 74 9-12-74 7 b e9utPaent NA NA NA Available NfP None Vogtle 4 PWR We 6- 2 8- 74 9-32-74 0* de!!vered NA NA NA Available NfP None Surry 3 rwa saw 12-20-i4 2-31-77 U" No equipment NA NA NA Avaliable NI'P, financial None Surry 4 PWR B&W 12-20-74 2-11 77 0* delivered MA NA NA Awallable NPP. financial Mone florth Anna 3 PWR B&W 7-26-74 6-22-s3 8 Equipment sold NA NA NA Available NfP, financial Mone North Anna 4 PWR B&W 7-26-74 18-25-a0 0 or scrapped NA NA NA Available NfP. financial None Jamesport ! PWR We 3-4-79 1-19-80 0 No equipment NA NA NA Available NfP, financial None

.Iamesport 2 PWR We 1-4-79 1 39-40 O delivered NA NA NA Available NfP. financial Mone Nrris 2 PWR We 3.y7 73 gy yg.g3 4C'* F1 Medium Routine No Ava11able,F2 Nfr Mone Harris 3 PWR We 1-27-78 12-18-81 1C** P1 Medium Routine No Available.F2 NfP None Harris 4 PWR We 1-27-78 42-1s-s1 IC .e F1 Nedium Rourine No Available.F2 NfP None Cherokee 1 PWR C-E 32-30-77 6-29-a3 18 Equipment sold NA NA NA Sold MfP NA Cherokee 2 PWR C-E 82-30-77 31-2-s2 O or scrapped NA NA NA Sold NfP NA Chero&cc ) PWR C-E 32-30-77 Il-2-a2 O NA NA NA Sold Nfp NA Nrble Hill 1 PWR We 6-4-7s 12-11-a ) 55C.e 90% of major Large F1 F3 Undet'd, F4 Financial rate, and F5 Nrt>le Hill 2 PWR we 6-4-7s 12-31-a3 35c.e equip't onsite Large F3 F3 Undet'd. F4 NfP issues F5 WiF-4 PWR B&W 2-28-78 l-22-42 24" F6 large Routine No DOE Lease ufr a financial issues None WI@-5 PWR C-E 7-31-78 3-13-84 16' F6 large Minimal No F7 ufP & financial issues kne TFrone ! PWR We O R R 32-27-77 7-24-7, R NA NA NA Available.F8 NfP. F9 None l Sterling 1 PWR We 3-26-77 5-2s-so 0 No equip't del, BA NA NA Available MfP F10 Forked River PWR C-E 7-10-73 11-6-80 5 R R R NA NA NA Available Fil Financial /1?II-2,NfP kne

, Callaway 2 PWR We 4-16-76 10-9-43  ! R R R Medium Routine No Available IlfP llone CD 8ailly 1 BWR CE S-2-74 s-41 I R R R Small SP No Undeternid,F12 Financial issues FIS e Hope Creek 2 BWR CE 11 74 12-29-81 18" F14 Small NA No Financial & rate issues Unavail..F15 bne Clinton 2 BWR CE 2-24-76 10-14-as IC R R F16 Small NA NA Available NfP Mone River Bend 2 BWR CE 3-25-77 1-29-84 Ic ' F17 R F17 Medium Routine No Available NfP, financial & rate Mone Zitrier RWR CE 10-27-72 1-21-84 98c FI8 F18 F18 Large.F19 NA NA coat conversion yA IRA Phtpps Bend A BWR CE t-36-7s 2-16-83 298 R R F20 Large SP, Routine No Up for sale MfP None yPhi$ Bend 2 BWR CE t-16-7s 2-16-83 5' R R F20 tarre SP. Routine No Up for sale NfP None Yellow Creek I BWR C-E 11-29-78 S-29-84 35' NA NA NA Large SP, Routine No Available MfP stone Yellow Creek 2 Ba C-E 11-29-78 S-29-84 3' NA NA NA Larne SP. Mutine No Available NfP None Hartsville Al BWR CE s-9-77 8-29-84 44" NA NA NA large Routine h Available NfP lione ILartsville A2 BWR GE S-9-77 S-29-84 34' NA NA NA large Routine No Available NfP None Hartsville 81 BWR CE s-9-77 3-22-83 17' NA NA NA Larre Routine No Available NfP None llartsville 82 BWR CE 5-9-77 3-22-43 7' NA NA NA Large 5;outine No Available MfP Ilone Legend: NSSS - Nuclear Steam Supply System; TG - Turbine-Cenerator; OIE - Construction Materials and Equipment; NA - Not Applicable; SP - Site- stab -

111:ation Plan; R - Resold, cancelled before delivery, or scrapped; PUC - Public Iftility Commission; NfP - Need for Plant issue; F1 - Footnote 1.

b Purchase price: excludes installation or maintenance costs (large - over $100 million; medium - $10 to 100 million; small - less than $10 million).

OL application received.

Available means there are no plans to sell the site and no known constraints to its ultimate use for a coal or nuclear plant addition.

e h CP cancellation by NRC has yet been issued for this unit.

f See next page for additional footnotes.

Additional Notes for Table 1 F1- For Harris-2, 98% of NSSS delivered to site, but much less for units 3 & 4 (reactor vessel and internals, piping, pumps, etc.); yard sale yielded little sales; TGs purchased for all units and stored offsite in Penna, and some piece of rotors sold.

F2- Site use for a possible coal plant addition may be feasible if plant would not exceed regional of site forair ashpollution ponds notlimits (already pressed) under EPA bubble concept; suitability studied.

F3- About 5-10% of onsite equipment has been sold by PSI from both units 1 & 2 under Investment Recovery Program; protective maintenance of remaining equipment monitored by onsite I&E inspector until a year ago.

F4- While a consortium has considered completion of Marble Hill Unit 1. no offer to purchase has been made. PSI states that there are no current or contemplated negotiations for such a sale. The PSI has requested cancellation of the construction h, permit and is currently awaiting NRC's decision. PSI has reviewed converting Marble Hill to coal and while there are dif ficult problems with conversion of a nuclear unit, PSI has not judged any of these problems to be insurmountable from an engineering standpoint. PSI has no plans to convert Marble Hill to coal-fired units.

F5-Investment recovery by PSI threatened by adverse Indiana Supreme Court ruling against rate-base decision by the PUC to permit investment recovery of cancelled Bailly plant, a ruling which may be challenged at the U.S. Supreme Court level.

F6- The combined acquisition value of delivered equipment (including some software services) for WNP-4 and WNP-5 is $558 million, of which $95 million (acquisition value) was sold at a recovery price of $20 million; the remaining equipment is onsite.

J F7- A future coal-fired plant is not a practical option for the WNP-5 site and is not being considered for the future use of this site; they do not foresee appreciable growth in electricity demand over next 20 years; WNP-5 is a siamese twin to WNP-3 at the Satsop site.

F8- Site for Tyrone-1 is regarded ideal for nuclear plant and not so good for coal with inadequate rail service.

F9- At time of cancellation, unable to obtain permit from State of Wisconsin because of PUC evaluation of inadequate need; part of Northern States Power Co. service area is in Wisconsin per a wholly owned subsidiary there.

L F10- Construction Permit for Sterling-1 was retracted by State of New York because of changed evaluation of need by the PUC; it is now forecasted that a baseload plant addition will be needed by 1995, Fil- A study in progress for installing either a coal plant or a waste recovery (refuse combustion) plant at the Forked River site with resolution undetermined arising, in part, from NfP and financial issues.

F12- Bailly site is inadequate in size for adding a coal plant, but could accommodate peaking units in addition to the coal unit already onsite; no interest in reviving a nuclear unit for the site.

F13- Possible appeal to U.S. Supreme Court for a reversal of Indiana Supreme Court decision denying investment recovery in the utility's rate base for abandoned nuclear construction work.

Fl4- Practically all of the equipment delivered to the Hope Creek-2 site was either scrapped.

sold or used for spare parts with less than $5 million (acquisition value) remaining to be sold; the generator was used in the Salem plant and the reactor pressure vessel was cut up and scrapped.

F15- The part of the site designated for Hope Creek-2 is now occupied by support service buildings and, therefore, site is unavailable for adding a nuclear plant in the future; a coal plant addition could be accommodated at the site if adjacent land is

_ purchased.

F16- The TG and NSSS for Clinton-2 was ordered but cancelled and never delivered; much of the remaining equipment delivered to site is warehoused for use as spare parts for Unit 1.

F17- Major components of the River Bend-2 NSSS being housed at the site (inerted reactor pressure vessel, pumps, motors, etc.) with no plan to sell; TG not fabricated; substantial quantities of CME warehoused both onsite and offsite.

FIB- Major equipment for Zimmer remains onstle; however, control rods and nuclear fuel

- removed from site and some equipment sold; the main steamline was cut and capped and the reactor building (with substantial equipment inside) was sealed and written off for tax purposes.

F19- Sealed off equipment in reactor building has large, but unrecoverable value since remainder of plant is being converted to coal use.

F20- The reactor vessel for Phipps Bend I & 2 was cut up and sold for scrap; other equipment delivered to site was either scrapped or will be scrapped.

.g.

the mean technological vintage of the engineering and safety design festures is at least 10 and possibly 12 years old considering that the major items of equip-ment such as the Nuclear Steam Supply System (NSSS) and Turbine-Generator (TG) would have been ordered several years before the CP issue date.

The date of construction cancellation holds several possible lovels of signif-icance: (1) it provides some indication of when the labor force may have.

been disbanded, (2) it indicates the length of time up to the present during which maintenance practices are of concern in preserving quality assurance in the utilization of the remaining equipment in the event of project reactivation, and (3) in some cases of longer duration (since cancellation), it suggests an adverse financial impact on the utility in the delay of investment-recovery in a rate base increase--an action which often does not begin until the plant.be-comes operational. To serve these purposes, the earliest reference date of cancellation (i.e., the press announcement date) would be the most meaningful.

For the population of 35 units, the oldest construction cancellation date is 9-12-74 (Vogtle 3 & 4) and the most recent is 8-29-84 (Yellow Creek 1 & 2 and Hartsville Al & A2).

The mean construction cancellation date for the 35 units is December 1982 or about 3 years ago. This is a conservative estimate since, as 1oted above, many of the cancellation dates recorded in Table 1 fall some months after the utility's board decision and public announcement. Moreover, it is known that, in some instances, the actual construction work stoppage occurred months, or even years, before the board's decision to cancel. liowever, in a_t least one instance (WNP-3), construction was resumed after the formal decision to can:el was made in order to complete the enclosure of the containment building as a prudent financial decision in the protection from weather elements of delivered onsite equipment located in the containment building. Moreover, the avoidance of cancellation penalties involved with construction contracts contributed to this decision.

Regarding the data on percent construction progress, the data of Table 1 repre-sents the current status as obtained from utility sources. This percentage sometimes differed significantly (often higher) compared to other available data. For 17 of the 35 units, the construction progress was 0 to 1%. The re-maining 18 units have construction progress ranging from 3% (Yellow Creek 2) to 98% (Zimmer), with a mean completion rate of 23%. Eliminating the Zimmer plant from these calculations (since it is being converted to a coal-fired plant) would yield a mean completion rate of 20% for the remaining 17 units. It is also significant that 8 of the 35 units are noted in Table 1 as having OL appli-i cations received by the NRC. Five of these eight have less than 5% construction progress.

The next set of information in Table 1 relates to the status of the equipment that was ordered for the 35 units and its disposal or retention. Both pre-ise and detailed data on the status of this equipment is not readily available.

However, some useful, though crude, insights were obtained from reconnaissance-level information received from utility sources responsible for the equipment's care or disposal. At this preliminary stage of investigation (and to facilitate response), only broadgage information was requested on three categories of equipment: the nuclear steam supply system (NSSS); the turbine generator system (TG); and other construction materials and equipment (CME).

I I

For seven of the units, the contracts were cancelled sufficiently early so that l no equipment was delivered to the site. Moreover, such equipment as was deliv-ered to the site was either resold, scrapped or used as parts, or spare parts, l for other nuclear or non-nuclear plants owned by the utility for an additional

seven units. Consequently, no equipment or materials assigned to the cancelled unit remains on the site for 14 of the 35 units.

For the remaining 21 units, the situations are so variable that their status is difficult to summarize. Indeed, for the 8 TVA units, only the sketchiest of information is available at this time. However, for some of their units with cancelled construction, it is known that substantial equipment remains onsite, while others have been scrapped, used as spare parts, and some was sold. Of the 13 remaining units having equipment onsite, perhaps a brief description of a few diverse situations will put into perspective the spectrum of status sit-uations. Marble Hill Units 1 and 2 (which are 55% and 35% complete) are re-ported to have close to 90% of the major equipment onsite that is needed to complete the project. About 5% to 10% of the equipment from both Units 1 and 2 has beer, sold and removed from the site. On March 7, 1986, the Public Service Commission of Indiana approved the terms and conditions of a negotiated settle-ment between PSI and the Indiana Utility Consumer Counselor. This settlement allows PSI an 8.2% rate increase but restricts the company's payment of common dividends for 3 years and general rate increases for 4 years. In addition PSI will never seek recovery of the cancelled Marble Hill plant through retail rates.

Another interesting illustration is provided by Harris-2, 3 & 4. For the NSSS, 98% of this equipment for Unit 2 (4% overall construction) was delivered to the site. Regarding Units 3 and 4 (each, 1% construction), delivery was made of the reactor pressure vessels and internals plus certain piping, safety injection pumps, and fuel handling equipment. The pressure vessels for all 3 units have been inerted using nitrogen. A yard sale was conducted, but not much equipment was sold. The turbine generators were purchased for all 3 units and are stored offsite in a Pennsylvania warehouse. Some pieces of the rotors have been sold.

A third example is the River Bend-2 unit whose construction was only 1% complete at the time of cancellation. Somemajorequipmentwaspurchasedanddelivered to the site. The inerted reactor pressure vessels are housed at the site. The turbine generator was not delivered to the site. Some other construction mate-rials and equipment were delivered and housed at the site and others are being stored in the company's offsite warehouses. This includes a certain amount of pipe, reactor circulation pumps, emergency diesel generators, etc.

The next subject of reconnaissance level information is the' maintenance status I of onsite equipment or materials. Where there is no longer any materials onsite

! (or offsite, for that matter) still assigned to the unit whose construction was cancelled, concern for maintenance is mooted and, hence, designated in Table 1 as "not applicable" (NA). As noted above, 14 of the 35 units bear this designa-tion. For the remaining 21 units, there is concern for the appropriateness of equipment maintenance to assure preservation of construction quality in the event construction is reactivated. A number of utilities are quite clear about l their intentions not to resume construction of the cancelled units. It is in-appropriate in this status report to perform any analyses or speculations on reactivation likelihoods for each individual unit. Accordingly, only factual information on the historic or current status involving maintenance programs for these units is reported.

l One crude indication of the magnitude of the maintenance problem is reflected in the acquisition value of equipment or materials assigned to the unit that ,

still remains onsite or in offsite warehouses, as the case may be. Warehousing  ;

of this equipment is, of course, one type of important protective measure of value to the dimensioning of the concern for quality assurance of equipment maintenance, as noted above regarding the completion of the containment build-ing for WNP-3. As noted in Table 1, only crude (order-of-magnitude) categories were used to express the value of equipment remaining onsite or warehoused off-site. The designation "large" was ut,ed for an acquisition value in excess of

$100 million; " medium" was used for values between $10 and 100 million; and "small," for values less than $10 million. In all cases, the value is the pur-chase price or acquisition value and does not include installation or mainte-nance costs. In some cases, a significant, but not overwhelming, component of this purchase value includes software services ',uch as engineering detail design work, equipment manuals or handbooks, etc. Of the 21 units for which mainte-i nance information is relevant, the value of remaining equipment was categorized l as small for 3 units, medium for 5 units, and large for 13 units.

i As shown in Table 1, no I&E monitoring is done regarding the maintenance status l of these 21 units having onsite equipment, since their cancellation relieves NRC l of any regulatory authority for such monitoring. However, reconnaissance level information reveals that routine maintenance practice of the utilities is being used to protect against deterioration of those onsite materials that have not

been cut up for scrap. Validation of the reliability of this information would, l of course, require field visits to the pertinent sites and offsite warehouses.

Factual information is also relevant to a reactivation study regarding the site i

disposition or known plans or constraints, if any, regarding the future use of the site for constructing new generating units (coal, nuclear, or other fuels) in lieu of reactivating the presently cancelled units that would make use of the remaining equipment discussed above. For 5 units, this latter possibility has been mooted by actions taken by the utility. The Cherokee site has already been sold for housing developments that negates quite definitely the. possibility that the 3 cancelled units could be revitalized as a construction project at this site. A decision has been made to convert the 98% completed Zimmer plant to a coal-fired generating unit that would nullify a nuclear unit being coin-pleted at this site. The fifth unit for which a different commitment has been cade affecting the future r;e of the site is Hope Creek-2. Here, the space originally dedicated for this unit adjacent to Unit 1 is now occupied by per-manently constructed buildings that provide support services for the cnmpany's operation of Unit 1. It is noted that the remaining open space on the site would be suitable for adding a coal-fired plant only if adjacent land is purchased.

A different kind of situation is the Phipps Bend site which, according to a media report,1 TVA officials have decided to put up for sale. Should this sale be c6nsummated, the site would no longer be available for building either a coal or nuclear plant. The Bailly site on which a coal-fired plant has long been located is too small to accommodate a baseload coal plant addition, but it i would be suitable for the construction of peaking units. If the Marble Hill l enits are not reactivated as nuclear units, there are some site-related problems l in converting them to coal-fired units. Public Service of Indiana (PSI) has commented on this as follows:

1"TVA to sell Phipps Bend plant site," News Sentinel, Knoxville, TN, Nov' ember 19, 1985.

a

" PSI has reviewed converting Marble Hill to coal and while there are difficult problems with conversion of a nuclear unit, PSI has not judged any of these problems to be insurmountable from an engineering standpoint. PSI has no plans to convert Marble Hill to coal-fired units."1 The Satsop site (WNP-3 and WNP-5) is located on a hilly location and is not re-garded as suitable for adding a coal-fired plant because of poor access to rail-road transportation for the large amount of coal that would need to be trans-ported to the site plus uncertainty over the transferability of water rights and

( discharge permits. The Harris site (Units 2, 3 & 4) would be suitable for the y L addition of a coal-fired plant, but there is some concern whether such a plant (even with 50 2 scrubbers) might unacceptably press against regional air quality limits under the EPA bubble concept because of the number of coal-fired plants already in the region. Similar problems may arise at present nuclear sites in other regions, especially if more stringent air pollution standards might be applied to deal with acid rain problems (502 and N0 ) or rising concern over greenhouse effects (C0 2 ) 2 Economic factors also could be a consideration in

[ the use of certain sites for coal-fired plants. A recent estimate is that acid rain legislation (H.R. 4567), if it should become law, would mean that 16 south-ern states would have to come up with 44 percent of the total emission reduction required nationwide and would have to pay an extra $2.3 billion per year for

.- electricity versus $5.8 billion nationally.3 It was recently stated that Caro-lina Power & Light Company will cancel its planned 720-MW Mayo coal-fired power plant if required to install flue gas scrubbers on it.4

__- The final status element dealt with in Table 1 is to identify and note whether there had been any significant change in those issues or actions of Public Util-ity Commissions or otner State agencies that, at least in part, contributed to

. the cancellation.5 Thir limitation of scope does not imply that other causal

_ factors and their recer.t or future status changes are not important to any fu-ture analysis that would impact utility choice of reactivation options. With reference to Figure 1, also of potential importance are the changes in status or the number and type of technical and environmental issues (item 6); the change since cancellation in NRC's current rules, policies and practices (item 5); and the past or future changes in various causal factors or develop-

, mental events (items 7-12). These represent a more ambitious scope of inquiry and analysis than is suited to this exploratory effort.

An inspection of Table 1 shows that a major factor contributing to cancellation of a majority of the 35 units were issues of need for plant (NfP) relating to a 1 Letter of June 4,1986 to Harold R. Denton from G. Kent Dyekman, Chairman of the AIF Ad Hoc Group on Reactivation of Construction Projects.

. 2U.S. Environmental Protection Agency, Potential Climatic Impacts of Increasing

• Atmospheric CO., with Emphasis on Water Availability and Hydrology in the United States (Washington, D.C., April 1984); and J. Hoffman, D. Keyes, and J. Titus, Projecting Future Sea Level Rise: Methodology, Estimates to the Year 2100, and

=

Research Needs, U.S. Environmental Protection Agency (October 24, 1983).

3" Acid Rain Threat to South," The Energy Daily, May 21, 1986, p 2.

4" Scrubbers Be Damned," The Energy Daily, June 9, 1986, p. 3.

5 Energy Information Administration, Nuclear Plant Cancellations: Causes, Costs, and Consequences, DOE /EIA-0392, U.S. Department of Energy, April 1983.

=

drastic reduction in electricity demand growth projections that occurred due to the severe rise in energy prices and other inducements to energy conservation following the Mid-East oil embargo of October 1973. Excessive reserve margins developed for all U.S. continental regions with interconnected grids. Although these margins are being worked down to varying degrees as a result of recent strengthening of electricity demand (see Appendix A), nevertheless, for many regions additional baseload capacity may not need to be added until the early or late 1990s and, in some cases, after the turn of the century. The use of the descriptor "none" in Table 1 for status change regarding need for plant reflects only that the NfP issue still exists for near-term reactivation of these units, even though some improvement in the longer term outlook may have occurred. This is an area requiring careful analysis for each region and ser-vice area of those utilities with cancelled construction of units, if the reac-tivation outlook affecting NRC staff requirements, etc. , is to be properly assessed.

The reduced electricity demand growth and consequent stretched-out schedules of both coal and nuclear plant construction contributed to financial stress on many utilities. Moreover, the potential controversies at the state level and slowness of Public Utility Commissions (PUCs) to institute appropriate rate measures or other needed actions contributed to, or failed to adequately re-lieve, financial stress on a number of the affected utilities.1 While improve-ments on this score may have occurred for some of the utilities, in a number of cases financial or rate issues still remain to so:ae degree that would dis-courage project reactivation. It must be acknowledged that a detailed investi-gation of these status elements was not possible in this exploratory effort.

The assembled data could thus be expected to reflect a number of gaps and possible inconsistencies of treatment or interpretation.

3.2 Status Summary of Units with Deferred Construction In contrast with the large number of LWRs with cancelled construction, there are only 7 units with deferred construction: Grand Gulf-2, Perry-2, WNP-1, WNP-3, Midland-1 & 2, and Seabrook-2. Previously, Limerick-2 was included on the NRC list of deferred units, but it was reactivated as a construction pro-ject by a board decision of the Philadelphia Electric Company on December 23, 1985 (see Section 3.3).

As seen in Table 2, the Construction Permit issue dates for the deferred LWRs range from 12-15-72 for Midland-1 & 2 to 4-11-78 for WNP-3. The mean CP issue date for these 7 units is May 1975 or more than 11 years ago. This implies a vintage of technological design that is almost 2 years older than the mean vin-tage of the 35 units with cancelled construction and a mean CP issue date of January 1977. However, the 7 deferred units have a mean deferral date of Decem-ber 1983 (about 2 years ago), which is somewhat more recent than the mean can-cellation date (December 1982) computed above for the population of cancelled units. As previously noted, the length of time since deferral or cancellation of construction holds implications for such concerns as the length of the equip-ment maintenance program and the likelihood that the construction labor force has been disbanded and moved from the region.

1For a discussion of the role of state. regulation and PUCs see The Nuclear Industry and Its Regulators (NUREG/CR-4446).

1

.e . l . v. s. L ., . . . .. . s. '. ..

Table 2. Status of 1.WRs granted Construction Permits whose construction has been deferred.

(Based on reconnaissance level informatien; data not fully validated)  ;

LWR Reactor Defer- Constr'n Equipment Status of Onsite Equipment or Mtis Site Dis- PUC or State-Level Issues or Actions Reactor Unit ven- Issue rol Progress Ordered Valueb Maintenance I&E Monit- posal or Type dor Date Date (I) Or Resold a g. Millions Program oring Future Usa At Time of Deferral Status Change Grand Gulf 2 BWR GE 9-4-74 8-15-84 35 (All major Large EPP Yes Undeter- Rate issues Resolution of (MK equipment mined Financing issues rate issue for III) on site) Need issue Unit 1 Seabrook 2 PWR We 7-7-76 9-25-84 24c (All major Large EPP Yes Undeter- Rate issues equipment mir.ed Financing issues No change on site) Need issue Perry 2 BWR CE 5-3-77 7-17-84 44d (All major Large EPP Yes NA Rate issues (MK equipment e Need issue No change III) on site)

WNP-1 PWR B&W 12-24-75 1981 63 C (All major Large EPP Yes Site Need issue equipment leased Financing issues No change on site) from DOE WNP-3 PWR C-E 4-11-78 March 76c (All major Large EPP Yes Undeter- Need issue 1983 equipment mined Financing issues No change 1 on site) in

' Midland 1 PWR B&W 12-15-72 7-15-84 85C (All major Large EPP Yes Undeter- Rate issues Hearing in equipment mined Financing issues Spring 1986 on f on site) i Conversion study rate issues Midland 2 B&W 12-15-72 7-15-84 c PWR 85 (All major Large EPP Yes Undeter- Ditto Ditto equipment mined on site) 1 8

Legend: NSSS - Nuclear Steam Supply System; TG - Turbine-Generator; CME - Construction Materials and Equipment; N A - Not Applicable; Ord - Ordered; R-Resold; EPP-Equipment Preservation Program; PUC-Public Utility Comission.

b Purchase price; excludes installation or maintenance costs (large - over $100 million; medium - $10 to 100 million; small - less than $10 million).

C OL application received, d

Perry-2 construction excludes facilities in common with Perry-1.

' Full security measures in place for Perry-1 and Perry-2.

f CP expired 12-1-84; extension requested on 5-24-84 for completion by 12-1-89.

9 CP expired 7-1-84; extension requested on 9-11-84 for completion by 7-1-89, D

Construction of unit 2 halted on 4-19-84.

I Resale is an option under consideration.

Of considerable relevance to the outlook for project reactivation is that the average construction completion for the 7 deferred units is 59%. This is sub-stantially higher than the mean completion rate of 20% computed above for the 17 units with cancelled construction having construction progress of 3% or more at the time of cancellation.1 In each of the cases, the deferred units have all the major equipment ordered and onsite and therefore the acquisition value is large (i.e., in excess of $100 million per unit). By the same token, equip-ment preservation programs have been in effect for each deferred unit and each unit has received periodic inspection by NRC regional I&E inspectors to ascer-tain whether construction quality is being preserved. The detailed nature of the equipment preservation programs and findings of NRC inspectors is beyond the scope of this exploratory effort.

Regarding the remaining subjects covered in Table 2, such as site disposition and the status of state-level issues or actions, these are sufficiently varied as to invite case-by-case discussion of the reconnaissance-level information.

A quite complex situation arises from the nature of issues surrounding the pos-sible reactivation, abandonment, or conversion options of the LWRs at Midland-1&2. Construction was cancelled for these units on July 15, 1984, fol-lowing a long history of litigation, technical, financial, and rate base issues.

Unit 1 was designed as a co generation plant that would supply electricity for Consumers Power's service area and process steam to a DOW chemical plant on an adjacent site. The delayed construction schedules and cost overruns led to court action involving 00W's suit to withdraw from its contractual obligations.

Quite significant technical issues also arose over the settling of the auxiliary building at the Midland site and what design changes or other measures are re-quired to deal satisfactorily with the attendant foundation problems. Both the legal and technical issues have exacerbated the financial and rate base issues that have also affected deferred units elsewhere.

The DOW Corporation backed out of the contract on July 15, 1983, and one year later, the Consortium of Users in the Detroit area (including the GM Corpora-tion) opposed the Utility's request before the PUC for favorable financing terms.

These actions had a negative effect on the utility's ability to raise funds for project completion, which currently is estimated to be 85% complete for each unit.

There have been two hearings going on in parallel with the same Atomic Safety and Licensing Board (ASLB) focusing on soil settlement issues plus such OL-contested issues as generic safety issues, cooling pond environmental analysis, cost-benefit analysis, severe accident analysis, emergency planning, and Quality Assurance / Quality Control analysis.

Faced with the possibility of filing for bankruptcy if rate relief for a re-covery of at least some of the $4.1 billion thus far invested in the Midland units, Consumers Power undertook a cost study of converting the units to either a natural gas combined-cycle plant or a coal-fired plant, completing them as a nuclear plant, or abandonment.2 3 Of the nuclear option, William McCormick, Chairman of Consumers Power said, "From a practical standpoint, I have no doubt that technically this plant could be completed as a nuclear plant. But I don't think the political and regulatory risks are acceptable."3 Part of their 1This excludes the Zimmer plant because of the coal conversion plan for this unit.

2" Consumers Power To Take Write-Off," New York Times, December 10, 1985.  ;

3" Consumers Studies Gas Option for Midland Plant," State Journal, Lansing, MI, February 25, 1986. '

problem, according to McCormick, is the need to educate the people of Michigan about the electricity demand growth in the last few years, the projections of grc.wth, the capacity requirements, and what the reserve capacity is.

On March 28, 1986, the Consumers Power Company announced that it would try to convert the Midland nuclear power plant to a gas-fueled generator on the basis that "it takes a shorter amount of time and costs much less."1 However, this plan is still under a cloud of uncertainty since Michigan Attorney General Frank Kelley said the conversion to gas is costly and unnecessary, claims that were challenged by McCormack.2 The company has now gone to court in an attempt to head off a Michigan Citizens Lobby petition drive for a state constitutional amendment that would impose tough conditions on utilities seeking to put new plants into the rate base.2 If adopted, the amendment could bar past practices in which the Public Service Commission of Michigan has sometimes allowed utili-ties to charge customers the cost of abandoned projects depending on the outcome of a prudency review of project management.3 The Construction Permits for both units expired during 1984 and the utility has applied to NRC for their exten-sion. The NRC staff reviewing this request has decided to wait on the out-come of the utility's decision expected this year whether or not to complete construction of the nuclear units or to exercise one of the other options under consideration.

Both need-for plant and financial issues have led to the deferral of the WNP-1 and WNP-3 units of the Washington Public Power Supply System (WPPSS), a joint operating agency and municipal corporation composed of 13 Public Utility Dis-tricts and three municipal lighting systems. The Northwest Power Planning Council (NWPPC) and the Bonneville Power Administration (BPA) share in the re-sponsibilities for projecting power requirements of the Northwest Region. The BPA is reported to have said the earliest that power from the two WNP units would be needed is 1994, but there is a one-in-three chance that one of the two LWRs would be needed before that date.4 A question being addressed is which of the two units should be completed first and whether the other should be aban-doned or preserved for later reactivation. Complicating these planning deci-sions is the inability of WPPSS to sell bonds to finance completion of one or both of these units because of the bond default on the cancelled WNP-4 and WNP-5 projects.

The WNP-1 unit located on the Hanford reservation of the DOE is 63% complete with estimated costs of $1.4 billion for completion and current mothballing (preservation) costs of $10 million per year according to the data supplied by WPPSS in Table 3.5 The acquisition value of prepurchased equipment for WNP-1 is $314 million. The WNP-3 unit located in the Grays Harbor area of western Washington (Satsop site) is 76% complete, requiring an estimated $1.3 billion for completion and $14 million per year. These preservation cost estimates for WNP-1 and WNP-3 represent a substantial reduction from those reported for 1" Consumers Power Plans Midland Shift," New York Times, March 29, 1986.

2" Consumers Power Hits Heavy Weather," The Energy Daily, June 9,1986.

3" Plan Allows PSC Advance Approval on Power Plants," Grand Rapids Press, November 19, 1985.

4"Which WPPSS plant will be finished?" Olympian, December 15, 1985.

5Information received from WPPSS by letter of January 30, 1986 from G. C. Sorensen to Miller Spangler.

i i

Table 3. Key information on the current status and plans regarding preservation costs and other data related to the possible reactivation of the deferred nuclear power plants WNP-1 and WNP-3*

I l Factor WNP-1 WNP-3 Size 1250 (MW Net) 1240 (MW Net)

Percent Completea 63% 76%

Operating Life 40 Years 40 Years Cost to Completeb $1,383 Million $1,310 Million Cost to Complete /kWhc 2.7 Cents 2.8 Cents Preservation Costsd $10 Million/Yr. $14 Million/Yr.

Peak Work Force 4,700 3,200 Peak Payroll $280 Million/Yr. $225 Million/Yr.

Peak State & Local Taxes $31 Million/Yr. $38 Million/Yr.

During Construction

! Generating Taxes During $100 Million $100 Million Operating Life Value Prepurchased Equipment * $314 Million $435 Million

• Source: Information received from WPPSS by letter of January 30, 1986 from G.C. Sorensen to Miller Spangler.

" Work was halted at WNP-1 in May 1982 and at WNP-3 in July 1983.

l b

Construction and fuel costs as of restart of construction (excludes future escalation and preservation program costs and/or reductions) reflect a reduction from $1,531 million for WNP-1 in 1984 and from $1,462 million for WNP-3 in 1984. To-date, $1,877 million has been spent on WNP-1 and $1.960 million on WNP-3.

• Source: Northwest Power Planning Council's Draft 1985 Power Plan, dated August 7, 1985.

d Includes minimum preservation only (excludes future escalation, contract close-out costs, earned value engineering costs). Earned value engineering programs are currently estimated at $16 million per year for WNP-1 and $12 million per year for WNP-3.

'Prepurchased equipment cost includes entire contract scope. This could represent not only the actual cost of equipment itself, but the cost of associated engineering /

design work, quality records, etc.

l

recent years.1 An illustration of the sort of safety issues during a shutdown period for deferred plants that involve regulatory interfaces with the NRC is provided in Table 4 for WNP-1 and WNP-3.2 A measure of controversy has arisen in that Pacific Power and Light Company wants WNP-3 terminated because the Western Public Agencies Group has requested the BPA tc put preservation costs into rates paid by the region's investor-owned utilities.3 Project WNP-3 is jointly owned by 4 private utilities (30%) J and BPA (70%), whereas WNP-1 is controlled totally by BPA. The ownership mix at WNP-3 led to a lawsuit in 1983 challenging the mothballing of this unit. An out-of court settlement subsequently guarantees the investor-owned utilities a fraction of BPA power beginning in 1987 in exchange for dropping the lawsuit.1 In the current controversy, Pacific Power & Light Company threatens not to go to BPA for additional future resources if preservation costs for WNP-3 are put into the new resource pool rate, arguing that there are more cost-effective, future resources than WNP-3, such as conservation, cogeneration, and small hydro.s According to this report, BPA still thinks it would be cheaper to complete WNP-1 and WNP-3 than to build another large power plant, noting further that conserva-tion and cogeneration would help, but with the region's projected load growth (see below), it wouldn't be enough.

Socio political factors are quite different in the immediate region of the two sites ana may also affect any reactivation decisions that could follow BPA's re-view in 1986 of the cost effectiveness of completing the two units. The bonds for WNP-1 and WNP-3 are ensured by BPA. A substantial fraction of the construc-tion labor employed at both sites has dissipated and project reactivation at either site would require a build-up phase for recruiting and retraining of workers. Construction unions have indicated a willingness to cooperate in ac-tions essential to maintain improved control over construction costs in the event of project reactivation. The BPA forecasts of regional total electricity loads for the period 1985-2005 cover a wide range of estimates. The low fore-cast is essentially zero growth, the medium forecast averages 1.3% per year (compounded annually), and the high forecast averages 2.8% per year4 The medium forecast of 1.3% per year for the period 1985-2005 is somewhat less than the 1.7% per year forecast of the North American Electric Reliability Council for the Northwest Power Pool (U.S.) for the shorter period 1985-1995.s In meeting this growing demand from alternative energy sources (including conservation),

the WNP-1 and WNP-3 alternatives are assumed by the BPA to " float," with con-struction occurring when needed, with a 10% probability of involuntary termina-tion (Ibid.). Further, the BPA notes that although WNP-1 and -3 are " valuable options, legal and institutional obstacles could impede their completion. Some obstacles have been cleared, but others still remain. BPA and others will continue efforts to remove those obstacle. However, because these efforts are 10lympian, December 15, 1985, op. cit.

2Information received from WPPSS by letter of January 30, 1986 from G. C. Sorensen to Miller Spangler.

