Exhibit__(JDS-12) Page 1 of 90

THE ECONOMIC AND FINANCIAT IMPLICATIONS OF NINE MIIE POINT NUCTEAR STATION TWO AND ITS ALTERNATTVES

Authored by

Thomas G. Dvorsky, P.E. Nine Mile Point fI Project Coordiirator Power Division

Kevin M. Bronner hincipal Utility Financial Analyst Office of Accounting and Finance

Princip al Investi gat ors

Ronald Calkins - Accounting William Kasper - Fossil Fuel Richard Kenney - hogrammer Frederick Haag - System Planning Andrew Harvey - Nuclear Fuel James Lahtinen - Forecasting Patrick Piscitelli - Finance John Stewart - Finance Salvatore Tilaro - System Planning

; Exhibit__(JDS-12) Page 2 of 90

TABLE OF CONTENTS

CHAPTER PAGE

I Introduction

A. Background I-I B. Objectives and ScoPe I-t C. Approach I-r

tr Executive Summary

A. Overall Conclusions II-1 B. Recommendations II-5

trI Options

A. Plan A m-1 B. Plan B m-t C. Plan C Itr.1 D. Plan D u-1 E. Plan E and Plan F trI-2

w Capital Costs

A. Total Costs of Generating Units w-1 B. Direct Cost of Nine Mile Point tr IV.2 C. Direct Cost of Coal Units rv-3 D. Escalation M E. Allowance for Funds Used During Construction (AFDC) IV-7 F. Decommissioning IV.8 G. Accounting rv-9

v Sunk Costs

A. Expenditures to Date and Penalty Charges v"1 B. Ratemaking Impacts v-I C. Financial Impacts Y-l

VI hoduction Simulation

A. General Inputs vI-l B. Fuel Costs VI.1 C. Lo¿d Forecaot vI-3 D. Capacity Factors YI.4 E. Statewide Coal Conversion vI-5 Exhibit__(JDS-12) Page 3 of 90

CHAPTER PAGE

Vtr Economic Analysis

A. EconomicComparisons vII-1 B. The Economic lrnpact of Nine Mile Point II Sunk Costs VII-8 C. Break-Even Analyses VII.9

VIII Financial Implications

A. GeneralConsiderations vltr-r B. Finaneial Impacts and Ratemaking Effeets of Plans A & B VItr.2 C. Financial Implications - Plans A through F vltr-r8 D. Investment Standing of New York's Utilities VIII.19

IX Assessment and Recommendations IX"1

Appendix: A Capital Costs B Fuel Cost Forecast Staff's Table B-1 ICFÆ'{YPP's Table B-2 Exhibit__(JDS-12) Page 4 of 90

CHAPTER I

INTRODUCTION

A. Background The 1085 MW Nine Mile Point II Nuclear Plant under construction near Oswego, New York, started in 197I with an estimated direct eost of $357 million and commercial operation date of December, L977. There have been several revised estimates and commercial in'service dates- the latest being September, 1980, indicating a direct cost of $2.4 billion, $I.3 AFDC and a commercial in-service date of November, 1986. Niagara Mohawk Power Corporation is responsible for building the plant and owns 4l percent. The remaining 59 percent is shared by four other New York State electric utilities, Long Island Lighting Company, Inc. (18 percent), New York State Elecbic and Gas Corporation (18 percent), Rochester Gas and Electric Corporation (14 percent) and Central Hudson Gas and Electric Corporation (9 pereent). In December, 1979, Niagara Mohawk and its Co-Tenants initiated a conshuction slowdown to evaluate the project. The New York State Public Service Commission awarded Theodore Barry & Associates (TB&A) and its subcontractor, Canatom, Inc., a conhaet to assess the feasibility and cost of further construction on the Nine Mile Point II plant. This audit began in August, 1980 and its findings were issued in July, 1981. To complement TBA/Canatom's audit, the Staff of the Department of Public Service under- took the responsibility of assessing the economic and financial implications of Nine Mile Point tr and its alternatives. This task began in December 1980 and is the subject of this report.

B. Objectives and Scope The objectives of this study are the following: o Provide the economics of particular expansion plans under various conditions; r Assess and determine the economic choice of the studied plans; c Examine the financial impact of particular expansion plans on the individual utilities; and o Identify the potential rate increases associated Ìr'ith particular expursion plans. The Department of Public Service staff (Staff) developed, reviewed and analyzed New York State production simulations, capital costs of future plant additions, economie analyses, utility financial models and various related documents. This study presents the results of Staff's aialyses and evaluations.

C. Approach The study evolved from the verification process of the Januar)¡, t98I Niagara Mohawk and its Co-Tenants' economic and financial study. In Staff's opinion this study did not present a complete and meaningful eva-luation, since various alternative options and assumptions which needetl to be evaluated were not considered. Staff, tJrerefore, incorporated these options and assumptions into various computer programs to assess their economic and financial implications.

