ML18017B477

Forwards Response to NRC Request for Addl Financial Info Re Decommissioning Projected (5-yr) Operating Costs for FY81-FY85.Info Required as Result of Request for Amends to OLs

ML18017B477
Person / Time
Site:	Harris, Brunswick
Issue date:	10/19/1981
From:	Utley E CAROLINA POWER & LIGHT CO.
To:	Harold Denton Office of Nuclear Reactor Regulation
References
NO-81-1713, NO-8101713, NUDOCS 8110260183
Download: ML18017B477 (41)

Text

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i$ )lQg, Carolina Power 8 Light Company October 19, 1981 File: NG-3514 (B) Serial No.: NO-81-1713 Mr. Harold R. Denton, Director Office of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, D."C. 20555 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NOS. 1 & 2 DOCKET NOS. 50-325 AND 50-324 LICENSE NOS. DPR-71 AND DPR-62 AND SHEARON HARRIS NUCLEAR POWER PLANT, UNIT NOS. 1, 2, 3, AND 4 DOCKET NOS. 50-400, 50-401, 50-402, AND 50-403 ~

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ADDITION OF CO-OWNER TRANSMITTAL OF ADDITIONAL INFORMATION

Dear Mr. Denton:

Carolina Power & Light Company (CP&L) has submitted an appli-cation (Serial No.: NO-81-1413) requesting amendments to the Operating Licenses for the Brunswick Steam Electric Plant, Units Nos. 1 and 2 to add as co-owner of such Units the North Carolina Municipal Power Agency Number 3 (Power Agency). CP&L has also submitted applications requesting amendments to the Construction Perad.ts and the Application for Operating Licenses for the Shearon Harris Nuclear Power Plant (SHNPP), Unit:s Nos. 1, 2, 3, and 4 to add Power Agency as a co-owner of the SHNPP Units.

In recent telephone conversations with NRC's Office of State Programs, CP&L was requested to provide certain financial information regarding decommissioning, projected (five-year) operating costs for Brunswick Plant for 1981 through 1985, and the ability of Power Agency to meet any obligations, it may have with respect to such costs.

A'ttachment I is a description of the cont:ractual arrangements between CP&L and Power Agency and between- Power Agency and the Municipal Participants concerning financial obligations associated with decommissioning.

Attachment II is a CP&L consultant's report which reflects. a decommissioning plan for CP&L's nuclear plants and provides an estimate of its cost.

CP&L has submitted this report to the Federal Energy Regulatory Commission for approval and is awaiting a decision by that Commission.

Attachment III is a description of the agreements between CP&L and Power Agency and between Power Agency and the Municipal Participants concerning financial obligations associated with operation of the Joint

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h Facilities. Attachment IV is an estimate of projected operating costs for the Brunswick Plant for the five-year period 1981-1985. These estimates include 06M (Operating and Maintenance) expenditures, fuel costs, and construction expenditures, all of which are based on today's information.

That is, the actual operating costs during the period may vary significantly

.from the Attachment IV values due to factors such as new regulatory require-ments and the plant's future operating experience which may change present refueling schedules.

Please advise my staff to complete your review.

if you require any additional information Yours very truly, E. E. Utley Executive Vice President Power Supply and Engineering 6 Construction JAM/lr (8824)

Attachments cc: Messrs. D. G. Eisenhut T; A. Xppolito M. L. Karlowicz E. A. Licitra F. J. Miraglia, Jr.

J. Van Vliet

Attachment I Carolina Power & Light Company NRC RE UEST FOR ADDITIONAL FINANCIAL INFORMATION

SUBJECT:

Decommissioning Costs Pursuant to the Project Agreements between CP&L and Power Agency, Power Agency will pay its proportionate share of all costs associated with the cancellation, retirement or decommissioning of the Joint Units. Section 25.3 of the Purchase, Construction and Ownership Agreement (submitted as. Exhibit F to this Application) requires Power Agency to bear its share of the costs of cancellation or decommissioning of any Joint Unit which is cancelled or decommissioned prior to the date of Commercial Operation of such Unit. Section 22.2 of the Operating and Fuel Agreement (submitted as Exhibit E to this Application) requires Power Agency to bear its share of the costs of retirement or decommis-sioning of any Joint Unit which is retired or decommissioned after the date of Commercial Operation of such Unit. These commitments extend for whatever period of time is necessary to complete the cancellation, retirement or decommissioning process so that no further expendituxe of funds is required.

Power Agency will include in its Monthly Project Power Costs to be charged its Participants pursuant to the Initial Project Power Sales Agreements (the form of which has been submitted as Exhibit B.l to this Application) charges sufficient to enable Power Agency to meet its commitment to bear its share of the costs of cancellation, retirement or decommissioning of the Joint Units. Each Participant agrees in the Initial Project Power Sales Agreement to pay its Participant's Shax'e of such Monthly Project Power Costs. Such costs are defined in Section 1(t) of the Initial Project Power Sales Agreement as including all costs incurred by Power Agency resulting from the retirement or decommis-sioning of the Initial Project, and. the providing of reserves for such purposes. The Initial Project Power Sales, Agreement. imposes an unconditional "take or pay" commitment, thereby obligating each Participant to pay its Participant's Share of Monthly Project Power Costs whether or not the Joint Facilities are completed, operable, operating, or retired or decommissioned and notwithstanding the suspension, interruption, interference, reduction or curtailment of the output, of the Joint Facilities, or the power and energy contracted for, in whole or in part, for any reason whatsoever. Power Agency will establish a reserve for such costs in the Decommissioning Fund established pursuant to Sec-tion 5.5 of the Bond Resolution proposed to be adopted by Power Agency's Board of Commissioners (submitted as Exhibit 0 to this Application).

Attachment II Caroiina Power 8 Light Company Determination of Depreciation P.rovisions for Nuclear Production Plant for implementation the First Quarter of 1981 FERC Basis

Osiltts Haskins+Salis One Main Place Dallas, Texas 75250 (214) 748-6601 Telex 732648 Carolina Power 6 Light Company November 15, 1980 P. 0. Box 1551 Raleigh, North Carolina 27602 Attention of Nr. Paul S. Bradshaw Vice President and Controller In accordance with your request, we have completed a study of the capital recovery requirements, on a Federal Energy Regulatory Commission (FERC) basis, for the Company's three nuclear generating units. The study results in recommended depreciation rates for each account and recommended annual depreciation provisions for decommissioning each plant.