3" Utility Urges End to Washington Nuclear Unit," The Energy Daily, June 6, 1986,

p. 4.

41g86 Resource Strateqv, Draft Report, Bonneville Power Adm 6istration, U.S.

Department of Energy, November 1985.

5"1985 Reliability Review: A Review of Bulk Power System Reliability in North America," North American Electric Reliability Council, 1985, p. 61:

Table 4. Proposed schedule by WPPSS for the treatment of safety issues relating to interfaces with NRC during the period of shutdown for the deferred nuclear plants, WNP-1 and WNP-3* l

)

Safety Issue Date to NRC WNP-1 Elimination of Arbitrary High Energy Line Breaks Sent October 10, 1985 TDI Diesel Plant Specific Portion October 1985 Increased Cable Tray Seismic Damping Sent September 6, 1985 No High Energy Line Break in Main Steam and Feedwater Isolation January 1986 Valve House (Superpipe Used)

Seismic Analyses (Input at Ground in Lieu of Base Mat and March 1986 Half-space vs. Finite Boundary Analyses and +15% Response Spectrum Broadening vs. Varying Soil Properties)

Consideration of Multiple Tornado Missiles March 1986 NF/AISC Jurisdictional Boundaries March 1986 Leak-Before-Break, Plant Specific Application March 1986 Appendix R (Specific Issues, Not Overall Review) June 1986 Response to ATWS Rule and SRP 5.2.2 (Fail First Trip) September 1986 ATOG Technical Basis Document Sent September 12, 1985 Relap-5/IST Benchmarking 1986 j Integral System Test Support Through March 1987 l WNP-3 l

Geology 8/86 (First Submittal)

Stiff Clamps Sent August 1985 Deconvolution February 1986 (Clarification of Previous Response)

Close-out Structural Audit (Containment Buckling) January 1986 Appendix R (Specific Issues, Not Overall Review) November 1986 Reactor Systems Branch, Question Responses (CESSAR March 1986 Interface Requirements) (First Submittal)

Subcompartment Pressurization April 1986 Power Systems Branch Question Responses June 1986 (Partial Submittal)

BTP PSB-1 January 1987 Plant Specific Fuel Cycle October 1986 Leak Before Break Later 1986 or 1987 All Other Outstanding NRC Questions Mid 1987

• Source: Information received from WPPSS by letter of January 30, 1986 from G.C. Sorensen to Miller Spangler.

l l l

not yet complete, the possibility that these obstacles could prevent completion was directly factored into BPA's analysis" (Ibid.).

Another of the deferred units is Seabrook-2, which was 24% complete at the time of deferral on September 25, 1984. The construction status report of Septem-ber 30, 1985, indicated that 69% of the structural concrete was in place, the reactor pressure vessel was 100% installed, plus 4% of the large bore process pipe and 3% of the large bore pipe hangers, restraints, and snubbers. The equipment preservation program is in effect, which includes long-term corrosion monitoring. At the time of deferral, Seabrook-2's outlook for completion was entangled in a number of issues involving PUC areas of responsittility or con-cern: rate base issues for investment recovery for Unit 1 with long-term im-plications for Unit 2, financial issues, and need-for plant issues. Currently, this list of concerns remains unchanged, although some improvement in outlook may have occurred for each of these factors. The Chairman of Northeast Utili-ties has recently predicted that the New England Region may face a power short-fall (without new units being added by 1996), assuming 2.1% annual growth in electricity Cemand and with Millstone-3, Seabrook-1, and some utility-owned hydroelectric projects all on line.1 If demand growth is as high as 3% per year, then he feels New England may have a shortage of baseload capacity as ,

early as 1992.

Still another view is a prediction by John Sillin that New England demand will likely grow by 4-5%, leading to additional new capacity requirements of 2600 MWe by 1993 if a 20% reserve margin is to be maintained. (Ibid.) The North Ameri-can Electric Reliability Council predicts that unacceptable reliability will be encountered in New York and New England, starting in the 1990's, unless present .

regulatory and financial impediments to committing new generating resources are removed (op. cit., p. 45). Thus, a decision is possible within the next year or so as to whether the perceived needs for baseload capacity in the New England Region should be met; for example, by reactivating Seabrook-2 or some other alternative supply sources.

The Perry-2 unit, for which construction is 44% complete, holds a Construction Permit that extends to November 30, 1991. Rate issues and lagging demand growth (NfP issue) were instrumental in the decision to defer construction. The re-vised completion date for Perry-2 is as yet undetermined, but no other use is contemplated for the site. The PUC of Ohio has in progress an audit or prudency review of the utility's project management responsibilities as related to pro-ject cost escalations.2 A favorable outcome of this review could contribute significantly to a decision to reactivate construction of Perry-2 along with continued strengthening of demand and need for plant. Moreover, there pre-viously existed a transmission right-of-way issue which has now been resolved.

The final unit among the list of deferred LWRs is Grand Gulf-2. As may be ex-pected, the completion of a second (or third) unit of a multi-unit site depends in part on the nature of the resolution of rate-base and other issues affecting the investment recovery and profit rate outlook of the first unit being com-pleted with implications for raising capital for a subsequent unit. Another 1"New England Coming Up Short," The Energy Daily, December 13, 1985, p. 4.

2"PUC0 hires firm to study Perry cost," The Telegraph (Painesville, Ohio),

December 11, 1985.

kind of interrelationship between multiple-unit construction is that completion of the first unit often requires a substantial increase in consumer rates for several years after the start of operations affecting the political climate for imposing further rate increases in a relatively few years for subsequent units.

Thus, a longer construction delay eases somewhat this problem, a strategy that works at cross purposes for maintaining cost-control over time-related cost over-runs such as interest charges during construction (IDC) and escalation, or in-flationary, costs for labor and construction materials (EDC). Moreover, the coming on line of a large block of baseload capacity of 1000 MWe or more with the first unit increases reserve margins for several years, thus weakening the near-term need-for plant case for subsequent units unless there is a fairly good rate of regional demand growth. These sorts of decisional considerations and uncertainties not only surround the question of whether or when Grand Gulf-2 will be reactivated but also a number of the other deferred units discussed above.

It was reported that the Board of Middle South Utilities, Inc. , would meet on December 19, 1985 to reach a decision whether to cancel the Grand Gulf-2 unit and to initiate actions necessary before the Federal Energy Regulatory Commis-sion and the courts to attempt to recover $927 million expenditures on Unit 2 through rate relief over a period of years by means of charges to the system operating companies.1 Similar rate relief proceedings before state and local

! regulatory authorities to recover Grand Gulf-1 costs proved to be long and pro-tracted. At its December meeting, the MSU Board decided to postpone for another year its decision regarding cancellation / reactivated construction of Grand Gulf-2. On a positive note, it was reported that in December 1985 the Securi-ties and Exchange Commission authorized Middle South Utilities, Inc. and its utility units to resume issuing bonds and short-term notes because the com-pany's financial prospects have improved.2 The need-for plant issue remains of significant concern for the region.

, 3.3 Limerick-2: The Case of a Reactivated Plant Whose Construction Had Been l Deferred As previously noted, there is a considerable climate of doubt and uncertainty regarding how many deferred or cancelled plants will ultimately be reactivated and their timing. A brief examination of the salient features of the Limerick-2 reactivation decision in a sense provides an antidote to an unwarranted level of pessimism. But, more importantly, for our purposes, the Limerick-2 expe-rience provides potentially valuable insights regarding the procedural course of utility /PUC actions and interactions that made reactivation of construction of Limerick-2 a realized outcome of institutional decisionmaking and its sup-porting analyses. In relation to the purposes of the conceptual model of Figure 1, the Limerick-2 experience illustrates that part of the diagram which reflects the potential importance of the sizeable variety of causual considera-tions (Factors 7-12) as these impinge upon a utility's choice of options (Factor 3) in deciding whether to reactivate a nuclear plant with deferred (or cancelled) contruction or to pursue some other option in meeting electrical l energy demand.

l l

l 1" Middle South may cut unit, make subsidiaries pay loss," Arkansas Democrat

! (Little Rock), December 5, 1985.

2"SEC Authorizes Middle South Utilities and Units to Resume Financing Efforts,"

Wall Street Journal, Eastern Edition, December 20, 1985.

Prominent among the causal factors leading to the construction deferral of the Limerick-2 unit were need-for plant issues and financial considerations common to many nuclear and coal-fired plants under construction in the turbulent period following the Mid-East oil embargo of October 1973. These untoward (and un-planned for) events related to the " energy crisis" of the late 1970's contrib-uted significantly to construction schedule delays and cost overruns, an im-portant component of which was due to rapid increases in interest rates and escalation rates for labor and materials as affected by the general trend of infla' tion in the U.S. economy. The design backfits to improve safety following the TMI-2 accident of March 28, 1979, also contributed significantly to nuclear power plant construction costs, including those of Limerick-2.

Thus, on August 8, 1980, the Office of Consumer Advocate (0CA) of the Common-wealth of Pennsylvania filed a petition seeking: (1) an Order to Show Cause why the continued construction of the Limerick Nuclear Generating Station (Limerick) of Philadelphia Electric Company (PEC0) is in the public interest and (2) a Commission investigation into the need for and economy of Limerick.1 In denying this petition, the Public Utility Commission (PUC) ordered that an investigation be undertaken to determine:

(a) The cost of construction delays at Limerick and whether those delays were reasonable; (b) The escalation of cost estimates for Limerick and whether those costs for the plant are reasonable; and (c) The eventual impact of Limerick on PEC0's capacity and reserve margins and the reasonableness thereof.1 The Commission staff, Philadelphia Electric Company, and the Office of Consumer Advocate were made parties to this investigation proceeding. The PUC stated, "We are opening this investigation proceeding so that information can be gathered in an orderly and expeditious manner, before PEC0 seeks to include Limerick in its rate base as used and useful property. This approach will enable us to proceed without the pressures of time associated with rate cases."

(Ibid.). On November 12,1980 (see Appendix B), the PUC amended this order to include three additional aspects in the investigation:

(d) What alternatives PEC0 considered at the time the decision was made to build the plant and the projected cost of each alternative.

(e) Could any currently available alternate sources of energy, conservation / load management activities, improvements in existing i

power plants' performance, etc., replace Limerick at a lower cost to the consumer assuming that:

(1) Expended costs are amortized over a reasonable period; or l (2) Expended costs are not amortized or collected from rate payers; or

( (3) Expended costs are shared among stockholders and rate l payers.

(f) The potential of large electric consumers directly buying the capacity and/or energy associated with Limerick.

1See the Order of October 9, 1980, issued by the Pennsylvannia Public Utility Commission, found in Appendix B.

At the conclusion of this investigation the PUC found that simultaneous con-struction of both Unit 1 and Unit 2 was not advisable. The Company was given  !

the option of either suspending or cancelling the construction of Unit 2. On )

August 7, 1984, the PUC instituted proceedings requiring PECO to show cause whether the completion of Limerick Unt 2 is in the public interest. Specifi-cally, the following issues were ordered to be examined (see Appendix B):

• Is construction of Unit 2 necessary for PEC0 to maintain adequate reserve margins?

• Are there less costly alternatives--such as cogeneration, additional conservation measures, or purchasing power from neighboring utilities or the P.J.M. interchange--for PECO to obtain power or decrease consumption?

• How will the capital requirements necessary to complete Unit 2 affect PEC0's financial health and its ability to provide adequate service?

• Should the Commission reject any securities filings, or impose any other appropriate remedy, to guarantee the cancellation of Unit 2?

• If Unit 2 is cancelled, what, if any, percentage of the sunk costs should PEC0 be permitted to recover from its ratepayers?

• If construction of Unit 2 is found to be in the public interest, should the Commission adopt an " Incentive / Penalty Plan" as an inducement to cost-efficient and timely construction?

The company promptly engaged in an expedited and quite comprehensive management decision process to compare the completion of Limerick Unit 2 with other prac-tical alternatives for supplying the required load to its customers. This pro-cess resulted in the identification of four alternative methods by which the Company.might provide electric service to its customers to meet the load and capacity requirements for the years 1985 through 2020:

• Base Case I: In this scenario, Limerick Unit 2 is completed, pro-viding 1055 MW of nuclear-fired capacity in mid-1990.

• Base Case II: In this scenario, Limerick Unit 2 is abandoned. It is replaced by two new coal-fired units constructed at the Chester site--

a 525-MW unit completed in 1994 and a 530-MW unit completed in 1995.

Power is purchased during 1990-1995 to meet otherwise unsatisfied need.

• Base Case III: In this option, the new coal plants at the Chester site are delayed until 1996 (for the 525-MW unit) and 2002 (for the 530-MW unit). Otherwise unsatisfied demand in the interim is met by extending the life of 617 MW of existing oil-fired capacity (Cromby-2, Delaware-7 & 8, Schuylkill-1). Again, Limerick Unit 2 is abandoned.

• Base Case IV: In this final scenario, the construction of new capacity in the decade between 1990 and 2000 is avoided. It is replaced by purchase of 1055 MW of power in 1994 from a utility located outside of the PJM Interconnection. The purchase is modelled at a price equal to the estimated cost of participation in a new coal-fired facility in a system in Ohio. Transmission facilities are built to carry the power; Limerick Unit 2 is abandoned.

1 The following chart summarizes the results of PEC0's analysis of the four base case studied:1 Philadelphia Electric Company Revenue Requirements 1985 Through 2020 (Million $)

Base Base Base Base Case I Case II Case III Case IV (Limerick (Chester (Oil Exten- (Purchase No. 2) Coal) sion/ Coal) Outside PJM)

Total Revenue Require-ments $393,559 $403,106 $407,012 $408,058 Revenue Require-ments Over Base Case I 9,547 13,453 14,499 The Company employed consultants in preparing this analysis and provided 21 witnesses for the hearing testimony. The complex analytical model and proce-dural sequences are shown in the flow chart of Figure 2. The Company's testi-mony regarded the quantitative analysis based on the modeling process of Fig-ure 2 as only a proxy for possible future outcomes; basically it was designed to structure and provide assistance to the decision-making process. This was complemented by sensitivity analyses to test whether changes in the more impor-tant inputs to the model (such as discount rates) will affect the result signi-ficantly enough to change the conclusion. The Company testimony stated the belief that there are many fewer uncertainties in continuing with the construc-tion of the duplicate Limerick Unit 2 (Base Case I) than in embarking on an entirely different project. A comparison of investment risks and uncertainties was made between this and the other base case options in the Direct Testimony (op. cit.) as follows:

" Base Case II, for example, requires that we site a multi-billion dollar coal-fired plant on the Delaware River in the heart of the Philadelphia i

urban area. The uncertainty regarding siting and permitting of a coal-fired plant at Chester, other sites in Southeastern Pennsylvannia, and elsewhere in the Commonwealth, gives management concern about the reli-

[

i ability of cost and schedule estimates. Our experience with as benign a project as a water inlet on the Delaware, and our observation of the problems of the City of Philadelphia in identifying an acceptable site or sites for waste combustion facilities, would give any responsible l management pause in reaching prematurely for such a solution.

l

15ee the Prepared Direct Testimony of V. S. Boyer and Dr. W. H. Hieronymus on L

Behalf of Philadelphia Electric Company, Respondent, before the Pennsylvania l Public Utility Commission, Limerick Unit No. 2 Nuclear Generating Station Investigation, Docket No. I-840381, Vol. 1, December 3, 1984.

i STFP 1: NEFI)S ANALYSIS STEP 2: t)ESIGN OPTIONS

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STEP 3: CAI,CULATE COST OF OPTIONS STEP 4: EVALUATE OPTIONS Figure 2 -- The analytical model developed by the Philadelphia Electric Company in evaluating options for meeting regional electricity demand for the period 1985-2020 and employed as an exhibit in the PUC show cause proceedings for Limerick-2 (Direct testimony of V.S. Boyer and W.H. Hieronymus, o,p_. ci t. )

" Base Case III provides only temporary relief and deprives us of signifi-cant insurance against the realistic possibility that our actual load in the 1990's will turn out to be on the high side of our median projections, and right in line with a number of other credible estimates. In effect, this option merely delays the problem until a later date.

" Base Case IV involves wide-ranging speculation as to the availability of water, sites and fuel at unidentified locations West or Southwest of the PJM area, and as to the feasibility of a unilateral effort by PECO to license, acquire rights-of-way for and construct one or more interregional tie lines to carry the power reliably to the Company's service area. In-deed, this approach might well be viewed as an attempt to impose our elec-tric generating siting problems into someone else's service area, a strategy which has been revealed as incurring much opposition in the case of regional solid waste disposal."

On December 5, 1985, the Public Utility Commission issued an order permitting the Philadelphia Electric Company to complete construction of Limerick-2 under special terms and conditions of cost containment and operating incentive plans (see Appendix B). PECO announced on December 23, 1985 that the Company's Board of Directors approved a decision to complete Limerick-2 under the PUC's terms.1 These terms included a total investment ceiling for Limerick-2 of $3.2 billion (of which $894 million has already been expended) and an operating incentive plan that involves an average annual capacity factor ordered by the PUC at 65%,

i 5%, subject to some adjustment.

The principal reason that Philadelphia Electric Company was willing to proceed s under a construction cost cap is that Unit 2 will duplicate Unit 1 and that de-sign of both units have been reviewed and approved by the NRC (Limerick SER, NUREG-0991).2 Further, the Company felt that the industry is in a period of regulatory stability (e.g., the recent issuance of the Backfit Rule) and there-fore the scope of construction of Unit 2 can be accurately predicted. Scope changes due to new or modified regulations should be minimum. Also, a favor-able development was the agreement entered into between the constructor (Bechtel Corporation) and the labor unions that prohibits strikes, lockouts, picketing and/or slow downs and contains a wage increase cap provision.

It is not wholly clear how much generality the Limerick-2 reactivation expe-rience lends to other possible construction reactivations for deferred or can-celled plants. Certainly there are notable differences, as well as similari-ties, between the statutory authorities provided by different states to their PUCs. Moreover, there are also important differences among utility owners of deferred or cancelled units as highlighted in Tables 1 and 2 regarding the construction progress of the units; the amount of onsite equipment; the licens-ing status of the units and the regulatory outlook for treating outstanding issues; the financial strength or weakness of the utility, its bond rating, and ability to borrow investment capital; and the suitability of the site (or other sites in the region) for constructing plants using alternative fuels.

However, it does seem clear that in a majority of the situations regarding deferred or cancelled units there is a need to meet the test of need-for plant 1"PE to Resume Limerick Work," Philadelphia Inquirer, December 24, 1985.

2 Letter of June 4,1986 to Harold R. Denton from G. Kent Dyekman, Chairman of the AIF Ad Hoc Group on Reactivation of Construction Projects.

in any reactivatism decision and to justify that the reactivation option is superior to alternatives for meeting the needed capacity or energy demand growth. To this extent, the PUC orders and PECO's analytical and other re-sponses to these orders holds potential relevance to other reactivation decisions.

i 4

4 1

1 1

4. IDENTIFICATION OF POSSIBLY RELEVANT SAFETY AND ENVIRONMENTAL ISSUES ARISING FROM SIGNIFICANT NEW INFORMATION 4.1 Safety Issues As noted in the discussions of Section 3, the mean CP issue date for the 35 LWR units with cancelled construction is about 915 years ago and for the 7 deferred units, more than 11 years ago. These lengthening years provide opportunity for significant new safety information to arise. There are basically two different sources of new safety information: (1) research programs directed to improved scientific information regarding safety phenomena associated with natural events, human factors, and engineering design features; and (2) analysis of the safety implications of failure / systems-reliability data from operating reactor experience in the United States and abroad. Regarding the second of these sources, Table 5 (reproduced from NUREG-1070) exposes the wide variety of docu-mentary sources of information from reactor operating failures of significance to understanding the nature and safety importance of the documented events.

Regarding new safety information resulting from research programs, of consider-able significance to the identification and assessment of importance of techni-cal issues in the reactivation of LWR projects is the Severe Accident Research Program (SARP). This ongoing program (NUREG-0900) has already developed a large body of information to improve understanding of the severe accident characteris-tics and risks of the current generation of light water reactors. The largest part of the SARP effort is dedicated to the better understanding of the physical phenomena of severe accidents and the staff's ability to model these phenomena in estimating severe accident behavior. This improved modeling capability is used in a number of ways, most notably in revised estimates of what radioactive materials are actually released to the environment in any identified severe accident sequence. The SARP also contains a substantial effort to examine all available data sources, especially the many detailed PRAs now available, to identify the important accident sequences for each class of reactor.

Especially since the TMI-2 accident, there is a common interest in the interna-tional sharing of safety information obtained from research and operating reac-tor experience with a view to reducing severe accident risk. To this end the Committee on the Safety of Nuclear Installations (CSNI) of the Nuclear Energy Agency (NEA) has undertaken a program to promote the sharing of technical infor-mation in this field. Areas of special concern include the thermal hydraulic behavior (both in-vessel and ex-vessel) of severe accident sequences, source term and fission product behavior, hydrogen and other gases, steam explosions, containment response, emergency instrumentation and equipment, and various aspects of short-term and long-term accident management.

Most of the backfits to operating plants or those engaged in the near-term operating licensing process (NT0Ls) have resulted from the TMI-Action Plan (NUREG-0737). Over 85% of the Commission-approved TMI Action Plan items have now been completed. Thus, any reactivated construction of cancelled or defer-red units could benefit from insights on technical issues involving desirable or required backfits made on behalf of the TMI Action Plan or other NRC require-ments or notifications from the backfitting or design amendment experience of other units of similar vintage and design. In a number of instances for defer-red or cancelled plants, the relevant experience has already been gained from the construction of a twin unit on the same site. On some of the more recently cancelled or deferred plants, some of the TMI Action Plan items will already have been made or planned for. It should be noted that many of the TMI Action

Table 5. Documentary sources of information to understand the nature and importance of new LWR safety experience

• e Operating Reactors Licensing Actions Summary (NUREG-0748) e IE Bulletins (8 in 1983) e IE Information Notices (84 in 1983) e NRR Generic Letters (41 in 1983) e AE00 - review licensee event reports (about 4500 per year) e AE00 published case studies (several per year) e AE00 published engineering evaluations (30 in 1983) e AE00 published techical review reports (41 in 1983) e AE00 published Power Reactor Events Reports (6 per year, NUREG/8R-0051) e Report to Congress on Abnormal Occurrences, NUREG-0090 (12 per year) e NRC monthly status report to Congress (Bevill report) e Miscellaneous NUREGs; case-related hearing testimonies, transcripts, etc.

e Plant-Specific PRAs e Foreign event information e INP0 SEE-IN Program (56 O&M reminders, 87 SERs, and 9 SOERs in 1983) e INP0 NPRD system (40,000 component reports in 1983)

• Resulting from experience of failures in equipment and procedures during i nuclear power plant construction, operation and maintenance.

Legend:

AE00 - The NRC Office of Analysis and Evaluation of Operational Data IE - The NRC Office of Inspection and Enforcement INPO - Institute of Nuclear Power Operations NPRD - Nuclear Plant Reliability Data (System)  !

NRC - Nuclear Regulatory Commission l

PRA - Probabilistic Risk Assessment that mathematically quantifies an expected l (or average) risk based on observed and calculated component and human failure rates and the anticipated consequences associated with these failures, which may occur either singly or in combination SER - Significant Event Report SOER - Significant Operating Experience Report Plan items involve changes in operating, maintenance, and accident management procedures rather than hardware change which comprise only about 30% of the different types of TMI action items (NUREG-1070, p. 100).

Moreover, it should not be assumed that the outcomes of the Severe Accident Research Program will necessarily have negative safety implications requiring backfits. In the face of broad ranges of uncertainty surrounding PRAs or other risk estimates, there sometimes has been a tendency to use, in the interest of safety prudence, conservative modelling assumptions or sizeable margins of con-servatism in equipment design. Thus, some of the research results may lead to new requirements while still others may reduce design requirements that have been overstated (NUREG-1175). Information regarding the Unresolved Safety Issue (A-49) involving the phenomena of Pressurized Thermal Shock (PTS) for cer-tain PWR reactor vessels has had downgraded significance as a result of research effort, provided that the affected types of reactor vessels can be demonstrated to meet a so-called " Pressurized Thermal Shock Screening Criterion" which is related to the fracture resistance of these reactor vessels. Another important set of safety issues involves piping cracks, piping supports, and leak-before-break criteri'a in severe accident progression phenomena. Recent operating events and research data in both the United States and foreign countries had led the NRC to initiate a comprehensive review of NRC requirements in the area of nuclear piping. The goal of such a review is to determine whether our cur-rent requirements should be modified. This could lead to increasing require-ments in :;ome areas and decreasing requirements in others. The NRC Piping Re-view Committee work, covering the aread of BWR Stress Corrosion Cracking, Seismic Design, Potential for Pipe Breaks, anJ Dynamic Loads and Load ~Combina-tions, has been completed and reports on each major area have been published.1 Still another example of how research progress has aided NRC's regulatory approach in dealing with generic operating problems relates to General Design Criterion 4 as implemented in conjunction with the definition of a Loss-of-Coolant-Accident (LOCA). In applying this regulation, a double-ended-guillotine break (DEGB) of the largest reactor coolant pipe has been postulated as design basis for containment, Emergency Core Cooling System (ECCS), and equipment qualification, as well as requiring protective devices (e.g. , pipe whip restraints, and jet impingement shields) against the dynamic effects of such a postulated break. As a result of the advancement of the fracture me-chanics technology, we are able to demonstrate by analyses that the probability of DEGB is extremely low for PWR main-loop piping and that the most likely failure made of these pipes is " leak-before-break"; i.e. , there will be a period of stable crack growth, not a sudden, " double-ended-break."

With regard to BWR pipe intergranular stress corrosion cracking (IGSCC), the AEC/ Regulatory staff shut down all operating BWR plants in 1975 because of cracks discovered in some of the 4-inch by pass lines in recirculation loops.

The same phenomenon was discovered in large recirculation pipe (up to 28-inch lines) in 1982 and 1983. The NRC mandated augmented inspections of plants scheduled for fueling in 1982 and 1983. The contrast here is that the NRC did not immediately shut down all plants for more severe, extensive cracking by the same degradation phenomenon. This is principally due to better understanding of the flawed pipe behavior under design basis loadings. However, IGSCC remains as one of the more salient BWR issues affecting piping and other components of 1 Report of the U.S. Regulatory Commission Piping Review Committee, NUREG-1061, U.S. Nuclear Regulatory Commission (April 1985).

the reactor internals as are certain issues in the halting of ATWS events (Anti-cipated Transients Without Scram). Diversity and reliability of Decay Heat Removal Systems and related Station Blackout issues (USIs A-45 and A-44) remain I of troublesome concern and may or may not lead to changed design requirements  !

for either BWRs or PWRs with further research and analysis. Sabotage and fire protection plus containment integrity issues--especially containment response to different scenarios of core melt accidents--are also of continuing concern for research and review efforts. On the other hand, there has been.a downgrad-ing of the perceived importance or need for further design changes beyond those I already in place in the rules regarding such issues as steam explosions and turbine missiles, certain aspects of hydrogen control, and a number of other generic safety issues and unresolved safety issues that have been investigated.1 Improvements in PRA methodology and the data inputs to these quantitative risk assessments are a major focus of the Severe Accident Research Program since the wide uncertainty bands of PRAs are a source of instability in determining needs for increased or relaxed requirements for design features or operating and maintenance procedures of LWRs. There are a number of reasons for this broad range of uncertainty in core-melt frequency estimations, arising both from the uncertainties in the assessment of risk for a specific plant and the uncertainties in extending a risk assessment of one plant to other plants simi-lar in design. The reasons for uncertainty include inherent difficulties in generically predicting the probability of a severe reactor accident: the con-siderable variability in the design features of existing LWRs; quantification of human error frequencies; common-cause failure mechanisms of multiple safety features; incompleteness in describing accident ' initiators (e.g., difficulty in including sabotage); assumptions made for success / failure criteria and for re-covery actions; and the estimation ~of the recurrence frequency of external events such as very high intensity earthquake, fires, hurricanes, and floods, With this backdrop, the SARP integrating elements--the Accident Sequence Eval-uation Program (ASEP) and the Severe Accident Risk Reduction Program (SARRP)--

have been using and extending available PRA data to assess present LWR risk from severe accidents, the impact of uncertainties, and the cost-effectiveness of plant changes to reduce risk (or to reduce uncertainty in risk estimations).

ASEP work to date indicates that a relatively small set of important accident sequences is probably common to many LWRs. However, it is very difficult to quantify their frequencies generically because of considerable variation in plant design. Risk studies performed to date indicate that the risk of any particular plant not yet explicitly studied could deviate significantly from the estimated risk of plants of similar design because of unique plant-specific design and operating characteristics.

The conclusion drawn from these research findings is that the safety technical issues for each of the cancelled or deferred LWR units of Tables 1 and 2 cannot be determined from generic analysis alone, but more importantly would be deter-mined principally by a plant-specific, systematic safety examination to deter-mine what particular accident vulnerabilities are present and what cost-effective changes are desirable to reduce them. This approach has become a cornerstone of NRC's Severe Accident Policy for dealing with any severe accident issues relating to the wide variety of LWR designs among operating reactors (NUREG-1070, p.19):

ISee, A Prioritization of Generic Safety Issues, NUREG-0933, December 1983,

g. seq.

• Recognizing that plant-specific PRAs have yielded valuable insights to unique plant vulnerabilities to severe accidents leading to low-cost modi-fications, licensees of each operating reactor will be expected to perform ,

l a limited-scope, accident safety analysis designed to discover instances (i.e., outliers) of particular vulnerability to core melt or to unusually poor containment performance, given core-melt accidents. These plant-specific studies will serve to verify that conclusions developed from in-tensive severe accident safety analyses of reference or surrogste plants can be applied to each of the individual operating plants. During the next two years, the Commission will formulate a systematic approach, in-cluding the development of guidelines and procedural criter,ia, with an ex-pectation that such an approach will be implemented by licensees of the remaining operating reactors not yet systematically analyzed in an equiva-lent or superior manner.

Many of the plant-specific PRAs have stimulated the licensees performing them to take corrective actions, either during the study or after the results were evaluated. To a large extent these modifications were implemented voluntarily by the utilities in an effort to correct weaknesses in their plants. Moreover, the resulting changes in equipment design and operating and maintenance proce-dures to reduce the uncovered severe accident vulnerabilities to an acceptable level were accomplished with relatively minor cost (NUREG-1070, pp. 123-131).

Some of the new safety information of possible relevance since the CP was issued for cancelled or deferred plants may involve environmental rather than design factors per se. This could--but probably infrequently will--include significant site-related safety information regarding: earthquake faults or new data bear-ing on the likelihood of high-intensity seismic events, meterological or flood data, and newly developed (or discovered) external hazards relating to proximal transportation systems involving hazardous chemicals or explosive substances, etc. The safety significance of any such newly developed information will need to be evaluated to determine what cost-effective changes, if any, are desirable.

4.2 Environmental Issues Significant new information bearing on environmental issues will have varying levels of importance in accordance with the situation of whether the Construc-tion Permit is still valid or not. This matter primarily affects those LWR units on the list of plants with cancelled construction since a majority of these have, or will have had, their cps cancelled. The expectation is that plants having cancelled cps would be required to reapply for a new CP, an action that would require updated environmental information and new environmental hearings on any contested issues.

Contested issues can almost assuredly be expected to arise in any new environ-mental hearings for any such reactivated projects regarding such issues as l

need-for planti and the cost-benefit analysis of alternative sources of energy for generating the proposed capacity addition of the reactivated unit. Both of these could prove to be difficult issues in light of the changed trends in electricity demand growth and construction and fuel costs including factors of uncertainty in their future projection. Regulatory uncertainty, as it could affect estimated construction completion schedules, would likely be an important issue related to the cost-benefit analysis of energy options. Any future devel-opments in reducing significantly the cost of presently non-conventional energy sources could also become an issue for some sites, depending on the inherent uncertainties of such technological progress and the length of the future date at which a utility might resubmit a CP application. It is to be noted that a Commission Final Rule on "Need for Power and Alternative Energy Issues in Opera-ting Licensing Proceedings" (10 CFR Part 51, September 1, 1982) generally fore-closes the reopening of both need-for plant and alternative energy issues at the OL stage of licensing.

In the case of LWR reactivations with cancelled cps, it appears likely that it will be easier to defend against need-for plant hearing issues the longer the delay in the reactivation decision as reserve margins dwindle and if, as some believe, electricity demand growth rates of 3% or 4% per year are sustained over a longer period, thus weakening the supportability of growth rates of 1 to 2%

per year that are now rather commonplace assumptions. Likewise, in 5 or 10 years from now, it may be easier to defend the credibility of regulatory sta-bility and the realism of shortened construction schedules and more effective management of construction quality and cost, assuming progress on these accounts by plants still under construction or possibly a new plant with a certified design- perhaps a new standard design using the Advanced LWR envelope design criteria developed by the current ALWR project of EPRI.2 There are, of course, other possible environmental issues that may need to be treated whether a reactivated unit has a cancelled CP or not. These could arise from significant new information or changes in local, State or other Federal (i.e., non-NRC) regulations. The latter might involve additions to the lists of endangered species, historic landmarks, wild or scenic rivers, etc.,

or possibly changes in water or air quality control regulations or regulations affecting noise, dust, aesthetic intrusions, etc. Any new court rulings on the validity or implementation adequacy of old regulations or review practices could portend a significant change in the treatment of environmental issues, but this is a questionable prospect. Significant changes in area demography and land or water uses beyond those projected at the time of CP issue could yield increases in environmental impacts.

1"Need-for plant" is quite similar to the term "need-for power" in that both terms encompass issues of projecting electricity demand growth. However, need-for plant is technically broader in scope in that it includes the prospect that a significant component of need might arise from the retirement from the utility's generating capacity of obsolescent or high operating-cost units.

Need-for plant also focuses more on need for baseload capacity as distinct from peaking capacity. However, as terms of art, the two terms are often used synonomously as implying the fuller scope of analytical and forecasting issues dealt with in the question of the need for added baseload capacity of x amount by y years in the future including the option of purchasing power.

2 John J. Taylor, " Reopening the Nuclear Future", EPRI Journal (March 1985),

pp. 2-3.

There is also the possibility that alternative siting issues might be reinstated as hearing contentions for at least some of the possible LWR project reactiva-tions where the CP has been cancelled. As in the case of need-for plant and alternative energy issues, the Commission has adopted a Final Rule on "Alterna-tive Site Issues in Operating Licensing Proceedings" (10 CFR Part 51, Septem-ber 1, 1982) that provides for NEPA purposes alternative sites will not be con-sidered in operating license reviews for nuclear powr plants and need not be addressed by operating license applicants in their environmental reports sub-mitted to the NRC at the operating license stage.

The treatment of alternative siting issues at the stage of reapplying for a new CP (as is expected to be required for all LWRs with cancelled cps) will be more tractable or more difficult in accordance with the kinds and importance of any significant new information noted above. Included in the rationale for imposing the Commission's Final Rule on alternative siting issues at the OL licensing stage is the following statement (46 FR 28630, June 29, 1981):

Construction is usually about 35-65 percent complete at this time (depend-ing upon the number of units to be built at the site) and a corresponding portion of the total construction costs have already been incurred. Major construction related environmental impacts have already occurred at the site and by the time the staff has completed its review of the application and the operating license hearings begin, the plan will be even further along. Given this factual background, the Commission cannot readily con-ceive of a situation where new information concerning the proposed site could be of such significance as to tilt the cost-benefit balance in favor of an alternative site. (In any event, 10 CFR 2.758 of the Commission's regulations would permit an exception to or waiver of the rule in particu-lar cases if special circumstances are shown.)

It is noted that none of the deferred units have cancelled cps (although one has less than 35% construction) and only five of the units with cancelled con-struction (Table 1) have construction progress of 35% or more: Marble Hill-1&2, Zimmer (now mooted), Yellow Creek 1, and Hartsville-A1. Three others on this list have construction progress in excess of 20% (WNP-4, 24%; Phipps Bend-1, 29%; and Hartsville-A2, 34%). These three units and seven additional units with construction progress between 3% and 17% (WNP-5, Phipps Bend-2, Yellow Creek-2 and Hartsville-B1 & B2) still have onsite equipment with acquisition value in excess of $100 million. It should be noted that in the long number of years since this equipment was purchased, inflation will have increased quite substantially its replacement value.