I-1 Exhibit__(JDS-12) Page 5 of 90

Niagara Mohawk and the Co-Tenants were cooperative in assisting with computer support. This enabled the Staff's and the Niagara Mohawk and its Co-Tenants'studies to be put on a comparable basis. The study was performed by a multidisciplinary staff within the Department of Public Service and is solely the result of the work of those individuals.

I-2 Exhibit__(JDS-12) Page 6 of 90

CHAPTER II

EXECUTWE SUMMARY

This study examines the economic and financial feasibility of Nine Mile Point II and its alter' natives. Studies were made comparing the economic consequences of generation expansion plans which include Nine Mile point II (Plans A, C and E) and three alternate generation expansion plans (8, D and F). The generation unit additions of the plans under study are explained in Chapter III and illusbated in Table tr-l. Two separate economic scenarios were made; first, Plans A through D and second, plans E and F. The basic difference between the two sets of scenarios is the total amount of required future caPacitY. Nine Mile point tr is a major undertaking for each of the five Co-Tenants. This study provides an analysis demonstrating the major financial effects that may occur if the project is completed. This examination used eãch Co-Tenants' long-term financial forecasting model to project items such as increases in electric revenues, cents per kilowatt-hour (c/Kwh), capitalization, and projected securities iszues. Financial models were performed for Plans A and B. In addition to the detailed financial forecast for these plans, all options were compared by a cash flow analysis to determine if any significant benefits can be derived from changing options.

A. Overall Conclusions

I. Economic Implications The economic implications of Plans A through F were assessed by discounting the lifetime revenue requirements ù9Sl dollars) relating to the capital, production, and sunk costs. The base case assumpti"* for the economic study are a $4.9 billion Nine Mile Point II capital cost with a l9B? commercial in-service date, Staff's estimate of fuel costs, Ilz percent statewide annual load and 3665 megawatts of coal conversions. For the plans without Nine Mile Point II, a 'lSgrowth, y"", amortization fãr sunk costs is assumed. Many comparisons were made to show the effects of varying key assumptions, including fuel costs, Ioad forecasts, nuclear capacity factors, the number of units to undergo coal conversion, future generation unit size, the level and amortization of sunk costs, and Nine Mile Point II in-service dates.* The major results of the economic comparisons are: .Aú phns which include Nine Mile Point II (4, C & E) showed an economic advantage as compared to their respective alternative plans (8, D & F): Plan A over Plan B by $1251 million; Plan C over Plan D by $1303 million; and Plan E over Plan F bY $20?2 million;

oThe amortization of sunk costs due to abandonment of Nine Mile Point II was a major factor in the economics. The 19Bl present value of the revenue requirement for the sunk costs was approximately $1,900 million; and

"See Chapter VII for details. tr-t Exhibit__(JDS-12) Page 7 of 90

TABTE II-T

PSC STAFF OPTIONS (Unit Size-MW)

Year A B C D E F 1987 r0s5 (NMFrr) r0B5 (NMPtr) r0B5 (NMPrr) r988

625 (Jamesport)

ffi; 625 (LEGST) lTqqo 800 (Jamesport) ó25 (Jamesport) 625_(LEGSIX) I t t.l 8990 850 (LEGST) 625 (LEGSI)

800 (Jamesport) fïoor Lr' 850 (LEGSI)

1,992 850 (IEGSII) 400 (LEcsrI),Êl+ 625 (COAI I)

r993 235 (Coal tr)" 235 (Coal tr)** 625 (Jarnesport) 1994 460 (LEGSI)'ç" 1'otal (MW) 2735 2735 2735 2735 --Tr0B5 r0B5

*Characteristics of an 850 MW unit *#Clraracteristics of. a625 MW unit Exhibit__(JDS-12) Page 8 of 90

oA-ll sensitivity runs produced small variations in the economics but none were large enough to swing the economic choice from one plan to another. The results of the sensitivity runs are quantified in Chapter YII. An important assumption of tJre economic analyses is the total capital cost of Nine Mile Point II. Since this project has experienced extensive cost increases and the cost of the facility can change the overall cost advantage of the project, Staff felt it necessary to determine how high the cost of Nine Mile Point fI could increase to make the economics of the comparative plans equal. This would provide boundaries to the economic comparisons in terms of Nine rVlile Point tr capital costs. The break-even analyses Ì,v'ere performed on the base case assumptions and varying Nine Nlile Point II in-service dates and fuel costs. For the base case assumptions, Plans A, C & E would require lesg revenue than their respeetive alternatives (8, D & F) until the capital costs of Nine Mile Point II exceed the levels shown in Table tr-2. The cost of Nine Mile Point II would have to reach these levels largely due to project scoPe changes. Variations of escalation or AFDC rates from those assumed in the study would, naturally, affect the overall economic comparisons and the break-even points.

