ML20078K058

Steam Generator Replacement Study for OL Amend Proceeding. Certificate of Svc Encl

ML20078K058
Person / Time
Site:	Robinson
Issue date:	09/30/1983
From:	CAROLINA POWER & LIGHT CO.
To:
References
ISSUANCES-OLA, NUDOCS 8310180174
Download: ML20078K058 (43)

Text

, . . . . . . . .

00f.KETED USNRC lt3 OCT 17 N1:30 0FFICE OF SECRtIAi.

00CKETING & SEHVlf.I.

BRANCH 1

1 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY F0R OPERATING LICENSE AMENDMENT PROCEEDING NRC DOCKET N0. 50-261 OLA k

SEPTEMBER 1983 l

8310180174 830930 PDR ADOCK 05000261 P PDR

4 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY TABLE OF CONTENTS SECTION TITLE PAGE I. BACKGROUND . . . . . . . . . . . . . . . . . . . . 1 II.

SUMMARY

AND CONCLUSIONS ............. 1 III. STUDY ASSUMPTIONS ................ 3 A. GENERAL ................... 3 B. REPLACEMENT CASE . . . . . . . . . . . . . . . 6 C. RETIREMENT CASE . . . . . . . . . . . . . . 10 IV. STUDY RESULTS . . . . . . . . . . . . . . . . . 13 APPENDIX A HARTSVILLE GROUP CONTENTION 3 APPENDIX B SENSITIVITY CASES APPENDIX C DESCRIPTION OF THE PROMOD COMPUTER MODEL APPENDIX D ROBINSON 2 ESTIMATED FUEL AND SPENT FUEL DISPOSAL COSTS APPENDIX E 1983 LONG-TERM O&M COST PROJECTIONS FOR ROBINSON 2 APPENDIX F PURCHASED POWER COST ASSUMPTIONS APPENDIX G PROJECTED SYSTEM RESOURCES, LOADS AND RESERVES APPENDIX H PROJECTED OPERATING DATA FOR ROBINSON 2 FOR THE REPLACEMENT CASE APPENDIX I ESTIMATED FUTURE CAPITAL INVESTMENTS FOR ROBINSON 2

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CAROLINA POWER &' LIGHT COMPANY f[. A ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY

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- - I.BACKGRbuND Y nI the current NRC licens;ng proceeding with respect to the replacement of the Robinson Unit 2 steam generator lower assemblies, the Hartsville Group contends,(see Appendix A) that retirement of Robinson 2 would be more cost-beneficial than the proposed steam generator repair. In mid-1983, Carolina Power & Light Company performed an economic analysis

, to compare the costs and benefits of repairing the Robinson Unit 2 steam

'/, generators and continuing its operation, with the costs and benefits of retiring the unit and relying on replacement power. .

l II.

SUMMARY

AND CONCLUSIONS The Company performed an economic analysis to compare the cost and benefits of two primary scenarios regarding the Robinson 2 steam generator replacement. One scenario - the Replacement Case - consid'ered the costs and benefits of replacing the steam generator lower assemblies (SGLAs) 1n an extensive outage in 1984. Replacement of the SGLAs is expected to allow Robinson 2 to return to full-rated power operation,

- without frequent periodic steam generator inspection outages.

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The second scenario - the Retirement Case - postulated that the Robinson 2 steam generators would not be repaired and that the unit would be permanently retired at the end of 1984. This scenario reflected the costs associated with retirement and the costs of replacing the Robinson 2 generation from other sources.

The study revealed that over the 15-year study period from 1984 through 1998, the Replacement Case would save CP&L customers approximately $830 million when compared with the cost of the Retirement Case.

In addition to the two' primary scenarios, the stu,dy also included sensitivity analyses of certain factors, including 0&M cost, capital cost, load growth, and capacity factor. All sensitivities continued 'n show a net savings to CP&L customers for the Replacement Case scenario.

A detailed discussion of the sensitivity analyses and other results is provided in Section. IV - Study Results. Also, a discussion of the bases for the study is provided in Section III - Study Assumptions.

Based on the study results, including the sensitivity analyses, it is concluded tha?. there will be considerable benefit to CP&L's customers resulting frg.a replacement of the steam generator lower assemblies and continuation of Robinson Unit 2 operation.

III. STUDY ASSUMPTIONS This section provides the various assumptions which were used in the study for each scenario, including the sensitivity analyses.

A. GENERAL The following are general assumptions which were used as a basis for all study cases.

1. Two primary study cases were considered:

a. Replacement Case - Replace the steam generator lower assemblies in 1984.

b. Retirement Case - Retire Robinson Unit 2 at the end of 1984.

See Appendix B for a schedule of the primary and sensitivity study cases.

2 ., Study Period: 1984-1998 (15 years)

The 15-year study perico (1984 through 1998) was chosen for two basic reasons: 1) that time period was considered long enough to reflect the effect of the steam generator repairs and payback period and to show the effects of retiring Robinson 2 on December 31, 1984, and 2) the use of any longer period would require increasingly speculative assumptions regarding costs and other data necessary for such calculations. The use of a longer study period should not change the conclusions resulting from the 15-year study.

3. Cost Compcnents

a. Operating Costs:

1) System fuel costs were determined by the production cost simulation modsi, PROMOD, which is generally used by the Company for planning, forecasting and study purposes. See Appendix C for a description of -

the PROMOD model. Appendix D provides the annual estimates of Robinson 2 fuel and spent fuel disposal costs which were used in the study.

2) 0&M costs were based on the Company's 1983 long-term projections as provided in Appendix E.

3) Power purchases were used as necessary to maintain a 20% annual planning reserve margin. All otner purchases were economy or emergency purchases.

Purchased Power cost assumptions, upon which the power purchases were based, are provided in Appendix F. Also, projected system resources, loads and reserves as used in each of the study cases are provided in Appendix G.

b. Capital Costs:

1) Only the capital cost of Robinson 2 was considered.

The capital costs and associated revenue requirements for other generating units required under the Retirement Case were not included.