In support of the Final Rule on removing siting issues at the OL licensing stage, it was further stated that "the Commission finds that new information at the l operating license stage is very unlikely to upset the prior conclusions concern-1 ing alternative sites." There is some basis for believing this conclusion may still prove relatively valid for many of the LWRs with cancelled construction in the event that interventions on alternative siting issues are introduced in new CP hearings for reactivated projects among this group. The staff has suc-cessfully dealt with alternative siting contentions and related environmental impact issues for a large number of licensing actions with a strengthened methodological approach (NUREGs-0398, -0499, -0625, and -0701). Moreover, the construction and operating environmental impacts (with appropriate mitigative measures) are observed to have been relatively minimal.

l

l S. IDENTIFICATION OF REGULATORY OR POLICY ISSUES OF POSSIBLE RELEVANCE TO THE ADEQUACY OF EXISTING RULES AND POLICIES OR THEIR NEED FOR REVISION i The discussion in Section 4 suggests that existing rules, policies, and staff i review practices would appear to be auequate to deal with those safety or envi- l ronmental issues arising from significant new information, insofar as it is possible to foresee such emergent issues using currently available information.

However, the proper regulatory issue in these cases is not so much a matter of whether present rules, policies, guidelines and regulatory procedures will prove to be adequate, but what modifications of these could improve the cost-effectiveness in the use of NRC and industry resources in treating these issues if, and whenever, these arise in the course of LWR reactivations and their treatment. Also at issue is whether a more stable regulatory outlook can be achieved that would encourage or facilitate LWR reactivation in the public in-terestl rather than certain features of the present regulatory regime which might inadvertently serve as unnecessary deterrents or encumberments to reacti-vation decisions and related implementation processes. The discussion to fol-low in Section 6 will identify candidate regulatory options relating to these two regulatory issues and propose decision criteria for their evaluation.

The AIF Ad Hoc Group on Reactivation Projects holds the view that existing NRC rules and policies are adequate to deal with significant new information and is understandably concerned about the possibly destabilizing effects of any changes in rules and policies:

"In planning for reactivation, a utility must be certain of what will be required. The possibility of change, even that which could be cost-beneficial, creates uncertainty which discourages reactivation. Such potential changes should be avoided unless they have been fully reviewed by the industry and endorsed as being cost and safety beneficial."2

, Several things need to be said regarding this concern about the uncertainties and potentially destabilizing effects of changes in rules, policies, regulatory guidelines, and review and inspection procedures that are directed to improving the cost-effective use of regulatory and industry resources:

(1) The time elapse between the project cancellation or deferral dates and project reactivation could stretch from 5 to 10 or more years until need-for plant strengthens and the financial and political climate improves sufficiently to warrant a reactivation decision for some of the units (others might be reactivated sooner).

(2) During a period of such duration, NRC, in its ongoing efforts to imp' rove its regulatory effectiveness, will possibly have introduced a number of changes in its rules, policies, guidelines, etc. (in-cluding some directed to treating significant new information) that may hold implications for reactivation issues and decisions even if these changes are not principally oriented to this purpose.

1See " Declaration of Purpose," Energy Reorganization Act of 1974, (Sec. 2a);

and the thoughtful discussion of the public interest by Lynn E. Weaver, "The Outlook for Nuclear Power: Is it still an energy option in the United States?"

Nuclear News, August 1984, pp. 108-112.

2 Letter of June 4, 1986 to Harold Denton from G. Kent Dyekman, Chairman of the AIF Ad Hoc Group on Reactivatior of Construction Projects.

(3) Cases in point include the recently issued Severe Accident Policy Statement (NUREG-1070 and 50 FR 32138), the Backfit Rule (10 CFR Part 50.109) and other current initiatives discussed in Section 6.

The Severe Accident Policy and Backfit Rule hold implications for reactivation issues and decisions and, although these did not wholly eliminate regulatory uncertainty, these changes were generally re-garded by industry as contributing to, rather than detracting from, regulatory stability.

(4) The least regulatory uncertainty generally exists whenever detailed prescriptive design and operational requirements are provided; regu-latory uncertainty exists whenever flexibility of interpretation is permitted when safety or environmental requirements and review pro-cedures are stated in general, non-specific terms. However, it is felt that a shift away from detailed prescriptive requirements (see below) toward performance criteria is a more cost-effective approach in assuring protection of public health and safety as well as environ-mental values despite the regulatory uncertainties this introduces during the period of transition.

(5) As noted in Section 3, the mean CP issue date for the 35 units with cancelled construction is January 1977 and for the 7 deferred units, May 1975. If reactivation decisions for some of these units might not come (if at all) until the period 1991-1996, this would repre-sent a time lapse of 14 to 21 years beyond the CP issue date. It is not difficult to believe that in the intervening years much tech-nical and scientific knowledge will have been gained from worldwide research efforts and nuclear power plant operational data that would be of value in improving the cost-effectiveness of industry's safety and environmental protection practices as well as present a need for NRC to revise its rules, policies, guidelines, etc. to yield the societal benefits made possible by these expanding information resources.

(6) It has been NRC's practice before ruling on proposed changes in its regulations and policies of major importance to publish them invit-ing public comment, thus providing opportunity for industry to com-ment on their implications for cost-effective improvements and re-gulatory stability. The benefits of many of the results of our re-search programs and insights from reactor operating data are made available to improve industry practices and regulatory review and inspection procedures through reports, generic letters, revisions in guidelines and standard review plans, etc. Often these provide l flexibility of implementation without recourse to changes in rules or l policies with their attendent uncertainties.

It is noted that Section 4 only examined the outlook for reactivation issues arising from significant new information affecting safety or environmental impact concerns. In this section, it is important to identify the family of technical and regulatory issues not necessarily involving new information but which relate to regulatory concerns over the adequacy of " routine" maintenance procedures for onsite (and offsite) equipment still assigned to plants with cancelled construction (Table 1) having no current I&E inspection, and the ade-quacy of Equipment Preservation Programs of the utilities and the inspection procedures of I&E for equipment assigned to deferred plants (Table 2). In this exploratory effort, no attempt was made to obtain detailed information on the i

maintenance or equipment preservation programs of the applicable utilities nor of I&E inspection procedures for the equipment of deferred units. Nevertheless, past experience is sufficient to identify certain maintenance issues relating to the storage or preservation of both nuclear and non-nuclear equipment under i a range of environmental conditions and preservation practices. Although there

, have been NRC-sponsored workshops on nuclear power plant aging and contracted research or research plans dealing with nuclear plant aging (NUREG/CP-0036, j

NUREG/CR-4144, and NUREG-1144), the main thrust of this effort is toward aging and related wear issues of equipment of operating plants under more or less normal operating environments. There does not appear to have been any similarly focused research studies by NRC or other institutions or agencies devoted to the objective, for example, of assigning prioritizations in the cost-effective application of maintenance and inspection resources to pre-operational storage conditions (including the variations of temperature, moisture, dust, and possi-ble corrosive environments1 ) associated with past and present warehousing or mothballing practices of the cancelled or deferred plants included in this study

! scope.

i' Quality Assurance (QA) criteria are provided for in Appendix B of 10 CFR Part 50.

As defined in these rules, quality assurance comprises all those planned and 4

systematic actions necessary to provide adequate confidence that a structure, system, or component will perform satisfactorily in service. Quality assurance j includes quality control, which comprises those quality assurance actions re-i lated to the physical characteristics of a material, structure, component, or

{ system which provide a means to control the quality of the material, structure, l component, or system to predetermined requirements.

j The applicant is required to establish a quality assurance program that docu-ments by written policies, procedures, or instructions and is to be carried out j throughout plant life in accordance with those policies, procedures, or instruc-

! tions. The applicant shall identify the structures, systems, and components to be covered by the quality assurance program and the major organizations parti- -

cipating in the program, together with the designated functions of these organi-zations. The quality assurance program shall provide control over activities l affecting the quality of the identified structures, systems, and components, to ,

an extent consistent with their importance to safety. Activities affecting quality shall be accomplished under suitably controlled conditions. Controlled

, conditions include the use of appropriate equipment; suitable environmental ,

l conditions for accomplishing the activity, such as adequate cleanness; and l i assurance that all prerequisites for the given activity have been satisfied.

! The program shall take into account the need for special controls, processes,

! test equipment, tools, and skills to attain the required quality, and the need for verification of quality by inspection and test. The program shall provide for indoctrination and training of personnel performing activities affecting j quality as necessary to assure that suitable proficiency is achieved and main-l tained. The applicant shall regularly review the status and adequacy of the quality assurance program. Management of other organizations participating in the quality assurance program shall regularly review the status and adequacy 1

of that part of the quality assurance program which they are executing. ,

{ 1Research on air pollutants causing acid rain, for example, might suggest that,

although regional pollutants of these kinds (being quantitatively small) might I

not have any significant corrosive impact on warehoused or outdoor mothballed equipment over only a few years, these corrosive elements possibly could have i significant impact over an extended period such as 8 to 12 years or more.

i

Moreover, the quality assurance rules require that measures shall be established to control the handling, storage, shipping, cleaning and preservation of mate-rial and equipment in accordance with work and inspection instructions to pre-vent damage or deterioration. When necessary for particular products, special protective environments, such as inert gas atmosphere, specific moisture content levels, and temperature levels, shall be specified and provided. Additional requirements of current NRC requirements for quality assurance and control pro-cedures include organization; design control; test control; inspection programs; audits; corrective actions; quality assurance records; and document control relating to procurement and documented instructions, procedures, or drawings appropriate to activities affecting quality including appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

An examinatior, of Appendix B (Part 50) reveals that the quality assurance and quality control procedural criteria are cast in very general terms and make no specific references to any special QA/QC circumstances that might arise from unusually prolonged periods of maintenance or equipment preservation that are being encountered for deferred LWRs or the possible reactivation of cancelled units. Indeed, the QA regulations were drawn up well before such cancellations and deferred construction of such large numbers of LWRs could have been antici-pated. Thus, there is cause to re examine the adequacy of these current QA re-gulations to deal with the sorts of safety issues that seem pertinent to the current situations of maintenance, inspection, and other measures of QA/QC that could affect the regulatory reviews of any reactivations of deferred or can-celled LWR units and the safety acceptability of this equipment or corrective measures.

What, then, are the regulatory questions or issues of possible significance to the adequacy of existing rules or practices or the need for modified rules and practices to achieve cost-effective measures for equipment maintenance and quality preservation? A preliminary list might include:

(1) Which equipment (e.g., as determined by advances in severe accident risk assessment) is in greatest need of maintenance preservation measures and which is of low or insignificant priority?

(2) What ranges of environmental stresses (e.g., moisture, temperature, mildew, dust or other air pollutants) that may be encountered in mothballing or warehousing practices are the most threatening to quality assurance of the priority equipment identified in item I?

(3) What possible stochastic events (e.g., vagrant or rodent activity, wind-blown missiles, fire, flooding, etc.) could damage equipment or violate protective coverings exposing equipment to deleterious environmental conditions?

(4) What does the length of equipment storage period signify for the severity of the QA/QC issues identified in items 2 and 3?

(5) How effective are presently used QA inspection and auditing techniques and preoperational or start-up testing methods in uncovering inadequate main-tenance practices and the state of corrosion, damage, or other quality deterioration of the safety prioritized equipment?

(6) What are the most cost-effective methods of dealing with the above issues and what should be the roles of NRC and industry in identifying and encouraging the use of the best available practices?

(7) If some of the above issues are relatively unimportant, is there adequate information available to support this judgment?

Information that would shed adequate light on the above QA/QC issues might not yet exist in organized and readily availabls form to resolve the regulatory issue of whether existing NRC rules, policies, or review practices are appro-priate ir dealing most effectively with these issues or whether an improved regulatory regime is desirable and what specific form the improvements should take. The mothballing experience of the U.S. Naval Sea Systems Command would appear to yield substantial relevant information but the classified nature of the documents would evidently be a barrier to its dissemination and use.

Staff resources permitting, another source of potentially useful information could be the growing volume of inpection and auditing experience of NRC's Office of Inspection and Enforcement. The following selected features of NRC Inspection Procedure 92050 issued on January 1,1983 on " Review of Quality Assurance for Extended Construction Delay," suggest the possibility of pro-viding organized information that could improve the cost effectiveness of both industry and NRC practices regarding equipment preservation, inspection and auditing:

• QA procedures to meet inspection requirements are based on a current list that identifies the location, storage level, and preventive main-tenance requirements of all safety-related equipment and. materials.

• I&E observations of QA/QC work require initial selection of four representative safety-related items that are sorted / retained at the site and, if applicable, an appropriate sample of off-site locations.

(Inspection every 6 months).

I&E observations include inspection of protective coverings and coat-ings: cleanliness preservation; weather protection; fire protection; rodent protection; protection against unauthorized site intrusion; and preventive maintenance requirements established for safety-related activities.

Review of QA records for the four selected representative safety-related items.

Inspection guidance provides for flexibility in scope and frequency of audits /surveillances.

l

• The licensee's QA plan should include provisions for additional mea-l sures if duration of construction delay exceeds the time previously established. (Different preservation requirements may be necessary if storage time is significantly increased.)

• Much of QA program for extended construction delay is expected to be similar to that for active construction but additional surveillance procedures would be expected. (If construction is over half completed, quarterly inspection may be required).

• QA/QC requirements will vary from site to site depending on construction status and environmental factors such as temperature variations, atmo-spheric pollution, or proximity of site to salt water.

• Sample selection for I&E observations should reflect the importance of the " activity" to safety; the detection of unusual conditions would warrant additional observation or evaluation.

• Preventive maintenance should include periodic exercise of valves and rotating machinery; lubricants and dessicants changed as appropriate.

• The listing of equipment "important to safety" requires ' updating during construction suspension.

Similarly, the consolidation and sharing by industry of its collective experi-ence could provide useful information on effective / ineffective preservation practices and examples of environmental stresses, etc. leading to undesirable quality deterioration of equipment. In general, it can be expected that non-metallic components such as gaskets, "0" rings, valve gland packing materials,

~

greases, electrical insulation materials, etc., may deteriorate over extended periods even in environmental conditions not regarded as extreme. Suggestions for improved industry sharing of information are provided in NUREG/CR-444F (p. xi).

3

-)'

r

/

l 6. REGULATORY OPTIONS AND DECISION CRITERIA l 6.1 Decision Crite-ia and Regulatory Purposes Guiding LWR Reactivation Policy Development In the period since the Construction Permits were issued for the LWRs listed in Tables 1 and 2 with deferred or cancelled construction, a great deal of reactor operating experience and research findings have been generated increasing our knowledge of the safety and environmental effects of numerous plant designs in l

a variety of environmental settings with diverse site characteristics. Substan-tial progress has been made in the assimilation of these findings in improved risk assessment and environmental impact methodologies and further advances can be expected in the next several years, especially in risk assessment deriving from the Severe Accident Research Program and the independent efforts of indus-try and other individual and programmatic efforts.

At the same time, the NRC has sought to improve its regulatory effectiveness through policy developments and rule changes, some of which have recently been accomplished or that may be expected to be completed in the next several years.

Holding special significance for policy development regarding LWR reactivation are the recently issued Commission Severe Accident Policy Statement (NUREG-1070 and 50 FR 32138) and the revision of the rule on backfitting (10 CFR Part 50.109).

Further policy developments are in progress relating to safety goals (NUREG-0880, Rev. 1), reassessment of methods for estimating severe accident source terms (NUREG-0956), and probabilistic risk assessment of severe accident consequences (NUREG-1050 and NUREG-11501).

Because of these recent and pending developments of policies, rules and safety review procedures, it is fair to state that our regulatory regimen is in a state of transition. In general, these changes are intended to reflect:

A shift away from detailed prescriptive requirements toward performance criteria consistent with NRC's primary responsibilities to assure protec-tion of public health and safety as well as to protect environmental values; The carrying out of regulatory activities in a manner which recognizes that licensees have the primary responsibility for achieving safe opera-tion of nuclear facilities; and

• The principle that, in conformance with NRC's extant rules, policies, and understanding of safety vulnerabilities gained through operational experi-

ence data and research, the vendors and permittees or licensees are per-mitted a substantial flexibility to search for and select the most cost-effective approaches in the design, construction, operation and mainte-nance of nuclear power plants to satisfy NRC safety goals 2 and require-ments and to protect environmental values subject to NRC regulatory review and dispository action consistent with our statutory authorities ard responsibilities.

1This study (in draft) will develop base-line assessments of severe accident risk for a spectrum of typical LWR plant and containment designs for regulatory applications including implementation of the Severe Accident Policy.

20n June 19, 1986, the Commission approved a Safety Goal Policy Statement and ordered its publication in the Federal Register; this is regarded as a first i step in an ongoing process of related policy developments.

1 1

Within this developing framework of regulatory philosophies and principles, the following purposes or objectives are proposed to guide the formulation of an LWR Reactivation Policy:

(1) To achieve improved stability and predictability of reactor regulation in a manner that would encourage optimal utility choices of LWR reactivation options in keeping with the public interest; (2) To clarify the regulatory procedures and requirements for cost-effective equipment preservation and site stabilization programs, as appropriate, for those LWR units with cancelled or deferred construction where the pos-sibility of LWR reactivation cannot wholly be ruled out, especially where significant (onsite) equipment still remains that could be used in reacti-vation projects at the same or other sites; (3) To develop a strategic, integrated plan to improve and implement a regu-latory process that would deal most effectively with the variety of regu-latory issues envisioned for the differing circumstances and conditions of any reactivated LWR projects either in the near- or long-term regarding the CP or OL licensing phases of project reactivation; (4) To avoid imposing any unnecessary burden of information, analytical effort, or commitment of other industry or regulatory resources on behalf of any regulatory objectives that have only marginal or dubious value for protect-ing the public health and safety, the common defense and security, and the environment; and (5) To ensure that NRC's review process will continue to provide appropriate access for the expression of the public's safety and environmental con-cerns associated with LWR project reactivations.

The above regulatory philosophies, purposes, and objectives would serve to guide the formulation of a reasonable set of regulatory options in the initial phase of an orderly decision process. Even before the analysis of these options should proceed, it is also desirable to establish the decision criteria by which the regulatory effectiveness of the options will be evaluated. For the identi-fication of an appropriate set of decision criteria will establish the kinds of information that needs to be assembled for the analysis. For example, some advance thought as to what decision criteria would be appropriate was instru-mental to the formulation of the conceptual model of Figure 1 and the matrix content of Tables 1 and 2.

However, the parameters encompassed in these tables and chart do not alone suggest a sufficient set of information in meeting the needs of decisionmaking relative to a choice of regulatory options. As discussed in Section 4, there is a need, in the reactivation of LWR projects, to consider whether certain backfits might be required as a result of significant new safety or environmen-tal information that developed subsequent to the CP issue date. Unless these backfits have been mandated by subsequent rule changes, a determination of their requirement is subject to the procedures and criteria established in NRC's new Backfit Rule (10 CFR Part 50.109). In this Rule, backfitting is defined as the modification of or addition to systems, structures, components, or design of a facility; or the design approval or manufacturing license for a facility; or the procedures or organization required to design, construct or operate a facility; any of which may result from a new or amended provision in the Commission rules or the imposition of a regulatory staff position interpreting the Commission rules that is either new or different from a previously applicable staff posi-tion after: (i) The date of issuance of the construction permit for the facil-ity for facilities having construction permits issued after October 21, 1985; or (ii) Six months before the date of docketing of the operating license appli-cation for the facility for facilities having construction permits issued before October 21, 1985; or (iii) The date of issuance of the operating license for the facility for facilities having operating licenses; or (iv) The date of issuance of the design approval under Appendix M, N or 0 of this part.

The reference dates thus established for applicability of the Backfit Rule apply in different ways to the lists of LWRs in Tables 1 and 2 having deferred or cancelled construction. Those requiring a new CP to be issued would be affected by provision (i) since all of these would come after the cut-off date of Octo-ber 21, 1985. Those LWRs having still-valid cps issued before October 21, 1985 and having docketed their OL applications (i.e., eight LWRs with cancelled con-struction aad all of the deferred LWRs), would benefit to varying degrees from the exemption dates of provision (ii). However, some of the other LWRs might benefit from reduced backfitting requirements if they are duplicate, replicate, or standard reference designs that would qualify them under provision (iv).1 One deferred LWR (WNP-3) and 19 cancelled LWRs fall into one of these categories under the Standardization Policy.

For those future LWR reactivation projects to which the Backfit Rule would apply, the relevant decision criteria are set forth in general terms in Sec-tion (a)(3) and in more specific terms in Section (c) as follows:

(a)(3) The Commission shall require the backfitting of a facility only when it determines, based on the analysis described in para-graph (c) of this section, that there is a substantial increase in the overall protection of the public health and safety or the com-mon defense and security to be derived from the backfit and that the direct and indirect costs of implementation for that facility are justified in view of this increased protection.

(c) In reaching the determination required by paragraph (a) of this section, the Commission will consider how the backfit should be prioritized and scheduled in light of other regulatory activities ongoing at the facility and, in addition, will consider information available concerniraany of the following factors as may be appro-priate and any other information relevant and material to the pro-posed backfit:

(1) Statement of the specific objectives that the giroposed backfit is designed to achieve; (2) General description _of the activity that would be required by the licensee or applicant in order to complete the backfit; (3) Potential change in the risk to the public from the accidental off-site release of radioactive material; i (4) Dotential impact on radiological exposure of facility employees; (5) Installation and continuing costs associated with the backfit, including the cost of facility downtime or the cost of construction delay; 1This discussion does not encompass the full provisions of the Backfit Rule, in the interest of brevity; the complete set of provisions should be carefully examined for relevancy to specific LWR reactivation situations.

(6) The potential safety impact of changes in plant or operational complexity, including the relationship to proposed and existing regulatory requirements.

(7) The estimated resource burden on the NRC associated with the proposed backfit and the availability of such resources; (8) The potential impact of differences in facility type, design or age on the relevancy and practicality of the proposed backfit; (9) Whether the proposed backfit is interim or final and, if in-terim, the justification for imposing the proposed backfit on an interim basis.

In addition to regulatory options involving possible future backfits to deal with any safety or technical issues resulting from significant new information affecting reactivated LWRs, NRC has developed Regulatory Analysis Guidelines (NUREG/BR-0058, Rev. 1) that provide decision procedures and criter.'a for deal-ing with certain proposed regulatory actions including rulemaking an,i the pos-sible establishment of other NRC requirements and guidance. The intent is to allow decisionmakers, and other interested parties, to easily determiae:

(1) the conclusions reached, (2) the bases for conclusions, (3) the t)oe, magnitude and source of uncertainties which might affect the conclusicis, (4) the sensitivity of any conclusion to variation in the important input para-meters affecting the conclusions, and (5) the analytical methods used aid the logic which led the analyst to the conclusions presented. ,

A Regulatory Analysis of a proposed action, including a discussion of any reasonable alternatives to the proposed action, shall be prepared for each pro-posed rule and final rule that, in the determination of the responsible office director or the Executive Director for Operations, will likely result in the following:

• An annual effect on the economy of $100,000,000 or more in direct and in-direct costs, ce

• A significant impact on health, safety or the environment, or

• A substar,tial increase in the cost to NRC licensees, permit holders or appli-cants, to Federal, state or local governments, and geographical regions.

Appendix D to NUREG/BR-0058 (Rev. 1) provides the following specific examples of effects that could result in a cost or benefit of a proposed regulatory action or its alternatives (including the no action alternative), thus constituting decision criteria:

1. RADIOLOGICAL SAFETY CONSEQUENCES (a) Change in accident probabilities; specify the accidents (old, new probabilities)

(b) Change in failure probabilities; describe the equipment directly and indirectly affected by the proposed action (old, new probabilities)

(c) Change in population at risk (percent and absolute)

(d) Change in occupational exposure; during installation, operation or maintenance (rem)

(e) Change in unplanned radioactive releases offsite (curies)

(f) Change in routine radioactive effluent releases (curies)

(g) Change in operator response times (seconds / minutes)

(h) Change in maintenance capability (yes/no) (explain)

(i) Change in NRC's inspection and enforcement capabilities (yes/no)

2. SAFEGUARDS IMPACTS (a) Change in facility security (yes/no) (explain)

(b) Change in materials control and accountability (yes/no) (explain)

(c) Change in transportation security (yes/no) (explain)

3. OPERATIONAL IMPACTS (a) Change in reactor availability (hours / days)

(b) Change in facility downtime beyond that normally scheduled (hours / days)

(c) Change in allowable reactor rating (percent and absolute)

4. ECONOMIC IMPACTS (a) Construction cost change (dollars)

(b) Operating cost changes (dollars)

(c) Retrofit costs (dollars)

(d) Recordkeeping and reporting cost changes (staff-hour; dollars)

(e) Change in onsite personnel requirements (staff-hours)

(f) NRC costs change; include contractor technical assistance costs (staff-hours or dollars)

(g) Other increases in applicant expenditures for compliance with regula-tory requirements (staff-hours or dollars)

(h) Change in expected direct cost of an accident (dollars)

5. ENVIRONMENTAL IMPACTS (a) Change in water quality (b) Change in air quality

6. INFORMATION COLLECTION IMPACTS (Resulting from application, reporting or recordkeeping requirements)

(a) Annual licensee / applicant staff hours (hours)

(b) Annual licensee / applicant cost (dollars)

(c) Annual cost to the NRC (hours / dollars)

7. OTHER IMPACTS (for example)

(a) Consequences for small business (dollars / Sours)

(b) Significant impacts on vendors, and equipa.ent suppliers (yes/no)

(c) Anti-competitive consequences (impact on viability of avisting firms to complete or provide equipment)

(d) Availability of skilled labor / professional assistance (regional employment figures by a relevant category)

(e) Number of licensees affected It is noted that the above examples of possible costs and benefits to include in the scope of decision criteria include qualitative assessments as well as quantitative estimates of effects and their probabilities not necessarily expressed in commensurable units. The " apples and oranges" nature of these decision criteria is dealt with by an overall subjective balancing judgment of beneficial and adverse effects. In addition to the aforecited examples of costs and benefits, it is proposed that the decision criteria include a determination of how well the regulatory options for an improved treatment of regulatory i

N issues in LWR reactivation projects are in agreement with the three regulatory philosophies and five purposes or objectives set forth at the beginning of this

! section, some of which are reflected, at least in part, in the above examples of decision criteria. )

i ' 6. 2 Regulatory Options for Dealing with Reactivation Issues

One alternative to the development of a policy for dealing with issues asso-ciated with the reactivation of nuclear plants with deferred or cancelled con-struction is to have no policy at all. That is to say, if there is little prospect for more than a few such plants to be reactivated, an economical use

of NRC resources might be to treat such reactivations on a case-by-case ad hoc j basis rather than through policy formulation. The exercise of the ad hoc option, however, involves a Catch-22 situation. This option is likely to have a discouraging effect on utility decisions to reactivate construction such units, given that

1 i (1) Many of the involved utilities have a troubled financial situation compounded by an uncertain outlook for demand growth and the rate at which excess reserve margins will shrink;

(2) The lack of NRC policy development would create a compounding of un-certainties (especially regarding the reactivation of cancelled units) over the stability and predictability of NRC regulation in dealing with reactivation issues and what this course of action might mean

for licensing and construction delays and the need to demonstrate adequate management in cost control to obtain the confidence of in-l vestors, Public Utility Commissions, and the consumer public; and i

(3) The no policy option would forego opportunities to improve the cur-rent regulatory regime at possibly modest cost in ways described below that would tend to encourage utility decisions on reactivation i

options which would best serve the public interest 1 (see above statement of proposed objectives of LWR reactivation policy).

} Thus, the no policy option, if based on the assumption of a small number of reactivations, would be a self-fulfilling prophecy since it is a course of action that would likely exert a negative impact on reactivation decisions by

utilities. Accordingly, the remaining discussion will deal with sub-options within a framework of LWR reactivation policy development.

i It must be recognized at the outset that some policy options will pertain only to plants with cancelled construction (and especially those with a withdrawn l Construction Permit), while others will apply to both cancelled and deferred

units, albeit with different weightings of decision criteria. It is expected,

for example, that the reactivation of units with a withdrawn CP would require a i

re-application for a CP involving new (or amended) safety and environmental reports, staff re-reviews, hearings, and board decisions. Thus, policy options l exist whether staff review for selected safety and environmental issues might lIn the case of the Limerick-2 reactivation decision, it was laudably the per-ception by the Pennsylvania Public Utility Commission, and not the NRC, as to what would best serve the public's economic interest in the affected region in the face of a controversial decision climate.

i

best be accomplished through generic rulemaking covering some of these issues or whether these should receive, as before, case-by-case review for a CP reapplication.

It could be a desirable option to proceed initially with a Reactivation Policy Statement addressed solely to the class of LWR units that are deferred or still have an active Construction Permit. This could be followed at a later time by a Policy Statement involving rulemaking for selected environmental and safety issues (see below) that would apply jointly to reactivation of plants with cancelled cps as well as new plants on existing or new sites. There are several arguments favoring this bifurcation of policy development:

(1) There is an apparent lack of urgency for a Reactivation Policy to deal with plants with a cancelled CP since no owner of such a plant has expressed any interest in a Policy Statement at this time to deal with this class of plant. All of the industry members of the recently organized AIF Ad Hoc Group on Reactivation of Construction Projects are interested in the possible reactivation of deferred plants or units with still active cps.

(2) As discussed below, the set of licensing issues for reactivating con-struction of plants with cancelled cps are much more extensive and difficult than those associated with the reactivation of deferred units or other units with still active cps. Accordingly, the sep-arate regulatory treatment of the latter plants from those plants with cancelled cps in different Policy Statements at different points of time holds distinct advantages in permitting a more simplified and less encumbered Policy Statement for deferred units while allowing more time for reaching policy decisione regarding the more difficult regulatory issues associated with reaci.ivation of plants with cancel-led cps.

(3) Moreover, the regulatory issues associated with the reactivation of plants with cancelled cps have more problems in common with a (re-vised) policy for the improved treatment of regulatory issues for new plants and consideration needs to be given to the future development of a policy statement to jointly treat these two classes of plants.

For example, 22 of the plants with cancelled cps have equipment onsite with acquisition value less than $100 million and, hence, would be prime candidates for reactivation using plants of new standard design with superior outlook for cost and safety.

An initiative to improve the regulatory efficiency and predictability of the treatment of certain environmental and safety issues through generic rulemaking is described in a 1978 NRC report on " Preliminary Statement on General Policy for Rulemaking To Improve Nuclear Power Plant Licensing" (NUREG-0499). In this report the staff proposed ten issues for generic rulemaking:

(1) Future availability and price of uranium; (2) Alternative energy sources to the nuclear option; (3) Need for adding baseload generating capacity; (4) Methodological and information requirements in the analysis of alternative sites;

(5) Criteria for the assessment of nuclear plant impacts and mitigative measures; (6) Generic procedural criteria tp define more concretely NRC responsi-bility in assessments and decisions regarding certain water-related impacts in relation to the statutory authorities of EPA and permitting states; (7) NEPA decision criteria for Operating License (0L) reviews; (8) Occupational radiation exposure control; (9) Generic radiological impact for normal LWR radionuclide releases; and (10) Threshold limits for generic disposition of cooling tower effects.

As stated in NUREG-0499, the principal benefits sought in generic rulemaking for these issues are:

• Achievement of more effective public input and improved public under-standing of NRC's analytical procedures and decision criteria in treating potential environmental and safety issues in the licensing process for nuclear power plants;

• Improvement of the stability and predictability of the licensing pro-cess, including the provision of orderly and clear procedures for State-Federal cooperation in treating generic licensing issues; and

• Accomplishment of an overall savings of manpower and financial resources of the NRC, the public, the utility industry, and other local, State, and Federal agencies involved in the nuclear licensing process.

The main drawbacks to the rulemaking option were perceived as: (1) the short-term increase in dollar costs of the various participants in the rulemaking action, including contractual support; and (2) the additional impacts (i.e.,

opportunity costs) of diverting manpower and other resources to the rulemaking process and away from other productive uses for a temporary period.

On December 14, 1978 the Commission published for public comment an Interim Policy Statement on " Generic Rulemaking To Improve Nuclear Power Plant Licens-ing" (43 FR 58377). However, due to the absence of new applications for Con-struction Permits and the diversion of staff effort to the development of a TMI Action Plan following the TMI accident of March 28, 1979, only Issue-7 (NEPA decision criteria for OL reviews) of the above ten issues was subsequently dealt with through generic rulemaking. This action led to two final rules in 10 CFR Part 51: (1) Alternative Site Issues in Operating License Proceedings (46 FR 28630), and (2) Need for Power and Alternative Energy Issues in Operat-ing License Proceedings (47 FR 12940). Both of these rules preclude the sub-ject issues from consideration in OL proceedings--an advantage to utilities reactivating deferred plants and to those plants with cancelled construction that still have an active CP. Options also exist to improve the cost-effectiveness, stability and predictability of the licensing process through generic rulemaking of the remaining nine (and possibly additional safety and environmental) issues that would apply at the CP licensing stage. This rule-making would apply to any new CP application as well as a reactivated LWR pro-ject with a cancelled CP. It is also possible that rulemaking on some of these

issues could have provisions for closer cooperation or a shift of regulatory responsibilities between the NRC and States in which the units are sited.1 A different kind of regulatory option of possible benefit to the reactivation of plants with cancelled cps would be to establish through rulemaking a one-step CP/0L licensing and hearing process on the grounds that the bulk of the site-related and design-related environmental safety issues will have already i been dealt with in the original CP hearings. Any environmental and safety

, issues arising from significant new information since the initial CP hearing

^

could thus be dealt with in a combined CP/0L hearing for any reactivated LWR project falling into the category of cancelled cps.

Other options involving new or changed rules, policies, review procedures, etc.

would appear to hold potential for improved regulatory cost effectiveness and stability for LWR reactivation of both deferred and cancelled plants. These include:

, -(1) Policies and review procedures for standard plant designs (replicate  :

plants, duplicate plants, FDAs, or Design Certifications of reference 4 designs through rulemaking v_s_ a custom plant; i (2) Policies and review procedures involving a relatively complete design with a full-scope PRA n a design and PRA of limited scope; and (3) Options for revised rules, regulatory guidelines, policies, technical specifications, standard review plans, hearing guidance, legislative or administrative reforms, etc., to improve regulatory efficiency g the current regulatory regime.

I The regulatory benefits associated with standard plant designs (item 1) would, of course, only apply to those deferred or cancelled plants that qualify. For i ext.mple, only one deferred plant is a standard design. However, 19 of the 35 cancelled LWR units are some type of standard plant: duplicate (3), replicate (4), and reference design (12). While some of these units had cancelled equip-l ment deliveries, by the same token, it would appear that all of the 22 cancelled units (see Table 1) having no or less than $100 million aquisition value of onsite equipment might be candidates for a new unit of advanced design without j economic penalty. For example, it is possible that some of the Balance-of-Plant

equipment might suitably be matched with a new reactor design. But the biggest economic gains and safety review benefits in reactivating cancelled units would

~

likely accrue in substituting a new standard plant with Design Certification i

through rulemaking as provided for in the new Severe Accident Policy (NUREG-1070).

l The essentially complete design and the fulfillment of the following criteria l and procedural requirements of a Design Certification (and other new plant i d signs) will increase stability and predictability of the regulatory process and provide for a shortened licensing and construction schedule with its 4

attendent cost savings and safety assurance benefits (NUREG-1070, p. 10);

a. Demonstration of compliance with the procedural requirements and i criteria of the current Commission regulations, including the Three Mile Island requirements for new plants as reflected in the CP Rule

, [10 CFR 50.34(f)];

IFor example, see " Federal-State Cooperation in Nuclear Power Plant Licensing"

. (NUREG-0398) and various reports of the NRC Office of State Programs

(NUREGs-0195 through -0204) and NUREG/CR-0022.

j - - - . - - .

b. Demonstration of technical resolution of all applicable Unresolved Safety Issues and the medium- and high priority Generic Safety Issues, including a special focus on assuring the reliability of decay heat removal systems and the reliability of both AC and DC electrical supply systems;

c. Completion of a Probabilistic Risk Assessment (PRA) and consideration of the severe accident vulnerabilities the PRA exposes along with the insights that it may add to the assurance of no undue risk to public health and safety; and

d. Completion of a staff review of the design with a conclusion of safety acceptability using an approach that stresses deterministic engineer-ing analysis and judgment complemented by PRA.