TABLE II.2

Break-Even Analysis

Nine Mile Point tr Capital Costs Economic Comparison $ (Millions)

Plan A equals Plan B $6,800 Plan C equals PIan D 6,975 Plan E equals Plan F 8,075

2. Financial Implications Since Nine Mile Point II is only a portion of each Co-Tenants' construction program, the ability to finance the project varies with each company. The financial studies for Plan A indicated that some Co-Tenants will face heavy amounts of new financings throughout the Nine Mile Point tr construction period (f 98f-f987).* Some Co-Tenants require special forms of rate relief such as inclusion of construction-work-in-progress (CWIP) in rate base to successfuly finance their con- struction programs. The findings for the specific companies are: o Niagara Mohawk must issue large amounts of new securities to finance Nine Mile Point II and the rest of the company's constuction program. No CWIP, however is required in rate base in order to achieve proper financial ratios. Through Lg}Z, Niagara Mohawk's electricity prices are projected to increase at an average amount oI Z.Lpercent yearly while capitalization must grow at an average rate of l0.l percent;

o Central Hudson plans to construct the Danskammer coal conversions and Nine Mile Point II at the same time. As a result of this large construction program, the company is projected to require CWIP in rate base during the mid-1980's. Central Hudson's electricity prices are projected to increase an

"This analysis assumes a $4.9 billion cost for Nine Mile point tr.

II.3 Exhibit__(JDS-12) Page 9 of 90

average of 6.9 percent yearly by L987. Capitalization is projected to grow at 8.5 percent yearly through the same time period. Central Hudson's electricity price increases appear low since they reflect fuel savings from the Danskammer coal converions. If these conversions are not factored into the analysis, electricity prices would be substantially higher;

oRochester Gas and Electric Corporation has no other major generating unit con- struction projects other than Nine Mile Point II. No CWIP should be required in rate base during the period. The cost of electricity is projected to increase by 8.8 percent yearly through L987. Capitalization should grow by an average of 6.2 percent yearly through the same time period;

olong Island Lighting Company has other major projects (Shoreham nuclear unit and various coal conversion projects) to be completed during the l980's. LILCO's construction requirements will continue to place financial stress on the company until the Shoreham nuclear unit is eompleted in 1983. No CWIP should be required in rate base after 1983. The analysis indicates that electricity costs and capitalization will increase by average amounts of 8.5 percent and 3.7 percent through 1987, respectively; and

oNew York State Electric & Gas must construct the Somerset generating unit before Nine Mile Point II is operational" The financial studies show that CWIP is required in rate base until Somercet is eompleted (f984). After that date, however, none is required. NYSE&G's c per Kwh cost is projected to increase at an average rate of 10.5 percent yearly throughout the Nine Mile Point II con- sbuction period. Capitalization is projected to grow at an average of 10.5 per- cent yearly.

Each of the financial projections assume a reduction in current high money costs and that each company earns its fair rate of return. Should neither of these assumptions materialize, the growth rates in electricity costs and capital expansion could increase. As stated earlier, individual financial projections were made for each Co-Tenant assuming con- stuuction of the assets associated with Plan B. Although Plan B relieves the immediate financiai pressures associated with financing Nine Mile Point II, over the long-term, no significant frnancial differences occur between Plans A and B. This happens since Plan B requires heavy amounts of frnancing after 1987. This report also analyzed the cash requirements {or Plans A through F. These are outlined in Table II-3.

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TABTE tr.3

Incremental Construction Requirements Plans A through F $ (Milions)

A B C D E F

1981 $ 372 $4 $ ¡zr $6 $ 369 $z 1982 489 4 490 L4 486 2 r9B3 54L 18 551 31 536 ç, L9M 6L6 40 630 169 596 6 1985 677 30r 82r 400 63s 6 r986 997 499 I,105 '/o5 668 20 r987 L,L57 880 1,310 r,22r 6rr 45 19BB 879 L,482 1,151 1,620 244 1889 1,412 1,665 1,220 1,572 365 r990 l,3Bl 1,815 l,0gl 1,157 6s6 r99r L,027 970 343 945 901 r992 730 L96 623 1,226 r993 181 r25 1,089 L994 347 Total $9,98 $B,5Bg $9,281 $8,649 $3,901 $4,911

Table II-3 shows that Plan A requires the largest amount of new capital. It should be noted, however, that if Nine Mile Point II were cancelled, Plans B, D, and F would have an additional financing charge associated with cancellation costs. It is estimated that the additional financing charges for cancellation costs would be about $373 million. AIso, AFDC would have to be accrued on the existing Nine Mile Point II balance until some method to treat the sunk costs is developed. Therefore, the incremental construction requirements differences among the plans would be greatly reduced. Table tr-3 also shows that if the plans without Nine Mile Point II (8, D, F) are constructed, heavy capital expenditures would occur during the mid to late 1980's and early I990's. Therefore, deferral scenarios, such as Plans B, D, & F, may not be desirable.