2) The financial factors were based on the capital structure and cost of capital as originally requested in the Company's 1983 North Carolina Rate Case (Docket E-2, SUB 461), as follows:

Weighted Type Ratio Cost Cost Long-Term Debt 49.5 9.59 4.747%

Preferred Stock 12.5 8.96 1.120%

Comon Equity 38.0 15.50 5.890%

Overall Rate of Return 11.757%

Tax Rate = 49.24% ,

Discount Rate = 9.420% (11.757% overall rate of return, net of tax)

No adjustment was made for future changes in the capital structure or cost of capital due to inflation or other economic impacts. This structure was assumed to remain constant throughout the study period.

3) Fixed charge rates were based on the above capital structure and cost of capital. Separate sets of fixed charge rates were developed for both the initial capital cost and post commercial capital additions. These fixed charge rates reflect a 25-year depreciable life for all capital costs.

4. Sensitivity Analysis:

In order to assess the effects of changes in various study components, sensitivity analyses were performed on values of the capacity factor of Robinson 2, system load growth, Robinson 2 0&M cost, and capital additions for Robinson 2.

Specific sensitivity parameten are described under the individual study case assumptions and are also shown in Appendix B.

B. REPLACEMENT CASE The following are assumptions specific to the Replacement Case.

1. The steam generators were assumed to be replaced in 1984 during a 43-week replacement outage starting January 21, 1984.

2. It was assumed that Robinson 2 would maintain an operating capacity factor of 70 percent until it is removed from service for the replacement outage. An operating capacity factor of 85 percent was used fcr Robinson 2 thereafter. For clarification, an " operating capacity factor" is an average capacity factor which excludes periods of scheduled outage.

For example, assuming a projected 85% operating capacity factor and 15 weeks of scheduled outage time would result in a projected annual capacity factor of approximately 60%.

However, for Robinson 2, this annual capacity factor would be somewhat higher because of the difference in summer and winter seasonal capability. Appendix H provides projections of operating capacity factor, scheduled outages, annual capacity factor, and energy generation for the Repiccement Case for each year of the study period.

3. The Company's nuclear outage schedule in effect at the end of March 1983 was used as a basis for outage scheduling and operating capacity factors. See Appendix H for a list of the Robinson 2 scheduled outages used in the study.

4. For additional system generating capacity needed during the study period, the Company's current construction schedule was used, plus additional undesignated units, as follows:

Unit Size In-Service Unit (MW) Date Harris 1 900 1986 Harris 2 900 1990 Mayo 2 720 1992 Undesignated 1 690 19,96 Undesignated 2 690 1998 Appendix G provides the system reserves associated with the above capacity additions. Additional generating capacity was used for determining production cost only. The capital costs associated with these units were not considered, as a conservative approach for the comparison with the Retirement Case.

5. Capital Cost:

a. The capital costs of projected Robinson 2 additions and modifications estimated for the entire study period were based on the Company's 10-year construction program. The estimates incorporated those modifications included in e

the Company's 1983 Construction Budget. Appendix I provides the estimated annual capital cost of Robinson 2 additions and modifications which were used in the study for the Replacement Case.

b. The capital' cost of the replacement steam generators was depreciated over 25 years using straight-line depreciation.

c. The existing steam generators were retired by-appropriately adjusting the depreciation reserve.

6. Decommissioning:

Decommissioning revenues were provided based on estimates supporting current rate recovery. These revenue projections were provided from a decomissioning revenue computer program, and were based on the current plans adopted by the North Carolina Utilities Comission (NCUC) and the South Carolina Public Service Comission (SCPSC), which use a retirement date of April 13, 1997. (Note: This retirement date is used only for decomissioning revenue collection and is not the Company's proposed retirement date).

It was assumed that the existing steam generator lower assemblies will be stored on site and decomissioned at the same time the unit is decommissioned. Interim storage was assumed in an on-site tomb; the cost of this tomb is included in the 1983 Construction Budget and reflected in this study.

Ultimate disposal cost is considered negligible since the radiation level of that equipment should be insignificant at the time of unit decommissioning.

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7. Sensitivity Analysis:

a. Capacity Factor: For sensitivity analysis purposes only, the operating capacity factor for Robinson 2 was assumed to be 70 percent for the entire study period. In addition to other scheduled outages, a four-week steam generator inspection outage was assumed to be required every three effective full power months (EFPM). No improvement in operating capacity factor was assumed after replacement of the SGLAs. Operating capacity factor is an average capacity factor which excludes periods of scheduled outage. Assuming 6 70% operating capacity factor for Robinson 2; an annual refueling, maintenance and steam generator inspection outage; plus an additional steam generator inspection outage, the resulting annual capacity factor would be approximately 51%.

b. Load Growth: For sensitivity analyiis purposes only, zero system load growth was assumed after the forecasted 1984 summer peak of 7043 MW. Using this peak will allow for the increase in additional Power Agency load, which is already under contract. This case was compared to a similar sensitivity under the Retirement Case.

c. 0&M Cost: It was assumed, for sensitivity analysis purposes only, that the Robinson 2 0&M cost would be significantly higher than current projections. For 14 years of the study period, the sensitivity case 0&M costs ranged from 41% to 95% higher than the Company's long-term 0&M estimates which were used in the Replacement Case. During 1984, the year of the steam generator replacement outage, the sensitivity 0&M costs were 15% higher than in the Replacemert Case. The sensitivity case 0&M costs averaged over mp- -- # -- ,y- ,

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58% higher for the 15-year study period. Therefore, the sensitivity 0&M cost values were substantially higher than the 0&M costs based on historical actual costs and projections based on repair of the steam generators.

d. Capital Additions: For sensitivity analysis purposes only, the capital estimates for Robinson 2 additions and modifications beyond 1986 were arbitrarily

-increased by a factor of 4.

C. RETIREMENT CASE The following are assumptions specific to the Retirement Case.

1. It was assumed, for study purposes only, that Robinson 2 would be permanently retired on December 31, 1984. This date was based on a qualitative review of the accelerating corrosion rates from the spring 1983 steam generator inspection outage and an extrapolated future corrosion rate. The actual date of retirement would depend on future actual operating experience and the point at which continued operation of the unit would not be economical. Any decision on retirement of the unit would be influenced by several factors, such as a continuous evaluation of the allowable thermal limits, any necessary reductions in power level, and the frequency of required inspection outages.