In addition, the Commission has proposed to the Congress its draft " Nuclear Power Plant Licensing and Standardization Act of 1985" which would provide for the issuance of combined Construction Dermits and Operating Licenses in a one-step licensing process, early site approvals and standard design approvals.

It is recognized that the above criteria and procedural requirements for new plant designs (both standard and custom) represent changes to the Commission's 1978 Standardization Policy Statement and to 10 CFR 50, Appendix 0, which deals with standard reference designs. Accordingly, the Commission has requested the staff to prepare a revision of the standardization regulation and policy (NUREG-1070, p. 31). The staff has considered a number of options for this revision (including those provided by a Study Group of the Atomic Industrial Forum) and on December 4,1985 proposed to the Commission a draft "Standardi-zation Policy Statement" (SECY-85-382). The most significant proposed revisions to the 1978 standardizat. ion policy statement are:

(1) The four licensing requirements for new plant designs as set forth in the Commission's severe accident policy statement have been added.

(2) Provisions for Design Certification through rulemaking have been added.

(3) The ability of the staff and Commission to make changes to approved or certified designs has been made more restrictive. An explanation of the applicability of the backfitting rule (10 CFR 50.109) to each of the options has been added. The ability of holders of design approvals or certifications to make such changes has been made less restrictive.

(4) The overlap in the reference periods between the duplicate and repli-cate design concepts has been eliminated.

(5) Fees required of reference design applicants will be allocated among the applicants for permits and licenses which propose to use the reference design. Enactment of the draft " Nuclear Power Plant Licensing and Standardization Act of 1985" would be necessary prior to adopting this approach.

(6) Final design approvals and design certifications can be renewed once for a duration up to the original approval period. Preliminary design approvals can only be renewed on a finding of good cause.

Regarding both cancelled and deferred plants of custom or standard design, i options are being explored by the staff in cooperation with IDCOR and other l industry representatives or groups in the development of policies and review j procedures (supra) involving a relatively complete design with a full-scope PRA

vs a design and PRA (or other systematic safety examination) of limited scope.

l It is recognized that there are a diversity of PRA methods, which, in accor-dance with Severe Accident Policy, are to be used to complement deterministic cngineering analysis and judgment.1 These PRA methods will continue to under-go evolutionary development as the results of research programs and reliability data from operating reactors become available and as innovative uses of PRA in safety decision contexts suggest better ways to achieve the benefits of these methods while guarding against their limitations or improper uses. While learn-ing curves of these kinds will likely continue for a decade or more, it would nevertheless be constructive to consolidate this experience at various stages of PRA development and utilization. At the present stage of development, a number of positive uses of PRAs have been demonstrated, especially in identify-ing: (1) those contributors to severe accident risk that are clearly dominant and hence need to be examined for cost-effective risk reduction measures and (2) those accident sequences that are clearly insignificant risk contributors ,

tnd can therefore be prudently dismissed. In-between cases are more problematic.

The use of PRA and related systems reliability analysis methods are being ap-plied to both new plants and existing plants. In the Severe Accident Policy, existing plants are defined as operating reactors and plants under construction for which an operating license has been applied. Regarding such methods of safety analysis and staff review, the Severe Accident Policy states (NUREG-1070, p. 8.):

One important source of new information is the experience of NRC and the nuclear industry with plant-specific probabilistic risk assessments. Each of these analyses, which provide a more detailed assessment of possible accident scenarios, has exposed relatively unique vulnerabilities to severe accidents. Generally, the undesirable risk from these unique features has been reduced to an acceptable level by low-cost changes in procedures or minor design modifications. Accordingly, when NRC and industry interac-tions on severe accident issues have progressed sufficiently to define the methods of anlysis, the Commission plans to formulate an integrated syste-matic approach to an examination of each nuclear power plant now operating or under construction for possible significant risk contributors (some-times called " outliers") that might be plant-specific and might be missed absent a systematic search. Following the development of such an approach, l

an analysis will be made of any plant that has not yet undergone an appro-priate examination. The examination will include specific attention to containment performance in striking a balance between accident prevention and consequence mitigation. In implementing such a systematic approach, plants under construction that have not yet received an Operating License l will be treated essentially the same as the manner by which operating reactors are dealt with. That is to say, a plant specific review of severe accident vulnerabilities using this approach is not considered to be neces-sary to determine adequate safety or compliance with NRC safety regulations under the Atomic Energy Act, or to be a necessary or routine part of an Operating License review for this class of plants.

IFor a fuller discussion, see NUREG-1070, Part IV, Severe Accident Program (pp. 21-36).

l

The Severe Accident Research Program (see below) as well as NRC's extensive severe accident studies of certain individual plants will aid in determining the extent to which carefully analyzed reference plants can appropriately serve as surrogates for a class of similar plants as the basis for any generic con-clusions. These studies will also aid in identifying the desirable scope and approach for follow-up safety studies of individual plants. Any generic design changes that are identified as necessary for public health and safety will be required through rulemaking and will be consistent with the Commission's backfit policy.

6.3 Potential Impact of Research Programs on the Choice of Regulatory Options It is apparent from the preliminary status information regarding the continuing presence of financial and need-for plant issues of cancelled and deferred plants (see Tables 1 and 2) that relatively few LWR project reactivations can be ex-pected in the next year or so. Accordingly, it is desirable that a LWR Reacti-vation Policy be formulated in such a way as to flexibly permit the use of the near-term results of NRC's research programs. These results hold promise, among other objectives, of aiding the definitization of policy options, safety review procedures, etc. that could measurably improve regulatory stability and the cost-effective treatment of issues in LWR reactivation. In view of the lag time that often accompanies the spreading application of research results, the following discussion would hold greater relevance to the reactivation of can-celled plants that would be expected to come at a later time than some of the deferred plant reactivations. Good management, however, strives to shorter the lags in the adoption of the best available technology.

A number of these research programs are either part of the Severe Accident Re-search Program (SARP) described in NUREG-0900 or are follow-up programs or con-tracted research efforts that further improve PRA and related systems reliabil-ity analysis methods and their useful implementation in safety management.1 One such program is the Accident Sequence Evaluation Program (ASEP) begun as part of the SARP. The dominant accident sequences from some of the 20 completed plant PRAs in the United States are being used in the ASEP research in order to obtain risk profiles of the approximately 100 near-term and presently operating plants. In the absence of PRAs on each plant, the ASEP approach is the only known means for obtaining risk statements for all plants. A report describing this industry-wide accident sequence likelihood information data base has been delayed to address the needs of the severe accident research program, but it will be resumed when the demands caused by the NRC reference plant analysis permit (NUREG-1150, forthcoming). In addition to plant-specific PRAs and ASEP-dominant accident sequences, operational occurrences as reported in licensee event reports can be analyzed in generic event trees to obtain a gross assess-ment of nuclear industry risk over periods of time. The NRC Accident Sequence Precursor Program has completed an assessment of the 1969-1979 period (NUREG/CR-2497) and also the period 1980-1981 (NUREG/CR-3591).

Information on containment systems performance and failure modes, fission pro-duct source terms, and health consequences is being developed under the Severe 1Much of the discussion of research programs in this section is adapted from:

Gary R. Burdick and Carl E. Johnson," Relevance of PRA to Regulatory Develop-ment," NRC Office of Nuclear Regulatory Research, a paper presented at the WATTec 13th Annual Energy Conference, Knoxville, TN, February 13, 1986.

Accident Risk Reduction Program (SARRP) scheduled for completion in the summer of 1986. Another research program is aimed at the development of a Systems Analysis and Risk Assessment (SARA) system. The direct purpose of the program is to develop a capability for computation and analysis of nuclear power plant risk characteristics, using state-of-the-art, user-friendly and modularized computer software and existing nuclear power plant risk information developed under two other key current research programs. The SARA system will enable a time-dependent display of cumulative costs and risk reduction benefits result-ing from past or future implementation of the resolution of a number of generic issues.

A research program is being mounted to improve regulatory effectiv'eness in treating a number of problems that have evolved over the years regarding tech-nical specifications (hearafter, tech specs). Today, the compilation of tech specs has grown to over 500 pages and several thousand surveillance require-ments. The absence of specific criteria as to the content of tech specs has resulted in numerous items of vastly differing levels of importance being in-cluded, as well as requirements that are occasionally inconsistent. This sit-uation tends to divert attention from the principal safety parameters while focusing attention on detailed surveillance of lower-importance systems. The voluminous technical specifications have also become burdensome and costly to utilities, yet do not contribute corresponding benefits to safety. Further, some tech specs are complex and difficult for the control room operators to implement, and others may actually be adverse to safety (e.g., certain forced shutdowns when, in fact, continued steady-state operation is the safest plant condition). Other concerns have been expressed regarding: excessive testing contributing to component wear, added maintenance downtimes resulting from com-ponent wear, unnecessary test downtimes, introduction of human errors, and the potential for common-cause failures. Finally, the NRC has not in the past discriminated between utilities with excellent preventive maintenance programs, who may not need prescriptive technical specifications, and utilities with poor preventive maintenance programs who may need them. Rather, the NRC and industry have concentrated on standardized specifications which would be applied to utilities uniformly to protect against the worst performers. This practice tends to place unnecessary burdens upon the good performers.

Accordingly, a contract study has been recently authorized to provide a reli-ability and risk basis for evaluating technical specifications and exemption requests and to support the Office of Nuclear Reactor Regulation efforts to improve technical specifications, especially the identification of tech specs not important to reliability / risk and to identify dominant failure modes of safety equipment.1 While this program is principally directed to providing cost-effective methods of achieving reactor operation safety, its features would also aid in determining the dominant accident sequences of individual plant designs and, hence, it would be relevant to a determination of which on-site equipment of cancelled or deferred plants requires the greatest care for raintenance and preservation and which are insignificant 1y safety-related, requiring minimal preservation measures from a regulatory standpoint.

1" Procedures for Evaluating Technical Specifications: Integrated FY 86-87 Program Plan," Technical Report A-3230, Reliability & Physical Analysis Group, Department of Nuclear Energy, Brookhaven National Laboratory, May 1986.

Another research program serving similar purposes is directed to the use of PRA in a Plant Reliability Program. Following the Three Mile Island accident and the Salem reactor trip failures, the NRC and others sponsored surveys of reli-ability techniques used by the aerospace, defense and other industries that might be applicable to LWRs. In 1984, Argonne National Laboratory coalesced the results into a set of reliability elements that appear applicable to LWR safety. Brookhaven National Laboratory was then engaged to evaluate the effec-tiveness of these elements.1 The results of this planned evaluation of the effectiveness of reliability elements will serve two purposes. One is to serve as part of the technical basis for staff evaluations of tradeoffs that licensees may propose to substitute reliability program elements in place of specific pre-scriptive requirements. The second purpose of this research is to help achieve NRC goals to shift its regulatory emphasis away from detailed prescriptive re-quirements toward performance criteria (NUREG-0885, Issue 4) with significant implications for improved safety and regulatory cost-effectiveness.

In order to develop methods for applying PRA results to manpower allocation decisions made by NRC inspectors, NRC has established a "PRA Application to NRC Inspection Program". One feature of this program is the development of a Plant Risk Status Information Management System (PRISIM), which is a decision-oriented, user-friendly, menu-driven program that contains data base management and interactive routine that will aid NRC regional inspectors in allocating their efforts toward those areas where they will have the greatest impact on safety. By the same token, it would be a possibility for utility management to adapt this system (perhaps in conjunction with SARA) for use in developing cost-effective approaches for equipment preservation of cancelled or deferred plants as well as subsequent use in reactivated construction quality assurance programs.

Because some decisions made by inspectors depend on the current status of the plant, PRISIM contains an interactive routine that allows the user to specify components or subsystems that are out of service (or could fail in the future if equipment is not adequately preserved and maintained during a delayed con-struction phase). The user is then apprised of the impact the specified condi-tion (s) places on instantaneous risk and the components that are most critical to maintaining plant safety under the specified condition (s). Thus, inspectors can plan their actions using PRA-based information integrated with plant status information. A computer program was chosen to catalog and present the PRA in-formation because the total amount of information is large, but the amount needed for any particular decision is relatively small. PRISIM allows the user to quickly and logically access the desired information without being over-whelmed by enormous quantities of data. Moreover, the user does not need to have a background in computer operation or PRA to use the program or understand and employ the information it presents.

One of the problems in using PRA-based information in the above fashion to aid decisions in equipment preservation prioritization or in allocating inspection /

auditing resources is that it often stops at the system or sub-system level of cost-effectiveness of these functions. A research project to provide a greater level of PRA detail on failure events is the draft technical report on " Trial 1 Carl E. Johnson, " Operational Safety Reliability Research," NRC Of fice of Nuclear Regulatory Research, a paper presented at the International Conference on Nuclear Power Plant Aging, Availability Factor and Reliability, American Society of Metals, San Diego, CA, July 8-12, 1985.

Application of Reliability Technology to Emergency Diesel Generators at Trojan."1 The following list of 28 integrated critical components identified from the BNL fault tree analysis out of an initial list of about 300 components illustrates the level of diesel engine component failure examined and prioritized in their approach:

fuel oil transfer pump breaker service water / jacket water heat exchanger service water motor operated valve auto voltage regulator circuit generator excitation circuit field flashing circuit i main lube oil pump strainer lube oil scavenging pump strainer compressor unloader jacket water themostatic control valve engine main bearing camshaft / timing gear generator bearing / coupling

! generator slip rings and brushes crankshaft-to piston connecting rod diesel generator control circuit lube oil scavenging pump

main lube oil pump engine driven jacket water pump crankshaft fuel oil day tank outlet valve circuit breaker 152-108 closing coil generator stator winding lube oil cooler turbocharger aftercooler jacketwater/servicewaterheatexchanger voltage regulator selector switch generator lockout relay 186-101 (102)

A related draft report by Brookhaven National Laboratory issued for comment in May 1986 (NUREG/CR-4618) describes technical work that was performed through a many-faceted approach to accomplish the following:

o Characterize current industry application of reliability technology for improving operations and safety, i o Determine the impact that reliability programs could potentially have on resolving safety issues, l o Demonstrate the use of reliability technology of the kind that would be applicable for a reliability program, on an actual nuclear power plant system, and o Initiate development of techniques that hold particular promise of having a large impact on the successful implementation of a reliability program, and that are useful to the NRC for regulating such programs.

One final example of a research program with " piggy-back" implications for an LWR Reactivation Policy that would improve the outlook for greater regulatory 1 Technical Report A-3282, Brookhaven National Laboratory, April 1986.

r stability and cost effective approaches for treating reactivation issues is that of the NRC Research " Program Plan on Effectiveness of LWR Regulatory Re-quirements in Limiting Risk" (ELR). On October 3, 1984 the Commission issued a public notice of the availability of the ELR Program Plan and invited public comment (49 FR 39066). This program is being initiated to identify current regulatory requirements which, if deleted or appropriately modified, would im-prove the efficiency or effectiveness of NRC's regulatory program for nuclear power plants without adversely affecting safety. Initially, this program will systematically assess the risk importance of selected current regulations .in 10 CFR Part 50 and related regulatory requirements.

A number of existing programs1 assess the adequacy of present regulations.

However, these programs are not specifically designed to weed out existing re-gulations or regulatory requirements which do not reduce risk significantly.

Initially, this program is designed to (1) systematically screen all current regulatory requirements associated with 10 CFR Part 50 and to assess the impor-tance of selected requirements based first on their contribution to assuring that nuclear power plants are safely designed, cor iructed, and operated and second on their impact on licensee applicant, and A. resources and (2) identify and propose appropriate modifications to eliminate duplication., inconsistency or unnecessary requirements r d thus focus available NRC and industry resources more directly and precisels a 'se significant safety are n and issues.

Prime candidates for modification will be (1) old regulatory requirements which in light of present knowledge may no longer be considered risk important or whose risk importance may have been reduced substantially by the implementation of newer requirements and (2) areas in which there are large safety margins or conservatisms which can be reduced without measurably increasing the level of risk. In such cases, modification could produce a significant safety benefit, since the attention and resources of licensees, applicants, and the NRC that are now directed to these areas could be redirected to other areas of greater safety significance.

6.4 The Image Problem of Identifying and Choosing between Alternatives to Deal More Effectively with a Complexity of Regulatory Issues It would be unfortunate, indeed, if the above (and future) discussions of regu-latory options to deal with the complexities and risk uncertainties of nuclear power plant technology created an impression that major or costly safety and environmental improvements are likely to be needed in LWR reactivations or that would yield an image of regulatory instability with adverse impact on investor confidence. It is an inescapable fact that nuclear technologies have system complexities and that assessments of severe accident risks have broad ranges of uncertainty in the face of numerous accident scenarios, each with a relatively low probability and, hence, an insufficient (but growing) data base of failure frequencies of a wide variety of custom designs. However, the large program of severe accident research that the NRC launched several years ago has not been

~

justified on the basis of expectations that major changes would be required in 1 Examples include (1) the Generic Issue and Unresolved Safety Issue programs; (2) programs and tasks that would be guided by the Severe Accident Policy Statement; (3) the Integrated Safety Assessment Program for operating reactors; (4) the operating experience review by the Office for Analysis and Evaluation of Operational Data; and (5) the many studies, analyses, test and experiments supported by the Office of Research.

plant designs to make them acceptably safe. Rather, the prime objective of this program is to reduce the uncertainties surrounding the level of risk posed by the possibility of severe reactor accidents. We are not seeking risk reduc-tion except in those cases in which the new information would suggest undue risk. Said in another way, it is our judgment that existing plants are safe enough, but we seek to narrow the window of uncertainty.

Moreover, an extensive appendix of NUREG-1070 on Severe Accident Policy dealt with current information bearing on the need for generic design changes of LWRs.

The principal conclusion reached was that it is believed that the large body of currently available information summarized in this Appendix provides substantial support to the notions that existing plants pose no undue risk to public health and safety and few, if any, generic design changes imposing major costs are likely to be required by new safety information that is prospective of develop-ment in the next several years. During the two years since this conclusion was first reached, no significant new information has been developed from SARP pro-ject completions or interim results, as well as other sources, to significantly undermine this conclusion. Although research results on the Mark I/BWR contain-ment design did suggest that certain substantial modifications might be cost-effective in reducing sa cre accident risk for this particular design, none of the deferred and only o.- of the cancelled plant designs (Hope Creek-2) involve a Mark I containment.

Indeed, there are reasons for believing that regulatory changes already made or options for change under consideration (some of which have been discussed above) would lend substantial support to the conclusion that a fairly stable regulatory climate is being achieved with a relatively favorable outlook for a shortened licensing and construction schedule for both new plant applications or the reactivation of cancelled or deferred plants with relatively minor changes affecting overall costs. These include:

(1) Staff efforts to re-examine more carefully what constitutes an appropriate course (including modifications in present rules, policies, guidelines, review procedures, etc.) that would avoid the disbenefits of both over-regulation and under-regulation.

(2) On balance, it is believed that the design improvements cost-effectively justified as a result of new safety or environmental information to avoid under regulation might, in a majority of plant-specific cases, be roughly compensated cost-wise by a relaxation of certain tech specs or other design criteria or requirements as a result of new information revealing that safety margins earlier assumed for certain systems or components are ex-cessive or that certain systems or components have only marginal importance to severe accident risk.

(3) About 85% of the TMI action plans backfit requirements (NUREG-0737) are now completed.

(4) A final technical resolution has been achieved for 15 of the 27 identified Unresolved Safety Issues (USIs) and substantial progress has been made on the remaining USIs. Likewise, substantial progress has been made in the analysis / resolution of the high- and medium priority Generic Safety Issues that have been prioritized in NUREG-0933.

(5) Regulatory stability is promoted for both existing and future plant designs by the issuance of the Severe Accident Policy Statement (NUREG-1070):

.._.. _ _ _ . . . . J

w  %"

(a) the inherent flexibility of the Statement permits risk- risk tradeoffs in systems and sub-systems design and encourages thereby innovative ways of achieving an improved overall systems reliability at a reasonable cost; (b) the statement that operating nuclear power plants require no further regulatory action to deal with severe accident issues unless significant new safety information arises to question whether there is adequate assur-ance of no undue risk to public health and safety; (c) in the latter event, a careful assessment shall be made of the severe accident vulnerability posed by the issue and whether this vulnerability is plant- or site-specific, or of generic importance; and (d) a requirement that the most cost-effective options for reducing this vulnerability shall be identified and a decision shall be reached consistent with the cost-effec.tiveness criteria of the Commission's backfit policy as to which option or set of options (if any) are justifiable and required to be implemented.

(6) The establishment of the Committee to Review Generic Requirements and the issuance of Regulatory Analysis Guidelines (NUREG/BR-0058, Rev. 1) and the new Backfit Rule (10 CFR 50.109) to ensure, among other purposes, that there is a substantial increase in the overall protection of the public health and safety to be derived from any proposed backfit and that the direct and indirect costs of implementation for that facility are justi-fied in view of this increased protection.

(7) The achievement of material progress in PRA methods and implementation techniques to reduce uncertainty in regulatory decisionmaking along with growing results from the Severe Accident Research Program and related research by U.S. industry and foreign sources.

(8) Cooperative efforts between NRC and such industry groups as IDCOR, EPRI, INPO, and various study groups of the AIF to share factual information and insights on the importance of safety and environmental issues and possible cost-effective modifications of design or operating and main-tenance procedures deserving of staff review or further research effort.

Regarding the last item, it is clear that, if there is to be an improved and stable outlook for new or reactivated nuclear power plant construction in the

. United States, there are certain initiatives that need be the primary respon-sibility of industry, other initiatives that must be the primary responsibility of government, and still others that need to involve the cooperative or joint efforts of industry and government. A preliminary rationalization of government and industry roles regarding such initiatives is shown in Figure 3.1 It should be noted that, in regard to government initiatives, a number of the items in-volving an integrated plan of policy development have already been accomolished and several others are expected to be completed in the next few years. Thus, any LWR reactivation decisions made after 1988 could reasonably be expected to have an even firmer outlook for regulatory stability following the completion of research and regulatory reforms currently in progress.

In sum, an extensive discussion of regulatory options involving change in regu-latory policies, rules, review practices, etc., might, at first blus1, _imy_1y regulatory instability. However, a closer examination of the changes recently achieved or being considered or developert, plus the increasing volume of sup-porting data being provided by the Severe Accident Research Program and other 2As adapted from Harold R. Denton, "The Maturing of the U.S. Nuclear Industry,"

Nuclear Engineerina and Design, Vol. 92, No. 3, April 1986, p. 314.

research efforts that are collectively and purposely directed to improving re-gulatory stability and cost-effective methods for dealing with safety and envi-ronmental issues, provides an opposite and more favorable perspective. Hence, it is believed that the culmination of these efforts toward regulatory improve-ments will be successful in promoting a stable regulatory outlook which, among other benefits, would portend better control over construction schedules and costs for any new plant applications or LWR project reactivations. Yet, it is recognized that the actual achievement of improved cost control over plant con-struction will depend also on improved project management and possibly coopera-tive agreements with construction unions as was consummated recently in the Limerick-2 project reactivation.

4 l

i

NATIONAL GOAL MPROVING THE U.S. OUTLOOK FOR PROGRESS IN THE MATURATION OF NUCLEAR REACTOR SAFETY TECHNOLOGY AND THE RESUMPTION OF INDUSTRY GROWTH RATIONALIZATION OF INDUSTRY b GOVT ROLES I I

( INDUSTRY INITIATIVES ) ( JOINT EFFORTS ) ( GOVERNMENT INITIATIVES )

I

_ NUCLEAR POWER PLANT OESIGN IMPLEMENTING THE LEGAL -

LEGISLATIVE REFORM FOR IMPROVED SAFETY 4 COST REQUIREMENTS OF THE LICENSING PROCESS ADMINISTRATIVE REFORM 6

- IMPROVED CONSTRUCTION =

CHANGES IN GUIDELINES 4

, PERFORMANCE SAFETY RESEARCH STANDARO REVIEW PLANS I

" IMPROVED RISK MANAGEMENT COMPONENT 4 SYSTEM OF OPERATING REACTORS _ CHANGES IN RULES RELIABILITY DATA FROM k REGULATIONS OPERATING REACTOR EXPERIENCE

= ACCIDENT PREVENTION

= ACCIDENT MANAGEMENT l -

OTHER RULEMAKING, INCLUDING STANDARD l SOURCE TERM REVISION DESIGN CERTIFICATION

= CONSEQUENCE MITIGATION I

PROSA88USTIC RISK REQUIREMENTS FOR BMPROVIDCOST ASSESSMENT METHODOLOGY COST EFFECTIVE SAFETY

'" - IMPROVEMENTS THROUGH PERFORMANCE OF OPERATING REACTORS [ GENERIC LETTERS ANO I SULLETINS 4 ORDERS RISK COST SENEFIT ANALYSIS

= PLANT OPERATION OF TECHNOLOGICAL OPTIONS e MAINTENANCE

- INTEGRATED PLAN

= RELIABILITY ENGINEERING l OF POUCY OEVELOPMENT

& PLANT AVAILASIUTY ESTABLISHING TECHNOLOGICAL PERFORMANCE STANDARDS = SEVERE ACCIDENT POLICY FOR FUTURE

= FUEL EFFICIENCY l Gr EXISTING PLANTS 1

QUALITY ASSURANCE PROGRAMS = SAFETY GOAL

= EXTENDED PLANT LIFE D OPERATOR TRAINING POLICY i

= OTHER COST FACTORS SAFETY 6 ENVIRONMENTAL = SITING POLICY MONITORING i - POLICY ON EMERGENCY PREPAREONESS 1 Figure 3. A preliminary framework of industry and government i

initiatives that would serve an implicit national "

goal Of improving the U.S. outlook for maturation "'$N$Ni$iENTAL E

PROTICTION progress in nuclear reactor safety technology and the resumption of inoustry growth.

" PFuN dlNUALS WASTE MANAGEMENT Source: H. R. Denton, "The Maturing of the U.S. Nuclear

! Industry", Nuclear Engineering and Design, Vol. 92, " yyyJf,0,,,,

l No. 3 (April 1986), 303-322. POuCY

7. REFERENCES

• NUREG-0195, " Improving Regulatory Effectiveness in Federal / State Siting Actions,"

May 1977.

NUREG-0196, " Success Factor Evaluation Panel," March 1977.

NUREG-0197, " State Regulatory Activity Involved in Need for Power," April 1977.

NUREG-0198, " State Perspectives on Energy Facility Siting," March 1978.

NUREG-0199, " Environmental Planning and the Siting of Nuclear Facilities: The Integration of Water, Air, Coastal, and Comprehensive Planning into the Nuclear Siting Process," February 1977.

NUREG-0200, " Federal / State Regulatory Permitting Actior.:, in Selected Nuclear Power Station Licensing Cases," June 1977.

NUREG-0201, " Water Supplies and the Nuclear Licensing Process," July 1977.

NUREG-0202, " Nuclear Power Plant Licensing: A New England Perspective,"

March 1977.

NUREG-0203, " State and Local Planning Procedures Dealing with Social and Economic Impacts from Nuclear Power Plants," Final Report, June 1977.

NUREG-0204, " Alternative Financing Methods," March 1977.

NUREG-0398, " Federal-State Cooperation in Nuclear Power Plant Licensing,"

March 1980.

NUREG-0499, " Preliminary Statement on General Policy for Rulemaking To Improve Nuclear Power Plant Licensing," December 1978.

NUREG-0625, " Report of the Siting Policy Task Force," August 1979.

NUREG-0701, " United States Experience in Environmental Cost-Benefit Analysis for Nuclear Power Plants," August 1980.

NUREG-0718, Rev. 2, " Licensing Requirements for Pending Applications for Construction Permits and Manufacturing License," January 1982.

NUREG-0737, " Clarification of TML Action Plan Requirements," November 1980.

NUREG-0880, Revision 1 for Comment, " Safety Goals for Nuclear Power Plant Operations," May 1983.

t NUREG-0885, Issue 4, "U.S. Nuclear Regulatory Commission Policy and Planning Guidance 1985," February 1985.

l

• Copies of these publications by the U.S. Nuclear Regulatory Commission may be

, purchased by calling (202) 275-2060 or (202) 275-2171 or by writing to the l Superintendent of Documents, U.S. Government Printing Office, P.O. box 37082, Washington, D.C. 20013-7082 or the National Technical Information Service, Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161.

NUREG-0900, " Nuclear Power Plant Severe Accident Research Plan," January 1983.

i NUREG-0933, "A Prioritization of Generic Safety Issues," December 1983.

NUREG-0956, " Reassessment of The Technical Bases for Estimating Source Terms,"

Draft Report for Comment, July 1985.

NUREG-1024, " Technical Specifications--Enhancing the Safety Impact,"

November 1983.

NUREG-1050, "Probabilistic Risk Assessment (PRA) - Reference Document," Final Report, September 1984.

NUREG-1061, " Rep' ort of the U.S. Nuclear Regulatory Commission Piping Review Committee, (Vols. 1-6), April 1985.

NUREG-1070,"NRCPolicyonFutureReactorDesigns: Decisions on Severe Accident Issues in Nuclear Power Plant Regulation, July 1985.

NUREG-1144, " Nuclear Plant Aging Research (NPAR) Program Plan," July 1985, i

NUREG-1150, " Nuclear Power Plant Risks and Regulatory Applications," Draft Report for Cormient (To be published).

NUREG-1175, "NRC Safety Research in Support of Regulation: Selected Highlights,"

May 1986.

NUREG/BR-0058, Rev. 1, " Regulatory Analysis Guidelines of the U.S. Nuclear Regulatory Commission," May 1984.

i NUREG/CP-0036, " Proceedings of the Workshop on Nuclear Power Plant Aging,"

Sandia National Laboratories, November 1982.

NUREG/CR-0022, "Need for Power: Determination in the State Decisionmaking

Processes," Center for Natural Areas, March 1978.

NUREG/CR-0153, " Insights into Improving The Efficiency of Nuclear Power riant Inspection Procedures Based Upon Risk Analysis," Battelle Columbus Laboratories, July 1978.

t NUREG/CR-2040, "A Study of the Implications of Applying Quantitative Risk i

Criteria in the Licensing of Nuclear Power Plants in the United States,"

Brookhaven National Laboratories, May 1981.

NUREG/CR-2497, " Precursors to Potential Severe Core Damage Accidents: 1969-79, A Status Report," Dak Ridge National Laboratories, June 1982.

j

' NUREG/CR-2631, "A Logical Framework For Identifying Equipment Important to Safety in Nuclear Power Plants," Sandia National Laboratories, September 1983. i NUREG/CR-3591, " Precursors to Potential Severe Core Damage Accidents:

l 1980-1981, A Status Report," Oak Ridge National Laboratory, July 1984.

NUREG/CR-3762, " Identification of Equipment and Components Predicted as Significant Contributors to Severe Core Damage," Idaho National Engineering Laboratory, May 1984.

i NUREG/CR-3818, " Report of Results of Nuclear Power Plant Aging Workshops,"

Sandia National Laboratories, August 1984.

NUREG/CR-4144,"ImportanceRankingBasedonAgingConsiderationsofComponents Included in Probabilistic Risk Assessments, Pacific Northwest Laboratory, April 1985.

NUREG/CR-4446, "The Nuclear Industry and Its Regulators: A New Compact is Needed," International Energy Associates Limited, February 1986.

NUREG/CR-4618, " Evaluation of Reliability Technology Applicable to LWR Opera-tional Safety," Draft Report for Comment, Brookhaven National Laboratory (To be published).

1 l

i i

APPEi4 DIX A FORECASTS OF ELECTRICAL EilERGY DEMAND AND NEED FOR ADDED PLAhT CAPACITY l

APPENDIX A I. Explanatory Note l

The following sections of Appendix A include those selected sections from l recent reports of the North American Reliability Council, the Energy Informaticn Administration of the U.S. Department of Energy, and the Edison Electrical ,

Institute that have a bearing on the outlook for adding new electrical generat- '

ing capacity to the interconnected regional grids of the lower 48 states, includ-ing summary analyses and projections of the use of nuclear fuel in meeting rising consumer demands.

No commentary is provided, nor is endorsement to be implied, of the projections and views presented in these excerpts. These excerpts are relevant, however, to the scope of the present study inasmuch as they represent some of the major sources of currently available information on the status of certain key consid-erations discussed throughout this report that will have an important bearing (among other factors) on utility decisions and their timing to reactivate or not construction of any of the cancelled or deferred nuclear power plants.

The excerpts from the referenced documents are reproduced using the original '

table and chart numbers to facilitate convenient access to their location in the reference reports where additional supporting narrative is to be found.

This narrative provides important information as to the assumptions and addi-tional analyses that support the projections and views on energy outlook. For example, the report by the Edison Electrical Institute has separate Chapters on:

(1) Why Utilities Will Not Opt for Nuclear Power, and (2) The Case for Reopening the Nuclear Option. These and other important sections of this and the other reports covered in the following excerpts were omitted primarily in the interest of brevity rather than a criterion of importance.

I

APPENDIX A II. Ten Year Projections and Analyses by the North American Reliability Council I of U.S. Electric Power Supply and Demand Plus Need for Added Plant Capacity 1

l The following excerpts are reprinted by permission of the North American Relia-bility Council from two of their most recent reports:

1985 Reliability Review: A Review of Bulk Power System Reliability in North America (1) Executive Summary (2) Generating Capacity and Fuel (with selected tables and charts)

(3) Assessment of Power Supply Adequacy 1986 Electric Power Supply & Demand for 1986-1995 (1) Overview of NERC Projections, 1986-1995 (2) Detailed projections for 1986-1995 of the 9 U.S. NERC Regions and 17 Sub-Regions regarding: winter and summer peak hour demands (by year); annual net electrical energy for load; and winter and summer planned annual expansion of capacity resources.

l

1985 Reliability Review A REVIEW OF BULK POWER SYSTEM RELIABILITY IN NORTH AMERICA i

1 l

1985 Reliability Review: A REVIEW OF BULK POWER SYSTEM REUABluTY IN NORTH AMERICA )

EXECUTIVE

SUMMARY

l THE OUTLOOK the North Arnencan Electrc Reliabdity Couned expects the rehabdity of Some key questions facing the industry are:

electnc supphes to dochne over the next ten years By the mid-1990's- e Win the economies of Canada and the United States remain strong?

electnc generating capacity margins wdl be near minimum acceptable

• How wdl the price of electncity move in relation to other fuels and the levels in some parts of the United States, even af electncity demands grow no faster than the present forecast rate of 2.2% per year. In Canada.

opendam incorne okustoiws?

generating capacity is judged to be adequate for the entire 19851994 e Willload management programs be effective?

penod.

• To what degree will customers develop their own electncal generation to offset their utihty purchases?

Some of the generating capacity that will be needed ten years from now has not yet teen committed to by utiht>n. Actual commitments for major LOAD MANAGEMENT gener~)ing units in the United States have virtually stopped. Unless leed Utilites are relying on load management and conservation programs to times can be substantelty shortened, the uncommitted capacity may not restrain load growth. Some of our experts assert that their forecasts have be in eennce when needed. Thus, the industry is in a precarious position to been adsusted by up to 3% per year by these programs. There are practical react to a growth in demand higher than presently forecast Cogeneration, limits to what load management and conservation programs can achieve; renewabies, demand management and conservation win each play a role, they win not ehminate the need for future generating capacity additions.

but w;n account for only a fraction of the forecast need.

Aino, thm is uncertainty as to whether these programs wdl continue to be supported by regulatory commissions and the pubhc - and uncertainty as TIC future availabihty and performance of the elec*ric utihty industry's to the relebihty of these programs once they are operational.

aging equipment is an additional unquantifeble factor.The composite age of our fossil-fueled steam electne generating capacity is 17 years and, in 1FJO, will be 25 years. Even with the addition of all planned units over the ELECTRICITY PRICES next 10 years, the utihty industry will be entering 1995 wtth more than Strong correlations have been demonstrated between electncity use and 100,000 MW of fosoikfusied steam capacrty that is over 30 years old. electncity pnce. Utilities which are comp leting large nuclear or coal construction programe win be seeking rete increases to recover the The prodction of future energy needs is uncertain at best. However, even investment, which may in tum reduce the rate of load growth in these if needs were precieety known, utshties would stdl be reluctant to commit to areas. The utility industry, however, is responding to forces of compotrtion large power projects because of the large financial noks. Consequently, and has placed a major priority on controlhng prices. Competition is electric utdities appear to be adopting a " minimum capital outtay" poicy. coming from neighboring utdities, other fuels and customer-owned TIC wdl result in the least near-term cost to the Customer and esems generating resources. As prices are expected to noe in some areas and fall consistent with rnost regulatory mandates. However, the altemate with the in others, the effect on long-term demand and energy forecasts becomes least near-term cost may not be the isast sesina in ir L.Q M. Such Inure uncarisin.