B. Recommendations Based on the economic and financial evaluations contained in this report Staff recommends the following:

oCompletion of Nine Mile Point II is warranted; and

o The Co-Tenants' senior management must emphasize its attention on project cost control and meeting the schedule for 1986 Nine Mile Point II commercial j operation date to minimize the project's impact on its ratepayers.

il-5 Exhibit__(JDS-12) Page 11 of 90

CI]APTER Itr

OPTIONS

Staff selected and developed several generation expansion plans. This study encompasses two separate economic scenarios; first, Plans A through D and second, Plans E and F. The plans are illustrated in Table ltr-1. The approach taken was to utilize first the generation plant sites which have undergone state certification (Article Vm). Certain expansion plans require additional capacity beyond the certified sites so that a direct economic comparison could be made. Site locations of these generation plants $'ere assumed to be upstate New York.

A. Plan A This plan assumes commercial operation of Nine Mile Point II in 1987, an 800 MW coal unit at Jamesport in 199I, and an 850 MW unit at Lake Erie in 1991; total new capacity of 2735 MW. The only difference between Plan A and the plan proposed in the New York Power Pool's (NYPP) 1981 5-lf 2 report [Long Range Plans] is that Nine Mile PointII is scheduled for 1987in Plan A as compared to 1986 in the 1-LLZ report. The l9B7 date accordingto the TBA/Canatom Nine Mile Point II audit is the likely completion date. However, due to the controversy of the in-service date, this study presents the effects of a 1986, l9B7 and l9BB Nine Mile Point II commercial operation dates.

B. Plan B Plan B represents a coal alternative to Nine Mile Point tr. The Nine ùlile Point II project is assumed to be abandoned and 2735 MW of new coal capacity is scheduled. The timing of the coal additions is based on the status of the licenses for Jamesport and Lake Erie and the need for an additional license for the Coal I unit. For study purposes, it was assumed that the Coal I unit would be an 850 MW unit at a central New York site, but that only 235 MW would be allocatecl to the Nine NIile Point II participants. This results in the same total capacity as was installed in Plan A. Staff understands that the Co-Tenants, especially Long Island Lighting Company, feel in the event of abandonment of Nine Mile Point II, l99l would be the earliest a Jamesport unit would be in-service.

C. Plan C This is a variation of Plan A in that the size of all the coal units is assumed to be 625 NIW and the design to be a duplicate of the Somerset unit.

D. Plan D This is a variation of Plan B-the "all" coal plan-but ¿rssumes the units are sized at 625 NIW and duplicates of the Somerset unit. For that reason, it has been assumed that there will be a reduction in engineering design time that will permit installation at an earlier date. Thus, the first units in Plan D are installed in 1989. Ag"itt, if Nine Nlile Point tr is abandoned, Staff understands that Long Island Lighting Company feels l99l would be the earliest a Jamesport unit would be in-service.

m-1 Exhibit__(JDS-12) Page 12 of 90

E. Plan E and Plan F Plan E assumes the installation of Nine Mile Point II in 1987 with no further generation installed, and Plan F assumes that installation of 1085 MW of coal capacity in the early 1990's with further capacity modifications. The dates selected for the coal units in Plan F correspond to the latest date required to meet the composite NYPP reliability requirements of the five Nine Nlile Point II participants. A direct economic comparison between these two plans and the first four plans cannot be made since differing amounts of new capacity are installed.

Itr.2 Exhibit__(JDS-12) Page 13 of 90

TABTE III-T

PSC STAFF OPTIONS (Unit Size-MW's)

E F Year A B C Ð

r9B7 r0B5 (NMPII) r0B5 (NMPIT) rOBs (NMPn)

1 I9BB

625 (Jamesport)

Imo 625 (LEGSI) [_t989

l-lqqo 800 (Jamesport) ó25 (Jamesport) 625 (LEGSII) I I I ¿r []sqo ssO (LEGSI) 625 (LEGSI)

l-rqqr 800 (Jamesport)

L'n' 850 (LEGSI)

r992 850 (LBGSII) 400 (LEGSII)"¿' 625 (Coal I)

625 (Jamesport) r993 235 (Coal I)" 235 (Coal II)**

(LEGS I)åÉ" r994 460

Total (l\{W> 2735 2735 2735 273s r0B5 1085

"Characteristics of an 850 MW unit **Characteristics of a625 MW unit Exhibit__(JDS-12) Page 14 of 90

CHAPTER IV

CAPITAL COSTSfÉ

A. Total Costs of Generating Units The capital costs of Nine Nlile Point II and the other generating units used for this study are shown in Table IY.1. The remainder of this chapter discusses Staff's major assumptions and methods for determining these costs.