Presented herein are the bases for the determination of the depreciation rates, the determination of the estimated cost for accomplishing decommissioning, discussion of methods of capital recovery consistent with the framework of depre-ciation accounting principles and regulatory rules, our recommendation of the capital recovery method to be used for decommissioning, and calculation of the annual decom-missioning depreciation provision for each unit foe the recommended method.

As a result of the Final Order in FERC Docket No. ER76-495, the Company has been authorized by its Federal and state regul'atory bodies to use different depreciation rates for Nuclear Production Plant. The Final Order authorized a depreciation rate of 4.0X based on an average service life of 25 years and zero net salvage. The rates authorized by the state regulatory bodies are based on 25 years and 7.3X nega-tive net salvage.

In adopting a zero net salvage factor, the Final Order in Docket No. ER76-495 states that it was "without prejudice to a redetermination of this item when information becomes

.available." (Order page 5) . This study provides the basis for redetermination of salvage, and recognizes that portion of'the existing book depreciation reserve applicable to net salvage. For Federal regulatory purposes the existing depre-ciation reserve applicable to net salvage is zero, while for state regulatory purposes it is positive. This distinction requires a unique determination for FERC purposes of the depreciation provisions for decommissioning the nuclear units.

The study reported here confirms that the 4.0X depreciation rate is lower than can be justified and determines the annual depreciation provisions required to cover net salvage (decommissioning) . Schedule 1 shows the average service lives, net salvage factors, and previously approved annual depreciation rates for each account in Columns 4, 5 and 6, respectively. Column 7 shows the average service lives that are justifiable.

As a result of our study, we recommend that the Internal Sinking Fund Depreciation method of capital recovery be used for providing for the decommissioning costs of the nuclear units. A summary of the annual and total revenue require-ments, total depreciation expense and ultimate cash expen-diture for decommissioning each unit is shown on Schedule 2.

Because of the negative impact of the book depreciation reserve, total revenue requirements are much less than total depreciation expense, amounting to only $ 0,686,000 annually, 1

as shown on Schedule 2. The annual depreciation provisions, anticipated to commence the first quarter of 1981, for each unit are shown on Schedule 3. The accumulated depreciation provision for decommissioning is zero as of December 31, 1980 as a result of the zero net salvage component in the existing depreciation rates. The depreciation provision we recommend for the first year is $ 10,686,000, as shown on Schedule 3.

A major purpose of the nuclear decommissioning section of this report is to provide a procedure for calculating the required capital recovery amounts. The Company has a policy of periodic review of the adequacy of its depreciation rates used for capital recovery. The reasons for this policy also require its application to the capital recovery for decom-missioning the nuclear units.. The criteria used for this study are outlined on Schedule 4 and illustrate the need to periodically review the bases for capital recovery. The calculations of the actual cash expenditures for decom-missioning, annual and total depreciation provisions, and annual revenue requirements for Robinson No. 2 appear on Schedule 5, for Brunswick No. 2 on Schedule 6, and for Brunswick No. 1 on Schedule 7.

The remainder of this report discusses the bases for the study, how it was accomplished.and our recommendations for present and future actions relative to the depreciation rates and the capital recovery of the decommissioning costs for the nuclear generating units.

PURPOSE OF DEPRECIATION The purpose of depreciation is to provide for the recovery of invested capital and net salvage over the life of the facili-ties constructed with that capital from those customers receiving benefits from the facilities in a pattern that matches the pattern of customer benefit. The Uniform System of Accounts prescribed for electric utilities by the Federal Energy Regulatory Commission (FERC) states that depreciation "as applied to depreciable electric plant, means the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of electric plant in the course of service from causes which are known- to be in current utility is not protected by operation and against which the insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the are, changes in demand and requirements of public authorities.

Service value means the difference between original cost and net salvage value of electric plant."

Depreciation accounting is an allocation process whereby con-sumption of physical assets is recognized in the income statement of a business enterprise. The purpose of depre-ciation expense is to provide full recovery of invested capital adjusted for net salvage to be incurred at the time the facilities are decommissioned, over the expected life of the facilities constructed with that'apital from those customers receiving benefits from the facilities. The study reported here is consistent with this purpose.

The capital recovery requirements for decommissioning dis-cussed in this report cover only the net salvage component of depreciation. The FERC Uniform System of Accounts defines net salvage value as "the salvage value of property retired less the cost of removal. Salvage value means the amount received for the property retired," and "cost of removal means the cost of demolishing, dismantling, tearing down or otherwise removing the, electrical plant, including the cost of transportation and handling incidental thereto." Thus, it is the decommissioning cost that will actually be incurred that is requi,red to be recognized by the Company through capital recovery. For Nuclear Production Plant, cost of removal and decommissioning cost are synonymous terms.

LIFE ANALYSTS The remaining was based on service life of each nuclear generating the term of the operating license granted unit the Nuclear Regulatory Commission. The lives of Robinson 2 byand Brunswick Units 1 and 2 were adjusted downward from those indicated by the license in order to recognize the uncer-tainty as to whether such installations will be permitted to operate for the full term -of their license. The existence of this uncertainty and the need to reflect it in the depre-ciation rates are unquestioned. This rational method of life

adjustment for recognizing the uncertainty surrounding the continued operation of Carolina Power & Light's nuclear units is considered to be the most reasonable procedure for doing so ~

An additional reason for the downward adjustment of the capital recovery period is the fact that totals of the already elapsed operating lives of the three nuclear units and their remaining lives is either equal to or less than the 25 year average service life determined applicable to these units by the FERC in Docket No.

ER76-495, as illustrated by the table below.

Elapsed Remaining Unit Life Period Total Years Years Years Robinson No. 2 16 25 Brunswick No. 1 19 22 Brunswick No. 2 19 24 The approach for recognizing retirement dispersion is through the development of an interim activity factor applicable to each primary account. An analysis of past retirements iden-tifies activity which is not true interim retirements. The analysis results in the determination of the annual depre-ciation rate that would have provided an amount sufficient to cover past interim retirements. The interim activity factors selected for use as a result of an evaluation of the signifi-cance of past retirement experience reflect the fact that some existing plants are mature and some are not, and also the fact that historical experience may or may not be a reasonable indication of what will happen to the new modern generating plants. The analysis included the experience of both steam and nuclear generating units.