UTILITY PLANS FOtt NEW CAPACITY TAKE A Electric transmission systema will continue to be loaded heavily with " WAIT AND SEE" APPROACH economy energy transfers. These transkrs, from areas wrtn now generation coste to areas with higher generation costs, help lower the cost of Electrtetty is unique among energy sources in that it must to produced at the precies moment it is required, it cannot be produced in excess at times electricity to the customer but also lower the rol. ability of the electnc of low demand and saved for use at times of peak demand. Thus, the power systems. When eiectric transmission systems are loaded to their maximum sete limits continuously, httle margin remains to handle the produce h4 M p p wtan N ned for R unexpected. As a result, rehability suffers. Budding add tional transmission A We d W m m m M W we4eing of would help, but impediments exist whch impedo the partial remedy a modem economy - when demands cannot be served, industry, Interruptions to customer service in the future w!D test customers' Grven the uncertainty of future electnc requirements and the entcal nature acceptance of the noks now being taken try some utilites. The Electric of an adertuate electnc supply, it is important that utdities have the Reliabihty Council is concemed that if our reguletory, economic, and flexit>hty to respond to changing trends in future demand.

i national escurity potcies do not reflect an increased awareness of the I nood for adequate future esectnc suppies, tne spector of unrelebte e6ectnc Utihtes' plans for adding new capacity are about the same as they were service may become reality. inst year. Several observations can be made about these plans FUTURE DEMAND GROWTH REMAINS e en the post year,there have toen no new orders for targe coal or UNCERTAIN nuclear unrts by United states utdites, and on'y one large coal unit was puced under constmeton.

Loneorm electricity growth forecasts continue to be uncertem. Electric

• ""*'"""****O'"*"YY'** Y**' e The program of building hydroelectnc and nuclear generstmg plants in Canada is proceeding. which wdl make more energy available to electncity use foNowing the price increasse caused by the 1973-74 oil embargo. Ten-year forecasts of peak demand and electric energy growth utihtes in the United States l

e Dunng 1964. 8 nuclear units were cancelec 6n the United States and 29 he as he others were oeisyed,24 coal units were also delayed an average of 20 Whetfor utihties can eatisfy future needs wiH depend on their ability to months.

respond to changes in peak demand and energy requ6rements. While the general economy has been strong 6n the last two years and demands have e Only 7 of the 16 nuclear unrts scheduled for 1964 operation in the

==4=d forecasts, tenth-year forecasts by the utilites have remained United States were placed in service about the same The United States' utilites are forecastmg 2.2% annual growth in summer peak demand and 2A% in electric energy. In Canada, e Cogeneration and renewab6e resources are beginning to appear as winter peak demand is expected to grow at 3.0% per year and energy at signifcant components of utihty generating expansion plans in Texas.

3.1%. Cahfomia and New England.

l l

l l

4 Smaller units with short lead turnes are gaining poputanty as a planning are in that situation because they have a large nuclear or coal unit under option with utilities. construction. Many such plants were planned to meet expected loads that have not yet matenakzed. Most utihties in good financial condition Overall, utihties are striving to maintain flexibehty while avoiding long-term achieved that status by svoiding such protects or completing them several commitments. There is a withngness to take the nsk that meresses in loso ywn ego. TM == son 6 me pien to see Thua with su,. excsWris.

growth will not outstnp the abihty to build or buy cap 9 city. financially healthy and ailing utihties s4ke are implementing a low capital, flexible strategy of resource planning as follows:

TRANSMISSION ISSUES 1. Maximize availatwhty and utilization of existing resources.

The transmission systems continue to be heavily loaded with economy 1 Purchase pw from m utihm cenwators and small poww energy transfers a high percentage of the time. As a result, there is a producws.

greater vulnerabihty to system disturbances and customer service interruptions. Building more transmission lines would increase the 3. Impioment load management and conservation programs.

capabihty to transfer economy energy and at the same time, ircrease the capabihty to respond to emergencies. However, there are impediments and 4. Install small, short lead time generating units.

disincentives to planning, hcensmg and constructing new knes.

For some utilities, these steps could be insuffcient to avoid occasional Since rehabihty has been exceed:ngty high in most regions since World capacity shortages. For those utihties, provis.ons for interruptmg and War 11, the constant supply of electreity has been taken for granted by the restonng loads will be needed pubhc and govemment offcials. The Electnc Reliability Council is concemed that this attitude, reflected in regulatory, economic and in pursuing a philosophy such as this, which evo:ds major capital investment polcy, will result in a gradual dochne in reliability not easily nor commitments, utihties beheve they are following pubic mandate.

quickly reverned. Customers on the North Amencan continent, while concemed with the cost of electncrty, are presently unaware of the effect that an unrehable THE UTILITIES' VIEW OF RESOURCE electne supply would have on them.

PLANNING AND RELIABILITY The Electnc Reliabihty Council is concerned that continued The current theme for resource plannng is " avoid commitments to large implementation of this philosophy willlead to unrehable electnC service in power propects.* Almost all the utshties now facing severe financial enses the 1990's, which the public w'll then find unacceptable.

m.

North American Electric Reliability Council The North Amercan Electnc Pohabihty Council (NERC) was formed by tne electnc ^ ^

uhhty industry in 1968 to promote the / \ N RELIABILITY of bulk power supply in the electre utihty systems of North Amenca. 9 J

NERC consists of nine Regional Reliability Councils and one affihate encompassing i f virtually all of the power systems in the United ) g <3 States and Canada RELIABILITY, in a bulk power electnc system, is the degree to which the performance of the '7 MPCC elements of that system results in power being delivered to consumers within accepted - g

]

standards and in the amount desired. The N i degree of rehabihty may be measured by the g

j _

frequency, duration, and magnitude of adverse j _

gea, ,asAAC Cffects on consumer service. I w gggggg s

Bulk power electrc system rehability can be L addressed by considenng two basc and sliF L functional aspects of the bulk power system-adequacy and secunty. j_ f i

i eBaC k

$_ c}g - #

ADEOUACY is the abihty of the bulk power ~h 5200T electnc system to supply the aggregate ECAR electncal power and energy requirements of East Central Area Rehab hty NPCC the consumers at all times, taking into account Coardination Agreement Northeast Power Coordinating Couned  ;

scheduled and unscheduled outages of ERCOT l system components. SERC Electre Rehabihty Council of Texas Southeastern Electnc Rehabihty Couned SECURITY is the abihty of the bulk power MAAC Spp electre system to withstand sudden distur- M'd-Atlante Area Couned Southwest Power Pool bances such as electre short circuits of MAIN WSCC unantcipated loss of system components Md Amenca Interpool Network Western Systems Coordmatmg Couned MApp ASCC - AFFILIATE Mecont nent Area Power Pool Alaska Systems Coordinatmg Couned CENERATING CAPACITY AND FUEL j Planned capacity additions in the United States for the has been deferred beyond 1994. Other nuclear units and

' 10-year period are about 17,600 MW (or 13.5'!c) less than some coal-fired units have been deferred because of report;d last ysar. Reductions in plans for coal and lower demand forecasts. Comparison of this yeafs and nuclear units account for essentially all of the cutback. last years projections for 1993 generating capacity are In Ccnsda, utilities arc planning to add 2.900 MW less shown in Tables 6 and 7.

capacity, all of this reduction coming in coal a%

There is a trend toward use of smaller units, partly nucinr units.

because of an increase in the number of planned oil / gas peaking units. The number of smaller units may c niinue to increase for several reasons. One is that CURRENT SITUATION smaller units take less time to construct and therefore l may incur lower financing costs and may allow Coal-fueled generating capacity provides more than commitments to be postponed. This is an advantage, 50% cf the electricity in the United States tcday, while considering the uncertainty of load growth and the hydroelectric units are the mainstay in Canada. Despita uncertainty of rate treatment upon completion.

coal's predominance in the United States, several regions continue to depend heavily on oil or gas. Advantages of smaller units are attainable with fluidized Nuclear energy will grow in importance in some areas bed combustion (FBC) units as well, and there is utility of the United States and Canada as new plants are interest in several FBC demonstration projects. The placed in service. The situation in each region is FBC units also have the advantage of meeting sulphur discussed in detail in the " Regional Assessments" dioxide (SO2) limitations without the use of expensive section of this report. desulphurization equipment.

I PLANNED CAPACITY ADDITIONS COGENERATION United States' electric utilities are planning to install Four regions or subregions of the Electric Peliability 113,200 MW of generating capacity from 1985 through Council expect to have significant amounts of 1994. Coal and nuclear-fueled capacity additions cogeneration capacity in service by 1994. The total amount to 42,200 MW and 46,300 MW, respectively. cogeneration in thess four areas is expected to reach Canad'*n electric utilities are planning to install about 9,000 MW in 1994, and represents at:out 5% of i 15,000 MW of generating capacity from 1985 through their total capacity.

1994. Coal, nuclear and hydroelectric capacity additions amount to 2,600 MW,6,400 MW and 5,400 MW, Expected Cogeneration respectively. These additions are shown in the

% 1'S4 accompar.ying figures and tables. Area cepecity (toes) Area cepecity ERCOT 4,270 MW 6.8 f

TRENDS New England 1,182 MW 5.3 Califomia 2,$27 MW 4.5 Tctal capacity planned to be added for the 10-year MAAC 1,029 MW 2.1 period is less than shown in last years 10-year projection. Nuclear projects removed from last years capacity list include Midland 1 and 2 (1,194 MW) and Cogeneration has been used for many years to produce Marble Hill 1 and 2 (2,260 MW). The schedules for electricity in connection with industrial processes where Seabrook 2 (1,150 MW) and Perry 2 (1,179 MW) are steam is a requirement. Favorable tax and regulatory under review and are not counted as part of the NERC treatment in the United States have increased the capacity during the review period. TVA's Bellefonte 2 potential use of cogeneration and small power production. The potential for cogeneration appears to be increasing rapidly. Some reputable parties are e a eM b exd M.M M

' capacity addit ons as reported for the April 1.1985 to December 31, However, the situation is very fluid, and any one of a 1994 period in ttw April 1985 " Coordinated Bulk Power Supply Prograrf (IE-411) Reports of the Regional Councits.

number of factors Could change the amount of

l cogeneration capacity that is EUE E actuaffy placed in service.

(United States) The fact that the construction ihm no e ww Papaue a W Jemmy. ises lead time is short may be a 15- significant advantage to the utility, both financially and in une" the flexibility of the planning C " "# " I ty nd pe ability of cogeneration units as a i capacity and energy source, to- and the long range prospect for continued operation. Since cogenerators are permitted to

. use natural gas or oil as fuel, their incentive to continue operation will be subject to price variations of these fuels.

5- p , Many will operate as base load 4 generation and may not respond effectively to the need to reduce output at times of light utility demand or during ll i =

_ c emergencies. It is anticipated

,, that cogenerators will be more o- G E" U= --

responsive to process needs Yews >85 06 87 86 88 90 9192 93 M 95 86 87 88 88 90 9192 93 M 86 86 07 88 80 90 9192 93 M than to the needs of utility COAL NUCLEAR HYDRO customers for reliable electric service. Many cogenerators will FIGURE 2 resist participating in voltage and frequency control.

Table a NERC - United States Installed Ger.arating Capacity -1993 Summer Comparison of Forecasts ,

l Thousands of MW This Years Last Years MW l Forecast  % of Forecast  % of Changein l Fuel Type for 1983 Total for1983 Total 1983 Forecast Coal 306.5 43.5 312.8 44.4 -6.2 Nuclear 110.4 15.7 115.6 16.3 -5.2 Hydro 68.5 9.7 66.9 9.4 1.6 Oil / Gas 186.6 26.5 183.1 25.8 3.5 Pumrmd Storaga 19.6 2.8 18.8 2.6 0.8 Other 12.6 1.8 13.4 1.8 -0.8 TOTAL 704.3 710.6 -6.3 Table 4 NERC Generating Unit Additions,1985-1994 NUCLEAR 1 United States Canada Number Thousands  % of Number Thousands  % of of Units of MW Total MW of Units of MW Total MW Planned, but not utility authorized 0 0.0 0 0.0 Regulatory approval pending 0 0.0 0 0.0 Regulatory approval received, but not under construction 0 0.0 0 0.0 Under construction less than 50% complete 6 7.0 15.1 4 3.5 55.1 Under construction more than 50% complete 35 39.3 84.9 4 2.9 44.9 TOTAL NUCLEAR ADDITIONS 2 41 46.3 8 6.4 COAL United States Canada Number Thousands  % of Number Thousands  % of of Units of MW Total MW of Units of MW Total MW Plenned, but not utility authorized 35 14.9 35.3 3 0.9 34.6 Regulatory approval pending 4 2.2 5.2 0 0.0 Regulatory approval received, but not under construction 5 1.1 2.6 0 0.0 Under construction less than 50% complete 21 13.6 32.3 3 1.1 43.5 Under construction more than 50% complete 21 10.4 24.6 2 0.6 21.9 TOTAL COAL ADDITIONS 2 86 42.2 8 2.6 HYDRO 3 United States Canada Number Thousands  % of Number Thousands  % of of Units of M W Total MW of Units of M W Total MW Planned, but not utility authorized 107 1.5 46.1 2 0.1 2.5 Regulatory approval pending 29 0.5 14.9 0 0.0 l Regulatory approval received, but not under construction 25 0.3 10.1 6 1.9 35.4 Under construction less than 50% complete 12 0.5 14.5 14 2.2 40.7 Under construction more than 50% complete 21 0.5 14.3 6 1.1 21.4 TOTAL HYDRO ADDITIONS 2 194 3.2 28 5.4

'Seabrook 2 (1,150 MW) and Perry 2 (1,179 MW) are included in these totals but are not shown on the charts of Generating Unit Additions or Generating Capacity By Fuel.

rTotals may not add due to rounding sDoes not include pumped storage NERC n?'ou"dif'" NERC itecraicoe rion.v, vet (United States) (United States)

- - , ~ . , -  %.,~,.

E53 HYDRO O NUCLEAR lE22 COAL o,(

GBl olLGAs M oTHER / 4,gg eco-esvasto l g lll lll l Il lll !!! -

OTHER g III NUCLEAn o.9%

lll 17.5%

)

"" NUCLEAR orwEn a,7s L*,t n

}

k '

o-4.is e.:

y 5 5 5 5 h E N N k 5 85 86 87 88 89 90 91 92 93 94 FIGURE 4 FIGURE 6 RETIREMENTS Planned unit retirements over the 1985-1994 period total Table 5 NERC Generating Unit 12,600 MW, essentially all of which is in the United States. The planned retirements amount to about one Additions, Retirements year's load growth. Increasing attention is being given

& Conversions, to extending the life of existing units and to improving 1985-1994 their availability. Such programs are influencing Thousands United  % of  % of decisions on capacity additions and retirements and of Mw states Total canada Total account for some of the deferrals and cancellations.

The capacity mix of additions between 1985 and 1994 is Nuclear 46.3 40.9 6.4 42.7 shown in Figures 4 and 5 for the United States and Coal 42.2 37.3 2.6 17.3 Canada, respectively.

Hydro 3.2 2.8 5.4 36.0 Oil / Gas 6.7 5.9 0.6 4.0 Pumped PROJECTED ENERGY AND FUEL Storage 5.2 4.6 0.0 0.0 USE l Cogeneration 6.6 5.8 0.1 0.0

Other* 2.9 2.6 0.0 0.0 North American utilities expect to provide nearly 3,400 Total million megawatthours of electricity in 1994. This is over Additions

• 113.2 15.0 27% more electricity than was required in 1984. Coal-fired generation is projected to its over-50% share of Retirements 12.4 0.2 total electricity generation in the United States by 1994 Oil-to-Coal while nuclear will increase its share to 22%2 and oil / gas Conversions 4.5 0.0 will decrease to 12% as shown in Figure 6.

' Totals may not add due to rounding the U K., west Germany and Japan, for examples AOSESOMENT OF POWER SUPPLY ADEQUACY in the United States. Installed generating capacity is However,8,300 MW of coal-fired capacity was dropped forecast to be riear the minimum acceptable levels in from the forecast while less than 3,700 MW was added, some regions by 1994 and may not be sufficient unless 24 units totaling 12,500 MW were delayed an average of cerfaln important actions are taken, in Canada, 20 months each. Another 18,200 MW of coal-fired electricity supply is judged to be adequate for the entire capacity is planned but not yet under construction. It is 1985-1994 period. questionable if all of that amount can be licensed and constructed by the time it is needed. Construction was Pnorities for assuring adequacy of electric supply in the begun on only one large coal-fired unit in the past year.

United States for the 1990's include keeping existing generating units in operation, maintaining schedules for Recenti f, some regulators have not allowed costs for units under construction and shortening lead times for coal and nuclear units to be included in rate base. In the siting. licensing. and constructing of new units. other cases, extended phase-in periods have been l required. These actions are preventing or discouraging l REQUIREMENT FOR FUTURE utilities from committing to further construction.  ;

ADEQUACY Reliability is likely to suffer in the process.

Electric power supply in the United States during the ACID RAIN 1985-1994 period will be adequate if utilities can:

In the past, the effect of acid rain legislation was Complete and place in service generating units considered to be heaviest east of the Mississippi River.

which are well along in construction. However, calls for further restriction in SO and NO, emissions are being voiced in other areas as well, in the Use life extension, refurbishment and maintenance United States, there remains a need to further programs to get the most out of existing generating document cause-effect relationships, assure equipment. effectiveness of any program offered for adoption, and achieve consensus regarding societal costs. Further Develop capacity attematives having shorter lead emission restriction would lower unit availability and times for licensing and construction. lacrease the power required to operate new emission control equipment. Any control equipment added to Resolve the acid rain question in a manner that will existing plants would require extensive unit downtime not result in an undue reduction of existing coal- while installation was made. While the outages required fired capacity, or in lengthy outages for retrofitting for retrofitting units with new control equipment can be units. acheduled in phases, some replacement capacity wou!d still be required.

Commit to new capacity that has a demonstmted need.

SHORTEN LEAD TIMES COMPLETE UNITS NOW UNDER CONSTRUCTION A reduction in the time between wmmitment and operation of a generating unit (lead time) would be of In Canada,6,400 MW of nuclear capacity,1,700 MW of great benefit in capacity planning. In fact, it could be coal-fired capacity, and 2,100 MW of hydro capacity considered the single most important step needed to presently planned for service over the next ten years is assure future electric supply adequacy, already under construction. The expectation is very high that all or most of this capacity will come into Smaller units are also being considered as a traans of service on schedule. shortening the time between commitment and operation and reducing capital requirements. The smailer units' The United States' situation for units under construction greater ratio of shop labor to field labor should does not appear as favorable. At present, there is minimize construction time. This is particularly true of 46,300 MW of nuclear capacity under construction. combustion turbines. Another type of unit being studied During 1984,3 units totaling 2,383 MW were indefinitely uses fluidized bed combustion, which can bum a wide delayed and 8 units totaling 9,040 MW were canceled. In range of coals or even refuse in an environmentally addition,26 units had their service dates delayed an acceptable manner. The smaller units should make average of 7 months each. Of the 16 ur,its scheduled for siting easier, and also ease financing of projects.

l commercial operation during 1984, only 7 (totaling l 7,566 MW) were placed in service. Based on continuing LIFE EXTENSION AND

( difficulties in satisfying all regulatory requirements and REFURBISHMENT obtaining operating licenses, the service dates of the remaining nuclear units must be considered For various reasons, raany systems have made studies questionable. of extending the life of existing units or of doing major maintenance to improve availability. Some have entered United Stes' utilities also have 24,000 MW of coal-fired into programs to implement the results of the studies.

, capacity under construction. These units are not These programs have the effect of increasing capacity immune to problems, but the outlook is much brighter in a short period of time. They can also allow delaying than for nuclear. Since last year,18 coal-fired units the decision date on new capacity additions.

totaling almost 10,000 MW were placed in service.

l l l i

l l

1986 ELECTRIC POWER SUPPLY & DEMAND FOR 1986-1995 1

FOR THE REGIONAL RELIABILITY COUNCILS OF THE NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL

- _ . . . _ . . __. _. T- - - ::_ _ :-- _ .. . = - - - - - - ~ -

@VERVIEW 1986-1995 PROJECTIONS DEMAND Annual Growth SUMMER 1986 1995 Rate (%)

NERC-U.S. 475 577 2.2 PEAK NERC-CANADA 47 61 3.0 l HOUR NERC-MEXICO 0.6 1.2 7.1 DEMANDS NERC-TOTAL 523 639 2.3

('Ihousands of MW)

WTNTER 1986/87 1995/96 NERC-U.S. 435 533 2.3 NERC-CANADA 65 83 2.8 NERC-MEXICO 0.4 0.8 7.1 NERC-TOTAL 500 618 2.4 ANNUAL 1986 1995 NET NERC-U.S. 2,525 3,103 2.3 ELECTRICAL NERC-CANADA 350 462 3.1 ENERGY NERC-MEXICO 3.0 5.6 7.3 POR LOAD NERC-TOTAL 2,878 3,571 2.4 (Millions of MWh)

SUPPLY Annual Growth SUMMER 1986 1995 Rate (%)

NERC-U.S. 636 715 1.3 PLANNED NERC-CANADA 85 96 1.4 CAPACfrY NERC-MEXICO 0.8 1.2 5.1 RESOURCES NERC-TOTAL 721 812 1.3

('Ihousands of MW)

WINTER 1986/87 1995/96 NERC-U.S. 655 727 1.2 NERC-CANADA 87 100 1.6 NERC-MEXICO 0.9 1.2 4.3 NERO-TOTAL 743 828 1.2 NOTE: As of 1986, the North American Electric Reliability Council's electric power supply and demand projections include the load and capacity resources data for Nova Scotia Power Corporation in NERC-CANADA. In addition, similar data is included for that part of the Comision Federal de Electricidad system in the northern portion of Baja California which is interconnected with the U.S. systems under the new category NERC-MEXICO.

TABLEI NORTH AMERICAN ELECTRIC RELIASILITY COUNCIL LOADS & RESOURCES DATA SYSTEM ACTUAL AND PROJEC1ED PEAK NOUR DEMANDS - SUMMER - MW 1996-1995 FORECAST 1988-1995 ACTUAL AVG. ANNUAL 1985 8996 1997 1988 1999 1990 1999 1992 1993 1994 1995 GROWTH (%)

NERC-U.S.

ECAR 6629.3 ;3356 70041 72212 73085 75042 76345 77710 79888 40666 92217 2.0 t

ERCOT 30062 30957 40239 41247 42784 44394 46002 47613 49436 58288 53052 3.5 8

MAAC 37053 34689 37049 L/377 37764 30864 30680 39126 39620 40094 40593 1.1

( MAIN 32432 35752 36219 36658 37246 37779 3840s 39024 39649 40287 40940 3.5 CNNWLTH EDISON T7H5 15250 T5550 T53H TTTYE THYE 16e00 17850 T75TO iT653 T3YTT 2.0 EAST MISSOURI 6124 6444 6526 6508 6660 6732 6014 6906 6999 7098 7193 f.2 S CENT ILLINOIS 5999 6535 6490 6495 6564 6632 6707 6791 6081 6998 7079 .9 WIS-UPPER MICH 7144 7523 7645 7725 7872 7965 8079 8177 0269 8365 8469 9.3 MAPP 19936 21541 22126 22479 22900 23334 23651 24059 24520 24956 25306 1.s NPCC 40010 40920 41950 42740 43350 43029 44430 45183 46045 46916 47701 f.7 g HEW YORK 22958 23020 23450 23940 24950 24420 24730 25070 25410 25790 26140 f.4 CD NEW ENCLAND 97059 17000 18400 19900 19200 19400 19700 20183 20635 2tl26 21561 2.2 SERC 98572 tettle 193578 196023 199922 819675 194645 997161, 119642 822134 124619 2.4 $

FLORIDA 21834 22012 22674 23Je9 23670 24255 25022 25639 2643I 27079 27794 2.6 g SOUTHERN 25510 25854 25932 26583 27225 27800 29660 29324 29890 30603 38265 2.4 TVA $8532 19279 19770 20174 21452 28858 22390 22934 23305 23780 24118 I 2.5 VACAR 32696 34373 35895 36027 36775 37762 38573 39264 40015 40750 48442 2.1 SPP 45826 47290 47827 40961 49921 51986 52435 53042 55226 54690 57920 2.3 l SOUTHEAST 19585 20l74 20024 20329 20645 21088 2:530 22148 72740 23344 23935 1.9 m WEST CENTRAL 15026 15833 16237 16676 17946 17630 19178 18704 19238 19707 20277 2.8 NORTMERN 10485 88291 18569 81856 52130 12398 12727 12997 13248 13479 13786 2.2 WSCC b 83889 84862 87292 89615 91773 93300 95449 97468 99944 192050 104000 2.3 NW POOL Y5YOY 26049 262e2 27270 27e72 2s285 2s540 29049 29709 30145 30530 1.s ROCKY MT-AREA 5739 6147 6462 6674 6893 7072 7368 7570 7777 8002 8213 3.3 ARI2-N.MEX 10072 10469 19189 11588 19974 12351 12702 13116 13556 33971 14404 3.6 CALIF-61 NEV 42106 42375 43359 44170 45100 45709 46846 47835 G995 49992 50969 2.1 i .. ..........................................................................................................

TOTAL (U.S. ) 460503 475093 406206 497211 500676 518704 530046 541198 553384 564983 576544 2.2 a) Interruptible loads are not included.

b) The sum of the subregional peak hour demands do not necessarily equal the coincident WSCC-U.S. total because of subregional peak load diversity.

I l

TABI2 E NORTN AMERICAN ELECTRIC RELIASILITY COUNCIL LOADS 6 RESOURCES DATA SYSTEM ACTUAL AND PROJECTED PEAK HOUR DEMANOS - WINTER - MW 1986-1995 FORECAST ACTUAL 1996/07-1995/06 1985/06 1996/87 1991/92 AVG. ANNUAL 1987/98 1989/99 1989/90 1990/91 1992/93 1993/94 1994/95 1995/96 G ROWTH (%)

NERC-U.S.

ECAR 45667 67355 69300 71077 72375 73694 75079 76496 78077 79609 99879 2.8 ERCOT 29776 31574 32845 34332 35967 37632 39499 48249 43209 45946 47820 4.5

( MAAC* 38652 32742 33323 33944 34638 35338 34038 36696 37337 37968 38590 t.8 MAIN 29060 28953 29499 30005 30752 39373 32097 32640 33294 33975 34661 2.0 CMNULTH EDISON 81713 81440 11670 19900 82840 12300 12630 12880 83840 13400 13670 2.0 EAST MISSOURI 5039 5868 5330 5482 5644 5804 5998 6170 6352 6544 6736 3.0 S CENT ILLINOIS 5487 5532 5531 5598 5685 5775 5876 5983 6097 6287 6334 1.5 WIS-UPPER MICH 6829 6013 6968 7112 7283 7412 7513 7607 7707 7814 7928 I.7 MAPP 18803 19249 89673 20018 20486 20007 21234 20646 22044 22433 22760 8.9 R NPCC 38233 39003 39940 40660 48220 48740 42370 43026 43979 44679 45409 f.7 5

c NEW YORet 755TE Y1575 YTT4 5 71755 72TY5 22440 IITT5 23:00 23520 23900 24260 t.6 m h NEW ENGLAND 17408 17973 18500 19900 19000 89300 19600 19916 20359 20779 21159 8.8 Y SERC 97854 99450 199478 104f93 106524 809366 991867 814359 917000 819806 122442 2.3 >

FLORIDA 23659 fUil 25380 25742 26245 2706 27786 2e715 29678 30535 38228 2.6 SOUTHERN 20453 28844 21508 21763 22498 22987 23469 23926 24395 24949 25574 2.8 TVA 20807 19233 9947e 20593 20041 23401 22800 22553 23028 23506 24117 2.5 I YACAR 32935 34285 35175 36097 37020 37937 38582 39257 40016 40766 4f530 2.2 g SPP 34618 34829 35816 36453 37426 30407 39537 40625 41787 42822 43863 2.6 Y SOUTNEAST 15054 44065 15046 15882 15487 15902 16212 16643 17069 17506 17919 2.1 8 WEST CENTRAL 81696 19647 12208 12461 12895 13326 13709 14226 14686 15151 15578 3.3 NORTNERN 7868 8317 8562 8810 9044 9259 9536 9756 9962 19865 19366 2.5 b

WSCC 77997 88592 83446 85587 87206 99267 90880 93256 95245 97225 97473 2.0 MW POOL 333H 34237 35040 36078 36704 37203 37762 3853s 39242 39820 38573 s.3 ROCKY MT-AREA Slet 6181 6351 6553 6740 7013 7214 7419 7630 7847 7702 2.5 ARI2-H.MEX 7998 8463 8686 8946 9278 9571 9040 80205 10508 19826 10966 2.9 CALIF-SO.NEV 32466 33865 34183 34583 35464 35939 36766 37700 38650 39387 40232 2.2

......................................................................................................me....i TO T AL( U . S . ) 423660 434767 445393 456349 466514 477704 488511 499985 511913 523663 S33407 2.3 a) Interruptible loads are not included.

b) The sum of the subregional peak hour demands do not necessarily equal the coincident WSCC-U.S. total because of subregional peak load diversity.

TABLE El MORTH AMERICAN ELECTRIC RELIABILITY COUNCIL LOADS & RESOURCES DATA SYSTEM ACTUAL AND PROJECTED HET ELECTRICAL ENERCY FOR LO40-Millions kWh (1996-8995 FORECAST) 1996-1995 ACTUAL AVG. AMMUAL 1995 1996 1997 8988 1989 1990 1991 1992 1993 1994 1995 GROgdDi(%)

NERC-U.S.

ECAR 347584 309000 399400 414000 424000 430900 437900 445700 453300 463300 469400 2.8 ERCOT 190758 194821 201561 207854 296609 226359 236283 245500 256098 266627 277404 4.0 MAAC 889678 199740 894009 196952 200168 203569 207168 210698 204890 217790 221004 f.6 MAIN 173589 177114 179948 L32216 111112 [S1311 D2612 until L11282 21342Z 207359 t.0 CNNWLTH EDISON 69674 70900 72300 73750 75225 76750 70300 79950 81450 03900 84750 2.0 EAST MISSOURI 29970 30454 31057 31583 32127 32682 33301 34013 34721 35432 36101 f.9 S CENT ILLINOIS 32615 33230 33097 32907 33430 33939 34446 35046 35505 36863 36739 1,1 WIS-UPPER MICH 40319 42530 43494 44816 45167 45970 46765 47552 49226 48942 49699 g,y j MAPP 195797 198923 112276 194469 186723 199250 121429 123869 926512 128977 131469 2.8 SU NPCC 220702 22162f 222222 22Z213 241791 245065 249972 222182 258345 263375 268044 f.9 HEW YORK 126032 827524 129700 132032 133792 135633 137547 339552 141443 143664 145752 1.5 NEW ENGLAND 94750 99104 802699 195879 197916 199432 191425 113935 116922 199471 122292 2.4 SERC 522640 526298 Eiflii 121322 570763 595233 603028 617495 529872 134278 657999 2.5 FLORIDA 192742 199929 195897 199685 123010 126473 329930 133223 836946 140711 844068 2.0 SOUTHERN 126793 126883 130977 132208 133887 136967 843010 196107 148574 151985 155433 2.3 TVA 198322 107J02 100429 112881 119702 128937 125852 117942 129693 131612 133673 2.5 VACAR 174791 180377 194968 199949 194964 199956 204936 2I0223 214659 220040 224925 2.5 E

SPP 229677 223357 224517 229434 233950 239596 245599 252642 259007 265426 279710 2.2 O SOUTHEAST 109039 902l30 100364 101678 102520 104489 106592 199666 192204 114762 197406 f.6 h WEST CENTRAL 74845 73133 74957 76732 79023 98352 G4027 86746 99366 92007 94526 2.9 g NORTHERN 47493 48034 49296 51031 52407 53749 55060 56230 57437 58577 59786 2.5 g WSCC 478790 487253 501911 516798 529042 539779 549603 562824 575576 588268 599724 2.3 5 HW POOL 885449 183299 189337 196364 200731 203525 205251 209202 213377 2t6753 219006 2.0 ROCKY MT-AREA 35404 37177 38428 39668 40999 41936 43127 44209 45310 46879 47886 2.9 o t

62428 64390 66393 68341 70452 3.3 p

, ARI2-H.MEM 50635 52300 55960 57241 58001 60657

! CALIF-SO.NEY 207002 2 4397 218136 223525 228512 232661 238804 245023 250506 256296 261380 2.2 8 i .............................................................................................................. ,

2586228 2654589 2788912 2778085 2842724 2908680 2972982 3039566 3803200 2.3 O TOTAL ( U.S . ) 2499226 2525135

TABLE IV NORTH AMERICAN ELECTRIC RELIASILITY COUNCIL LOADS & RESOURCES DATA SYSTEM 9966-8995 PLANNED CAPACITY RESOURCES - SUMMER - MW

( GENERATINC CAPACITY +SCPEDULED CAPACITY PURCHASES-CAPACITY SALES) I DH-IN5 AVG. ANNUAL 1946 1987 190s 19e9 199e 1999 1992 1993 1994 1995 GROWTH (%)

HERC-U.S.

ECAR 9195e 95209 96389 97994 97969 190386 800632 102154 182297 192735 1.2 ERCOT 45806 40610 51629 52939 53736 54793 56e34 Se75e 60945 63360 3.7 Maec 40996 5003e 50103 50157 50219 50123 507t2 50325 50347 50895 .4 NAIN 45536 48349 40076 49309 49239 49432 49M63 50277 50309 50424 1.1 CMMWLTN EDISDN 09071 24894 71EEE 21972 28972 IIS72 28972 28972 21972 21972 f.6 9 EAST MISSOURI 7989 7969 79e6 7966 7971 0047 0047 e343 934e e349 .5 5 S CENT ILLINOIS e633 9503 9503 9503 9503 9543 95e3 9e?9 9e79 9041 1.5 l WIS-UPPER MICN 9043 9643 9625 979e 9713 9838 9968 10003 10190 10262 .5 g

MAPP 20998 29221 29754 29702 30181 38305 30305 30202 30278 30705 .6 Q

NPCC 54453 56919 57503 57897 58232 59074 597f6 59652 lj t1R 60165 1.1 >

NEW YORK YTTTE 33i17 33568 33620 33e93 33959 349e8 34207 345e8 34698 .9 O NEW ENGLAND 22523 23407 23942 24277 24339 25995 25536 25445 25437 25474 1.4 4 SERC 132045 138649 140557 14411t 144512 146501 147007 148093 149506 151603 1.5 FLORIDA 30036 3061 YT3T3 ~32te4 322e2 3243: 32555 38269 30655 3t460 .5 o SOUTHERN 30193 31501 39456 34823 34154 34635 331e2 36556 37206 37646 2.5 $

00 TVA 29972 30342 31782 31712 31782 31782 31792 31712 32924 32924 1.4 O No VACAR 43444 45745 45998 46092 46364 47723 4e239 4e556 4e721 49573 1.5 E

' i ePP 65883 66161 66030 65960 66978 66057 655e5 66996 67362 60003 .5 g SOUTNEAST Tf4ET IfiT3 YTTH 2TITV 29000 19397 2e262 20373 27974 2ee70 .2 WEST CENTRAL 21944 21430 21364 28427 21530 21676 22044 22450 23106 23702 1.3 E NORTHERN 05250 15230 15346 15584 85564 15144 15279 16065 162e2 163tt .7 g WSCC" 1284te 124994 127995 128861 130621 139096 139943 932e72 134e35 f35e53 f.3 NW POOL 44922 44623 46534 46519 46549 47147 47894 47266 473tl 4692f .5 ROCKY MT-AREA 8999 9859 9305 9313 9353 9467 9469 9470 102e2 102e2 l.6 ARIZ-N.MEX 13764 85413 15e70 16176 17068 1747s 17503 17553 17636 17ee5 3.0 CALIF-SO.NEY 55t63 57005 50050 59506 60926 61201 62999 63794 649t6 65795 2.0

............. ....................................................................................=

TOTAL ( U.S. ) 635893 65e270 467956 677020 480507 693801 699te9 705970 784633 1.3 f40eI7 4

i al Since the subregional peak hour demands may occur in different months than the coincident total WSCC-U.S. pea 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> demand, the sum of the individual subregional resources based on those peak hour demands may not always equal the WSCC-U.S. total.