Tahle IV-l Capital Costs - Various Generating Units Capital Costs** In-Service $(Nlillions) Generation Unit Date

Nine Mile Point II f 0B5 MW r986 $2,660 $1,618 #4,278 1987 .2,889 2,005 4,894 1988 3,148 2,436 5,584

496 L,937 Jamesport 625 MW r9B9 L,44L r990 1,577 541 2,118 1993 2,064 699 2,763

639 2,496 Jamesport 800 MW r990 1,857 l99r 2,032 694 2,726

LEGSI625 MW 1989 L,487 411 1,898 r990 L,625 452 2,077

2,168 LEGSI 460 luwrçr*1È 1994 r,687 48r 2,693 LEGSI SSO lWW r990 2,1L4 579 r99r 2,3L2 63r 2,,943

LEGSII625 NIW r990 l,2A 328 1,582 LEGSII400 NlU,/rð** L992 9s9 246 1,205

LEGSTI 850 MW t992 L,949 s03 2,452

968 Coal I 235 IVIWTFTÊ'&,i 1993 77r L97

Coal I625 NIW L992 1,971 507 2,478 Fr4a tt¿ Coal II 235 IVIWtÈte r993 615 I58

and AFDC. "Capital costs as defined. in this report includes direct construction costs "*Nominal dollars: (Ùlixed, current or as'spent) dollars. ***Characteristics of a 625 NIW unit. *'{ç*rÊCharacteristics of an 850 ilIW unit.

IV-1 Exhibit__(JDS-12) Page 15 of 90

B. Direct Cost of Nine Mile Point II Staff's estimated direct costs (excluding AFDC) are found in Table IV-2.

Table IV-2

Nine Mile Point II Direct Costs $ (Miüions)

In-Service Date: f 986 1987 1988

Amount: $2,660 $2,889 $g,l48

These costs were developed using the same basic construction patterns employed by Niagara Nlohawk and the results of the Theodore Barry & Associates/Canatom, Inc., Nine Mile Point II Audit.* Staff developed iæ own escalation rates. Table IV-3 compares the escalation rates used by Niagara Mohawk and Staff."s

Table IV-B

Nine Mile Foint II Annual Direct Cost Escalation Rates

r9B0"r9B8

NMPC Staff Year Rate Rate

r980 r0.2% t0.s% r98r 8.8 10.5 L982 7.9 10"5 1983 t"Ð r0.5 r984 ?"8 10"5 l9B5 8.0 10.5 r986 ö.u 9"c t987 8.0 9"5 1988 8.0 9.5

*See Appendix A. **See Chapter IV-D for details.

IV-2 Exhibit__(JDS-12) Page 16 of 90

C. Direct Cost of Coal Unitss l. Jamesport The clirect costs for Jamesport were based on the 1981 5'112 report submitted by the New york power Pool (NYPP) io the New York State Energy Office on April l, 1981. Since ,,Jamesport several different options" are included in Plans A-F, it ìMas necessary to develop sepa' rate costs for each plan. Direct costs for each Jamesport unit are found in Table IV'4.

Table IV4

Direct Costs - Jamesport Units*å $ (Millions)

In-Service Plan Rating Date Cost

A BOO MW 1991 $2,032

B 800 1990 1,857

C 62s r990 1,577

D 625 r9B9 L,44L

F 625 r993 2,064

The costs developed for Jamesport assumed the same basic construction patterns used by the NYPP. The only major change concerns escalation. Staff used escalation rates of 10.5 percent (1980- lgBS), 9.5 percent (f986-1990), and 9.0 percent (1991-2000) throughout the study period. The costs of a 625 MW unit located at the Jamesport site on Long Island were keyed to the costs of the 800 r\IW unit, scaled down as described in Appendix A.

2. Lake Erie Generating Station (LEGS I and II) The costs the LEGS I and II units were developed by using the construction pattern of NySE&G's Somerset unit. This approach was used because Somerset's pollution control equipment requirements are approximately equivalent to the expected requirements at the LEGS site. Also, the Somerset plant presents the most recent data available. The same escalation rates used for the and tr' Jamesport units were used for LEGS I and II. Table IV-S summarizes the cost of LEGS I

*See Appendix A. All coal units assume scrubbers are required' Ë*Mixed dollars

IV-3 Exhibit__(JDS-12) Page 17 of 90

Table IV-5

Direct Costs - IEGS I and IIå $ (Mitlions)

LEGS In-Service Plan Unit Rating Date Cost

A I B5O MW 199r $2,312

B I 850 1990 2,rLA

B , 850 L992 r,949

C I 625 1990 1,625

C , 400 1992 959

D I 625 r989 1,497

D 2 625 r990 1,254

F I 460 r994 r,697

The above table shows various ùIW ratinp for LEGS I and II. The 400 NIW and 460 NIW units were assumed to have capital cost characteristics identical to the 625 lllW units.

3. Generic Coal Units The generating plans studied included a number of generic units (CoaI-I and Coal-tr). These units were assumed to have the same capital cost characteristics as LEGS I and II.