2. The operating capacity factor of Robinson 2 was assumed to be 70 percent until retirement on December 31, 1984.

3. The Company's nuclear outage schedule in effect at the end of March 1983 was used as a basis for outage scheduling and operating capacity factors, except as indicated herein.

4. Based on the results of the spring 1983 steam generator inspection outage, it was assumed that a four-week steam generator inspection outage would be needed every three EFPM, until retirement.

5. The retirement of Robinson 2, as assumed in the Retirement Case, would result in insufficient generating capacity on the CP&L system. For study purposes, construction of generating units planned or anticipated for the future was assumed to be accelerated to make up the deficiency created by the retirement of Robinson 2, as shown by the following table:

Unit Assumed Assumed Size Accelerated Schedule Unit (MW) In-Service Date Acceleration Harris 1 900 1986 No acceleration assumed

• Harris 2 900 1990 No acceleration assumed

• Mayo 2 720 1991 1 year Undesign. 1 690 1994 2 years Undesign. 2 690 1996 2 years Undesign. 3 '690 1998 2 years

• No acceleration of the in-service date of Harris 1 or 2 is assumed tacause of the current stage of construction, lead time requirements on equipment and ccnstruction, and regulatory schedules.

Appendix G provides the system reserves associated with the above capacity additions.

The benefit of the acceleration of the units, as shown in the above table, was included for determining production costs.

However, the additional capital costs and associated revenue

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requirements for constructing the replacement capacity, plus other financial impacts of accelerating construction of the above units, have not been included in the study cost comparisons, as a conservative approach. Inclusion of these costs would further increase the cost of Robinson 2 retirement, resulting in increased savings from continued operation of Robinson 2 after replacement of the SGLAs in 1984.

6. The decision date for accelerating the construction of new units was assumed to b'e January 1, 1984

7. Capital Cost:

a. The capital cost of Robinson 2 additions and modifications through December 31, 1984 was included,

b. The uravoidable portion of capital cost commitments (such as " sunk" costs for materials and equipment, and work already performed) for future additions and modifications identified in the Company's 1983 Budget and 10-year construction program, was included.

c. It was assumed that the undepreciated cost of Robinson 2 I

based on retirement on December 31, 1984 would be recoeered over a 10-year period.

8. Decommissioning:

I The assumption was made that upon early retirement, the unit I will be entombed, with surveillance following for the next i 30 years. At the end of the surveillance period, the unit would be dismantled and permanently disposed of. This amounts

to basically the current decommissioning cost-recovery plan, as approved by the NCUC and the SCPSC for ratemaking purposes, but accelerated for work to begin in 1985 rather than 1997.

Escalation rates for projecting nominal costs were those adopted by the NCUC and the SCPSC for decommissioning cost collection. All decommissioning costs were assumed to be collected from customers in 1984 to make the fund whole and allow work to begin in 1985.

9. Sensitivity Analysis: .

a. Capacity Factor: No sensitivity for Retirement Case $hi capacity factor was performed.

b. Load Growth: For sensitivity analysis purposes, zero load growth was assumed after the 1984 summer peak of 7043 MW. Using this peak will allow for the increase of additional Power.Acency load, which is already under contract.

c. 0&M Cost: No sensitivity for Retirement Case 0&M cost was performed.

d. Capital Additions: No sensitivity was performed in the Retirement Case for the cost of capital additions and modifications for Robinson 2.

IV. STUDY RESULTS The Company's economic analysi3 to assess the benefit of steam generator 1 repairs at Rcbinson 2 was based on comparing two primary scenarios. The Replacement Case considered the cost and benefits of replacing the Robinson 2 SGLAs in a 43-week outage beginning January 21, 1984 The Retirement Case assumed that the SGLAs woulo not be replaced, resulting

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I scenario. The costs considered included the fuel and O&M costs of N

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costs, the carrying charges on nuclear fuel inventory, and the capital

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L The results of the study cost comparison show that replacement of the fk,%h. -

Robinson 2 SGLAs will s' ave the Company's customers approxi u tely ...Y! p,h.

$830 million in nominal dollars (or $343 million in 1983 dollars) over f:

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' the 1984 through 1998 study period. Table 1 shows a comparison of e' -

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9 Company's best estimates of cost and other input available at the time / h-g g-the study was prepared. Therefore, these results are considered to D. j .

%. 3 .I i reflect the most probable cost comparison. However, in order to assess (9@. u-Y the effect of possible changes in some of the key study assumptions, .M E sensitivity analyses were performed. Assumptions upon which sensitivity (M.Av, analyses were performed include Robinson 2 0&M cost, the capital cost of ':.7 y- .

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1 For the sensitivity analysis, the Company's best estimate for each of these assumptions was separately replaced with a value that was generally considered to be a boundary or worst case assumption. The I values used for each sensitivity analysis are described for each study case in Section III - Study Assumptions.

Table 2 provides the results of the various sensitidty analyses. As shown on Table 2, for each sensitivity cost comparison using generally boundary or worst case assumptions for the variable indicated, there remains a cost savings to customers for replacing the Robinson 2 SGLAs.

Considering all of the economic analysis and cost comparisons performed for the Dobinson 2 SGLA replacement, the study shows that replacement of the Robinson 2 SGLAs will result in a net cost savings to Carolina Power

& Light Company's customers.

4 TABLE 1 ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY COST COMPARIS0N OF REPLACEMENT CASE WITH RETIREMENT CASE

, REPLACEMENT CASE:

Replacement of Savings of Savings of  ;

Steam Generator RETIREMENT CASE: Replacement Case Replacement Case Lower Assemblies Retire Robinson 2 Over Over in 1984 December 31, 1984 Retirement Case Retirement Case Year (000s $) (000s $) (Nominal 000s $) (1983 000s $) _

1984 761,828 719,514 -42,314 -38,671 . .