Also, the sum of the subregional resources does not equal the total WSCC-U.S. resources because in some cases firm power transfers have been reported for which either the buying or the selling system has not yet been identified.

TABI2 V NORTN AMERICAM ELECTRIC RELIABILITY COUNCIL LOADS 6 RESOURCES DATA SYSTEM 1996-1995 PLANNED CAPACITY RESOURCES - WINTER - NW (CENERATING CAPACITY + SCHEDULED CAPACITY PURCNASES-CAPACITY SALES) 1000 4 7-1995/90 AVG. ANNUAL

$996/97 1987/88 1989/99 1989/90 1990/91 1991/92 1992/93 1993/94 1994/95 1995/96 C ROWTH (%)

NERC-U.S.

ECAR 96799 97373 99460 99496 99999 191044 182590 18360s 193883 194545 .9 ERCOT 46934 50939 59791 53099 54546 56094 57893 60273 62747 64002 3.5 NAAC 51370 52437 52502 52514 51816 52869 52090 52743 52756 53304 .4 NAIN 47045 49328 49050 50241 50257 50374 50623 59312 55344 51378 1.0 CNNULTH ED1SOM 19248 28783 28401 22521 22529 2252I 22528 22529 2252t 22521 1.9 mr EAST MISSOURI 4034 8039 8080 0005 8090 8090 0090 8393 8399 9398 .5  %

S CENT ILLINOIS 9753 9753 9753 9753 9753 9753 9753 90049 18049 10011 .3

• WIS-UPPER MICH tette 9916 9996 9882 9893 10010 10259 10349 10376 10449 .5  %

O NAPP *29079 29639 29679 29955 30239 30333 38253 30096 31083 38528 t0 o NPCC 55405 57902 58517 50773 60493 60615 k

11427 60510 60521 60036 1.0 NEW YORK 31604 33664 33785 33948 34124 34258 34419 34438 34812 34922 1.1 O NEW ENCLAND 23889 24318 24732 24925 26569 26876 26099 26089 26024 25693 .e h s

yj SERC FLORIDA 537938 39533 149050 32427 144150 33037 145917 33239 146969 33355 140466 33535 149948 33875 151295 32361 151338 38755 154794 32636 f.3

.4 l

o e SOUTNERN 30289 39370 32466 33867 33728 34688 35736 36536 37025 37423 2.4 C TVA 30908 30700 3f079 3f071 31079 31879 38871 33083 34295 33003 f.2 $

VACAR 45215 46552 46776 46940 47215 49449 49159 49315 49475 50440 1.2 g 1

SPP 64224 66459 66399 66277 66325 66203 66042 67256 68590 69099 .4

( SOUTNEAST 29496 29333 29157 20034 29320 28972 28373 28128 28770 29285 .I i

WEST CENTRAL 21267 21599 2t559 21614 21519 21790 22f23 22921 23294 24042 NORTMERM 15478 15607 15698 15029 15494 85459 15546 16314 96532 1G562 1.4

.8 g

l WSCC" 123449 127962 #20799 830446 13f102 132200 132926 134151 135996 136830 1.1 NW POOL 46509 47415 47477 47494 47584 47479 47483 47558 47772 43025 .4 l ROCKY MT-AREA 9994 9409 9436 9475 9575 9579 9502 95e4 10394 10396 f.4 l ARI2-M.NEX 84595 15949 15616 16239 16953 17379 87470 17506 17680 17912 2.2 I

C AL IF-90. NEW 32638 55012 56727 57513 58653 59004 59995 60694 61996 62921 2.0

eeeeeeeeeeesommeeeeeeeeeme==ese===eeeeeeeeeemmeeeeeeeeeeeeeeeemmessenesseeeeeeeeeeeeesomemessessesse l TOTAL (U.S.D 654508 673946 680355 606728 691100 690198 703618 712253 719531 726895 1.2 a) Since the subregional peak hour demands may occur in different months than the coincident total WSCC-U.S. p ak hour demand, the sum of the individual subregional resources based on those peak hour demands may not always equal the,wSCC-U.S. total.

Also, the sum of the subregional resources does not equal the total WSCC-U.S. resources because in some cases firm power transfers have been reported for which either the buying or the selling system has not yet been identified.

i APPENDIX A l

i III. Ten Year Projections by the U.S. Department of Energy /EIA of Domestic Energy Consumption and Supply by Sector and Fuel Type The following excerpts are reprinted from the most recent report of the Energy Information Administration of the U.S. Department of Energy, " Annual Energy Outlook,1985 With Projections to 1995," DOE /EIA-0383(85), February 1986, 100 pp. The excerpts include:

(1) Administrator's Foreword: Prophecy or Statistical Service?

(2) Comparison of Energy Suppl, and Demand Projections for Different Energy Sources (3) Trends and Projections of Total End-Use Energy Consumption by Economic Sector (4) Trends and Projections of Energy Consumption of Sectors by Fuel Source (5) Electric Utilities and Nuclear Supply (includes demand and supply projections of electricity by type of fuel)

Administrator's Foreword:

Prophecy or Statistical Service?

No one can responsibly claim to know precisely what presence of a very nervous market where prices are will happen in energy markets over the next 10 years. seemingly unable to stay at current levels, given the Any forecasts, including those in this report, are at best oil producing countries' intense efforts to retain, or to informed judgments about what is likely to occur. Be- increase, their respective market shares. These short-cause of the limitations to this inexact science, these term price swings notwithstanding, the fundamental forecasts are offered as information to interested users, message in this issue is that real prices of crude oil are providing a range of possible outcomes, rather than as likely to come down and stay low the next few years, a government plan for the next decade. The projections but that they will recover and resume their upward should be viewed more as a statistical service than as trend by the end of this decade.

a prophecy of future events.

The longer term forecasting models used for previous In large part, these forecasts are based on historical editions of this annual outlook relied on relatively less trends in energy production and consumpthn, modi- current but detailed sectoral data. During the most fled to reflect current and expected future conditions. recent period of falling energy prices, these models This process is aided by a modeling system that is used were not able to anticipate the continuing conservation to forecast a consistent series of energy balances for efforts of consumers or the stability of domestic energy the United States based on specified assumptions. The production. In an attempt to adjust for this failing, solution of these models in each case identifies a market aggregate targets were established this time for key clearing price (the point where supply equals demand) energy trends--based on historical trends, but also in-for each form of energy, and the corresponding levels corporating current information on apparent changes of consumption and production for each form. to them. These designated targets include the annual rates of change in the ratio of total energy consumption Both U.S. energy demand and the supply to meet it to GNP, petroleum demand growth, and several other are affected directly by energy prices, especially the major trends that are interrelated with energy supply price of oilin world markets. To highlight this impor- and demand. An internally consistent extrapolation of tant link, the relationship between energy prices and these trends may provide the framework for a more movements in supply and demand is a major theme of reasonable picture of what energy markets could look this report. Energy markets also are strongly influ- like over the next 10 years.

enced by economic growth. Because world oil prices and national economic growth are critical but uncer- The outlook for the future that emerges from this new tain variables in the forecasting exercise, a range of approach is more conservative than previous forecasts results for energy supply, demand, and imports is pro- from the Energy Information Administration. Energy duced using alternative assumptions about these vari' consumption is expected to grow minimally, as the ables (higher and lower than those used for the base continuing effects from the high energy prices of the case). Demographic changes and other economic de- 1970's (which should further improve the efficiency of velopments are likely to influence energy supply and ener8y use) combine with several long term trends, demand too; but these factors (such as the population .

growth rate and age distribution, turnover in the stocks such as slower population growth and m.eresses m the of buildings and automobiles, and the size of domestic efficiency of the automobile fleet. Slower net growth energy reserves) have been kept at the base-case values in U.S. demand for energy translates into an expected throughout the projection exercise. rise in oil imports that is significantly less than estimat-ed just a year ago.

The accuracy of forecasts usually depends on the valid-ity of the underlying assumptions. Yet this forecasting These projections thus incorporate historical trends, system assumes no changes to current law and no new some recently recognized changes, reasonable assump-legislation, so the effects of such possible modifications tions about key variables, and a good bit of professional are not considered. Furthermore, trends in energy pric- judgment. By representing the most likely energy fu-es or economic growth that are markedly different ture based on such current knowledge, this report of-from those assumed here would probably result in a fers those who are interested in the U.S. energy market i different energy supply and demand future than this some potentially useful insights into many key factors i

report pictures. Finally, by definition, the effects of affecting energy supply and demand. The way free unpredictable world events (such as heightened unrest market choices are made now (based not only on pro-in the Middle East) cannot be reflected accurately in jections like these, but even more on a multitude of advance. Circumstances could change. diverse individual preferences, perceptions, logic, and

( intuition) will be the final crucial determinant of the As always, long term projections such as the one at accuracy of these forecasts over the next 10 years.

hand follow relatively smooth trajectories when, in fact, the variables depicted may be subject to wide short term swings of considerable magnitudes. As the Dr. H. A. Merklein deadline for this volume approaches, the world is once Administrator again in the throes of a violent downward swing in

, Energy Information Admimstration mternational crude oil prices. This simply indicates the

Table ESS. Comparison of Energy Supply and Demand Projections, 1995,1990, and 1995 (oundrtmon Stu per Year) we2 mv im l

Low High Low Migh Ott Base Ott Oil Base Ott Imports Case Imports Imports Case Imports Domestic Energy Production Oil ............................. 21.3 20.5 19.6 18.7 18.1 16.3 14.1 teatural Gas ..................... 17.6 17.7 17.9 18.1 17.2 17.5 17.2 l

Coat ............................ 19.6 21.5 21.7 22.0 24'.0 24.3 leuclear Power ................... 24.6 4.2 6.2 6.2 4.2 6.6 6.6 6.6 leydroelectric/

Geothereal/0ther ............... 3.1 3.4 3.4 3.4 3.4 3.4 3.4 Total ........................ 65.8 69.3 68.8 68.3 69.3 68.3 46.0 feet Imports Oil ............................ 8.8 9.9 12.1 14.1 12.8 16.3 21.2 seatural Gas .................... 1.0 1.9 1.9 1.9 2.5 2.5 Coal, Coke, and 2.5 Electricity .................. -1.7 -1.7 -1.7 -1.7 -1.8 -1.8 -1.8 Total ........................ 8.1 10.1 12.3 14.3 13.5 17.0 21.9 Total Primary Supplya ............ 74.8 78.7 80.4 81.9 81.8 84.3 86.8 End-Use Consumptionb ltesidential .................... 4.9 9.5 9.7 9.8 9.8 10.0 10.2 Commercial ..................... 5.9 6.4 6.5 6.5 4.6 6.7 Industrist ..................... 6.8 21.3 22.2 22.7 23.2 22.1 22.7 23.5 Transportation ................. 20.0 19.4 20.1 20.6 19.4 20.3 21.2 Total ........................ 54.0 57.4 59.0 40.2 57.8 59.8 41.7 l'

aincludes domestic production plus not imports, stock changes, and other adjustments.

l bDoes not include fuel used by electric utilities for the generat on and i j transeission of electricity. Lease and plant fuel is included under j industrial consumption.

j Isota: Totals may not equal sum of components because of independent rounding.

Source: Tables A1, A2, B1, B2, C1, and C2.

Figure 1. Total End-Use Energy Consumption by Sector, 1970-1995 The industrial and transportation sectors are expected to remain years.

the major consumers of energy over the next ten History Projectio n s eO eO e

> e "g s o s o 'g

~5 ~

E Indu s trial 3 l d 4o E ,

3 40 0 )

en -

3

., , , , , , , Comm ercial . ' '}; ali 3* 20

^ ,s SWeiig%_

u m e. g .. ma%wsgimaassss%..

m .w . . m. n ti . .

Ml' ! -

sf v ! s,-20 8 8 10 '

l ira n s,p o rt a tio n i >10 1

1 O . ,

1970

,O 1975 1980 1988 1990 1995 source: En o ra v Inf o rm ation Asiministra tion, me nt e Kn a re w nata st e n a r t _

co n n u m a nia n ma nTm a na m _

s ma n. ta a 2. Do E/EI A-0214(5 3) (19 55).

Figure 2. Residential Energy Consumption by Source, 1970-1995 The share of electricity in residential energy consumption is '

projected to continue growing -- expanding from 30 percent <

to 35 percent between 1985 and 1995. I History Projections 100 Coal 100

~B ,

~B 3 So- i -90 3 g sO- +,

Electricity., ,

-so g

E .

E o ,

O  ;;Rd:id? {!gg,,((gg -j;Rj- e u

- 7O- ;d - .gy,

..(i.fi' g.,;,0 g5 i }x;' .$',;w ',<g;.: ,

,. .; ;,4;. : , , , '

-7O -

!$$!i 5 . ,$$<<y' C((>{j<b'i }$$!$$,0:-S.$:dj;Q!{ g

>9 # " N,!b -, ! (' ge'IO,,

,; p ,{:0$ ',0,N v < - ,, , , -,- ,

~~l 60-  !! (< , ' !<!di#'IN#:;>b -

~

,i-SO W h b,<S$![', , "[ ]:?$';[{ 'v{j!f'!'!$!iS9:

,W,

{E}?i!# #h ; N ';!; ' '! ', ,' ! ' < '::;$: '[ [ yej ", ! '< : $

e 60-1 60 5 c

o , , , , , , o U 40- , , , , , ,, , , , ,

-so U q-

, ir , , , , , ,

Natural Gas -

pO 30- '

--- 3 0 @

', ', ', ' , , l ', ,'

$g 20- <

,a

-20 $c GP , , ,, , ,, e M 10- ,' ,, ' ' ,'. -10 M CL as ', ' , , ,

es cm.

O , , , , , O 1970 1975 1980 1985 1990 1995 Note: Renewable s, such a s wood, sola r, and wind, a re not included.

source: Ene ra y inf orm a tion Adminletra tion, Sta te Enernv Data M an ort _

con s u m ntio n E n tTm a t a a _ 1a s o.1 e a 3, D o E/EI A- 0214(8 3) (1985).

Figure 5. Commercial Energy Consumption by Source, 1970-1995 By 1995, electricity is projected to meet 45 percent of the energy requirements for the commercial sector.

History Projections too Coal 100 e :6 ~B 1

.E So-  : Leo .2t '

E ik,  %

eO-Electricity 3 E -

r- e O E s e a b 70 W-: :L70 )

.O j

.*d S O j: ,

-60 -

g 1 E 1:: ' -

. ._- E I a so y: ,

0 11 , -

_sO

, g g p. --

) g U AOd - e40 U j .- y -

. .. - 4 S

20q ,

f, 3 o @ _

J l 20- Natural Gas .L 2 o I

e * -

c e < t e i i M 10 2 .-10 M l

cf J ,'r cE  :

O , , , , , $0 1970 1976 1980 1985 1990 1996 I

Note: Renewables, such a s wood, solar, and wind, are not included.

(

I Source: Energy Inf ormotion Administration, State Enernv Data M a n ort _

i con s u mntio n Es tim at e s. 19 8 0 - 19 a 3. D o E/ EI A- 0214(8 3 ) (1985).

1 s

Figure 7. Industrial Energy Consumption by Source, 1970-1995 The use of electricity in the industrial sector is projected to int. csase its share over the f orecast period, but oil remains an importent industrial source of energy.

History Projections  ;

too T

eo jj Electricity ,

too g

3 1! i -eo 3

_=

j so

_e

= Coal and Coke so $

M M

=

-I- y::: :y:3, e 7o 1::

7o

,o - ,

e

'J:::.::;:!. :,, , . . -.::- ,y: ':, , ::t a eo-,

,o E -: ' '

','! Oil Pr o d u c t a ' ' ' ' > ,feo

~

g R so M[:: -

E c '. ,a *

, * < , ,: Oncluding , ?:Q: ,

' i.jk s o 3 U

o 1:

a o W:,

, ,-  :' F,e,e, d, s,t o c, k, s) ,- ::- - ' -<' c x, ,

, , ..' - ' , ' , g. ':;-40 o

, j- :4 ,

0 so g '

:g S .

so C

g e. - y6 n o Y.

g E Na tu ral Ga s '. ~*O o 4 E o

M

-10 2 cE to,o )' .

',-r cE te7o te7s teso sess teso

~l o teos Note: Renewable s, such a s wood, sof er, and wind, are not included.

co source: Energy Inf ormation Adminletration. Etate Enarav Data R e n art _

n s u mntio n E s tim m te n _ teso-1ee3 D o E / E I A - 0 214 ( s 3 ) (t e s s).

Figure 9. Transportation Energy Consumption by Source, 1970-1995 Distillate fuel oil is projected to increase its share of consumption in the transportation sector between 1985 and 1995 because of increased use of diesel-fueled trucks.

History Projections too too 1::M:i ' ,

M g

vo so,

,. , i: ::

<3.,

,-~ '

'i Jet Fuel i

-!:L yo S

-:t

1 '

E s >

.yeo g g s o _j - '- E c J ',

Motor Gasoline .g eo g o c O 4o1 ~.

o

= l' .L 4 o U

=

N 30k ,b 8 0 N

'o 2o is I-2o 'o a

E I "

M to - d o sE Y .-to M

o. I sE se7o ie7s seso sees

$o ieeo sees source: Eneroy Inf ormation Adminlettation, state Enarav Data Rennet _

consumntion En tim a t e n _ t e s o - 1 e B 3, D o E/EI A-02TUs 3) ( t s s a).

_ _ _ _ ________ - ^ - - - - l

Figure ESt. Primary Versus End-Use Energy Consumption by Fuel Type: M ?5, 1985, and 1995 Aithough the demand for primary energy tthe entire stee of each circle) to projected to incrosse slowly. energy use et electric utilities tthe eroe of the inner circle in each esse) le forecent to grow more rapidly and thus account for en increening ehere of totei energy use.

, 01 f,.h

.'d h.L

] M ydro'

'. n

/  ; //

Nucio.r

~

osi :

1975

/, .

(70.5 Quadrillion Btu) h Coal j

G

',o~.il s Mydro' h

> =

Nuclear

/ Gas

// + 7 -b b $ y' Area of inner '7 circle represents l fuel use at electric 1985 [

utilities- (74 8 Quadrillion Blu) ,

5 a

Oil yw

.msn -

Nuclear Outer circle represents end use consump' ion of fuels.

1995

• Share of other renewable sources is too small to represent at this scale.

(84.3 Quadrillion Btu)

Electric Utilities and Nuclear nolosical Preference for electricity in most sectors is projected to be reinforced by a decline in the real price Supply of electricity through 1995.

Demand for electricity is projected to increase by 2.7 Generating Capability percent per year between 1985 and 1995, close to the rate projected for GNP growth over that period, Al. Largely because of a current excess in electricity pro-though the growth rate in electricity output has slowed duction capacity, total generating capability' (net of considerably since the 1970's, electricity demand still retirements) is projected to increase less rapidly than is expected to grow more rapidly than the demand for electricity demand between 1985 and 1995-growing other energy sources over the forecast period. A tech- at an average annual rate of about 1.2 percent over that

'Capabihty values pubbshed here differ in three respects from the nameplate capacity values published m previous editions of EIA's Amal I

Ewry Outlook. First, pubhshed capabihty values desenbe " net summer capabihty", the load. carrying abihty of a generator under adverse conditions (usually in the summer) for a specified time period, these values are generally about 5 to 7 percent below the nameplate capacity values l i

pubhshed in the past. The net summer capabihty value also includes a small amount ofinactive capacity that was formerly excluded. Furthermore, capabihty values projected here are net of expected retirements, which are expected to total about 15 gigawatts between 1982 and 1995. AEO projections published in earlier years did not reflect these retirements.

1 period. Total net d:pendable gen:r ting capability in the United States, estimated to be 642 gigawatts in Utility Fu;l Us] cnd imports 1985, is projected to increase to 685 gigawatts in 1990 and 727 gigawatts in 1995 ( Table 10). Most of this Utility fuel use is constrained by fuel economics as well increase is expected to be in new coal capability, with as by the availability of generating capability. Al-net additions of 39 gigawatts forecast between 1985 though the vast majority of the oil- and gas-fired capa.

and 1995. Significant nuclear capability is projected to bility that was in use during the 1970's still exists, the be added through 1989, with additions tapering off fuel costs of utilities are lower when coal and nuclear thereafter through 1995: Net nuclear additions over the power can be used instead of oil or gas. Because this next decade are anticipated to total 32 gigawatts, with fuel-cost relationship is not expected to change appre-total nuclear capability equaling 15 percent of total ciably, and because the size of the present generating generation capability in 1995. All of the expected nu. base is so great, the percentage shares of electricity clear units and the majority of the new coal fired facili. generated by the various fuels are projected to change ties are already under construction. only slightly over the next 10 years ( Figure 14 on page 39 and Table A5). The share of nuclear genera-Additional new generating capability not currently tion is projected to grow from nearly 16 percent of planned or under construction may be required to meet total generation in 1985 to about 19 percent in 1995, the level of electricity demand projected nationwide with nuclear output increasing in absolute terms from for 1995. Some of this potential shortfall in generating about 383 bilhon kilowatthours to about 606 billion capability may be met by other means, such as conser. kilowatthours. Despite new coal capacity additions, vation, electricity imports, increased bulk transfers of the percentage share of coal generation is forecast to drop from 57 percent m 1985 to 56 percent in 1995 power, load management, cogeneration, or deceptral- (although the actual contribution from coal over this ized generation. Projections of the amount of addition-al capability needed through 1995 range from 13 period is projected to rise from about 1,400 billion kilowatthours to nearly 1,800 billion kilowatthours),

gigawatts to 25 gigawatts, depending on the level of because total generation grows more rapidly than coal electricity demand resulting from different assump- capability.

tions about economic growth and world oil prices.

This range of additional generation requirements is Generation from coal and nuclear energy is used (and based only on the cases contained in this report. Differ- probably will continue to be used) chiefly to meet ent values assumed for peak demand, reserve margins, baseload electricity demand. Because existing and or retiremer.t rates could expand this range consider- planned capacity of this type appears to be inadequate ably. to provide all of the additional generation that will be Table 10. Electric Utility Net Generating Capability by Type, 1974-1995 (Gigawatts at End of Year)

History Projections capability Type 1974 1954 1955 1990 1995 Coal-Fired ..................................... 176 275 280 295 319 Nuclear Power .................................. 32 70 79 105 111 Oil- and Gas-Fired Steam ........................................ 137 152 145 141 135 Turbine ...................................... 37 44 43 45 61 Combined Cycle ............................... 2 5 5 5 5 Other Hydroelectric and Othera 57 72 74

..................... 76 77 Hydroelectric, Pumped Storage ................ 9 14 16 18 19 Total ..................................... 449 631 642 685 727 aIncludes geothermal power, wind, wood, central station solar, and waste.

Note: Components and totals rounded independently. A gigawatt is 1,000 megawatts or 1 billion watts.

Source and additional notes: Table AS.

l

r l

t Figure 14. Sources of Electricity Supply, 1970-1995 Coal and nuclear power are expected to provide rnost of the increase in electricity generation requirernents.

3,,_

History Projections _

y 3- es y:=

R Natural Gas g "Ei 2 . 5 -. 4 b j '

24  ! Nuclear i

'~~ ~

2 y  :.l:.

so 1.6 1.6  %

I ll 3 1 9

.0 8 0.6 0.6 Other l l

1970 1976 1980 19'86 19'90 19'O6 Note: other consists of hydropower and reesowebles.

oo!7Ei2*5s's"2t's23 Y O U I." " ^""""'* * ' "" ^""""'"""'" " "~^'***'

needed to meet electricity demand growth by 1995, ty generating systems in this country is highly depen-natural gas- and oil-fired generation is also projected dent on the relative prices of natural gas and low-sulfur to grow during the next decade, particularly after 1990. fuel oil to utilities in certain regions. If crude oil prices Generation from the two latter sources combined is should rise significantly, as assumed in the low imports projected to increase from 392 billion kilowatthours case, utility fuel oil would become relatively*more in 1985 to 501 billion kilowatthours by 1995. All of this expensive than natural gas, and its share of total genera-increase is expected to occur after 1990, with fairly tion would fall. Conversely, very low oil prices could similar increments in generation projected from gas conceivably make fuel oil relatively more attractive to and oil. However, growth in generation from these some utilities.

sources could be moderated if utilities announce and complete new coal-using facilities between now and Net imports of electricity to the United States have 1995. The level of central station electricity generation grown steadily over the past 10 years, from about 13 by hydroelectric dams and other sources is expected billion kilowatthours (0.1 quadrillion Btu)in 1974 to to change only slightly over the forecast period (except 39 billion kilowatthours (0.4 quadrillion Btu)in 1984 for years of unexpected drought or heavy precipita. (about 2 percent of total electricity supply in the latter tion). "Other sources" include geothermal, wood, year). Most of this electricity is purchased from Cana-waste, wind, photovoltaic, and solar-thermal energy da, although a small amount comes from Mexico.This ecurces connected to electric utility distribution sys, electricity trade is rn important source of electricity tems. All these sources accounted for less than I per. for certain regions of the country where relatively cent of total central-station generation in 1985, and higher cost oil and gas generation is displaced by rela-their combined output is not expected to grow signifi. tively cheaper imports. Electricity imports could reach cantly in absolute terms over the next 10 years. 80 billion kilowatthours (0.8 quadrillion Bru) by 1995 (remaining at about 2 percent of total supply) if all The choice in the use of oil versus and natural gas as current international trade agreements are maintained the marginal sources of primary fuel inputs to electrici- and those under consideration become firm.

i APPENDIX A IV. Excerpts from the Report of the Edison Electrical Institute on the Outlook for Reopening the Nuclear Option The following excerpts are reprinted by permission of the Edison Electrical Institute from the report of the EEI Task Force on Nuclear Power, " Report of i the Edison Electrical Institute on Nuclear Power," February 1985, 69 pp. The excerpts include:

(1) Executive Summary (2) The Need for New Capacity, 1984-2000 (3) Two, forecast charts on U.S. electric generating capacity and peak demand (4) One table on additional capacity needed by the year 2000 i

4 5

-1 01-

EXECUTIVE

SUMMARY

American electric utilities have virtually ceased ordering new electric generating ccpacity of any kind. They are completing existing construction programs as ra-pidly as possible and are moving into a period in which little new capacity will ba under development.

This impending absence of construction reflects two facts:

e Generating capacity that was ordered in an environment far different from that in which the utilities operate today will be sufficient to meet the electricity demands for a number of years.

e Electric utilities now face strong economic and financial disincentives to undertake new construction. Recent improvements in the industry's financial health are closely linked to the completion or winding down of current construc-tion programs. On the other hand, both the utilities and the investment com-munity recognize that major new construction is likely to cause severe deteri-oration in a utility's financial condition.

But demand for electricity continues to grow. In the years after the Arab 011 Em-i bargo of 1973, total demand for energy in the United States declined. But demand for electricity grew at the same pace as the economy. While the exact rate of

growth is uncertain, electricity use will keep on increasing throughout the 80s cnd 90s.

With a growth rate that is modest by historical standards, additional generating espacity will be needed by the mid 90s. By the year 2000, America is likely to nred at least 100 to 200 million kilowatts of generating capacity in addition to the power plants now in place and under construction. If the capacity needs of the mid 90s are to be met with conventional generating units that take 6 to 8 years to build, many utilities will need to resume construction during this decade.

But the dominant public view is that electricity supplies will remain ample with-out any substantial additions to the current stock of generating units.

In our judgment, the United States is on a course that is full of peril. Our coun-try has drifted into a de facto electricity policy that it would not deliberately choose. But if we can soon adopt policies shaped by a long-term view of our elec- ,

tricity situation, it is not too late to avert serious damage to our economy. I For future electricity needs to be met, utilities must agait. be willing and able to build new generating units. This requires reforms in economic regulation to casure that utilities can finance the investments they are making und to provide a reasonable treatment of the risks inherent in building electric generating plants.

If too little economical generating capacity is built, the lights will probably stay on but the United States will pay heavy penalties in losses of economic growth, jobs and income.

For future electricity needs to be met at the lowest cost, utilities need to be Eble to choose among the best options that the state of technology will allow --

including measures to reduce demand below what it would otherwise be through con-sarvation and by shifting use away from the times when demand is highest.

But as it is now, the principal options available to utilities are limited to de-acnd-reducing measures and conventional coal-fired plants. Demand-reducing programs, l

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a. __ - ._ ._ - . . .

which exist in nearly every utility system and can be expanded, can reduce or post-pone, but will not eliminate, the need for new capacity.

New conventional oil and gas fired plants are ruled out by high fuel costs and un-certainties about future fuel supply, as well as by current law.

And under present regulatory and institutional arrangements, no American electric utility would consider ordering a new nuclear power plant. The cost and risks of nuclear development in the United States have become unacceptably high.

1 Yet, based on earlier experience in the United States, on current foreign experience {

and on economic analyses, nuclear power could again be an economical means of meet-  ;

ing future demands for electricity safely and reliably, and an option that utili- '

ties could rationally consider. The problems of the current generation of nuclear units in the United States arise not from the nature of the technology but from the way we have chosen to regulate and manage the nuclear enterprise.

Reforms that would lower the costs and risks of new nuclear units would move in the same direction and have the same purpose as the ongoing development of new non-conventional generating technologies that may have attractive costs and opera-ting characteristics. Both will enhance the utilities' ability to serve their customers reliably at the lowest possible cost.

To address these issues, we are making recommendations in two major areas:

To consider the need for new electric generating capacity and how it can best be met, we recommend the prompt appointment of a National Commission on Electricity.

The Commission should consist of a small and expert group of distinguished Ameri-cans who would complete their work expeditiously and report to the President and Congress within six months. Taking into account the irreducible uncertainties, the Commission should make judgments on the future growth of electricity demand and the means by which any need can be met by both reductions in demand and in-creases in supply. If it finds that additional generating capacity will be needed, it should consider the circumstances under which it would again become economically rational for utilities to make major capital investments and the generating op-tions that should be available. That would include consideration of the need for, and the nature of, actions that would again allow utilities to consider building new nuclear units.

We hope that the Commission's findings and recommendations would lead toward a national consensus on issues that have hitherto been marked by controversy and

an absence of realism.

To address the problems of nuclear power, we recommend a broad agenda of reform in the industry and in government regulation of nuclear power.

I We recommend that the industry:

( e adopt and present for licensing standard designs for new nuclear power units; l

e maintain excellence in the operation of existing nuclear units and continue j its record of safe nuclear operations; i

l e continue efforts to educate the public about nuclear power;

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e prepare for greater use of joint ventures and separate nuclear companies as a means of spreading risk and achieving a better match between capacity additions and load growth, and e develop nuclear units only through contracts providing for sharing of the risk of cost increases among the nuclear suppliers, architect-engineers and electric utilities.

We recommend changes in Federal law and regulation so that:

e standard nuclear plant designs are approved and units proposed to be built according to those designs are promptly licensed; e nuclear plant sites are considered and approved in advance of an application to construct a plant; e new regulations requiring changes in design at units under construction and in operation would be adopted only if they would clearly produce substantial benefits to the public safety and health of equal or greater value than their cost; e in place of the current two-stage licensing system, a single license would permit construction and operation once the NRC had determined that the plant as built conformed to the approved design and met qualicy standards; e NRC public hearings would be more like legislative hearings and less like a trial and be limited to previously unresolved issues concerned with nuclear safety and supported by substantial facts, and e a utility building a unit on an approved site would be able to put in place an emergency plan to protect public health and safety.

We also recommend:

e examination of the management structure of the NRC with the objective of improving the organization's effectiveness and efficiency; e resolute action to implement the existing Federal legislation to provide for the safe, permanent disposal of highly radioactive nuclear wastes and to de-velop regional sites for disposal of mildly radioactive materials; and e extendion of the Price-Anderson Act with the continuation of a cap on utili-l ties' total liability.

l The crucial result of these recommendations would be to reduce sharply the time cnd cost required to construct a new nuclear unit and to lessen the risk of un-cxpected cost increases beyond the control of the utility.

Moreover these recommendations would increase the already high level of nuclear plant safety and provide for full public participation in all the major decisions concerning nuclear plant development. As the need for additional generating capa-city becomes widely understood, these reforms will foster increased public support for nuclear power. Because it will take some time to restore nuclear power as an cption utilities can consider, the effort should begin at once.

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- )

The electric utility industry is not attached to nuclear power for its own sake.

Rather our interest and obligation is to provide reliable electricity service at the lowest cost. We advocate these reforms because we believe nuclear power, if sensibly managed and governed, can again play an important role in achieving that objective.

1

-1 06-

_________ - _ n _ _

The Need for New Capacity, 1984-2000 As might be expected, uncertainties about all of the factors affecting the need for new capacity result in a range of estimated need. It fa possible that the additional generating capacity needed by the year 2000 could be as little as a few million kilowatts and as much as 500 million kilowatts - or about three quar-ters of today's installed capacity.

The following chart shows the need for new generating capacity -- or additional demand-reducing measures -- with different rates of growth of peak demand and as-suming the completion of all of the generating units now under construction and no capacity retirements other than about 15 million kilowatts reported to the North American Electric Reliability Council as planned through 1993.

With demand growth of 2.5 percent and a capacity margin of 20 percent, additional capacity is needed by 1992 and a total of 152 million kilowatts of new capacity or demand reductions will be needed by the year 2000. Of this need, 34 million kilowatts of capacity have been reported to North American Electric Reliability Council as planned but not under construction.

In the present economic and regulatory environment, some of the nuclear units now under construction may not be completed or permitted to operate. For example, if 8 million kilowatts of the capacity under construction are cancelled and if one third of the units over 40 years old are retired, the capacity needed by the year 2000 would total 192 million kilowatts with demand growth of 2.5 percent. Capacity needs with these assumptions are shown on Chart 5.

The amounts of additional generating capacity needed by the year 2000 with differ-ent assumed rates of growth in peak demand and with alternate assumptions con-cerning cancellations and retirements are shown in the following table, l i

Table 1. Additional capacity needed by the year 2000  ;

(millions of kilowatts)

Limited Annual Growth No Retirements Nuclear Cancellations and Rate or Cancellations Retirements 1

2% 89 129 l I

2.5% 152 192 4% 359 409 )

As noted above, the selection of the most probable need is a matter of educated l judgment. But such judgments must be made by the electric utility industry and l by public policy-makers. i With growth rates of GNP and electricity demand that are moderate by historical standards, a very modest assumption concerning cancellations and retirements, and allowing for achievable incremental reductions in demand, we judge that 100 to 200 million kilowatts of new generating capacity will be needed -- in addition to units still under construction today -- before the year 2000.

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CHART 4 U.S. ELECTRIC GENERATING CAPACITY AND PEAK DERATfD 1984-2000 1100-4.0 %

1 K

W -

900- i 2.5 %

I -

1 i N l N  : 2.0 P l

l L -

L 700- INSTALLED _

CAPACIT - -

0 N  :

S _

l

500 ,, .,. .,. .,. .,. ,,. .,. .,. ,,. .,. .,. ,,, .,. .,. .,. .,. .,

1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 0 8 8 8 8 8 8 9 9 9 9 9 9 9 9 9 9 0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 U YEAR

( NOTE:

PEAK DEMAND AT STATED GROWTH RATES WITH 20% CAPACITY NARGIN NEEDED FOR DEPENDABLE SUPPLY. INCLUDES EXISTING CAPACITY AND CAPACITY UNDER CONSTRUCTION LESS RETIRENENTS OF 15 KILLION KILOWATTS THROUGH 1993 AS REPORTED TO NERC.

CHART 5 U.S. ELECTRIC OEERATING CAPACITY AND PEAK DEMAND WITH POSSIBLE CANCELLATIONS AND RET! REPENTS 1984-2000 1100-

4.0 %

K  :

W 900-j 2.5 %

N -

2.0 V I  :

L L 700$ INSTALLED -

CAPACIT  ;

! H  :

l S 500 ,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,. .,

1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 2 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 9 0 8 8 8 8 8 8 9 9 9 9 9 9 9 9 9 9 0 4 5 6 7 8 9 0 1 2 3 4 5 6 7 8 9 0 YEAR NOTE:

PEAK DEMAND AT STATED OROWTH RATES WITH 80% CAPACITY NARGIN NEEDED FOP

, DEPEtCABLE SUPPLY. INCLUDES EXISTING CAPACITY LESS RETIREMENTS REP 0RTED TO i tqRC Ato ASSUMED RETIREMENTS AFTER 1993, AND CAPACITY UNDER CONSTRUCTIOri utSS ASSUPED CANCELLATIONS.