D. Escalation ¡\. C+-ß! l^--^l^-^l ¡ | ñl ä5 sLaLsr¡-+^+^J earlicrr^--l:^- Júari (levelopeû consEucüorr^--^-L---i: cost escalauon raies.'ihese costs are Summa- rized in Table IV-ó"

Table IV-6

Staff's Estimate of Constuction Escalation

r9B0-r985 rc.s%

1986.1990 9.5%

r991-2000 9.0%

*\lixed dollars IV-4 Exhibit__(JDS-12) Page 18 of 90

These estimates reflect Staff's estimates that a real price increase of 2 percent above the GNP Implicit price Deflator is appropriate. These escalation rates were used for the nuclear and coal fired plants. In support of this finding, Staff examined the historical behavior of the GNP Implicit price Deflators (GNP deflator) and the Handy Whitman Index of Nuclear Production Plant and Total Steam production Plant for the North Atlantic Region. We examined the relationship between changes in the general level of prices and changes in nuclear construction and equipment costs, *àl as escalation forecasts developed by TB&A and Canatom, Inc., and escalation forecasts developed", by stone & weber and Niagara Mohawk Power corporation. A comparison of the annual compound growth rates for the 19?0-1980 historical period shows that the Hanay Whitman Index increased about 1.5 percent per year faster than'the GNP deflator. The comparison of these indices is shown below in Table IV-?.

Table IV-?

Comparison GNP Implicit hice Deflator and Handy'lVhitman Indices for Nuclear Production Plant l9?2 = I00

Nuclear Production Plant GNP Structures & Reactor Plant Year Deflator Improvements Equip.

r970 9r.36 85.4 86.4 T97L 96.02 94.3 93.3 L972 100.00 r00.0 100.0 t973 105.92 108.2 L04.7 L974 r16"02 L22.8 1r9.5 L975 L27"L5 L34.2 t34.2 L976 L33.76 139.9 L45.6 t977 14r.70 r47"5 L54.4 1978 rs2.05 157.6 163.8 1979 r65"50 L74.7 r78.5 1980 r77.40 r88.6 r95.3

As can be calculated from the above table, the GNP deflator increased at a compound annual rate of 6.9 percent while the Handy Whitman Indices increased at compound rates of 8.2 percent and 8.5 percent, respectively. The Handy Whitman Index for Tota-l Steam Production Plant in- creased annually by approximtely 9 percent over the 1970-f980 peúod.

*The use of the GNP Implicit Price De{lator is consistent \^rith the Commission's proposed policy statement endorsing generally the use of the GNP deflator as an inflation index in rate cases. C. 27758, Notice Requesting Comments on a Proposed Statement of Policy in Regard to Escalation Rates in Rate Cases.

IV-5 Exhibit__(JDS-12) Page 19 of 90

In developing an escalation rate for the direct costs used in this study, an estimate of the percentage increase in the GNP deflator is necessary. Staff believes that the GNP Implicit Price Deflator will increase by the following compound growth rates during the 1981-2000 period, as shown in Table IV-8.

Table IV.8

GNP Implicit hice Deflator Forecast

Period Compound Growth Rate

r981.1985 B"s% r986-1990 7.5% 199r-2000 7"0%

Staff developed these projections by examining future projections of the Implicit Price Deflator developed by the Blue Chip Consensus Forecast for t98l and 1982, the 1980-1990 fore- cast made by Wharton Econometric Forecasting Associates, fnc., and the f 979-gf forecast made by Chase Econometrics" The Blue Chip Consenzus and I[harton forecasts both expect prices to rise between 9 and l0 percent per year during 1981 and f982. Wharton and Chase Econometrics are both forecasting that the GNP Implicit Price Delator will increase at a compound annual rate of about 8.5 percent during the next ten years (1980-f 990). These projections suggest that the GNP deflator will grow relatively more slowly over the 1986-1990 time period than during the 1980-f9BS time period. These forecasts are generally consistent with an acceleration in the GNP deflator over the l9?0- l9B0 historical period and the fact that the underlying rate of inflation has accelerated throughout the 1970's. In view of these factors, Staff believes that the GNP Implicit Price Deflator will increase 8.5 percent annually during 1980-1985, 7.5 percent during 1986-f990 and then settle down to a 7.0 percent per annum growth rate after 1990." In developing our escalation estimates, we have also considered data presented by Theodore Barry and Associates (TB&A) in conjunction with Canatom. They developed a range of escalation rates between l0 and 12.5 percent per year for the Nine Mile Pointtr project" These projections translate into an increase per year between 1.5 percent and 4.0 percent faster than the GNP deflator for the 1980-1985 period and between 2"5 percent and 5.0 percent faster than the GNP deflator for the years 1986 and 1987. The company used the following escalation rates for the Nine Mile Point II hoject as shown below in Table IV-9.

*It should be noted that 7.0 percent reflects the approximate historical growth in the GNP de- flator oyer the 1970-80 period.