1985 767,737 817,866 50,129 41,869 1986 847,616 894,338 46,722 35,664 1987 918,807 926,714 7,907 5,516 1988 1,101,398 1,118,362 16,964 10,815 1989 1,092,615 1,210,525 117,910 68,702 1990 1,189,124 1,214,104 24,980 13,302 1991 1,458,562 1,486,412 27,850 13,554 1992 1,441,645 1,514,283 72,538 32,307 1993 1,621,005 1,723,921 102,916 41,833 1994 1,934,101 1,990,309 56,208 20,880 1995 2,081,988 2,131,892 49,904 16,942 1996 2,315,034 2,435,528 120,494 37,386 1997 2,579,761 2,669,751 89,990 25,518 1998 2,868,250 2,956,285 88,035 22,814 s

TOTALS $22,979,471 $23,809,804 $830,333 $348,431

TABLE 2

• ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY .

RESULTS OF SENSITIVITY ANALYSIS COST SAVINGS RESULTING '

- SENSITIVITY ASSUMPTIONS FROM SGLA REPLACEMENT NOMINAL 000s $ 1983 000s $ =

BASE CASE 830,333 348,431

1) Increased Robinson 2 388,622 154,697 0&M Costs in Replacement Case by an average of over 58% for each -_

year of the study period. ..

2) Increased Robinson 2 Capital 676,522 292,126 costs in Replacement Case.

Robinson 2 capital additions and modifications after 1986 were increased by a factor of 4.

3) No improvement in Robinson 2 497,325 190,149 operating Capacity Factor after replacement of the _

SGLAs, in the Replacement _

Case. Operating Capacity _

Factor held at 70%, and _

assumed a 4-week steam 7 generator inspection outage every three EFPM. .

4) Zero system load growth was 314,617 112,094 assumed for both the Replacement and Retirement Cases. The forecasted 1984 -

summer peak load of 7043 MW -

was held constant for the remainder of the study period. -

Under all sensitivity assumptions, the Replacement Case continues to show a significant cost savings.

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CAROLINA POWER & LIGHT COMPANY l ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY l

APPENDICES APPENDIX A HARTSVILLE GROUP CONTENTION 3 APPENDIX B SENSITIVITY CASES APPENDIX C DESCRIPTION OF THE PROM 0D COMPUTER MODEL APPENDIX D ROBINSON 2 ESTIMATED FUEL AND SPENT FUEL DISPOSAL COSTS APPENDIX E 1983 LONG-TERM 0&M COST PROJECTIONS FOR ROBINSON 2 APPENDIX F PURCHASED POWER COST ASSUMPTIONS APPENDIX G PROJECTED SYSTEM RESOURCES, LOADS AND RESERVES APPENDIX H PROJECTED OPERATING DATA FOR ROBINSON 2 FOR THE REPLACEMENT CASE APPENDIX I ESTIMATED FUTURE CAPITAL INVESTMENTS FOR ROBINSON 2 l

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u APPENDIX A Page 1 of 2 HARTSVILLE GROUP CONTENTION 3 The Hartsville Group's Contention 3, as allowed for litigation by the Atomic Safety and Licensing Board (ASLB), is as follows: -- -

"The Applicant's Evaluation of Alternatives incorrectly weighs the costs of retirement of Robinson. The cost-benefit balance should be struck against the repair of the steam generators in favor of. retirement of Robinson as the most cost-beneficial alternative. The EIS should strike that balance. An analysis of the alternative of closing Robinson 2 is required by 102(2)(e) 42 USC4332(2)(e).

"The cost-benefit analysis involving repair?. to an aging nuclear plant like Robinson 2 is analogous to the analysis of major repairs to an aging automobile. Repairing the steam generators at Robinson 2 is like putting new tires on a car with bad main bearings.

"The Energy Systems Research Group of Boston found in an October 1982 study of Indian Point, The Economics of Closing the Indian Point Nuclear Power Plants, that the percentage impact on rates of closing those facilities would be less than 2%. Application of their Cost Assessment of Nuclear Substitution model to Robinson would show that the proposed steam generator repair to keep Robinson operating is not cost-effective. Robinson 2 is older than the Indian Point plants, and has continuing major equipment problems and reactor embrittlement which compounds the potential for Pressurized Thermal Shock, which may close Robinson 2 down within three to six years and/or result in significant derating. Non-oil fired make-up power is available to substitute for power that Robinson would have generated.

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APPENDIX A .

Page 2 of 2 "The cost-benefit analysis should include not just the cost of repairs to Robinson 2, but other avoided future costs if Robinson 2 is retired, -

including expenditures on nuclear fuel, operating and maintenance expenses, and a portion of the costs of nuclear waste disposal.

"Because the Applicant cannot demonstrate that the proposed changes in the Model 44F steam generators will solve the problems which have led to tube leaks in the old Model 44F steam generators, the Applicant cannot rightly ..

claim that occupational exposures to workers during testing and repair of the new steam generators will be reduced but should be required to assume that future exposur'es will be substantially the same as current exposures. As the staff's ' Steam Gene'rator Status Report' of February 18, 1982 notes regarding earlier ' fixes': 'these fixes have met with varying degrees of success, but ^~

none of them is a panacea. Furthermore, short-term solutions to one problem may create other problems.'"

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CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY SENSITIVITY CASES ROBINSON 2 LOAD O&M CAPITAL ROBINSON 2 HARRIS 1 HARRIS 2 PAYO 2 UNDES. 1 UNDES. 2 UNDES. 3 CAPACITY FACTOR GROWTH COST COST

, CASE NO.

Replacement Replace SGLAs 1986 1990 1992 1996 1998 -

(1) Current Base Base (Base) 1984 Retirement Retire Unit 1986 1990 1991 1994 1996 1998 (2) Current Base Base 1984

CF Replace SGLAs 1986 1990 1992 1996 1998 -

(3) Current Case Base 1984 Replace SGLAs 1986 1990 1992 1996 1998 -

(1) O(A) Base Base LG-1 1984 1996 1998 (2) O IAI Base Base LG-2 Retire Unit 1986 1990 1991 1994 1984 O&M Cost Replace SGLAs 1986 1990 1992 1996 1998 -

(1) Current +58%(B) Base 1984 Replace SGLAs 1986 1990 1992 1996 1998 -

(1) Current Base x4(C)

Cap. Cost 1984 ,

Robinson 2 Capacity Factor (CF) Assumptions (1) Operating Capacity Factor

• of 70% used until removed for Replacement Outage. Operating Capacity Factor

• of 855 used thereaf ter.