CALCULATION OF AVERAGE SERVICE LIFE The average service lives for each account are determined from depreciation rates calculated using the following formula:

ASL 100 Base Rate + Interim Activity Factor Vhere:

PB - BR Base Rate ARL X 100 PB ASL Average Service Life, years PB Depreciable Plant Balance, BR Book Reserve, ARL Average Remaining Life, years The resulting average service lives vary from 20 to 23 years.

t t ESTIMATES OF DECOMMISSIONING COSTS Decommissioning cost estimates were made by Nuclear Energy Services, Inc. (NES), for three different decommissioning processes: immediate removal, entombment with removal after a 30 year delay and entombment with removal after a 100 year delay. Costs were estimated at mid 1979 price levels for each of the three units. For example, the costs from the NES report for engineering and preparation, entombment," sur-veillance (annual), and removal are shown on Line 1, Page 1 of Schedule 5 for Robinson No. 2. Column of the Schedule 1

shows that the preparation process .takes 12 months, the entombment process takes 22 months, and the removal process takes 61 months. The same data for the Brunswick units are shown on Page 1 of Schedules 6 and 7.

DECOMMISSIONING PROCEDURE The NES report estimated costs for three decommissioning pro-cesses. Entombment with removal after a delay of 100 years was not considered by the Company to be a reasonable basis for calculating capital recovery requirements. Company stud-ies indicate that entombed property will not require signi-ficant maintenance for 30 years, thus the 30 year delay option'will allow taking advantage of the "state of the art" developed by other utilities which will have decommissioned units during the 30 year dormancy period. The delay period will result in decreased exposure of personnel to radiation.

It has been determined that the Company will use the 30 year delay process, therefore, this report covers only the entomb-ment process with a 30 year delay in removal.

CAPITAL RECOVERY METHOD Two basic capital recovery methods exist: Internal Sinking Fund Depreciation and Straight-Line Depreciation, both of which meet the required accounting and regulatory framework of depreciation. Two external methods of providing for decommissioning cost exist: Prepaid Invested Fund and Progressively Paid Invested Fund. The total revenue require-ments for the external methods are significantly higher than for the capital recovery methods, therefore, the external methods are not covered by this report.

Of the two basic capital recovery methods available, the Internal Sinking Fund Depreciation approach was selected as providing the most reasonable balance between the interest of investors and customers, especially during periods of high or uncertain inflation. This method has significantly lower annual revenue requirements in the early years than Straight-Line Depreciation. Total revenue requirements are lowest for Straight-Line Depreciation, but because of the high annual revenue requirements in early years this method was not used.

The utility regulatory process allows the sinking fund con-cept of depreciation to be applied with either a depreciated or an undepreciated rate base. The correct terminology for an undepreciated rate base is Sinking Fund and for a depre-ciated rate base is 'ifodified Sinking Fund. Either way, the book reserve is the accumulation of the annual annuity amount collected from customers plus the annual interest on the reserve. If the annual interest is not included in revenue requirements, the accumulated provision is not a deduction for the determination of rate base. If the annual interest is included in revenue requirements, the accumulated provi-sion is a deduction for the determination of rate base.

The discussion in this report relates to Modified Sinking Fund, as the regulatory process most often deals with depre-ciation provisions that affect rate base. However, it should be noted that use of the after-tax rate of return as the sinking fund interest rate makes the revenue requirements for Modified Sinking Fund identical to those for Sinking Fund, with tax normalization.

DECOMMISSIONING STUDY CRITERIA The study criteria are listed on Schedule 4. As discussed above, this report covers only entombment with a 30 year delay in removal. In order to recognize the uncertainty as to whether nuclear units will be permitted to operate for the full term of their license, the remaining lives for depre-ciation rate calculation purposes were adjusted downward ten years from those indicated by the license termination dates.

The license termination dates for the units are as follows:

UNIT OPERATING LICENSE TERMINATION Robinson No. 2 April 13, 2007 Brunswick No. 1 February 7, 2010 Brunswick No. 2 February 6, 2010 In order to be consistent with the basis for the calculation of depreciation rates, the capital recovery period for Robinson No. 2. ends April 13, 1997 and for Brunswick No. 1 and No. 2 February 7 and February 6, 2000, respectively.,

Costs for each component of the decommissioning process at these dates for each unit are shown on Page 1, Line 5 of Schedules 5, 6, and 7.

In order to eliminate revenue requirements beyond the end. of unit life, it was assumed that the accumulated fund would be turned into cash and invested at the end of life. The ear-nings on the investment were assumed to be 1.5 percentage points above the inflation 'rate and not subject to income tax.

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Cost of removal was assumed to be a tax deduction at the time the accumulated fund was turned into cash and invested.

Revenue requirements are calculated assuming tax normalization.

Inflation rates of 9.6% from mid-1979 to mid-1980, 8% from mid-1980 thru 1990 and 6% beyond were used in all calcula-tions.

The capital structure and costs are as shown by Item (9) on Schedule 4. The resulting composite rate of return is 10.18%. The sinking fund interest rate of 7.936% is calcu-lated from this capital structure and the effective tax rate of 49.24%.

The existing amount of book reserve is zero, as the FERC has authorized depreciation rates based on zero net salvage. Use by the Company of the calculated depreciation provisions is anticipated to commence the first quarter of 1981.

CALCULATION OF CAPITAL RECOVERY REQUIREMENT The capital recovery requirement for Robinson No. 2 is calcu-lated on Page 1 of Schedule 5, for Brunswick No. 2 on Page 1, Schedule 6, and for Brunswick No. 1 on Page 1, Schedule 7.

The ultimate cash expenditures for each unit are also calcu-lated on Page 1 for everything but surveillance; and for sur-veillance on Page 2. This discussion will cover only Schedule 5 for Robinson, a's the calculations are identical for Brunswick.

As discussed above, the figures on Page 1, Line 1 and the decommissioning process timing in Column 1 are from the NES report. Actual inflation of 9.6% is used to update the costs to a mid 1980 price level. The future value factor for inflation occurring thru 1990 is calculated on Line 3 and from 1990 to the life termination point on Line 4. The fac-tor for the entire period since mid 1980 is shown on Line.5, Column 4 and is applied to the mid 1980 costs on Line 2 to calculate the costs at the price level anticipated at the life termination point shown in Columns 5 through 8, Line 5.

The ultimate cash expenditures are assumed to be made at the midpoint of each period, therefore, the 12 month preparation process has an expenditure point a half-year beyond life ter-mination, as shown on Line 6, Column 3. The future value factor shown on Line 6, Column 4 is applied to the engi-neering and preparation cost shown on Line 5, Column 5 to determine the ultimate cash expenditure. The ultimate cash expenditures for entombment, surveillance, and removal are calculated in a similar manner in Columns 6, 7, and 8. For surveillance, the figure calculated is the amount that would be expended during the first year of surveillance. This figure is also shown for year one on Page 2 of Schedule 5.