IV.ó Exhibit__(JDS-12) Page 20 of 90

Table IV-9

Company Derived Nine Mile Point II Escalation Rates

Stone & Webster Niagara Mohawk Escalation Rates Estimated Escalation Estimated Escalation Used for the Nine Year Rates Rates Mile Cost Projections r9B0 10.2% 8.0% r0.2% r98r 8.8 8.0 B.B T982 7.9 7.0 7.9 t, D ("ô r983 t "tt 7.0 L984 o.b 7.8 7.8 1985 o.b 8.0 8.0 r986 5"9 8.0 8.0

Stone & Webster prepared escalation rates for the years 1980 through 1986. Niagara Mohawk accepted the estimates through 1983 but directed Stone & Webster to use the higher rates shown in Table IV-9 for the 1984 through 1986 period. In conclusion, given the wide disparity between the escalation forecasts of the company and TB&A and Canatomo and given Staff's independent analysis, the escalation rates shown in Table IV-6 were used for this study.

E. Allowance for Funds Used During Corutruction (AFDC) The allowance for funds used during construction (AFDC) rate reflects a utility's total cost of capital. The cost of capital components consist of common equity, preferred stock and debt, both long-term and short-term. The AFDC rates utilized in this study were calculated based upon the projected rates of return for the years 19Bl-L994, which span the period of construction for the various generating plants. The short term debt compone4t of the AFDC rate duúng the construc' tion period is estimated to be 5 percent of the projectetl eapitalization and assumed a debt rate which varied from a higþ of 12 percent to a low of 9 percent. The debt component included in the AFDC rate is deductible for federal income tax purposes. If a gross AFDC rate is utilized, the federal income tax expense reduction associated with the interest charge is flowed through to the current ratepayer by reflecting lower expense during the construction period than if there were no construction. Conversely, if a net-of-tax basis AFDC rate is utilized, the AFDC rate is lowered by the federal income tax expense reduction related to the debt interest charge; the amount of AFDC that is accumulated on a generating plant under con' struction is reduced. Utilizing a net-of-tax basis AFDC rate allows the future ratepayers, who bear the burden of interest charges incurred during construction, to receive the associated federal income tax benefits rather than the current ratepayers. These tax benefits are in effect capitalized as ffl offset to rate base, and benefit future ratepayers as an offset to depreciation accruals and return allowance over the life of the asset. The projected yearly rates of return and net-of-tax basis AFDC rates compounded monthly and utilized in the study are shown in Table IV'f 0.

IV.7 Exhibit__(JDS-12) Page 21 of 90

Table IV.fO

Net of Tax Year Rate of Return AFDC

1981 tr"5L% 9.52% L982 rr.62 r0.00 r983 r t.5B 9"85 r9B4 tr.67 9.90 l985 I r"75 9.95 r986 LL.62 9.79 1987 r r.65 9.79 r988 r 1.70 9.83 r989 IL.74 9.85" r990 TÏ,76 9.86 r99t-t994 rr.60 9.65

F. Decommissioning The projected decommissioning costs for Nine Nlile Point.II are estimated in l9?9 dollars at $f 01.385 million. This was derived by escalating the Nine Mile Point I unit decommissioning costs of $57 million (in 19?9 dollars) on the basis of the respective plant capacities.* The Ninã Mile Point II decommissioning costs of $10f .385 million were escalated utilizing a GNP implicit deflator of 8"5 percent through 1985, 7.5 percent from 1986-1990, and ? percent for the remaining years of the unit's operating life" The decommissioning cost is projected to be realized by utilizing a pre-tax rate of return of L7.BZ percent and a moclified sinking fund methodology as adopted by the Commission in the recent Niagara ÙIohawk Power Corporation (C.27741, 2, 3) rate decision granted March lZ,lgïl. The decommissioning costs will be provided by having customers pay during the service life of the plant for the cost of decommissioning in the form of additional depreãiation accruals. Altlough these depreciation accruals may not be deducted from income for tax purposes when booked, we have treated tJ-re depreciation accruals as though they could be. An alternative method is to recognize these accruals at the time of decommissioning, when the costs beeome a tax deduction. The projected yearly revenue requirements are reduced to reflect the effect on net investment of the prior recovery in rates of the average accumulated depreciaton accruals less the federal income tax payments which are multiplied by"the the pre-tax rate of return of IT.BZ percent. The federal income tax payments are required'since depreciation aecruals cannot be currently declucted. A variation from a recent Commission rate clecision (Case 27741) involves the escalation of the projected revenue requirements, during the operating life of the generating unit at a Z percent ' rate annuall/r rather than in three year intervals using a 5 percent escalation rate. The ..ãd"tior, *An alternate method to determine decommissioning costs is given in the Nuclear Regrrlatory Commission report NURBG/CR'0672' Vol. l, Technology, Safety and Costs of Decommissioning a Reference Boiling llater Reaetor Power .sntion (page l4-1). The scaling-up relationship is given 1y the relationship: OSF=0.324+(2.035x1ù4¡ PPR: where OSF=overall scaling iactor a¡d ppg=poîr, plant rating in thermal megawatts. if this method was used, decommissioninpç costs would equate to $86 million instãad of $l0I million. The $I5 million difference would not affect the conclusions of this report.