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With the disincentives to building that now face the electric utility industry, that is a daunting prospect for the industry and a challenge for the nation. The danger in the present situation is that decisions not to build that are in the best interest of the individual utilities will not add up to a result consistent with the national interest in adequate generating capacity.

Several studies

• have indicated that the economic value of electricity that is not available when needed is very high. The costs of electricity shortages show up in losses of production and foregone productivity gains and economic growth. Busi-nesses seeking to avoid the impact of reduced reliability may also incur costs for emergency generators or for spoilage of perishable items. While the direct effects of an electricity shortage are likely to be focused on the business sector and particularly on industry, individuals will be affected through losses of jobs and income and personal inconvenience.

O Costs and Benefits of Over/Under Capacity in Electric Power System Planning (Electric Power Research Institute, Palo Alto, California, October 1978).

Environmental and Socioeconomic Consequences of a Shortage in Installed Generating Capacity (Electric Power Research Institute, Palo Alto, California, June 1982).

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APPENDIX B ORDERS OF THE PENNSYLVANIA PUBLIC UTILITY COMMISSION BEARING ON THE DECISION PROCESS BY WHICH THE LIi4ERICK-2 NUCLEAR GENERATING STATION WAS REACTIVATED ON DECEMBER 23, 1985

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~

^~__...' _ _ _ _ _ . _

. 1 PENNSYLVANIA PUBLIC UTILITY COMMISSION Harrisburg, PA 17120 Public Meeting held ' ho 9. fo)

Commissioners Present:

Susan M. Shanaman, Chairman Michael Johnson James H. Cawley Linda C. Taliaferro Limerick Nuclear Generating Station I-Investigation 0RDER BY THE COMMISSION:

On August 8, 1980, the Office of Consumer Advocate (OCA) filed a petition, docketed at P-80080236, seeking (1) an Order to Show Cause why the continued construction of the Liwerick Nuclear Generating Sta-tion (Limerick) of Philadelphia Electric Company (PECO) is in the

, public interest and (2) a Commission investigation into the need for and economy of Limerick. PECO has filed an answer, along with its own

, petition. It opposes issuance of the Rule to Show Cause and suggests that any investigation of Limerick be consolidated with the current PECO general rate increase proceeding at R-80061225. The OCA has filed an answer to PECO's petition. We conclude that an investigation of certain issues concerning Limerick should be opened.

t We are opening this investigation proceeding so that informa-i tion can be gathered in an orderly and expeditious manner, before PECO seeks to include Limerick in its rate base as used and useful property. This approach will enable us to proceed without the pressures of time associated with rate cases.

We realize, of course, that Limerick is under construction and that it represents a major, and controversial, undertaking by PECO.

, However, although we agree with the OCA that a Limerick proceeding should be opened, we do not agree that the Rule to Show Cause requested by the OCA is appropriate. We must first proceed to gather facts. We can then reach conclusions and enter whatever orders we deem to be appropriate.

Although the pending PECO rate case at R-80061225 will necessarily deal with Limerick to some degree, we conclude that we should

' not burden that proceeding with additional issues and tha. an independent investigation of Limerick should be opened; THEREFORE, i

l 1

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IT IS ORDERED:

1. That the issue we incorporated into the rate proceeding at R-80061225 on August 28, 1980, concerning an estimate of the addi-tional costs occasioned by deferrals of the Limerick construction schedule, be eliminated from that proceeding.

2. That an investigation be, and is hereby, undertaken to determine:

(a) The cost of construction delays at Limerick and whether those delays were reasonable; (b) The escalation of cost estimates for Limerick and whether those costs for the plant are reasonable; and (c) The eventual impact of Limerick on PECO's capacity and reserve margins and the reasonableness thereof.

3. That the petition filed by the OCA, and docketed at P-80080236, be denied, except to the extent that it is granted by the opening of this investigation.

4. That Commission staff, Philadelphia Electric Company and the Office of Consumer Advocate are hereby made parties to this investigation proceeding.

5. That copies of this order be served on all parties to the proceeding at R-80061225, Pennsylvania Public Utility Commission v.

Philadelphia Electric Company.

6. That the Office of Administrative Law Judge assign this matter to an Administrative Law Judge for prompt hearing and initial decision.

BY THE COMMISSION, William P. Thierfelder Secretary (SEAL)

ORDER ADOPTED:

ORDER ENTERED: 50 M

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COMMONWEALTH OF PENN5Y LVANIA PENNSYLVANIA PUBLIC UTILITY COMMISSION P. O. BOX 3265. HARRISBURG. Pa.17120 November 12, 1980 IN REPLY PLEASE REFER TO OUR FILE I-80100341 DOCKETED TO ALL PARTIES g{$$

h ,e Investigation into the Philadelphia Electric Company's Limerick Nuclear Generating Station - Philadelphia County i

Dear Madam or Sir:

Chairman Shanaman moved that the Commission's Order entered October 10, 1980 in the above proceeding be amended to revise Ordering paragraph 2 as follows:

2. That an investigation be and is hereby undertaken to determine the need for an economy of the Limerick Nuclear Generating S ta tion. The investigation shall address, but not be limited to, the following issues:

(a) The cost of construction delays at Limerick and whether those delays were reasonable.

(b) The escalation of cost estimates for Limerick and whether those costs for the plant are reasonable.

(c) The eventual impact of Limerick on PECO'S capacity and reserve margins and the reasonableness thereof.

(d) What alternatives PECO considered at the time the decision was made to build the plant and the projected cost of each alternative.

(e) Could any currently available alternate sources of energy, conservation / load management activities, improvements in existing power plants' performance, etc. replace Limerick

, at a lower cost to the consumer assuming that:

(1) expended costs are amortized over a reasonable period; or (2) expended costs are not amortized or collected from ratepayers; or (3) expended costs are shared among stockholders and i

ratepayers.

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u (f) The potential of large ciectric consumers directly buying the capacity and/or energy associated with Limerick;

. Very truly yours, a 7 / x.

William P. Th felder '

Secretary f

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PENNSYLVANIA PUBLIC UTILITY CONNISSION p LE COPT Harrisburg, PA 17120 Public Meeting held July 6, 1984 l

[ Commissioners Present:

I Linda C. Taliaferro, Chairman, dissenting Michael Johnson James H. Cawley, dissenting Frank Fischl Bill Shana l-Limerick Unit No. 2 Nuc .ar Generating Docket No.

Station Investigation I-840381

. ORDEM TO Sit 0W CAUSC BY THE COHHISSION:

By order entered October 10, 1980 this Commission instituted an investigation at Docket No. I-80100341 into certain issues concerning Philadelphia Electric Company's (PECO) construction of the Limerick

Nuclear Generating Units 1 and 2 in order to gather information in an i orderly and expeditious manner prior to PECO seeking to include Limerick i in its rate base as used and useful property. At the conclusion of said I investigation we found that the simultaneous construction of Units 1

)

~

and 2 was not financially feasible if PECO was to insure the continued maintenance of safe and reliable service to the public. PECO was then

given the option of either suspending or cancelling the construction of

! Unit 2. In the event PECO refused to suspend or cancel the construction

of Unit 2, we declared that we would not approve any new securities l 1ssuances, in whole or in part, for the construction of Unit 2. The 1

Commission's decision was upheld by the Pennsylvania Supreme Court.

Pennsylvania Public Utility Commission v. Philadelphia Electric Company, 501 Pa. 153, 460 A.2d 734 (1983).

Subsequent to the Cour*8s decision, PECO elected to suspend construction at Unit 2 in accordance with the Commission's orders. On February 22, 1984 we accepted PECO's response to our order requiring suspension or cancellation as being in compliance with the Commission's

Orders of August 27, 1082, June 10, 1983 and December 23, 1983.

In the Order entered February 22, 1984 we also recognized that l PECO's decision to suspend construction meant that the company intended

to resume construction of Unit 2 upon completion of Unit 1. We also recognized that PECO, at some futura date, might seek Commission approval of securities financing for construction of Unit 2. Pursuant to Section 1903(a), we would then have to consider whether the proposed financing is "necessary or proper for the present and probable future capital needs" of the company. We therefore directed PECO to file certain information concerning Unit 2 no less than 120 days prior to the filing of any securities certificate for the financing of Unit 2.

i

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Since the company's anticipated in service date for Limerick Unit 1 is April,1985, it is reasonable to assume that PECO will resume construction of Unit 2 upon completion of Unit 1. However, we believe that serious questions exist regarding the need for the additional generating capacity represented by Unit 2, the cost effectiveness of Unit 2 as compared to other alternatives, and the effect upon PECO's financial health and its ability to provide safe and adequate service at reasonable rates. In addition, we are concerned about the potential effect of the cost burden of Unit 2 upon PECO's existing customer base.

Recent actions by same of PECO's industrial customers to generate their own power or to swit;S to alternate suppliers may come to typify these classes of customers. The loss of revenues from such customers could, of course, exacerbate PECO's financial situation and Lapact its ability to serve other PECO customers.

For the aforementioned reasons and to enable us to exercisa informed judgmcut when security certificates to finance Unit 2 are presented to us for registration, we believe that certain issues must be examined prior to any commitment by PECO to the resumption of construction on Unit 2. In order to gather information in an orderly and expeditious manner prior to having to render any decision on the resumption of construction of Unit 2, it is necessary to institute an investigation into such matters and to order PECO to show cause why the completion of Limerick Nuclear Generating Station, Unit 2, would be in the public interest. The following issues should be examined in this proceeding:

1. Is construction of Unit 2 necessary for PECO to maintain adequate reserve margins?

2. Are there less costly alternatives - such as cogeneration, additional conservation measures, or purchasing power from neigh-boring utilities or the P.J.M. interchange

- for PECO to obtain power or decrease consumption?

3. How will the capital requirements necessary to complete Unit 2 af fect PECO s financial health and its ability to provide adeouate service?

4. Should the Commission reject any securities filings, or impose any other appropriate remedy, to guarantee the cancellation of Unit 27

5. If Unit 2 is cancelled, what, if any, percentage of the sunk costs should PECO be permitted to recover from its ratepayers?

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6. If construction of Unit 2 is found to be in the public interest, should the Commission adopt an " Incentive / Penalty Plan" as an inducement co cost efficient and timely construction?

In recognition of the complexity of these issues and the need to proceed with such an examination prior to the completion of Unit 1 and the resumption of construction of Unit 2, we cannot delay instituting this investigation until the time frame established in our February 22, l 1984 order at Docket No. I-80100341. An examination of the issues l listed herein must be commenced at this tLae. THEREFORE, IT IS ORDERED:

1. That the Philadelphia Electric Company is directed to show cause why the completion of Limerick Nuclear Generating Station, Unit 2, is in the public interest.

2. That pursuant to the Order to Show Cause a formal investi-gation is hereby instituted and that this investigation shall include, but not necessarily be limited to, an examination of the following issues:

- Is construction of Unit 2 necessary for PECO to maintain adequate reserve margins?

- Are there less costly alternatives - such as cogeneration, additional conservation measures, or purchasing power from neigh-boring utilities or the P.J.M. interchange

- for PECO to obtain power or decrease consump*. ion?

- How will the capital requirements necessary to complete Unit 2 affect PECO's financial health and its ability to provide adequate service?

- Should the Commission reject any securities filings, or impose any other appropriate remedy, to guarantee the cancellation of Unit 27

- If Unit 2 is cancelled, what, if any, percentage of the sunk costs should PECO be permitted to recover from its ratepayers?

- If construction of Unit 2 is found to be i

in the public interest, should the Commission adopt an " Incentive / Penalty Plan" as an inducement to cost efficient and timely construction?

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3. That this investigation be referred to the Office of t.

Administrative Law Judges for hearing and Initial Decision.

4. That a copy of this Order be served upon all parties to the Commission's Investigation at Docket No. I-60100341.

BY THE COMMISSION, J

k Jerry R c Secretary (SEAL)

ORDER ADOPTED: July 6, 1984 ORDER ENTERED: August 7, 1984

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PENNSYLVANIA PUBLIC UTILITY COMMISSION Harrisburg, PA 17120 Public Meeting held December 5, 1985 l

Commissioners Present:

Linda C. Taliaferro Frank Fischl Bill Shane, dissenting (opinion attached)

Limerick Unit No. 2 Nuclear I-840381 Generating Station Investigation OPINION AND ORDER _

DOCKETED '

DEC161985 a

l l

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TABLE rF CONTENTS pg Page B. Trial Staff Position ................. 40

• I. INTRODUCTION AND HISTORY OF THE PROCEEDINGS ............................... 1 C. Consumer Advocate (OCA) Position ..... 41 D. The Positions of Other Parties ....... 43 II. PRELIMINARY MATTERS ....................... 10 E. Administrative Law Judge Recom-mendation ............................ 45 A. Request for Administrative Notice and Motions to Strike .................... 10 F. Discussion and conclusion ............ 45 B. Request for Oral Araument ............ 14 VI. THE COMMISSION'S AUTHORITY ................ 50 III. PRELIMINARY LEGAL ISSUES .................. 17

• VII. DISCUSSION AND CONCLUSION ................. 64 A. Burden of Proof - Conclusion of Law No. 5 ................................ 18 A. Capital Cost Estimates *and Completion Date ................................. 64 B. 2ecovery of Sunk Costs - Conclusion of Law No. 8 ............................ 19 B. Nuclear Operation and Maintenance .... 68 C. Motions of Strike .................... 19 C. Post Commercial Operations Capital 20 Additions ............................ 69 D. Confiscation .........................

D. Recommissioning Expense .............. 71 s

d IV. NEED FOR ADDITIONAL CAPACITY .............. 23 E. Useful Life .......................... 73 E$ 24 e A. PECO Position ........................ Another PECO Analysis of Economic F.

25 Benefits ............................. 73 B. Trial Staff Position .................

26 G. Conclusion ........................... 74 C. Consumer Advocate (OCA) Position .....

D. Governor's Energy Council (GEC)

Position ............................. 27

• VIII. CAPITAL COST CONTAINMENT AND OPERATIONAL INCENTIVE PLAN ............................ 77 E. Other Parties' Position .............. 28 A. PECO Positions ....................... 77 Administrative Law Judge (ALJ)

F.

Recommendation ....................... 29 B. Governor's Energy Council Staff (GEC)

Position ............................. 82 G. Discussion and Conclusions ........... 30 C. Trial Staff Position ................. 83 D. Consumer Advocate Position ........... 84 V. COMPLETION OF LIMERICK UNIT NO. 2 AND THE ALTERNATIVES .......................... 33 E. Our Review of PECO's Proposal ........ 84 A. PECO Position ........................ 33

1. Base Case I ..................... 34 37 G. Operational Incentive Program ........ 87

2. Base case II ....................

3. Base case III ................... 38 39 H. PECO Response ........................ 89

4. Base Case IV ....................

• These sections are reproduced on the following pages.

i 1

Limerick Township, Montgomery County. This application was made pursuant to Section 619 j of the Pennsylvania Municipalities Planning Code, Act of July 31, 1968, as amended, 53 P.S. $10619. The next time issues relating to the Limerick nuclear generating station were formally raised before the Commission was as part of a PECO rate proceeding which began on July 27, 1979. In its Order entered August 17, 1979, at Pa. P.U.C. et al. v. PBCO,

R-79060865, the Commission instituted an

. investigation to determine, among other issues, I whether PECO had been prudent in its actions in constructing new generating plants, and BY THE COMMISSION: directed ALJ Joseph J. Klovekorn to recommend an appropriate amount of additional annual rate j

relief. This investigation was an outgrowth of the rate case. At the conclusion of this investigation ALJ Klovekorn in his recommended I. INTRODUCTION AND HISTORY OF THE PROCEEDING decision concluded that the construction of Limerick should not be halted. In its final Order issued May 9, 1980, the Commission affirmed Judge Klovekorn's conclusions re-Before us for consideration is the Recommended garding the issue whether Limerick should be

Decision of Administrative Law Judge (ALJ) Allison K.

j, Turner. issued in this proceeding on July 16, 1985. ALJ The issue of whether Limerick Units No. 1 ro, and 2 should be built was next addressed by Allison K. Turner,s Recommended Decision in this proceeding, i

the Commission in a separate proceeding. This provided a thorough recitation of relevant matters preceding proceeding was instituted by an OCA petition.

the initiation of this proceeding. We shall quote Show Cause, but concluded that an investigation therefrom, as follows: should be initiated to gather information in

an orderly and expeditious manner regarding the i

Limerick nuclear generating station before while the present proceeding is the direct PECO sought to include Limerick in its rate result of an August 7, 1984 Order by the base as used and useful property. This

, Pennsylvania Public Utility Commission in investigation was docketed at Pa. P.U.C. v.

which it issued a Rule to Show Cause whether PEcG, I-80100341. The issues that were completion of the Limerick 2 Unit was in the considered in this proceeding inc_luded:

public interest, various aspects of the entire (a) the cost and the reasonablenens of j project of the Limerick nuclear generating construction delays at Limericks (b) the station have come before the Commission over escalation of cost estimates for Limerick the years. An overview of these proceedings and their reasonablenesst (c) the eventual should provide an informative background in impact of Limerick on PECO's capacity and considering the issues on this record. reserve marging (d) what alternatives PECO considered at the time the decision was made On January 6, 1971, the Commission entered to build the plant and their costs: (e) any an Order granting the Company's application currently available alternate sources of for a finding of necessity for the situation energy, including conservation / load manage-of a building to house electrical generating ment activities, performance improvements, equipment and two buildings to house outdoor etc. the treatment of sunk costs should substation control equipment on a site located alternative sources of energy be used to on the east bank of the Schuylkill River in replace Limericks (f) the potential for t

Following the conclusion of judicial review, sales of either capacity or energy from [ thel Casesission issued an Order on December 23, Limerick to large electric consumers. The 1983, rejectina a company proposal which ensuing investigation, which censidered both would have permitted work crews completing i units, was lengthy and massive. assignments on Unit No. I to move to undertake comparable projects on Unit No. 2 with a Unit Upon conclusion of the investigation, AI.7 No. 2 target in-service date of late 1988.

Klovekorn recosusended that the Limerick ,

station be completed as expeditiously as On January 24, 1984, PECO finally filed its

'. possible. Nowever, the Commission on response to the Cossiission's August 27, 1982 l review of this decision, in its opinion Order, and elected to suspend construction at and Order dated August 27, 1982, ruled that Limerick Unit No. 2 until the completion of the simultaneous construction of Limerick Limerick Unit 1. On February 22, 1984, the l Units No. I and 2 was not financially Commission accepted PECO's response to its Order feasible if PECO was to continue safe and requiring suspension or cancellation as being in reliable service to the public. The compliance with that Order, and directed that the Constission ordered the Company to either investigation be closed. The February 22 Order i]

suspend or cancel construction of Limerick directed that with respect to future PECO security Unit No. 2. It indicated that if the certificates filings involving the financing of

! Company did not suspend or cancel, it Limerick Unit No. 2 construction, that PECO submit

{ would not register security certificates certain data no less than 120 days prior to the pending the completion of Limerick Unit filing of such security certificates. The data No. 1, the proceeds of which would be used to be submitted included: a) estimated Limerick l in whole or in part for construction of Unit No. 2 construction costs and capacity factors l Limerick Unit No. 2. b) current fossil fuel prices; c) current load I growth projections d) data on operating and j PECO sought review of the Commission's maintenance expenses and capital additions that j

w

, Order and [ sic] the Commonwealth Court of may be required to enable the plant to last for i Pennsylvania, requesting that the Commis- its expected life: and el recent actions regarding y M on's Order of August 27, 1982, be set Limerick's water supply as well as any additional

, . side. The Commonwealth Court agreed with financial risks and costs that can be expected.

PECO and held that the Commission was not i authorized to directly or indirectly cause Concern about the completion and operation of the the Company to cease or suspend construction Limerick nuclear generating station is broad based.

of Limerick. Philadelphia Electric Company v. The issue of whether Limerick Unit No. 2 should be i i Pa. P.U.C., Pa. Commw. Ct. , 455 completed was also addressed by the House Select 9 A.2d 12t (19 C The Commission sought review Committee to Investigate Limerick II (the Committee) l of the Commonwealth Court's Order in the Penn- which was created pursuant to Resolution No. 257-

! sylvania Supreme Court, which reversed the of the Pennsylvania House of Representatives, Cocmonwealth Court's determination. The Supreme adopted on June 28, 1984. This resolution directed Court agreed that the Commission does not have the Comunittee to conduct an inves'tigation into the the power to directly interfere with general need for Limerick Unit No. 2 and to determine whether management's decisions of PECO such as the less costly alternatives were available which would decision to continue and complete construction make cancellation of the project desirable. The of the nuclear generating station. However, Committee was officially formed on July 22, 1984, the Supreme Court ruled that a commission and held public hearings beginning September 14, could indirectly force the cancellation of a 1984, and concluding November 13, 1984. It took j proiect by refusing to approve securities issues testimony from various PECO officials in support of

} for the funding of that project: Philadelphia ccompletion of Limerick Unit N% 2, as well as testi-

) Electric Company v. Pa. P.U.C., 501 Pa. 153, 460 mony from numerous other part es both for and against A.2d 734 (1983) (PECO Limerick). Both Courts completion. In addition, the Coruittee conducted a i' based their rulings on interpretations of the site tour for several of its members and its staff.

Commission's authority under Section 1903(a) On November 28, 1984, the Committee issued its report

of the Public Utility Code, 66 Pa. C.S. 51903(a), which included three specific findings. These findings r

.' 4 3

were: 1) there is strong evidence which the Since the Company's anticipated in service date PUC should consider indicating that the for Limerick Unit 1 is April 1985, it is construction of Limerick Unit No. 2 should not reasonable to assume that PECO will resume be completed: 2) the Committee urged that the construction of Unit 2 upon completion of PUC make a final resolution of this matter

• Unit 1. However, we believe that serious and 31 the PUC should make a speedy and defini- questions exist regarding the need for the tive decision on the matter, and the legislature additional generating capacity represented should expedite that decision by providing any by Unit 2, the cost effectiveness of Unit 2 legislation necessary. The Committee report as compared to other alternatives, and the set forth a specific recommendation for new effect upon PECO's financial health and its legislation which would grant the Commission ability to provide safe and adequate service l authority to order a public utility to modify at reasonable rates. In addition, we are or halt the construction of any generatin9 concerned about the potential effect of the plant where the Commission determines that cost burden of Unit 2 upon PECO's existing such construction is not in the public interest. customer base. Recent actions by some of This legislation also provides that an electric PECO's industrial customers to generate their utility may only recover sunk costs of a cancelled own power or to switch to alternate suppliers partially completed facility which the Commission may come to typify these classes of customers, determines have been prudently incurred. House The loss of revenues from such customers could, Bill 111 was introduced into the Pennsylvania of course, exacerbate PECO's financial situ-House of Representatives on January 28, 1985, ation and impact its ability to serve other sponsored by members of this Committee. PECO customers.

H.B. 111 is almost identical to the legisla-tion recommended by the Committee. It has been Order, mimeo p. 2.

referred to the House Committee on Consumer

! j, Affairs as of January 29, 1985. The Order continued and stated:

ru jf It is well to note that the Committee report was adopted by a majority of the Committee, For the aforementioned reasons and to enable but that various members submitted dissentin9 us to exercise informed judgment when security opinions, gr.d that the report was not certificates to finance Unit 2 are presented unanimous, to us for registration, we believe that certain issues must be examined prior to any R.D., pp. 1-7. commitment by PECO to the resumption of construction of Unit 2. In order to gather information in an orderly and expeditious By Order adopted July 6, 1984 and entered manner prior to having to render any decision on the resumption of construction of Unit 2, August 7, 1984, we, on our own motion, ordered PECO to show it is necessary to institute an investigation cause why the completion of Limerick Unit No. 2 would be in into such matters and to order PECO to show cause why the completion of Limerick Nuclear the public interest. In that Order we expressed the Generating Station, Unit 2, would be in the foliswing concerns; public interest. The following issues should be examined in this proceeding:

1. Is construction of Unit 2 necessary for PECO to maintain adequate reserve ILegislation was subsequently enacted in the form margins?

of an amendment to Senate Bill No. 543, and as Act 62, provides, inter alia, that the Commission shall order any electric public utility to cancel or modify con-struction of any generating unit where the Commission (Footnote Continued) determines that construction is not in the public (Footnote Continued) interest.

2. Are there less costly alternatives -

such as cogeneration, additional con- that Order would be satisfied by this proceeding.

servation measures, or purchasing The Company was direct ed to seek to have the power from neighboring utilities or record created in this proceeding accepted by the P.J.M. interchange - for PECO to the Commission as satisfaction of its February 22 obtain power or decrease consumption? Order at the time it intended to proceed to seek a security certificate. Therefore the following

3. How will the capital requirements additional issues were specifically included in necessary to complete Unit 2 affect this proceedings PECO's financial health and its ability to provide adequate service? Estimated Limerick Unit 2 construction costs and capacity factors.

4. Should the commission reject any Current fossil fuel prices.

securities filings, or impose any other appropriate remedy, to guarantee Current load growth projections, the cancellation of Unit 27

5. If Unit 2 is cancelled, what, if any, The rate of Limerick Unit 2 operating percentage of the sunk costs should and maintenance expense and capital PECO be permitted to recover from its additions that may be required to enable i ratepayers? the plant to last for its expected life.

6. If construction of Unit 2 is found to Recert actions regarding Limerick's water supply be in the public interest, should the as well as any additional financial risks and commission adopt an " Incentive / costs that can be expected in light of recent Penalty Plan" as an inducement to cost events in the rest of the nuclear power industry.

{ efficient and timely construction?

The matter was assigned to Administrative Law

2. In recognition of tha complexity of these Judge (ALJ) Allison K. Turner. A prehearing DJ conference was held on September 7, 1984, and iscues and the need to proceed with such an Of examination prior to the completion of Unit 1 a prehearing Order was issued on September 18, and the resumption of construction of Unit 2, 1984. An additional prehearing conference we cannot delay instituting this investigation was held on September 28, 1984.

until the time frame established in our Februa ry 22, 1984 order at Docket No. I-80100341. commission Trial Staff (Staff) entered a notice An examination of the issues listed herein must of appearance and has participated actively be commenced at this time, throughout. Petitions to intervene were filed by a number of groups and also an individual Order, mimeo pp. 2-3. complaint was filed. All were consolidated with I

i the Commission Investigation for purposes of hearings. As well as PECO and Staff, active Turning now to the course of the instant participants included the Office 'of Consumer i

Advocate (OCA), the Governor's Energy Council j proceeding, the ALJ advises us as follows: staff (GBC), Philadelphia Area Industrial Energy l User's Group (PAIEUG), Utility User's Committee (UUC), City of Philadelphia (City), and Consumers

' At a prehearing conference, PECO sought to Education and Protective Association and ACORN have the ALJ in effect consolidate the require- (CEPA/ ACORN). Inactive parties included United monts of the February 22 Order at I-80100341 States Steel Corporation which was represented incorporated into the instant proceeding

• at the first prehearing conference but subsequent-The ALJ issued a prehearing order which ly requested to assume inactive status and directed the parties to include evidence George E. Martin, Esquire, who filed a complaint relevant to the February 22 Order in this docketed at I-8466591.

{ proceeding, but refusing to rule on whether R.D., pp. 8-10

-7 8-

VII. DISCUSSION AND CONCLUSION A total of 23 days of hearings were held during l the period January - April 1985. In addition a total of As we mentioned above at the end of our discussion 6 public input hearings were held during January and of the subject of Completion of Limerick Unit No. 2 and the February at 6 separate locations in PECO's service territory Alternatives, we have concerns with regard to the costs during which 260 people testified. associated with the completion of Unit No. 2. These concerns lead us to the conclusion that completion is not in Briefs were filed by all the active parties the public interest, absent the Company's acceptance of cost identified above. Reply Briefs were filed I;y all active containment and operational incentive / penalty provisions.

parties with the exception of UUC. We shall address these concerns below.

The ALJ's Recommended Decision was issued for exceptions on July 16, 1985. Exceptions were filed by PECO' A. Capital Cost Estimates and Completion Date the Staff and CEPA/ ACORN. Replies to Exceptions were filed by PECO, the Staff, the OCA, the GEC, and the PAIFUG. In her Table 8 (R.D., p. 215) the ALJ set forth the positions of the parties regarding the capital costs and the expected completion date of Unit Wo. 2, as follows: '

e N

e

TABLE 8 nere important than the differences in capital costs which Costs s Schedule to complete Linerick 2 are quantified and reflected there, are other uncertainties.

(Millions)

We readily acknowledge that PECO witness Soppett offered To-Go Sunk Total Yrs / Months Completion Date nine advantages which construction of Unit No. 2 would i PECO $2,442.7 $754.6 1 $3,197.3 2 occasion (R.D., pp. 216-217), and PECO witness Kemper 4 yrs /3 mos 7/1990 Trial mentioned three other favorable considerations in support of Staff 2,586.95 3 _ _ _ _

his position that the capital cost estimates were reasonable OCA 2,568.3 -

3,936.

and achievable. These considerations do not alleviate our 7/1991 concern with regard to capital costs.

4 GEC Statt - - - - -

City 5 -

4,000. -

1992 The OCA points to the poor history of PECO's cos:

PAIEUG 2,650 -

4,070 forecasts and schedule delays for Limerick as a most tell!ng 1990 reason to question, if not to reject, PECO's current estimates. The history of PECO's estimates through the

1. July 1, 1984, PECO St.11. Exh. CKS-4, p. 8 years was set forth in OCA Exh. 22 as follows:

2. $1,263.6 million - total direct 1,933.7 million - includes escalation, overhead, AFUDC, PCCO's owners and materials costs Proiected Limerick Costs Over*Past Ten Years l 53,197.3 Millions of Dollars l na PECO St. 11, pp. 17-18 Exh. CKS-4, p. 8 Forecast Total $1 + 1004 Common CD Date cost Common Plant 82 Unit

3. Total direct for Limerick 2 plus 50% of common plant Trial Staff RRY-13 forecasts reviewed only included 10/74 $1,738 $1,208 * $ 531 direct costs 10/75 2,002 *

• a

4. There is a 354 chance Limerick 2 capital costs will exceed

• Forecast 7, Part 2 by 50%; 20% chance it will be lot less:

CEC Staff St. 1, p. 14 8/78 3,182 2,028

• 1,154 2/80 3,358 2,158

• 1,207

5. City St. 1, p. 13 Tr. 2322 9/80 3,774 2,449 $1,193 1,324 12/80 4,216 2,578 1,212 1,637

6. PAIEUG St. 1, p. 34 6/82 5,242 3,085 ,1,656 1,957 1/83 5,812 3,420 1,282 2,392 1/84 6,446 3,493 1,356 2,953 11/95 6,996 3,8,48 1,516 3,148

• #plit-up of costs not available.

OCA Exh. 22.

l The ALJ notes the OCA's contention that the continual cost increases for the Limerick project are not simply a function of time, inflation, or AFUDC, pointing out i

l  ! _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _

thst direct cocts co mescured by eithir man-hours er The ALJ took Cuch a dim view cf PECO'O GCtimat23 dolicrs, more thsn doubled betwe2n 1975 cnd 1782, cnd that that the ctated that "I roject PECO'o projected cost the increases outstripped the contingencies included in the schedule and construction cost results" (R.D., p. 228).

estimates with only one eNeeption.I4 while we do not reject PECO's estimates, for no purpose would be served by doing so, we are concerned that there is We also note that PECO witness Ward who testified a real possibility that they are understated.

in support of PECO's estimate stated that " simultaneous accomplishment of all schedule objectives will require performance better than the average historical experience on B. Nuclear Operation and Maintenance other nuclear projects". (PECO St. 12, PECO Exh. JEW-2 at 12E2-32). The ALJ also noted that construction performance The Company estimate allows for real growth in OsM i would actually have to be 304 better than average for all costs of 34 per year until 1990. Thereafter, the Company l

nuclear plants completed since the TMI accident, if assumes that there will be zero real growth in OEM expenses Forecast 7 estimates are to be met. (Hieronymous, Tr. 2030-2031, PECO St. 9A-4). The consequence of this assumption was the inclusion of OCA witness Komanoff pc.esented a capital cost $30 million per year in OsM costs, stated in 1984 dollars.

estimate for Limerick Unit No. 2 of $3'936 billion in Dr. Perl included $34.2 million per year in his analysis, on i contrast to the Company's estimate of $3.197 billion. The the same basis.

l details of this estimate are summarized at pages 226-227 of the Recommended Decision. Having reviewed witness These projections were challenged by the Staff,

2. Komanoff's testimony, we conclude that, on its face, his the OCA, the GEC, the City, and PAIEUG. OCA witness ro j) estimate has some merit. Komanoff estimates annual costs of $54.5 million per year in 1984 dollars. Staff witness Rosenthal estimates a 54 Staff witness Yanuck also presented testimony increase in real terms. City witness Knecht projects a real which raises substantial and valid questions regarding the increase of a conservative 24. GEC and PAIEUG both clain reliability of PECO's current estimate of total Limerick that PECO underestimates nuclear OsM costs, with PAIEUG Unit No. 2 costs of $3.197 billion, based upon the historic further pointing out that while PECO estimates increases of annual rate of increase in costs. (See R.D., pp. 227-228). 5.7%, historically the increases have been about 194 per year.

I The ALJ dismisses this subject at much greater 14 length at pages 239-246 of her Recommended Decision, which Between Forecast 6 in December 1982 and the current

Forecast 7, man-hours for Limerick Unit No. 2 increase by discussion we have previously adopted. That discussion 11,030,000 or some 40%. Forecast 6 also included a 1990 in concludes with the statement that service date for which the man-hours were 6,000,000 lest than Forecast 7, which has a 1990 in service date.

l

Nuclear OEM experses projected to be incurred are an important element which not provide or address the subject of estimates of capital should be considered in analyzing the additions subsequent to commencement of commercial economic value of Limerick 2. Here, as operations. The ALJ notes that OCA witness Komanoff in its capacity factor projections, the Corpany has rejected reliance on historic provided a figure of $10.6 million per year, which was trends. In fact, as regards nuclear O&M costs, the Company has predicted an absolute identified by another OCA witness in PECO's work papers, end to the significant increases in both ALJ Turner states that while not endorsing this figure, PECO its and national nuclear OEM costs. The has not denied or contested the figure, although PECO company appears to assume that all such increases have occurred because of one- witness Carroll agreed that post c'mmercial o operation time events and regulatory directives. In capital additions are to be expected.15 my opinion this position has not been ade-quately supported. The positions takin by intervenors that in fact one-time events OCA witness Komanoff estimated post commercial h e to r 1 db operation average nual capital' additions of $19.1 million effects of aging will continue to impose (in 1984 dollars),

maintenance and replacement requirements, and that the previously imposed regulatory retrofits will impose continuing increases This subject was addressed by the ALJ at greater in levels of maintenance costs are more reasonable bases for future projections. length and in more detail at pages 247-253 of her In my opinion the projections set forth by OCA of an average increase of $54.5 million Recommended Decision.37 The ALJ concIbded her discussion per year in 1984 dollars, for an increase to with the statement that:

1 the 1985 net present value of the revenue g ,

requirements in PECO's Base Case I by

$383.6 million is a more reasonable pro- g ,s adjusted position is premised upon jection (OCA St. CK-1B, p. 16' Exh. CK-34, PECO's historic experience as evaluated

p. 1: Exh. CK-35, p. 1; OCA Ein. RJC-II' by Mr. Komanoff. In this area, it is App. Al* not unreasonable to expect history to i repeat itself sufficiently to provide a R.D., p. 246. reasonable estimate of what can be expected during the useful life of Limerick 2. I note in particular that Mr. Komanoff has we are obviously concerned with the potential escalation of adjusted his projection for a diminution OsM costs, we will, therefore, establish a program which, with data cbtained from other nuclear plant's, will identify 15 The ALJ also comments that capital additions at expenditures that are out of line with results shown by PECO's Peach Bottom plant have been so large that they regression equations and other statistical analyses, and exceed depreciation accruals with the consequence that the take appropriate regulatory action.

net value of the plant has been increasing rather than decreasing.