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Page 2 shows the expenditures that would be made in each of the thirty years and the total. The ultimate cash expen-ditures for decommissioning shown on Schedule 2 for each unit are taken from Pages 1 and 2 of Schedules 5, 6, and 7. The calculations for Brunswick Ho. 1 anticipate its decom-missioning process will start one year after that for No. 2.

The fund required at the end of life for Robinson No. 2 is calculated on Lines 14 through 18 on Page 1 of Schedule 5.

As shown in Column 2, the rate of earnings on the investments made at the end of plant life is 7.5%; 1.5% above the infla-tion rate. The present value factors for preparation, entombment and removal are calculated in Column 4, Lines 14, 15, and 1.6, respectively. The present value of the expen-diture for engineering and preparation is calculated on Line 14, Column 5 by applying the factor in Column 4 to the expen-diture shown in Column 5, Line 6. The present value for entombment and removal are calculated in a similar manner.

The fund required at the end of plant life to provide for annual surveillance payments is calculated on Line 17, and amounts to $ 10,384,435. Recognizing earnings at 7.5% from the end of life to the first year of expenditures results in a present value of $ 8,161,927 as shown in Column 7, Line 18.

The total capital recovery amount of $ 112,910,970 appears in Column 9, Line 1.9.

ANNUAL REVENUE REQUIREMENTS The annual revenue requirements for each unit are calculated on Page- 4 of Schedules 5, 6, and 7. The calculations assume the capital recovery we recommend will commence the first quarter of 1981.

The annuity amounts for the units are calculated on Page 3 of Schedules 5, 6, and 7. The capital recovery period is 16.28 years for Robinson No. 2 and 19.10 years for each Brunswick unit. As shown, the required annual annuity amount for Robinson is $ 3,632,263. As the revenue requirements are calculated in thousands, the annuity amount is rounded to

$ 3,632, and appears in Column 6, Page 4 of Schedule 5. The revenue requirements consist of the annuity amount, fund interest and impact of the book reserve and deferred taxes on return and income taxes. The determination of the annuity amounts in Column 6 has already been discussed. The interest in Column 7 is calculated on the reserve at the end of the prior year in Column 4, using a rate of 7.936%. Return in Column 8 is calculated on the reduced outstanding capital in Column 3, using the rate of return of 10.18%. The income taxes calculated in Column 9 recognize that the debt portion of capital is a deduction for tax purposes and the composite tax rate of 49.24%. As is obvious from the calculation, return is generated from reduced outstanding capital; the net of book reserve and the reserve for deferred income taxes.

The annual depreciation provisions for each unit shown on Schedule 3 are the total of Columns 6 and 7 on Page 4 of Schedules 5, 6, and 7.

The discussion in this report relates to Modified Sinking Fund, but the inclusion of the revenue requirements for nuclear decommissioning in a revenue rate case could be on either the basis of Sinking Fund or Modified Sinking Fund.

The subcaptions for the income statement accounts on Page 4 of Schedules 5, 6, and 7 are for Sinking Fund. Under Sinking Fund the only component of revenue requirements is the annuity amount in Column 6. Under Modified Sinking Fund, the revenue requirements are those in Column 5; the total of Columns 6 through 9. Use of the internal after-tax rate of return as- the interest rate makes the revenue requirements identical for, Sinking Fund and .Modified Sinking Fund. The minor differences between Columns 5 and 6 are due to rounding.

Thus, the Company has the option of using either Sinking Fund or Modified Sinking Fund in determining revenue requirements for a revenue rate case. Care should be taken when using Sinking Fund to ensure all parties understand the distinction between Sinking Fund and Modified Sinking Fund.

RESULTS In order to give recognition to the uncertainty surrounding the continued operation of nuclear units in service to political and regulatory constraints, the remaining due service life of each unit was de'creased ten years from that indicated by the termination date of the operating license granted by the Nuclear Regulatory Commission for life calculation pur-poses. The resulting remaining lives were used in the test of the validity of the existing 4 .OX rate and in determining the depreciation provisions for decommissioning.

4 I

The average service life, net salvage factor, and recommended depreciation rate for each account is shown on Schedule 1, Columns 4, 5, and 6, respectively. As discussed above, average service lives were calculated for each account. The calculated lives shown in Column 7 vary from 20 to 23 years, compared to the 25 years approved by the FERC.

The determination of the depreciation provisions for decom-missioning was discussed above.

RECOMMENDATIONS Our recommendations for your future action in regard to book depreciation for the nuclear units are as follows:

1. The annual depreciation rates calculated on Schedule 1, are lower than can be justified, but we recommend they continue to be used for the t'me being.

2. The Internal Sinking Fund Depreciation method of capi-tal recovery should be used for decommissioning.

3. The annual depreciation provisions shown on Schedule 3 are applicable to each unit and should be adopted.

The cri teria shown on Schedule 4 for the determination of decommissioning capital recovery requirements will likely change over time, and actual experience for cer-tain criteria probably will not be identical to that estimated. Therefore, future capital recovery require-ments should be recalculated periodically, using the calculation procedures illustrated on Schedules 5, 6, and 7 Ne appreciate this opportunity to serve Carolina Power &

Light Company, and would be pleased to meet with you to discuss further the matters presented in this report, if you desire.

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CAROLINA POWER 6 LIGlIT COMPANY FERC Basis Summary of Mortality Characteristics and Recommended Depreciation Rates (1) (2) (3) (4) (5) (6) (7)

FERC Approved Rates Docket No. ER76-495 Average Net Average Servi

.ine FERC Service Salvage Life Wo. Zcc L-. Descri tion Life Factor Rate Justifiable Years Years Nuclear Production Plant (a) 1 320 Land and Land Rights (Rights-of-Way) 25 4.000 20 2 321 Structures and Improvements 25 4.000 23 3 322 Reactor Plant Equipment 25 4.000 21 323 Turbogenerator Units 25 4.000 23 5 324 Accessory .Electric Equipment 25 4.000 23 325 Power Plant Equipment

'iscellaneous 25 4.000 21 ote:

(a) The effect of decommissioning cost is treated separately.