(2) Operating Capacity Factor

• of 70% used until Retirement. A four-week Steam Generator Inspection Outege was assumed every three EFPMs. untti Replacement. ,

(3) Operating Capacity Factor

• of 70% used for duration of the study. A four-week Steam Generator Inspection Outage was assumed every three EFPMs for study duration.

• 0perating capacity factor is an average capacity factor which excludes perjods of scheduled outage.

General Notes

]A) Zero load growth (LG) was assumed af ter the 1984 suriner peak of 7043 MW. For this sensitivity case, all other parameters and results were the same as used in each primary study case. ,

(B) The Replacement Case was used as the basit for the sensitivity case for 0&*1 costs. For this sensitivity case, all parameters and results were the same as the Replacement Case, except for Robinson 2 O&M costs, which were increased on the average by over 58% in eaca year over the 15-year study period.  ?%

un m (C) The Replacement Case was used as the basis for the sensitivity case for capital cost. For this sensitivity case, all parameters and results were the same as the Replacement Case, except for the capital cost of future additions and modifications. These capital cos M were increased *Qno by a factor of 4 for this sensit%ity case.

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APPENDIX C )

Page 1 of 9 CAROLINA POWER & LIGHT COMPANY 1

ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY DESCRIPTION OF THE PROMOD COMPUTER MODEL INTRODUCTION -

PROMOD III is the primary computer software tool that CP&L uses for planning studies, forecasting fuel and purchased power requirements, and to perform economic analyses for consideration of various contingency scenarios.

PROM 0D III was developed by Energy Management Associates, Inc., from whom CP&L leases the right to use the model.

SUMMARY

OF PROMOD III The PROM 0D III system simulates the economic operation of the system and determines the associated financial impact of fuel and purchased power. It is first and foremost a comprehensive production costing model for projecting future operating costs.

PROMOD III differs from conventional production costing programs in its treatment of generating unit forced outages. It is these random and unpredictable forced outages that comprise the major factor in the disruption of fuel budget forecasts, operating cost estimates, and projected utilization of high-cost peaking and mid-range equioment. PROM 0D III employs a special mathematical technique to explicitly consider the impact of forced outages on fuel requirements and, thus, operating costs. A more detailed discussion of PROM 00 III's treatment of forced outages is provided later in this discussion.

In addition to forced outages, PROM 0D III considers the relative efficiencies (operating costs) of the generating units so that generator output will be matched with electric demand in the most econcmical manner. Other operating restrictions which impact CP&L operating costs include spinning and quick-start reserve requirements and import and export capability limitations of the transmission network. These as well as other considerations are explicitly modeled in the PROMOD III program. Its strength lies in the

APPENDIX C Page 2 of 9 combination of probabilistic production costirig techniques with detailed _

modeling of operating considerations to produce realistic estimates of fuel consumption and operacing costs.

PROM 00 III INPUTS; The minimum basic data needed to make a CP&L PROM 00 III study falls into five categories:

o Generating Unit Data - unit types, heat rates, fuel types, capacity states, forced outage rates, seasonal derations, and maintenance requirements. Specialized da*.a may be input for conventional hydro _

units.

o Fuel Data - cost of the various fuels used by generating units.

o Load Data - demand and energy forecasts and chronological load shapes.

o Transaction Data - type, capacity, energy, availability, timing, and costs.

o Utility System Operating Data - operating reserve requirements, reliability target levels, and available tie support.

MODELING TECHNIQUE At the heart of PROM 0D III is a modeling technique which allows the explicit consideration of randomly occurring forced outages, forced derations, and postponable raintenance outages of every generating unit and generation resource alternative. PROMOD III's probabilistic technique, in effect, dispatches every possible configuration of the generation system to obtain the best forecast of expected fuel consumption, unit generation, and system reliability, and ultimately leading to the best estimate of future operating

APPENDIX C Page 3 of 9 costs. PROMOD III accounts not only for the effect of a unit's outages and derations on its own operation, but also for the effect c:' a unit's outage on the operation of all other units in the utility system.

A simple example provides an introduction to the PROMOD III probabilistic technique:

In this example, there is a sirgle hour's load to be satisfied by two generating units. The value of the load is 150 MW. The generating unit, to be considered first on the basis of cost, has a capacity of 80 MW and an 80 percent probability of being available, while the second unit has a capacity of 100 MW and an availability of 90 percent.  :

In Figure 1, the loading of the first unit is depicted. The unit may be either available for service (probability 0.8) or unavailable (probability 0.2). In the event the unit is available, it will satisfy 80 MWH of load and leave 70 MWh remaining. In the event the unit is unavailable, it will supply nothing and 150 MWH will remain. The expected generation of Unit 1 is, therefore, 64 MWH, and the expected remaining load is 86 MWH.

In Figure 2, the loading of the second generating unit is illustrated.

Because of the two possible outcomes from the loading of the first unit, there are now four possibilities for the loading of the second unit.

The calculations show that the expected generation o' Unit 2 is 68.4 MWH, and the expected remaining load is 17.6 MWH. If more units existed, the number of outcomes would continue to expand exponentially.

In PROM 00 III, a number of separate calculations and probability branches shown in Figures 1 and 2 are replaced by a technique which, for this example, would require only one calculation per unit loaded.

Although it is a more complex calculation, it requires the retention of only one outcome after each unit is loaded rather than an exponential proliferation of outcomes. This technique is illustrated diagrammatically in Figure 3. Each unit, together with its probability

APPENDIX C _ -

Page 4 of 9 x:::y,:;..

. .r .. . . y:9 p.

. [5 i of being available, is combined with the remaining load from the 9 p .. .$.,

previous unit so that a new remaining load is produced representing all (ppj.

i.: . . .

of the outcomes possible with the units dispatched to that point, dn.%/.cT' y . w weighted according to the appropriate probabilities. Thus, the ..g

. n . .,

%.3 ,

remaining load in Figure 3 after Unit 2 is loaded is an accumulation of 'y..j thi same MW values and probability values that are used to describe the various remaining load outcomes in Figure 2 after Unit 2 is loaded. M M.

,/., y,;.gy 3 4 The above example demonstrates PROM 0D III's treatment of full-forced outages. .'h hjh Generating units can be further represented by a multistate failure model to i- yp.g

. c .,

give consideration to partial loss of unit capability.