16 This contrasts with $42 miIlion (in 1984 dollars) in average annual additions at Peach Bottom over the period

~

C. Post Commercial Operations capital Additions

• 17 we have previously adopted this portion of the ALJ's Comumencing at page 247 of the Recommended '# "*

Decision, the ALJ states that in its case in chief, PECO did in regulatory requirements. Moreover, as construction costs, adjusted for inflation. Based upon his seen by the discussion of the OCA position, construction estimate, Mr. Romanoff concluded that the cost a portion of witness Komanoff's assumptions could result in understating the capital would be $206.5 million in 1982 dollars, and $234.8 million additions that based on history might in 1985 dollars, reasonably be projected. Therefore I recommend that OCA's position be accepted by the Commission. This subject again was discussed at greater length R.D., p. 253. in the ALJ's Recommended Decision (pp. 254-259). The ALJ's conclusion was thats we generally agree with the ALJ's conclusion.

While neither estimate has such a degree of reliability that The Company has offered no evidence that the cost of decommissioning Limerick 2 will be we would feel comfortable adopting it as reasonable, equal to an amount included in a prior Mr. Komanoff's presentation casts considerable doubt upon Commission order for the cost of decommis-sioning a portion of one of the Peach Bottom the firmness and the reliability of the Company's estimate. units, and this amount seems completely It appears to us that there is a distinct possibility if not inadequate. As shown in OCA Exh. RJC-ll pp probability that the Company's estimate is unreasonably difference between *he OCA's, and the con =ervative. Company's estimate of the cost of decom-missioning Limerick 2 is $76.9 million.

In my opinion the OCA estimate should be utilized for the purpose of calculating a the economic cost of Limerick 2.

j D. Decommissionine Expense R.D., p. 259. We see no relevance between the rate making PECO did not present testimony regarding decommissioning allowance for the nuclear portion of Peach decommissioning expense in its direct case. After discovery Bottom and the actual decommissioning expense reasonably to and cross- examination of PECO witness Hill, it was be incurred in the decommissioning of the entirety of determined that the Company has assumed a cost of Limerick Unit No. 2.18

$71,640,000 (in 1983 dollars) for decommissioning the radioactive portion of Limerick Unit No. 2.

The Company's estimate does not appear to be based l

upon any analysis of Limerick Unit No. 2 decommissioning costs, but is based upon the decommissioning ratemaking 18 We agree with the OCA's point that the cost of allowance for Peach Bottom units which we allowed PECO to decommissioning the entire plant must be considered in any economic evaluation, regardless as to how that expense is recover from ratepayers in PECO's 1983 general rate case funded, be it through a decommissioning expense allowance proceeding at R-822291. for the nuclear portion, or a negative salvage allowance for the remaining portions.

OCA witness Komanoff estimated that decommissioning would equate to 10% of the original direct

E. Useful Life The Staff did not challenge the stated conclusion PECO has used a useful life of 39 years in its that all benefits would be eroded at an incremental cost of

$1,652 per RW, but challenged whether the incremental costs calculations, for the purpose of comparative analysis.

While the OCA has accepted this figure for the purposes of are actually only $1,263 based upon PECO's estimate.

the comparative analysis, it suggests, on the basis of Staff witness yanuk claimed that Drs. Perl and Mr. Romanoff's testimony, that a premature retirement before Wile made three serious errors, the correction of which the age of 30 years is more likely than a full 39 year life, resulted in an incremental cost of $1,838 per RW. Viewed in a different manner, Dr. Perl's incremental cost of The ALJ expressed no conclusion regarding this

$1,652 per RW at which Limerick Unit No. 2 becomes matter. We do note however that this is an uncertainty g g which exists regarding any nuclear plant which must be kept in mind when assessing whether the completion of Limerick $930 per KW, totals $2,582 per RW. By deflating Limerick Unit No. 2 is in the public interest. Unit No. 2 total cost to January 1985 dollars (Staff Exh. RRY-1A, Schedule 6 (revised)), the total cost for Limerick Unit No. 2 is $2,581 per RW. Consequently, in F. Another PECO Analysis of Economic Benefits the Staff's view Drs. Perl and Wile have established that the completion of Limerick Unit No. 2*is uneconomic.

dw PECO witnesses Perl and Wile, National Economic 7 Research Associates, Inc. were assigned the task of conducting an independent analysis or check upon the assumptions employed by the Company in evaluating the economics of completing Unit No. 2 Based upon the major errors in, and uncertainties The witnesses stated with regard to, PECO's various estimates which we have that, based upon the past experience of dramatic unanticipated increases in nuclear construction costs, the addressed above, that is PECO's estimates regarding capital possibilities of further future increases cannot be ignored. construction costs, O&M costs, post commercial operation capital additions, and decommissioning costs, we conclude However, rather than to attempt to quantify, future that completion of Limerick Unit No. 2 without some increases, they calculated the maximum increase which could occur without totally eroding the benefits of completion of assurance of cost control, does not favorably compare with Limerick Unit No. 2. the other alternatives available. In viewing the record here, as discussed above, we are satisfied that in several According to these witnesses, the company's incremental cost to complete Limerick Unit No. 2 is 19

$1,263 per RW and that cost would be required to increase to This subject is discussed in greater detail at pages 260-264, of the Recommended Decision. This is a different

$1,652 per RW, before the benefits of Unit No. 2 are analysis than the present value analysis discussed earlier completely eroded. and this analysis has no direct bearing upon the results shown there.

l 74 _

l

\

ingtences PECO ha3 under20timated ita Lic;erick Unit No. 2 unracsonab13 ritOc fcr that portion of servica provided by costs. In addition, nuclear power has its cwn peculiar set Limerick Unit No. 2.

of prcblems created by everchanging regulatory requirements, which are entirely outside the control the utility itself. Accordingly, we conclude that based upon the PECO would have us rest assured that the post TMI accident record before us, and in the absence of evidence of changed round of ever increasing regulatory requirements and circumstances, it would be incumbent upon us to deny the standards has run its course. We would hope that it has. registration of any securities certificate which would However, we believe it is unrealistic to totally foreclose directly provide funds for, or otherwise facilitate, the the possibility of additional regulations which might be completion of the construction of Limerick Unit No. 2, precipitated by some unexpected development, newly unless the Company agrees to a capital cost containment and identified operational problems, or another accident or operational incentive plan.

incident.

We are also mindful of the fact that PECO has delayed the construction of the Limerick units in May 1976 and again in May 1978, apparently because load growth did not materialize as originally expected.20 were PECO to aoain delay completion of Unit No. 2, we can expect another major cost escalation. As a consequence, we conclude that 2, at a minimum PECO has not carried its burden of proof, which E$ is to demonstrate by a preponderance of the evidence that the unconditioned completion of the construction of Limerick Unit No. 2 is in the public interest. Further, based upon the credible and probative evidence of record, we find that the other parties have satisfactorily demonstrated by a preponderance of the evidence that the unconditioned completion of Limerick Unit No. 2 is contrary to the public interest, in that the likely consequence of the completion of the construction offUnit will be inadequate, inefficient and unreasonable service, characterized by unjust and 20 The history of the Limerick plans and construction is set forth in the Recommended Decision at pages 27-34, which we hereby adopt.

VIII. CAPITAL COST CONTAINMENT AND OPERATIONAL INCENTIVE PLAN Mr. Paquette reinforced the testimony of PECO witness Hill (PECO St. 19), that a construction A. PECO Positions cost containment program is not apprcm late because it would increase the investor's perceived risk in PECO's securities, which In its Exceptions, at several places, the Company would increase PECO's cost of capital.

(PECO St. 27, p. 4). Furthermore, a cost makes reference to a cost containment program. At containment program would unfairly penalize pages 28-29 it states: PECO's shareholders because PECO s long-run economic analyses indicate that Limerick Unit No. 2 is the least costly alternative, even Moreover, as discussed in Section IV above, if the final Limerick Unit No. 2 costs in-to the extent the ALJ's determination of crease substantially over Bechtel's Forecast 7, "public interest" is based on a belief that Part 2 (PECO St. 11, Ex. CKS-4), and the costs the cost of timerick Unit No. 2 may be of the alternatives do not increase at all.

higher than PECG estimates, a cost contain-(PECO St. 27, p. 4).

ment program will remove this uncertainty.

(Emphasis added).

The Company has confidence in the assessment it At pages 29-30 it states: has made concerning the need for Limerick Unit No. 2, the Finally the major " uncertainty

• involved in various feasible alternatives to completing Limerick Unit the completien of Limerick Unit No. 2, the No. 2, and its ability to build Limerick Unit No. 2 in a potential for cost escalation, can be elimi-

-d nated throuch the implementation of a cost accordance with Forecast 7, Part 2. It is the Ccmpany's e

epntainment program (Emphasis added). judoment that there is little likelihood that matters beyond its control would seriously impair Limerick Unit No. 2's Earlier in its Exception at pages 24-25, PECO had stated: economic benefits (PECO St. 27, p. 6).

PECO has indicated its willinoness to negotiate a cost containment program In the context of a construction cost containment 1'

9 7 I is eklestblshdon Program, however, the Company does have concerns about a this record that such a program would cost containment program which does not make appropriate remove uncertainties relating to the

}

unit's costs. allowance for certain factors outside the company's control, The Brief continues and details what it considers to be the i

essential elements of a proper cost containment program. In Construction capital costs can be controlled order to avoid any possibility that a summary might through an appropriately structured cost containment program, inadequately describe PECO's position, we shall quote its comments in its Brief, at length.

In its Brief, commencing at pages 7-9, PECO notes l that during the course of the proceeding, witnesses for the a. The Construction Cost Containment Procram I

Should Be Restricted To Direct To-go Costs Staff and the GEC recommended the establishment of a construction cost containment program if PECO is to continue First, such a program should be related l only to the direct construction costs to-construction of Limerick Unit No. 2. PECO further stated go for Limerick Unit No. 2 to the date of

commercial operation, and should exclude can begin on or about October 1, 1985, as future AFUDC. The sunk construction costs assumed in Forecast 7, Part 2. Any significant are a fact which cannot be changed, and delay in the start-up date for Limerick Unit AFUCC on both sunk costs and to-co costs No. 2 would cause PECO to lose important crew is a function of debt, preferred and common supervisors and engineers who are not generally equity capital costs. Those costs are out available, and this loss could increase costs.

of PECO's control and, at least in part, If the Company is to be subjected to a con-are related to the rate relief which the struction cost containment program based on Company receives from the Commission. Forecast 7, Part 2, PECO must be permitted to Accordingly, if Limerick Unit No. 2 is to resume work in accordance with the schedule be completed with a construction cost assumed in Forecast 7 Part 2. If remobi-containment program, that program should lization is delayed beycnd July 1, 1985, the not be impacted by changes in either the program should be adjusted for any additional AFUDC rate or amount. (Id. p. 7). costs, such as inflation, contract rencoctiation,

b. The Ccnstruction Cost Containment Procram and labor recruitment, training and qualifica-tion (Id. p. 8).

Should Be Inflation Neutral Second, the program should be subject to Whether or not Limerick Unit No. 1 goes into commercial operation before construction adjustments for any increase or decrease in inflation which departs from the projected resumes on Limerick Unit No. 2 should not be 6% rate. The direct construction corts in a matter of concern to the Commission and Forecast 7, Part 2, have been estimated on the should not preclude PECO from an October 1, basis of an inflation factor of 64, but the 1985 construction date. Limerick Unit No. I rate of inflation which actdally prevails is complete and ready for commercial operation, subject only tor (a) the removal of the 5%

over the next five years is totally outside restriction on its full power license, and i of PECO's control. Indeed, increases in the (b) sufficient water for full power testing.

-d rate of inflation over 64 would cause increases Even if a delay should be encountered in this U$ in the costs of the various alternatives to a process, it would not have a significant finan-e larger degree than in the cost of Limerick cial impact on PECO, and would not interfere Unit No. 2. Accordingly, it is essential that with its ability to begin in July to prepare for any construction cost containment program be resumption of the construction of Limerick Unit subject to a positive or neoative adjustment .No. 2. (Tr. 3597).

to account for changes in inflation'which depart from the 6% rate. Thus, if the d. PECO is Prepared to Assume the Risk of

, inflation rate is less than 64, then the .Governmentally Impcsed Scone, Changes cost allowed should be adjusted downward accordingly, and vice versa. (Id., pp. 7-8), /'

f Fourth, the program should be subject to Since such an adjustment would Se even-handed adjustments for increased costs which are -

regardless of the future course of the economy, due to matters totally beyond the, control ano since there is no record evidence to support of PECO such as acts of God normally dealt  !

a punitive one-way treatment of inflation, with in a contract force majeure clause.

failure to include this element would clearly ,

(PECO St. 27, p. 9). Mr. Paquette originally be unfair to the Company. proposed that a construction cost containment program should be subject to adjustments for c.' she Dire-t To-co costs of Limerick Unit unforeseen major scope changes imposed on PECO No. 2 Assume an OctcFer 1, 1985-Construction with respect to Limerick Unit No. 2 by govern-

-sesumption 3 ate mental agencies, especially for those that are safety related. On sur-surrebuttal, ^

Third, if a construction cost containment however, PECO witness Hill, appearing on program is established, it is critical that behalf of Mr..Paquette, testified that .

PECO be permittei to begin preparino for a "the company would' be 'willing to negotiate ~

resumption of Limetick Unit No. 2 construction , ... a cost containment program for Limerick in July, 1985,'so that active constructicn work UnAt No. 2 which would not include" relief

r '

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m f f W

for PECO in the event of

• unforeseen major f. A Construction Cost Containment Procram scope changes imposed on PECO ... by govern- Should be Limited to Penalizino Return mental agencies, especially those that are on, but not R_eturn of, Investment safety related." (Tr. 4513). The basis for the Company's decision according to Mr. Hill Finally, the penalty for exceeding amcunts ]

specified in a construction cost containment

... is the confidence that the company program should not prevent PECO's recovery believes exists as a result of bott,our of prudently incurred costs cove such speci-internal analyses and those performed by fied amounts, similar to the hope Creek our consultants as well as the testimony incentive program adopted by the New Jersey as presented by Mr. Mattson on our behalf Public Utility Commission. (See PECO Exs 9 as it was presented in the rebuttal stage and 10). Denial of depreciation of such of this case, prudently incurred costs could cause serious investor reaction to PECO's securities (PECO (Tr. 4513). St. 29, p. 11).

e. A Construction Cost Containment Procram Should be Desianed to Avoid Double B. Governor's Eneray Council Staff (CEC) Position Counting Cost Overruns Disallowed for

> Imprudency The GEC was the most active party on the subjects of cost containment and penalty / incentive procrams, a $ th u o e i ent program should not apply to any prudency providing two witnesses who testified in some detail, adjustments to the Limerick' Unit No. 2 rate e

base claim. Otherwise, PECO would be sub-

--* jected to double jeopardy 1.e., if the Although the GEC does not make a specific x ee rec mmendation concerning the imposition of a cost cap or ruc o t eet sh-ment cost limit, these costs should not be penalty / incentive program, its position is that there may be d aga an economic benefit to completion of Limerick Unit No. 2, if yt t t c co nment procram (PECO St. 27, p. 10). This is a strict program designed to control both construction and og e ew operating costs is applied. We noted earlier that the GEC n nt th York Public Service Commission respecting believes implementation of a stringent program may well the Nine Mile Point No. 2 Nuclear Stations result in net benefits of $330 million when comparing As for the cap's relationship to issues Limerick Unit No. 2 completion with other Base Case alternatives. According to the GEC, the public interest p et o ts a y in 1 in he rate base: imprudently incurred costs requires that PECO's customers be offered "some reasonable degree of certainty as to the maximum cost that may be t ir ud ed c t cap in an amount equal to the prudence recovered in rates" (GEC Main Brief, p. 75). Accordingly, the GEC recommends that any cost containment program which n c nsecu ces fte pru finding. the Commission imposes include at least the following Re Nine Mile Point No. 2 Nuclear Station, provisions:

62 PUR4th 455, 464 (N.Y. Pub. Serv. Comm.

1984) (emphasis in original).

1. A cap on the total cost of the project

. - ~ . . -

e . . . . . . .

a

2. A progree to monitor and control O&M Staff Main Brief e P. 79) . In addition, the Staff states expenses, and that any cost containmen'. procram must,fnclude a plan to

3. Establishment of an operating performance control operations and maintenance expenses once the plant standard which would apply to Limerick goes into service and must not foreclose the possibility of Unit No. 2 throughout its service life.

a subsequent prudency investigation. (Trial Staff Main (GEC Main Brief, p. 75) Brief, p. 80).

As for PECO's offer to negotiate a cost The Staff states that while some of PECO's cost containment plan under certain conditions, the GEC considers containment criteria may be acceptable, other elements the Company's proposal to be wholly inadequate. The GEC clearly do not protect the interest of the ratepayers and states that any program which includes the terms proposed by should be rejected (Trial Staff Main Brief, p. 80).

PECO will almost certainly pass the bulk of any additional costs through to the customer, and will not elimincte the risks or ensure the benefits associated with completion of D. Consumer Advocate Position Limerick Unit No. 2 (GEC Reply Exceptions, p. 12).

The OC4's position is that, even with a cap on Limerick Unit No. 2 construction costs, there are more C. Trial Staff Position economic and less risky alternatives to ecmpletion of that unit. The OCA favors cancellation of the Limerick Unit d' Like the GEC, Trial Staff believes that in order No. 2 project, but states that if PECO is permitted to go to protect any benefit accrued by the completion of Limerick forward, the Commission must impose a strict and Unit No. 2, a construction cost cap as proposed by its comprehensive cost containment program. Such a program '

witness Rosenthal must be imposed. (Reply Brief, p. 12) should not be limited to a ceiling on direct construction The Staff states that if we permit PECO to proceed with costs but must deal with all aspects of Limerick Unit No. 2 completion of Limerick Unit No. 2, Staff favor a stringent cost and performance.

cost containment program.

Y et assessing the merits of the Company's proposal The Staff notes that during the course of this on cost centainment, the OCA states that it " offers so investigetion, company witnesses exhibited a high degree of little protection to ratepayers that it is not worthy of confidence in its latest cost estimate for the Limerick Unit consideration by the Commission" (OCA Main Brief, p. 213).

No. 2 project. This estimate is Bechtel's November 1984 aralysis of the cost to complete Limerick Unit No. 2 and is identified on the record as Forecast 7, Part I. The Staff E. Our Review of PECO's Protosal suggests that, in the event the Commission adopts a cost containment program, Forecast 7, Part 2 should be used to We believe it self evident that a properly establish an appropriate ceiling or; direct costs (Trial structured cost containment program, coupled with a

-84~

performance incentive plan could satisfy all or nearly all July 1, 1985 and, consequently, we view this condition as of our concerne, which we have concluded render the nothing less than an attempt by PECO to revise and increase unconditioned completion of the construction of Limerick the estimate which is to be the limit to which it is to be Unit No. 2, not in the public interest. held under a cost containment program, we find several of the conditions or terms set As to a revision to the cost containment forth in PECO's proposal, quoted above, to be unacceptable limitation for acts of God and regulatorily imposed scope because they would place much of the burden of risk upon the changes, the latt2r of which TLCO proposes to assume, we shoulders of the ratepayers. PECO has said that it *has again conclude that PECO wishes to place the risk of acts of

onfidence ... in its ability to build Limerick Unit No. 2 God upon ratepayers. We find this unacceptable.

in accordance eith Forecast 7, Part 2". Main Brief, pp. 7-10. If PECO truly has such confidence, it should be As to prudency disallowances, if we understand willing to accept various of the risks which are inherent in PECO's point, we agree that they should not be double continuing construction of Limerick Unit No. 2, and not seek counted. What we envision is that for initial rate base to absolve itself of certain risks and, thereby, to place treatment, the starting point would be the figure for gross them upon the ratepayers. plant, and then imprudency disallowances would be deducted.

If the resultant prudent investrent ist more than PECO's first condition is that the cost linitation $3,197.3 million cap, the rate base allowance would be i should include only future costs, not sunk costs, and should limited to $3,197.3 million. If the resultant prudent w exclude APUDC on both past and future costs. ?fe find this investment is less than $3,197.3 million, that lesser figure

• would represent the prudent investment rate base allowance.

1 i

e condition or proviso unacceptable. PECO's estimate of total cost is approximately $3.2 billion, which includes all costs Subsequent rate base allowances would be determined by past and future. In our view, there should be a ratemaking cornnencing with the prior determination of the prudent allowance limitation not in excess of $3,197.3 million. investment, limited to $3,197.3 million, deducting therefrom accrued depreciation, and adding capital additions, with the PECO's second condition is that the ecst result limited to $3197.3 million.

limitation should be subject to adjustments,for inflation above and below the projected 64 Jevel. We find this PECO's final condition is that while return on condition or proviso unacceptable fc,r reasons similar to prudent investment above $3.2 billion would be denied, those expressed above. return of investment above $3.2 billion would be permff .ed.

We find this condition unacceptable. This is but another As to an adjustment by reason of a restart of means by which PECO is attempting to avoid the risk construction later than July 1, 1985, this would essentially associcted with the completion of Limerick Unit No. 2.

require a reopening of the record for a new construction estimate. When that condition was first enunciated it was readily apparent that construction could not be resumed by F. Cost Contannment option would be gained by the customers. Therefore, in addition to the cost containment plan outlined above, we establish the The essentials of our cost containment plan are: following operational incentive plan.

1. The maximum net rate base allowance for 1. The established annual capacity factor Limerick Unit No. 2 (exclusive of common plant) shall never objective is 654 21 to be determined by means of the exceed a prudent investment of $3,197.3 million. following formula, adopted from FERC Form 1, pace 406:

2. Any of the investment (including Jubsequent Annual Capacity Factor = Net Generation - KWH capital additions) excluded by reason of the Unit FW Capacity (as included in plant total - line 5,

$3,197.3 million limitation shall not be recovered through p. 402) x 8,760 hours0.0088 days <br />0.211 hours <br />0.00126 weeks <br />2.8918e-4 months <br />.

depreciation expense or otherwise amortized.

3. Any of the initial investment (excluding 2. The targeted capacity factor will be

increased in those years when the Unit is not scheduled for capital additions as referenced in Paracraph No. 4) excluded

by reason of the $3,197.3 million limitation shall not refueling and decreased in those years when refuelina is

thereafter receive rate base recognitron, in whole or part, scheduled. The appropriate amount of,the increase or by reason of the reduction of net investment through decrease will be determined during general rate increase depreciation accruals. proceedings applicable to Limerick Unit No. 2, i

w w

' Operations within a range of +5 percentage

4. Any capital investment which occurr 3.

subsequent to commercial cperation shall receive rate base points of the applicable annual capacity factor will not recoanition, only to the extent that the total net result in either an incentive or penalty.

j investment for ratemaking purpose does not exceed S3,197.3 million. 4. The energy cost savings resulting from l

! operating more than 5 percentage points above the annual l capacity factor objective shall accrue to the stockholders G. Operational Incentive Program and will not be reflected in the ratemaking process, in an amount not to exceed 5% of the common equity investment in Our concerns regard the Company's estimates of th, Limerick Unit No. 2 (i.e. Limerick Unit No. 2 rate base economic alternatives to completion of Limerick Unit No. 2 are not limited to the issue of the ultimate capital cost of the unit. We believe that fu:ther assurances should be -

i given to the ratepayers in this case. Additional conditions 2I PECO has advocated and assumed a 65% annual capacity pertaining to the unit's impact on energy costs are intended factor in its economic onalyses. (Sy , ALJ's discussion, at pp. 229-238, of the Recommended Decision.)

to protect the economic benefits which the Company predicted t .

allowance, excluding common plant, x ecmmon equity component otherwise render the completion contrary to the public of capital structure). interest. Accordingly, there can be no room for negotiation. PECO shall notify the Secretary within 30 days

5. The additional energy costs incurred as a of the date of entry of this Opinion and Order whether it result of operating more than 5 percentage points below the wishes to and does undertake a formal commitment to the annual capacity factor objective shall not be recovered by terms and conditions of our cost containment and operational the Company, except to the extent that the additional incentive plans; THEREFORE, expense shall exceed 10% of the common equity investment in Limerick Unit No. 2. (Calculated as above). IT IS ORDERED:

6. The dollar amount of the incentive / penalty 1. That the Exceptions of the parties to the will be established for the life of the plant in the initial Recommended Decision of Administrative Law Judge Allison K.

Limerick Unit No. 2 general rate proceeding. Turner are granted and denied to the extent consistent with this Opinion and Order.

H. PECO Response 2. That the unconditioned completion of construction of Limerick Unit No. 2 if not in the public In the event the Company accepts our cost interest.

2. containment and operational incentive plans, we conclude c$ that the completion of Limerick Unit No. 2 is in the public 3. That the Philadelphia Electric Company shall

' notify the Commission Secretary, within 30 days of the date interest, and that rates which recognize in rate base only the limited capital investment of $3,197.3 million, would of entry of this Opinion and Order, whether it accepts and not be unjust and unreasonable solely by reason of exce9sive agrees to be bound by the terms and conditions of the cost capital investment in Limerick Unit No. 2. containment and operating incentive plans set forth in the body of this Opinion and Order.

The enunciation of our cost containment and operational incentive plans, is not the opeping round in a 4. That any notification of acceptance filed serlei of negotiations. We do not consider our plans to be with the Commission Secretary, shall be deemed approved negotiable. We have considered a variety of possible unless rejected by Conmission action within 30 days arrangements, including those suggested by the parties to thereafter.

this proceedings, and those adopted by other regulatory commissions. The plans which we have outlined above are the minimum provision which we consider to be both reasonable to the Company and adequate as a protection against the many uncertainties, with regard to the completion of the construction of Limerick Unit No. 2, which in our view would

5. That the Bureau of Conservation, Economics Public Meeting of December 5,1983 and Energy Planning and the Bureau of Rates are jointly assigned the task of developing the program with regard to operation and maintenance expense, which is referenced at DISSENTING OPINION OF CottilSSIONER BILL SliANE page 69 of this Opinion and Order, no later than June 30, 1986.

RE: LIMERICK UNIT NO. 2 GENERATING STATION INVESTIGATION I-840381

.BY THE COMMISSION' DEC-85-0SA-93*

". . ? ',p . f. .s

,. 'I The majority has concluded that completion of Limerick 11ait 2

,g is in the public interest if Philadelphia Electric Company (PECO) agrees

., Secretary to a cap upon the costs which may be recovered from PECO's ratepayers.

e

• F r the following reasons, I dissent.

ORDER ADOPIED:. . December 5. 1985 The Commission's decision is an artitrary and capricious ORDER. ENTERED: December 5. 1985 exercise of administrative power. The opinion and Order explains in detail why completion of Limerick 2 with a cost cap is preferable to 3 completion of the unit without a cost cap, but it fails to address why completion with a cost cap is preferable to cancellation of the unit.N Indeed, the Opinion and Order givet one the impression that imposition of a cost cap was the only remedy available to the Commission. In my opinion, cancellation of Limerick 2 would provide several benefits over completion of the unit with a cost cap.

1/ This failure to weigh all of the alternatives arises from the Cowenission's reasoning that "... our task here is not to deter-eine the best course of action from the alternatives developed on the record and then to direct PECO to follow that course but, rather, to determine whether PECO has demonstrated that comple-tion of Limerick Unit No. 2 is in the public interest." This statement is irrational; the public interest cannot be determined in a vacuum. Completion of Unit 2 is not in the public interest if there are better alternatives.

l

First, cancellation of Limerick 2 and pursuit of one of the (Recommended Decision, pp. 196-197). The Commission's opinion and Order

" Base Case Alternatives" discussed in the AlJ's Recommended Decision attempts to refute this point by stating that PECO is a member of the would lower PECO's revenue requirement, at least in the short run. Pennsylvania-New Jersey-Maryland (PJM) interchange, and that the size Instead of adding 1055 megawatts of costly generating capacity in the and diveri;ity of that system " invalidates" the AlJ's reasoning (0 pinion j

early 1990's, at a time when that much capacity will not be needed PECO and Order, pp. 31-32). However, while the size of the PJM interchstge 1

l could extend the life of oil-fired generating units, encourage conservation may mitigate the ef fect of this unreliability on PECO, the ALJ was l

l and cogeneration, and add coal-fired capacity, if needed, in the late correct in stating that "the construction and reliance on a series of 1990's. This diversified alternative also provides the benefit of sided large units can contribute to decreased reliabilitt for oo g PECO and flexibility if the forecasts of energy load growth turn out to be inaccurate. PJM." (Recommended Decision, p. 303) (emphasis supplied).

Second, cancellation of Limerick 2 would make PECO a less Fourth, and perhaps most importantly, there is a significant risky utility, thus decreasing its cost of capital. Under traditional risk that the " cost cap" contrived by the Commission will be ineffective.

ratemaking theory, the higher cost of capital which will accompany A cost cap is not a talisman which will guarantee completion of Limerick 2 completion of Limerick 2 will have the effect of increasing rates. at a cost of $3.2 billion. Assuming, for the sake of arpment, that 9

~g~ Third, cancellation of Limerick 2 is preferable because PECO takes extraordinary measures to prevent costs from escalating, it ro

' history demonstrates that PECO's large base load nuclear plants are very is still possible that factors beyond PECO's control could increase the unreliable.U As the AIJ stated: cost of Limerick 2. For example, the Nuclear Regulatory Consission could order additional, expensive safety modifications. If this occurs, (T]he scheduled and forced outages of a large nuclear unit will raise reliability requirements. PECO will either absorb the costs, placing it in a precarious financial Limerick 2 would not only add generation capa-city which would aid in maintaining PECO's position, or it will seek to have the cost cap lifted by arguing that adequate reserve margins, but would simulta-neously raise the required level of those preservation of its financial health supersedes its agreement to the reserve margins. Other types of units, parti-cularly if of smaller capacity, would meet cost cap. In this scenario, this Commission will, once again, be placed reserve requirements without adding to them as much. between the proverbial " rock and a hard place." Cancellation would avoid this problem.

In addition to its failure to address the relative advantages

2) Anyone who doubts this statement, should read the Commission's Order in the Salen Nuclear Generating Station Investigation, of cancellation versus completion with a cost cap, the Opinion and Order P-830453 (Order adopted October 24, 1985).

is legally flawed because it does not analyze the evidence according to the standards set out in Act 62 of 1985 (formerly Senate Bill 543).

2-MM .

Act 62 states that. the Coassissio.: shall order any electric utility to Another galiing aspect of this case is that it -eeris PECO's cancel or modify the construction of a generating plant when the Cosumis- blatent attempts te bypass the Cosmiission's adjudicating procedures. la sion deterafnes that construction is not in the public laterest. In the hearings, PECO opposed the concept of a cost cap and only put forth making this decision, the legislation specifically requires analysis of proposals which all the parties agreed were unacceptable. Af ter the AIJ whether the plant is needed, and whether there are less costly alternatives recommended cancellation of Limerack 2, however, PECO offered in its to construction of the plant. Finally, the legislation places the Exceptions to nego* tate a cost cap with the Commission. The Commission burden of proof on the utility. has now voted to give PECO the option of either cancelling the unit or The Opinion and Order does not make a finding that Limerick 2 completing it with a cost cap contrived by the Coossission. PECO should is needed, nor does it address in detail whether there are less costly not be given a second chance to look at a cost cap; it -hould be barred alternatives to completion of the plant. On the need issue, the Opinion from doing so because of its failure to support reasonable terms on the and Order concludes that "PECO may need additional capacity as early as record. The real message behind the Coavaission's action is that proposals 1992." (p. 31). However, as the Trial Staff emphasized in its Exceptions need not be put forth on the record, where they will be subject to (pp. 2-3), the full amount of Limerick 2's capacity would probably not cross-examination before an AlJ, but that it is a better strategy to be needed until 1998. This lack of synchronization between the time wait and then raise the issue directly to the Commission. Of course, y when capacity is added and the time it is needed must be considered in the majority has now added insult to the injury of the parties by voting B

addressing the need question. I also agree with the AIJ that the relia- against my motion to issue a tentative decision which would allow the bility problem with PECO's large base load nuclear plants must be parties to file comunents on the cost cap proposal.

considered in nalyzing the need for Limerick 2. On the issue of whether In conclusion, PECO's management is driving the economy of there are less costly alternatives, the Opinion and Order fails to Southeastern Pennsylvania into decline because of its obdurate comunitment discuss in detail the relative costs of cancellation versus completio's to nuclear power, regardless of cost. The Commission could have put a with a cost cap. As I stated earlier in this Opinion, I,believe that a stop to this, but it has refused to do so. My only hope is that the combination of the " Base Case Alternatives" discussed in the AIJ's courts will reverse this irrational decision.

decision would be less costly, at least in the short run.

Act 62 was signed by Governor Thornburgh on October 10, 1985, ,

@)

one week before the Ceaunission's polling on thas case. Since the legis-e - C s er

- lation became law after the litigation was completed, the parties did Date: I s o not have an opportunity te comment on the impact of these standards upon the outcome of the proceeding. This fact does not justify, however, 3/. The Opinion and Order notes the new standards and states that sanoring the new law.y The parties should f.e a l l owed t o a osunen t upon the assues of need and less costly alternatives were the f oc us of the parties' presentatsens an the case (p. 51). These issues how Act 62 affects the outcome of the case. are not, however, the focus of the Coassission's Final Order.

8 ORM 238 U S NUCLeb E.EQULATOAY COMMISSION i a tPORT NUM9 E R tass.pned by T'OC edd Vo' No .f ear l NmC.:

(28 E"222 BIBLIOGRAPHIC DATA SHEET NUREG-1205 SEE sN37mVCTION5 ON THE PC vER5E 2 TIT LE AND $V8 T iT t t J L E A V E B L A N at Reactivation of Nuclear Power Plant Construction Projects: g Plant Status, Policy Issues, and Regulatory Options E p A O A T E R E,oR1 coy,a ,E 0

, AuTROms,

\ ne MONTH 1986

+ EAR Miller B. Spang r I * """""'5

oONT- . EAR

/ July l 1986 7 74 A6 0RWeNG ORG AN12 AT lOh N AM NO MA sung ADDRE SS ' reuee 1-0 Code, ra ppOstCT T A 5K WOR w, vN T NuYBE R Office of Nuclear Re tor Regulation , ,,_,m,,,

U. S. Nuclear Regulat y Commission Washington, D. C. 205 10 SPONSOR >NG ORG ANi2 A T 6ON N A VE AND M AI L *N ' DDRE 55 f #eude I.a Cooe. -

11 e T v PE OF RE POR Y Same as above Regulatory Report

' ~ '

I[ceIbe719"5Eto June 1986 12 $UPPLE ME NT AR . NOT E S 13 L85TR AC T f 200 eoron or ressi Prior to tne TMI-2 accident on March 2 197 , four nuclear power plant units that had previously been issued a construction pe i were cancelled, principally because of reauced projections of regional power dem . Since that time, an additional 31 units with cps have been cancelled and eight un' deferred. On December 23, 1985 one of the deferred units (Limerick-2) was reactiva d ,d construction resumed. The primary objective of tnis policy study is to ide ify le principal issues requiring office-level consideratice in the event of reactivat' n of t construction of one or more of the nuclear power plants falling into two c Itegories: '1) LWR units issuea a construction permit whose construction has been can 311ed, and k)LWRunitswhoseconstructionhas been deferrea. The study scope is li deserving analysis rather than provid%ted g, attothis identiY tim inganswers regulatory issues or questions or recommendea actions.

Five tasks are aadressed: a tabulatiod and discussion o .the status of all cancelled and deferred LWR units; an identifichion of potential s .ety and environmental issues; an identification of regulatory or p61 icy issues and neede information to determine tne desirability of revising certaif rules and policies; an entification of regulatory options ano decision criteria; and n consiaerations in determiningstaffrequirementsandp[nidentificationofdecis rganizational cooraination LWR reactivation policyandimplementationefforts.I h

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i. OOcuvE N T AN A < .s s . o 40Ros oEsCm,10Rs >s 1.

g ,A,,, A Nuclear power regulation 6 mothballing practice unlimited nuclear safety nuclear environmental issues '

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.n,uc l iERs 0 c,EN oENT e,,ar onstru ENoEe avs ,cti on cancellation / deferral unclassified t Ts4 regger; unclassified 17 NuwSE n OF P AGES

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