Sechedule 2 CAROLlNA PQTiR & LIGHT C(RPAHY PIC Basis Revenue Requirem nts, Depreciation Expense and Ultimate Cash Expenditure - 30 Year Delay (2) (~) (4) (5)

Robinson Brunswick Brunswick Line Particulars No. 2 No. 2 No. 1 Total Revenue Reauirements a-"ter'Decembe 31, 1980 Annual 3,632~000 4,038~000 3,016,000 10,686,000 Total 59~ 137 000 77'39~000 57> 614 F000 193 090 000 Total Depreciation Expense 112,911,000 167,905,000 125,410,000 406,&~ 6,000 Ultimate Cash Expenditu e Engineering & Preparation 13,887,794 16,355,322 15, 695,443 Entombment 28 i 250 t 873 34 s 6 10 s 875 26,810,219 6 Surveillance (30 years) '3,303,418 39,182,505 16,258,474 861 933 096 1 446.921 762 1 128 834.365 Total Expendi,ture 937.375 181 1.537 070 464 1,187.598.501 3,662,044,146

Schedule 3 CAROLS POWER Ec LIGHT COMPANY FWC Basis Depreciation Provisions @or Internal Sinking Fund Method oz Capital Recove y Robinson Brunswick Brunswick No- 2 No. 2 No. 1 206al (000) (000) (000) (000) 1981 3,632 4,038 3,016 10,686 1982 37920 47358 3, 255 11,533 1983 47231 4,704 3,514 3.2,449 1984 4,567 5,078 3,793 13,438 1985 4,930 57481 4,094 14,505 1986 5 7321 5,916 47418 15,655 1987 5,743 67385 4',769 16,897 1988 6,199 6,892 5,148 18,239 1989 6,691 7,439 5,556 3.9,686 1990 7 7 222 8,029 5,997 21,248 1991 7,795 8,666 6;473 22,934 1992 8,414 9,354 6,987 24,755 1993 97081 10,096 7,54K. 26,7KB 1994 9,802 10,898 8,139 28,839 1995 10,580'1,419 11,762 '8,785 31 127 1996 12,696 9,483 33,598 1997 3,364 13,703 10,235 27,302 1998 14,791 U.7047 25,838 1999 15, 965 11, 924 27,809 2000 1,686 1.226 2.890 Total S112 911 S 167. 905 $ 125,410 8606.226

Schedule 4 CAROLZHA POQER & LICaa.'APABLY FERC Basis Criteria for Determination of Decommissioning Revenue Requi ements (1) Removal 30 Years after entombment (2) Capital recovery period 10 years less than the termination date of the operating license (3) Accumulated fund invested at end or life with earnings 1 1/27. ove inflation and not taxed (4) Effect ve tax rate - 49.247.

(5) Cost of removal 's a tax deduction at the time the accumulated fund is invested (6) Deferred taxes includ d in revenue requirements (7) Revenue requirement 'oasis (8) Inflation: 9.67. Pid-1979 - i6d 1980 (Actual experience) 8.0/ Mid-1980 through 1990 6.07, Beyond 1990 (9) Capital structure (3 year average) and cost rates (9-30-80):

Debt 49.867. x 9.14'/ ~ 4.567.

Prefer ed 13.30 x 8.50 ~ 1.13 Equity 36.84 a 11.19 4.49 Composite ~ 100.007. 10.187.

(10) Annuity interest. rate ~ R - TTB 10.18 - (0.4924 x 0.4986 x 9.14) ~ 7.9367.

(11) Timing and magnitude of emenditures zbr decommissioning per MES Report (12) Start'ng date for depreciation provisions for D/C based upon internal siaking und method of capital recovery << January 1, 1981

ChROI.1tlh PNIER 6 I.ICIIT COHPhIIY FE(C Basis Calculation of Ultl9uace Cosl4 Exllcndl cures and Total Capital Recovery for Robinson No. 2 (2) (3) (4) (5) (6) (7) (8) (9)

Engineer lng Period and I.Inc Porc I cul ars Race 2

Years Factor ~vr rlv Entoudlmcnc Bur vel 1 lance ReuVovu 1 Cosc ut HIJ - 1979 3,802,300 7,120,500 97,800/yr, 30,936,500 hccual Inflation - Hld '79 - HIJ '80 9,6 1.0 1.096 4,167,321 7 '040068 107, 189/yr. 33,906,404 Factor - 1980 - 1990 8.0 10 5 2.243621 1990 - hprll 13, 1997 6.0 6.29 1.442693 HIJ-1980 - hprll 13, 1997 16.79 3.236856 13,4890018 25 ~ 260 ~ 644 3466 ~ 955/yr0 109 '50, ll7 l2 Hontl2 I'reparation 6.0 0.5 1.029563 13 9117 794 12 Hunch I'reparation 6.0 1.118375 28 250 073 22 Huncl5 E27to74II7623cnc 6.0 9 34 H>nch I'reparation and Entocabu6ent 6.0 Z.8a] 1.214139 421 ~ 252/yr.

10 12 H4567C12 Props ra I.lon 6.0 ll 34 IIonch Prcparotlon ond Ento276I7u6cnt 6.0 2.83 12 30 Your Belay 6.0 30.00 7.853594 861 933 096 13 61 Honth Rcu2oval 6.0 2.54 Total Present Present Present Present Present Value Value 9 I 9 I V I I'rcpuratl un 7.5 0,5 0.964486 13 39'83 $ 13,394 ~ 583 15 Ew C o666I7666c n C 7.5 1.92 0.870354 24,588,260 24,588,260 16 Rculovul 7.5 35 '7 0.077461 66,766 F 200 66,766,200 Swrv<<l 1 lance Fund ut hugust, 2000 hlulual 17 X 1 Coo t, F622'ld 075 (24 ~ 65 1361) X (42 1 0252) 100 384 0435 18 o.06-o.o75

,7.5 3.33 .785977 80161 '27 8016l0927 19 1120~910 970

Schedule 5 Page 2 of 4 CAROLZHA PGvrZ 6 LjGEV CCW'ANY

~C Basis Annual Surveillance Cost for Robinson No. 2 Annual Surveillance Cost Year Afte Entcnrhnent Year 1 421,252 2 446,527 3 473,319 4 501,718 5 531,821 6 563,730 7 597,554 8 633,407 9 671,4 12 10 711,696 11 7545398 12 799,662 13 847,642 14 898,500 15 952,410 16 J.,009,555 17 1,070,128 18 1, 134,336 19 1,202,396 20 1,274,540 21 1,351,012 22 1,432,073 23 1,517,997 24 1,609,077 25 1,705,622 26 1,807,959 27 1,916,437 28 2,031,423 29 2,153,308 30 2 282 507 Total 33 303 418

Schedule 5 Page 3 of 4 CAROLXIK POD.R & LXGHT COMPANY C Basis Sinking Fund Reauirements fo- Robinson No. 2 Return = 10. 187. A ter tax inte est (R- ~B) = 7.9367.

30-year delay Recovery pe iod January 1, 1981 - April 13, 1997 16.28 yrs.