; d;i; g ~.4 , . . ,

& . ,y y The PROMOD III algorithms include much more than a multistate version of the .

k.:

probabilistic calculation discussed above. The basic program contains M ,g ,g .

dispatch logic capable of simulating the effect of unit commitment and (('.M[

economic dispatch. The economic dispatch process is achieved by the division [:dk of thermal generation units (coal, oil, gas, nuclcar) into discrete capacity h segment much in the same way that a real-time control system dispatches units on load control in discrete steps. Heat rates and availability data for each

)h}f.&

segment, coupled with unit forced outage rates and fuel cost data, provide h)h[

the program with input which must be considered in accurately predicting h economic dispatch. CP&L models its generating units with five capacity and

-[h availability states.

9.1%M;T; CP&L employs a slightly different approach in the modeling of nuclear ppg ymeration within PROMOD III. CP&L targets projected nuclear generation at a f .e -:s 4 '

le/el which takes into account maintenance outaqe requirements and the N  :

available capacity factor expected between maintenance outages. -

TM - .

In addition to determining the generation anticipated from the Company's [Yg.

thermal power sources, PROMOD III uses heat rate data, along with the type of [k.[h.J hat content of the fuel, to arrive at the amount of fuel consumed. ({h! u c d h y%+4 l er, i.' ~, .

%- [; F t 'I .-* ,e , es

- . J#,,

- mmmm mm m u ms u m E

mancy  :.

..; g - (

PROMOD III simulates the production of energy to meet projected customer g .

loads. Historical CP&L load data provides the basis for detenninina the load 4 k . .r '

pattern for a typical week during each month under consideration. The b /

9rs -

typical week ioad pattern is used to derive load duration curves for y 71 O,

m. , w weekdays, weeknights, and weekends, three periods during which similar -* c w -

operating conditions exist. These load duration curves are used in the [7

.i..... 1 program's probabilistic simulation to accu ately reflect CP&L's generation  %; . fj$ ,?h .

. .~

scheduling and unit commitment process. #O "W:.

p .4.'yp- M

> y r ? :'i Power interchanges may also be addressed within a PROMOD III simulation. AQ-;n . ..

Transactions involving a fixed emount of energy increase or decrease the 3_.,Q 1

~.. .

system load duriag the period for which they are applicable. Thus, hydro and . .,,U.N..y Q.

sy thermal generating units will be called upon to produce more or less energy 7pg to meet the demand, depending upon the amount or nature of the tranraction.  ;'K..p'y.

CP&L models nonfirm (economy) purchases in PROMOD III as a power source which Nt%'-

can be used after CP&L's fossil steam units have been loaded but before I~Nk;..IE Q?y - .

CF&L's internal combustion turbine units are utilized. The amount of IC g,. q .# -

generation displaced is controlled by the specific characteristics of the economy power source, such as maximum capability and availability, and is i:.4}py i .. Q n . . .-

based upon analyses of historical economy interchange activity and future g_ {

market conditions. bq~E.h.: .. . t

. .=

4 Energency transactions occur in PROMOD III only when the utility system has .!

.s exhausted all of its other resources and is faced with unserved energy. In [ N. %N the area of emergency transactions, CP&L's approach is to model the use of its ties with other utilities as a source of power with a capability 'f consistent with maintaining targeted system reliability. This power source h/f.

is not utilized until all other units have been loaded to their maximum Y[

g: g[.5. 4 .. i dependable capacities. 7 ; J-[?

tu i

APPEtiDIX C Page 6 of 9 ADDITIONAL INFORMATION ,

In 1977, CP&L acquired a license for the use of PROM 0D III from Energy Management Associates, Inc., the creator of the program. Within that license, CP&L acknowledges and agrees that the use of the program is furnished on a confidential basis and that CP&L will treat the program and f

I other supporting material as the proprietary information of Energy Management Associates. The information which has been provided herein is an attempt to supply as much detail as possible regarding the program employed by CP&L, ,

without compromising CP&L's confidentiality commitment to Energy Management Associates, Inc.

4 S

tr

• APPEf1 DIX C Page 7 of 9 Load Unit 1 150 MW Unit 1 Expected Cacacity = 80 MW Expected Availacility = 0.8 Remaining Generation Load 150 '

70 MW Remaining 80 '

OMW 0.8 x 80 0.8 x 70 Unit 1 Generation 150 MW 3 @ #

\

0 ' *s 1 Hour , '$

150 3 150 MW

• Remaining 0.2 x 0 0.2 x 150 -

Load 0 >

64 MWH 86 MWH Figure 1: Probabilistic View Of L0ading One Unit

T '?

, , APPENDIX C Page 8 of 9 l

1 o O O .

i_? x x , x g i

I u..io o o

e o s l

I

$64 wy x x x N

~

e e N a l o a o o l

e o

N o 8

- o I N 3. h. -

a - a -

s .

c an a o . o o ,

U w ho X X X X e a e n n o o o o a

3 6 F F  ?

.a e eg a 5 ge by5 Rod

$la !l 2"E 3ja

$ n n R23 SE $$8 Cx3 g, n -

03< 82

, R o S 8 s

'? > $ q '* * $ q 3

sm - -

o '

i s

03< > S 8 S 9 'e cd*

% e

^

1:

3!

3 o

, s S. .

Figure 2: Probsbilistic View of Loading Two Units 1

J

APPENDIX C

. Page 9 of 9 4

l Load Unit 1 Unit 2 150 MW Capacity = 80 MW Cacacity = 100 MW Availability = 0.8 Availaodity = 0.9 08 150 150-

~

iso ! ,,,

Unit 1 l/

• 80 MW eneration/ hI Unit \

Generation

\

70 4 70 e Remaining load 50 Remaining load

= 150 < (0.2 - 0.0) = 150 (0.02 - 0.01

+ 70 x (1.0 - 0.2) + 70 (0.10 - 0.02)

= 86 MWH / + 50 (0.28 - 0.101 Ceneration$ -0 (1.0 - 0.28) 0 0 0'

= 17.6 MWH ll l 0.00.2 1.0 e gog 1.0 I

Unit 1 Generation Unit 2 Generation

= 150 - 86 = 86 - 17.6

= 64 MWH = 68.4 MWH l

Figure 3 : PROMOD III's Method Of Probabilistic Simulation ,

l

. - - - -.- , _ - -..~ .._ ..._ _.-. _ -_ -._ ..-,....... - __ - - - _. . .- - _. _ - . - _ . . .