Cost at the end of plant life $ 112,910,970 16.28 (1. 07936 112,910,970

.07936

.0321692671 112,910,970 3,632,263 Annu ty $ 3.632

8 8 CAIIOLINA POWER (> I.lCIff COIIPAIIY FERC Uouls Cslculotlon of Annual Revenue Requlrc)2)ento for Robinson No. 2 (000's)

(2) (3) (4) (5) (6) (7) (6) (9) (10)

UAI.AIICE SUEEI'CClMtffS 1ttCOtIE STATEttEttT ACCHIIITS COST OF SEIIVICE NON COS OF SFRVICE I I IF I AT I ON UEFERIIED IIFDUCED OUTSTAUIIINO D/C

~88 ~>X aiSS INCONE htt JUS'fttD CII ItIt IIESEIIVE I'.Ifl'OST YEAR TAXES.DR CAPITAL RESERVE IIEVEttUE Altttttl TY ltITEREST ItE'IllIUI TAXF.S IIATIO 1981 $ 1 ~ 788 $ 1,644 (3,632) $ (3 '32) $ 3,632 $ $ $ 39,161 .0927 1982 3,719 3,833 (7 '52) (3,631) 3,632 288 (188) (101) 42,29(i .1786 1983 5,802 5,981 (11,783) (3 '32) 3,632 599 (390) (209) (i5,677 .2580 1984 8,051 8,299 (16,350) (3,63'2) 3,632 935 (609) (326) 49,331 . 3314 1985 10,478 10,802 (21,260) (3,632) 3,632 1,298 (84i5) (453) 53,278 .3994 1986 13,098 13,503 (26,601) (3,632) 3,632 1 ~ 689 (1,100) (589) 57,5(iO .4623 1987 15,926 16,418 (32,344) (3,632) 3,632 2>111 (I ~ 375) (736) 62,143 .5205 1988 18,979 19 ~ 56(i (38,543) (3,633) 3,632 2,567 (1,671) (695) 67,1I4 .5743 1989 22 F 273 22,961 (45,234) (3,632) 3,632 3,059 (1 ~ 992) (I ~ 067) 72,463 .6241 1990 25,829 26,627 (52,456) (3,633) 3,632 3 '90 (2,337) (1,252) 78,282 .6701 1991 29,668 30,583 (60,251) (3,632) 3,632 4, 163 (2,711) (1,452) 82,979 .7261 1992 33,811 34i,854 (68,6G5) (3 '34) 3,632 4,782 (3,113) (1,6G7) 87 ~ 958 1993 38,282 39,464 (77,746) (3 '33) 3,632 5,449 (3,5(ie) (1.900) 93,236 1994 43,109 44,(i 39 (87,5(ie) (3>634) 3,632 6,170 ((i,017) (2,151) 98,830 1995 488,316 49,810 (9'28) (3,633) 3,632 6,948 (4,524i) (2 '23) 104,759 .9367 I 996 53,941 55,606 (109,547) (3,632) 3>632 7,787 (5,071) (2,716) 111,045 .9665 4/13/1997 55,597 57,314 (112 > 911) ~)>le) I 017 2~347 ~)528) ~8) 8) 112,911 1.0000

'IYffbi. 137) IL35,828) 2>I~59> ~59>129 ~Ie~75S)

% f(I a n fe ID I3

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ChROLlkkh POWER 6 LICIIT COHI'hIIY FERC Saslu Calculation of Ikltlmste Cssli Expenditures and Total Capital Recovery for Ikrunsulck Iko. 2 (2) (3) (4) (5) (6) (7) (8) (9)

E>>8lnccrl>>8 Period a>>d I.I>>epartli:>>lars Rate Years Factor ~rr r 11 Entombment Survcl lla>>ce Removal 7 $ $ $ $

1 Cost at HI J - 1979 3,806,000 7,414,600 97,800/yr. 44,243,700 2 hctual I>>flotion - klld '79 - kkld '80 9.6 1.00 1.096 4, 171,376 8,126,402 107, 189/yr. 48,491,095 Factor - 1980 - 1990 8.0 10,50 2.243621 1990 - Feb', 2000 6.0 9.08 1.697373 IIIJ-1980 - Fi.b. 6 ~ 2000 19.58 3 ~ 808262 15 ~ 885 6693 30 ~ 9476468 4083204/yr. 1 84,666, 794 6 12 Huntli Preparation 6.0 0.50 1.029563 16~355 322 7 12 Huntb Prcpuratloii 6.0 8 22 klontli Entoubmcnt 6.0 1.118375 34 610 613 9 34 kkonkli Pi'operation siid Entombment 6.0 10 12 klontb I'reparation 6.0 1 214139 *495,616/yr.

11 34i tDnkki Preparation and Entombment 6.0 12 30 Year I)clay 6.0 7 '35311 1 446 611 161 13 - 60 klo>>tb Rciaoval 6,0 Total Present Present Present Present Present Fu>>J Reiulrcd at Feb. 6 2000 V 1 Value V 1 Value Value 14 Prcliarat koii 7.5 0.5 0.964486 15,774,479 $ 156774,479 15 E>>tombmcnt 7.5 1.92 0.870354i 30,123,713 30,123,713 16 Rcaioval 7.5 35.33 0.077685 1 12 404 ~ 117 12 404 17 itk M Survellls>>cc ~ 1 ~ 1 IU n F>>>>d at J46>>e6 2003 (8 (0 h>>nua1 I3 g

17 075 (24 ~ 651364) (4956616) 12 ~ 217 ~ 610 0.06-0.075 X 1 0 III 18 7.5 3.33 0.785977 9,602,760 9 3 602 760 19 Total ~167 9U5aOG9

Schedule 6 Page 2 of 4 CAROLYN POWER & LiGET COMPANY

.""RC Basis Annual Survei llance Cost for Brunsvick No. 2 Annual Surveillance Cost Year A-ter Entcnnbment 1 495,616 2 525,353 3 556,874 590,287 5 6H~, 704 6 663,246 7 703,041 8 745,223 9 789,937 10 837,333 887,573 940,827 13 997,277

14. 1,057,113 15 1,120,540 16 1,187,773 17 1,259,039 18 1,334,581 19 1,414,656 20 1,499,536 21 1,589,508 22 1,684,878 23 1,785,971 24 1,893,129 2,006,717 2,127,120 27 2,254,747 28 2,390,032 29 2,533,434 30 2 685 440 Total 39.182.505

Schedule 6 Page 3 of 4 CAROLZHA PCNER & LZGET CO~ANY PERC Basis Sinking>>und Require nts zo Brunswick No. 2 Return ~ 10. 187, A"ter taz inta est l,'R - TZB) ~ 7.9367, 30-year delay Recove~ pe iod January 1, 1981 - February 6, 2000 ~ 19.10 yrs.

Cost at the end o" plant lize, $ 167,905,069 1.07936) - 1 167,905,069

.07936

.0240478898 167,905,069 4,037,762 Annuity 8 4,038

CAROL1UA POIIER & LICIIT COIB'AIIY FERC Reels Cele>>latlon of Annual Revenue Bcctutrements for Brans>>ick No. 2 (000'e)

(2) (3) (4) (5) (6) (7) (8) (9) (10)

DAIAIICE SIIEFT ACCOUtlTS 1ttCOHE STATEIIEtlT ACC(l)trfS Ci)ST OF SERVICE IIOtl (X)ST OF SERVICE I IIFI.AT<otl REDUCED n/C Al)JUSTI'.0 EXI EIISE DEFLBBED OUTSTABUltlU 0/C IIICOtlE CllBBEIIT, Rl'.Sl BVI'.

YEhR 'I'AXES-DR CAPITAL llill>IIII> AtlIIUI 'I' I tlTE RL'ST B 8'lllBtl TAXES COS r RATIO RESERVL't>,038) 1981 $ 1,988 $ 2,050 $ (4>038) 4,038 $ $ $ $ 49>ti20 .0817 1982 ti, 134 4,262 (8,396) (ti,037) t>,038 320 (209) (112) 53,373 .1573 1983 6,450 6,650 (13 '00) (4,038) 4,038 666 (434) (232) 57,6ti3 .2273 1984 8,951 9,227 (IB ~ 178) (4,038) 4,038 I >Ot>0 (677) (363) G2,25ti 1985 1986 Ill 650 12,009 (23 '59) (4,039) 4,038 1,4ti3 (939) (503) 67 '35 .3519 14,563 15,012 (29,575) (4,038) 4,038 1,878 (I 223) (655) 72,61t>> .ti073 1987 17 '07 18,253 (35,960) (ti,039) 4>038 2,347

~

(1 ~ 528) (BIB) 78,423 .4585 1988 2 I,100 21,752 (42,852) (4,039) ti,038 2,854 (1,858) (995) St>,697 .5059 1989 24,763 25,528 (50,291) (4,039) ti,038 3,401 (2,214) (I 186) 9l,ti 72 . 5ti98 1990 28,717 29,603 llew ~

(58>320) (4,038) ti,038 3,991 (2 '99) (1,392) 98 '90 .5903 1991 32,98ti 34,002 (66,986) (ti,038) 4,038 ~

ti,628 (3.014) (1,6lti) 10ti,717 .G397 1992 37,590 38,750 (76,3tiO) (4,040) 4,038 5,316 (3,461) (1,853) 111,000 .6877 1993 42,561 43 '75 (86,436) (ti>038) 4 '38 6,058 (3,945) 1994 ti7,927 (2, 113) 117,660 . 73ti6 49,ti07 (97,334) (4,040) 4,038 6,860 (4,ti66) (2 ~ 392) 12ti, 720 .7804 1995 53,719 55,377 (109>096) (4,038) 4,038 7,724 (5,030) (2,69ti) 132,203 .8252 1996 1997 59,970 66,718 61,822 (121,792) (4,0ti0) 4,038 8 '58 (5,637) (3,019) 140 '35 .BG91 68>777 (135,ti95) (4,04>0) 4>038 9,665 (6 ~ 293) (3,370) lti8,54ti .9122 1998 74 F 001 76,285 (150,286) (4 >041) 4,038 10,753 (7,001) (3, 749) 157,ti56 .95t,5 1999 Ol>BG2 Sti ~ 389 (166,251) (4,040) 4,038 927 (7,766) (4, 159) 166,904 .99GI 2/06/2000 82,676 85,229 (167 '05) ~401) 40ti I 210 ~0)6) (437) 167,905 .1000 TfrrhL LL(77~139) ~77 F 126 ~90 779 110)

@~59 Q(31 ~656) w rt)

IU n ID ID I3 Mg I

0 ID Ih

l CAROLIOh POMER 6 1:lC98T CQ'8'hW FERC Basis Calculation of Ultimate Cash Expenditures snd Total Capital Recovery for Drunsulck No. 1 (2) (3) (4) (5) (6) (7) (8) (9)

Kllg l lice Il I g 1

Period I.l lie Particulars Rate 2

Years Factor ~rr slid 11 Entombment 0

Surveillance 8

Rclllova 1 Cost st llld-1979 3,Ii61,,800 5,539,700 39,600/yr. 338GU28800 hctual lnflntlon - Old 79 " tlld '80 9.6 1.00 1.096 3,794,133 G,071,511 43,402/yr. 36,916,3Ii9 Factor - 1980 - 1990 8.0 10.50 2 '43621 1990 - Feb. 7 ~ 2000 6.0 9.08 1.697373 tlld-1980 - Feb. 7, 2000 19.58 3 808262 lIi 4Ii9 053 23 121 905 165 286/yr 140,587,128 6 12 kloiith Delay 6.0 1.886261 15 695 443 7 10 llnnth Preparation 6.0 8 12 llontli Delay 6.0 9 10 tbintli Propsratlon 6.0 1.159516 26 818 219 10 17 tlo>>tli EiitoakIsent 6.0 ll 45 Hoiitli Delay, 1'reparation snd Entombsent 6.0 3.75 1.2IiIi220 205,652/yr.

12 39 llunth Delay, Preparation snd Entombment 6.0 3.25 13 30 Year Delay 6.0 30,00 8.029429 ~1 128~8348365 14 60 llonth Removal 6.0 2 50 Totol Present Present Present Present l'resent Fund Required st Feb. 7 ~ 2000 9 I Value Value Va lue Value 15 Prcparatlon 7.5 1.42 0.902402 14 '638599 8 14,163,599 16 Kn tomb iaen t 7.5 2.54 0.832190 22,311, 196 22,311,196 17 Rcmove 1 7.5 35.75 0.075361 85,070,086 85,070,08G Surveillance Fund at IIovcmbcr 2003 hnnIial Cost Fund 18 X 1.075'(24,651364) (205,652) 5,069,602 0.06-0.075 19 7.5 3 '5 0.762462 3,865,379 3 865,329 20 Total ~125 410~260

% CO Ri 0 (8 ID A

W g 0 ID

F

/

Schedule 7 Page 2 of 4 CAROLiNA PORE & L1GRT CO~ANY FERC Basis Annual Suzveillance Cost for Brunswick No. 1 Annual Su~eillance Cost Year After Entombment Year 1 205,652 2 217,991 3 231,070 244,935 5 259,631 6 275,209 7 291,721 8 309,224 9 3270778 10 ll 12 347,445 368,291 390,389 13 413,812 438,641 464,959 16 492,857 17 522,428 18 553,774 19 587,001 20 622,221 21 659,554 22 699,127 23 741,075 24 785,539 25 832,672 26 882,632 27 935,5 90 28 991,725 29 1,051,229 30 1 114 302 Total 16 258 474

Schedule 7 Page 3 of 4 CAROLTHA H)Vr.R cx LIGET COMPANY

~rC Basis Sinking Fund Requirements for Brunswick No. 1 Return = 10. 18",. After tax interest (R - TZB) = 7.936%

30-yea- delay Recovery pe . od January L, 1981 - February 7, 2000 ~ 19.10 yrs.