APPENDIX D Pagg 1 of 1

-CAROLINA POWER & LIGHT C MPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY 4

ROBINSON 2 ESTIMATED FUEL AND SPENT FUEL DISPOSAL COSTS The following table provides the Company's annual estimates of Robinson 2 ,

fuel and spent fuel disposal costs, as used in the study for the Replacement Case:

Robinson 2 Robinson 2

• Spent Fuel

- Total

• Fuel Disposal Cost Cost Years ($/MWH)_ ($/MWH) 1984 4.7 1.1

-1985 5.0 1.2 1986 6.5 1.3 1987 7.1 1.4 1988 7.5 1.5 1989 8.3 1.6 1990 9.2 1.7 1991 10.0 1.8 1992 11.0 1.9

. 1993 12.7 2.0 1994 13.7 2.1 1995 14.4 2.2 1996 15.6 2.3 I

1997- 16.9 2.5 1998 17.7 2.7 l

• Includes spent fuel disposal costs.

i

APPENDIX E Page 1 of 1 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY 1983 LONG-TERM 0&M COST PROJECTIONS FOR ROBINSON 2

-In early 1983, CP&L developed long-term 0&M cost projections for its generating plants. These long-term projections were based on the Company's 1983 0&M Budget and the schedule of outages and maintenance activities which had been identified at that time. The following are the Company's 1983 long-term 0&M cost projections for Robinson 2, which were used in the study: ,

Robinson 2 O&M Cost Projections Year ,

(000s $)

1984 ,

37,769 1985 32,944 1986 28,724 1987 38,519 1988 41,978 1989 41,306 1990 37,141 1991 49,155 1992 52,706 1993 49,65i 1994 54,290 1995 64,910 1996 69,589 1997 60,426 1998 77,198

APPENDIX F Page 1 of 2 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY PURCHASED POWER COST ASSUMPTIONS The following assumptions for the cost of purchased power were used for the Robinson 2 Steam Generator Replacement Study.

General Power purchases based on these assumptions were used as necessary to maintain a 20% annual planning reserve margin. All other purchases were economy or emergency purchases.

Period 1984-1988 i

For this period it was assumed that sufficient capacity to replace Robinson 2 would be available from Southern, TVA, and/or SCE&G systems.

Based on a 1982 survey of all three companies, the following estimated purchased power costs were used.

Demand Charge: Based on an average cost of existing mature coal-fired units, as follows:

1984 1985 1986 1987 1988

$/KW/M0.

• 8.00 8.50 9.00 10.00 Energy: Based on mid-priced coal-fired fuel cost + 0&M cost + 10% of that sum, as follows:

Mills /KWH:

• 39.81 47.61 51.73 52.11

• No firm purchases required in 1984.

1 APPENDIX F Page 2 of 2 Period 1989-1998 In this period, no determination can be made as to the availability of capacity from neighboring utilities. A reasonable assumption might be that some capacity could be purchased in this time period; but in lieu of the lower rates being offered in the mid 1980's, it should be assumed that capacity would have to be purchased at prices based on new coal-fired units with scrubbers installed in this time period. Purchased power costs were assumed as follows (note that 1989 demand charge is based on a transition value betweer the 1988 and 1990 demand charges):

Demand Charge: Year $/KW/MO.

1989 20**

1990 30 1991 33 1992 36

. 1993 39 1994 42 1995 46 1996 50 1997 55 1998 60 Energy Charge:

Mills /KWH Undesignated Unit Fuel Cost + 0&M + 10%

(for each year in this period)

The price for economy purchases continued to be based on a split between the Company's coal and oil generating costs.

• • Transition Value

APPENDIX G Page 1 of 3 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY PROJECTED SYSTEM RESOURCES, LOADS AND RESERVES FOR THE REPLACEMENT CASE Previous Yea 's Installed Other New Total Peak Capacity Resources Capacity Resources Load ,

Reserves Percent Year (MW) (MW) (MW) (MW) (MW) (MW) Reserves

• 1984 8725 75 8800 7043 1757 24.9 1985 8725 75 8800 7346 1454 19.8 1986 8725 75 900 9700 7557 2143 28.4 1987 9625 75 9700 7674 2026 26.4 1988 9625 75 9700 7852 1848 23.5 1989 9625 75 9700 8043 1657 20.6 1990 9625 75 900 10600 8224 2376 28.9 1991 10525 75 10600 8461 2139 25.3 1992 10525 75 720 11320. 8605 2715 31.6 1993 11245 75 11320 8854 2466 27.9 1994 11245 75 11320 9094 2226 24.5 1995 11245 75 11320 9386 1934 20.6 1996 11245 75 690 12010 9696 231a 23.9 1997 11935 75 12010 9998 2012 20.1 1998 11935 75 690 12700 10300 2400 23.3

• CP&L's planning criteria is to maintain a minimum 20% reserve margin.

1

APPENDIX G Pags 2 of 3 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STilDY PROJECTED SYSTEM RESOURCES, LOADS AND RESERVES FOR THE RETIREMENT CASE Previous Year's Installed Other New Total Peak Capacity . Resources Capacity Resources Load Reserves Percent Year (MW) (MW) (MW)* (MW) (MW) (MW) Reserves

• 1984 8725 75 8800 7043 1757 24.9 1985 8060 740 8800 7346 1454 19.8 1986 8060 93 900 9053 7557 1496 19.8 1987- 8960 234 9194 7674 1520 19.8 1988 8960 447 9407 7852 1555 19.8 1989 8960 677 9637 8043 1594 19.8 1990 8960 75 900 9935 8224 1711 20.8 1991 9860 75 720 10655 8461 2194 25.9 1992 10580 '75 10655 8605 2050 23.8 1993 10580 75 10655 8854 1801 20.3 1994 10580 75 690 11345 9094 2251 24.8 1995 11270 75 11345 9386 1959 20.9 1996 11270 75 690 12035 9696 2339 24.1 1997 11960 75 12035 9998 2037 20.4 1998 11960 75 690 12725 10300 2425 23.5

• CP&L's planning criteria is to maintain a minimum 20% reserve margin.