Cost at the end of plant Life $ 125,410,260 1.07936) - 1 125,410,260

.07936

. 024 04 78898 1 5,410,260 ~ v 3j015,852 Annuity S 3 016

CAIIOL)tth I'OIIEII 6, I.)CIIT Cnts'AIIT I'ERC Sue la Calcu)ation of An<<uaj Revenue ttequjre<2>cute for Qrunaulck lto. 1 (noo'a)

(2) (3) (4) (5) (6) (7) (8) (9) ()0) i<At.httCE SIIEI T ACCOUtITS ttcottE sTATEIIEIIT hcccotrrs cour of 8 Rv cE ttntl COST Of SEINICR I IIFI.ATIOtt I<EI<IICEII hl<JOSTL'0 III'.fERRED OIITSThttnl tin It/C I tlCOtta c~tattslrc RESERVE Yah-I<R CAP I Thl. RRRRIIIIR ItEVEI<tt8 Rlllllll'IT IIITRIIRRT IIE'lllfol TAXES COST RATIO 1981 $ 1,485 $ 1,531 $ 3,016 $ (3,016) $ 3,016 $ -n- $ 36,9I2 .OBI 7 1982 3,088 3,183 6,271 (3,015) 3,016 239 (156) (84) 39,865 .1573 1983 4,aja 4,967 9,785 (3,016) 3,016 498 (324) (174) 43',054 .2273 1984 6,686 6,892 .13,578 (3,016) 3,016 771 (50G) (271) 46 498 .2920 1985 8,702 8,910 17,672 (3,016) 3,016 1,078 (702) (376) 50,218 .3519 1986 10,877 11,213 22,090 (3,016) 3,016 1,402 (9i3) (489) 541,23G .4073

)987 13,225 13,634 26 '59 (3,017) 3,016 1,753 (1,141) (611) 58,574 .4585 1988 )5,760 16,247 32,007 (3,017) 3,016 21132 (1,388) (14i 3) 63,260 .5060 1989 )8,49G 19,067 37,5G3 (3,016) 3,016 2,540 (1,654) (886) 68,321 .5498 1990 21,449 22,111 43,560 (3,011) 3,016 2,981 (1,941) (1,039) 13,787 .5903 1991 24,636 25,397 50,033 (3,017) 3,016 3,457 (2,251) (1,205) 78,214 .6391 1992 28,077 28,943 57,020 (3,018) 3,016 3,971 (2,585) (1,3tl4) 82,901 .6tl78 l99'l 31,790 32,771 64,561 (3,017) 3,016 4,525 (2,946) (1,518) 87>882 .734i6

)994 35,797 )6,903 72,7on {3>016) 3,016 s,i23 {3,336) (1,187) 93,155 .7804 1995 1996 4U,123 44,793 41, 362 46,175 81,485 90,968 (3,016)

(3,017) 3,0)6 3,0)G 5.769 6,467 (3,157)

(4,21 t)

(2,012)

(2,255) 98,744i

)04,669

.>2 1997 49,832 5 I, 311 101,203 (3,016) 3,016 7,219 (4,701) (z,sls) 110 949 .9122 1998 55,272 s6,'978 112,250 (3,016) 3,016 8,03) (S,Z)o) (2,801) II7,606 .9545 1999 61,143 63,031 124,174 (3,018) 3,016 8,908 (s,ano) (3,106) 124,662 .99G1 2/nz/zono 61,152 63,658 125,410 302 934 ~32 J6 125,410 1.0000 rOTAI. ~57~614} ~57~606 +44~)SI

~67,8OC $ ~23 645}

<2 M It< 0 Is rs I3

>CR g 0 IB

Attachment III Carolina Power & Light Company NRC RE UEST FOR ADDITIONAL FINANCIAL INFORMATION

SUBJECT:

Five-Year Operating Costs Pursuant to the Project Agreements between CP&L and Power Agency, Power Agency will pay its proportionate share of all costs associated with the operation, maintenance and fueling of the Joint Units. Section 9.1 of the Operating and Fuel Agreement (submitted as Exhibit E,to this Application) requires Power Agency to advance to CP&L by the first business day of each month Power Agency's share of the costs expected to be incurred by CP&L in that month for operation and maintenance of the Joint Facilities. Similarly, Section 9.2 of the Operating and Fuel Agreement requires Power Agency to advance to CP&L by the first business day of each month Power Agency's share of the costs expected to be incurred in that month for Nuclear and Fossil Fuel Material and Nuclear and Fossil Fuel Services for the Joint Facilities.

Power Agency will include in its Monthly Project Power Costs to be charged its Participants pursuant to the Initial Project Power Sales Agreements (the form of which has been submitted as Exhibit B.l to this Application) charges sufficient to enable Power Agency to meet its commitment to bear its share of the costs of operation, maintenance and fueling of the Joint Units. Each Participant agrees in the Initial Project Power Sales Agreement to pay its Participant's share of such Monthly Project Power Costs. Such costs are defined in Section 1(t) of the Initial Project Power Sales Agreement as including all costs to Power Agency under the Operating and Fuel Agreement resulting from the operation, maintenance and 'fueling of the Joint Facilities. The Initial Project Power Sales Agreement imposes an unconditional "take or pay" commitment, thereby obligating each Participant to pay its Participant'.s Share of Monthly Project Power Costs whether or not the Joint Facilities are completed, operable, operating, or retired or decommissioned and notwithstanding the suspension, interruption, interference, reduction or curtailment of the output of the Joint Facilities, or the power and energy contracted for, in whole or in part, for any reason whatsoever.

Attachment IV Carolina Power & Light Company NRC RE VEST FOR ADDITIONAL FINANCIAL INFORMATION Brunswick Steam Electric Plant Estimated Operating Costs 1981-1985 Estimated Annual Operating Cost Year $ (000) 1981 145,893 1982 217,259 1983 179,648 1984 1505207 1985 155,371