APPENDIX G Paga 3 of 3 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY PROJECTED SYSTEM ENERGY INPUT REQUIREMENTS The following table provides the Company's projected system energy input requirements which must be served by the Company's generating units or purchases from other utilities. These system energy input requirements are based on the Company's 1983 forecast of energy sales.

Projected System Energy Input Requirements * ,

Year (GWH) 1984 35985.0 1985 37303.0 1986 38475.0 1987 39460.0 1988 40705.0 1989 41978.0 1990 43232.0 1991 44654.0 1992 46064.0 1993 47427.0 1994 48789.0 1995 50290.0 1996 51868.0 1997 53493.0 1998 55171.0

• Based on 1983 Energy Forecast

APPENDIX H Page 1 of 1 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY PROJECTED OPERATING DATA (1) FOR ROBINSON 2 FOR THE REPLACEMEN Operating (2) Annual (3) Energy (4)

Capacity ,

Capacity Generation Year Factor (Percent) Scheduled Outages Factor (Percent) (GWH) _

1984 85(5) 01/21 - 11/16 15 878.7-1985 85 10/19 - 12/31 69 4045.0 1986 85 01/01 - 01/31 80 4660.0 1987 85 01/31 - 05/15 62 3611.4 1988 85 07/16 - 10/28 63 3671.7 1989 85 - 88 5103.3 1990 66 01/01 - 04/01 65 3804.5 1991 85 06/03 - 09/01 66 3866.3 1992 85 11/02 - 12/31 73 4259.9 1993 85 01/01 - 01/31 80 4660.6 1994 85 04/04 - 07/07 66 3850.4 1995 85 09/04 - 12/03 66 3824.4 1996 85 - 88 5117.6 1997 85 02/03 - 05/04 65 3806.7 1998 85 07/06 - 10/04 66 3867.0 NOTES:

U )The data provided are the Company's current projections at the time the study was performed; however, these projections are subject to change as system or controlling conditions change.

(2)0perating capacity factor reflects forced outages only, not scheduled outages.

(3) Based on a 665 MW maximum dependable capacity rating for Robinson 2 and projected annual energy generation.

(4) Annual energy generation is developed from ceasonal Robinson 2 capacity '

ratings of 665 MW for summer and 700 MW for winter.

(5)In 1984, prior to the start of the steam generator replacement outage (January 21) Robinson 2 is projacted to cperate at only 70% operating capacity factor. Upon return to service following that outage, Robinson 2 is projected to operate at 85% operating capacity factor.

APPENDIX I Page 1 of 1 CAROLINA POWER & LIGHT COMPANY ROBINSON UNIT 2 STEAM GENERATOR REPLACEMENT STUDY ESTIMATED FUTURE CAPITAL INVESTMENTS FOR ROBINSON 2 The following table provides estimates of the future.capit.a1 investments for additions and modifications at Robinson 2, as used in the study for the Replacement Case:

Robinson 2 Estimated Net Construction Cost of Future Additions and Modifications Year ($000s) 1984 69,155.

1985 26,021 1986 7,921 1987 2,174 1988 2,377 1989 2,584 1990 2,829 1991 3,075 1992 3,359 1993 3,656 1994 3,992 1995 4,354 1996 4,742 1997 5,168 1998 5,633 NOTE For study purposes, it was assumed that $62,800,000 was spent for the Robinson 2 steam generator replacement project in years prior to 1984. The estimated total capital cost of the Robinson 2 steam generator replacement project, which was used in the study and reflected in the Company's 1983 Construction Bud9 et, is $105,673,000.

a l 4

00CKETED USNRC 1D DCT 17 -41 :30 UNITED STATES OF AMERICA 0FFICE OF SElat.!An -

NUCLEAR REGULATORY COMMISSION 00CKETING & SERV 101.

BRANCH BEFORE THE ATOMIC SAFETY'AND LICENSING BOARD In the Matter of )

)

CAROLINA POWER & LIGHT COMPANY ') Docket No. 50-261-OLA

)

(H. B. Robinson Steata Electric ) ASLBP No. 83-484-03LA Plant, Unit 2)- )

CERTIFICATE'0F~ SERVICE I hereby certify that copies of " CAROLINA POWER & LIGHT COMPANY -

ROBINSON UNIT 2 STEAM CENERATOR REPLACEMENT STUDY FOR OPERATING LICENSE AMENDMENT PROCEEDING - NRC DOCKET NO. 50-261 OLA - September 1983" were served:this 12th day of October, 1983 by depositing in the United States mail, first class, postage prepaid to the parties on the attached SERVICE LIST.

Jhtl Andrew McD'aniel Attorney for Carolina Power & Light Company October-12, 1983 i

J

-r UNITED STATES OF AMERICA-NUCLEAR REGULATORY COMMISSION BEFORE THE ATOMIC SAFETY AND LICENSING BOARD In the Matter of )

)

CAROLINA POWER S LIGHT COMPANY ) Docket No. 50-261-OLA

)

-(H. B. Robinson Steam Electric )' ASLBP No. 83-484-03LA Plant, Unit 2) )

SERVICE LIST Administrative Judge Morton B. Margulies ~ Atomic Safety and Licensing Board

Chairman, Atomic Safety and Licensing Board Panel U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Washington, D.C. 20555 Administrative Judge-Jerry R. Kline Atomic Safety and Licensing Appeal Atomic Safety and Licensing Board Board Panel U.S. Nuclear Regulatory Commission U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Washington, D.C. 20555 Administrative Judge David L. Hetrick e. A. Matthews Atomic Safety and Licensing Board Hartsville Group Professor of Nuclear Engineering P. O. Box 1089 University of Arizona Hartsville, South Carolina 29550 Tucson, Arizona 85721 Dr. John C. Ruoff Docketing & Service 3ection (3) P. O. Box 96 Office of the Secretary Jenkinsville, South Carolina 29065 U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Myron Karman, Esquire Office of Executive. Legal Director U.S. Nuclear Regulatory Commission Washington, D.C. 20555 2