IV.B Exhibit__(JDS-12) Page 22 of 90 rate utilized in determing the revenue requirernent was increased to 7 percent annually in order to correspond with the GNP implicit deflator utilized when calculating the estimated decommissioning costs of the Nine Mile Point tr unit.

G. Accounting The following financial and accounting parameters have been utilized in deriving the Co- Tenants' operational revenue requirements for Nine Mile Point II and the various coal'fired generating units. The operational revenue requirement reflects the construction cost and carrying charges on the investment of the generating plant, book depreciation, other taxes, insurance, deeommissioning, federal income taxes and revenue taxes extending over a 30 year operating period. The carrying costs are calculated by applying an average rate ofreturn of 11.66 percent to the depreciated plant balance for the 3$year period. The ll.66percent rate of return was derived by averaging the projected rates of return for the 14 year period 198f-I994 which spans the construction period of the-various generating plants. The book depreciation for both the nuclear and coal'fired generating plants was calculated by the straight line method for a 30 year service life. The other taxes were ãalculated by estimating a level in the first year of operations which when escalated utilizing the GNP deflator of 7 percent throughout the operating period equates to 1.21 percent of the nuclear and l.4S percent of the coal-fired total construction costs. The insurance costs were calculated for the nuclear and coal-fired generating plants at .2 percent and .1 percent of the total investment, respectively. The decommissioning costs for Nine Mile Point II have been explained previously. Thã revenue taxes have been calculated utilizing a 4 percent rate. Computing the federal income taxes for the individual generating plants necessitated that certain financial accounting assumptions be made regarding the construction overheads, allowance for funds used during construction (AFDC), investment tax credits and the deferral of the tax effect of the Accelerated Cost Recovery System. When constructing a generating plant certain costs, zuch as property taxes and pension costs are included as part of the cost of the plant for financial accounting purposes. These items may be deducted in computing federal income tax in the year they are incurred. The federal income tax deductions relating to these constuction overheads have been recognized in our calculations as though they were not realized until the costs which gave rise to them are recognized as an expense for financial accounting purposes. The difference in amount between the tax'expense so calculated and the actual tax liability, as it relates to these items of costs, is assumed to be allowed as part of the cost of service in ratemaking. The excess, thus arising of the revenues so received by the company over what it requires to satisfy iæ actual tax liability, is considered to be available for investment in the plant and the amount so invested is considered to require no return. As previously mentioned AFDC has been accrued on a net of tax basis during the generating plant's construction period. This recognizes the federal income tax deduction related to the AFDC's interest component over the operating life of the unit instead of during the construction period. The construction of a generating plant allows the company to elect a 10 percent investment tax credit which can be utilized to directly reduce federal income tax expense. We have assumecl that the investment tax credit is elected and utilized during the generating plants initial year of

IV.9 Exhibit__(JDS-12) Page 23 of 90

operation. The l0 percent investment tax credit is deferred in first year of commercial operation, which conforms with the Economic Recovery Act of 1981 and the accumulated balance is deducted from rate baseo provided the reduction in rate base is restored "not less rapidly than ¡atably" over the book life of the property. Under applicable tax law the utility's cost of service for rate making purposes cannot be reduced by reason of any portion of the allowable 10 percent investment tax credit other than the effect of the rate base reduction. The tax depreciation for Nine Mile Point II and coal-fired plants was calculated utilizing the Accelerated Cost Recovery System depreciation rates for property placed in sen'ice after December 3I, l9B5 for 10 year and 15 year (public utility) periods, respectively. The reductiern in income tax liability from the use of this method (compared to what that tiability would have been had the method used for calculating depreciation for financial accounting been used and applied to a period equal to the tax life of the property) is assumed to be normalized * during the earlier years of the generating plants operating life and subsequently amortized over the remaining years. The federal income tax expense also reflects the tax effect of the capital costs relating to the common equity and preferred stock components. As was previously mentioned, a utility's capital cost consisæ of debt, common equity and preferred stock components. Unlike the debt component for which there is an offset to federal income tax expense resulting from interest charges; a matching of federal income tax expense must be provided for the common and preferred stock components The revenue requirement also reflects the reduction in rate base owing to the deferral of investment tax credits, the normalization of federal income tax benefits relating to the construction overheads and tax depreciation.

"This is treated in a manner similar to the method described for construction overheads above.

IY.IO Exhibit__(JDS-12) Page 24 of 90

CHAPTER V

SUNK COSTS

The economic studies performed by staff assume a Nine Mile Point II sunk cost disposition of approximately $2.057 billion if the project is terminated. The disposition of these costs is discussed in the following sections of this chapter. It should be noted, however, that Staff's study used a method to dispose of sunk costs that charged the entire amount to ratepayers. This was done in recognition that sunk costs should be presented in the economic comparisons. It should not be construed, however, as an admission by Staff that all or any part of the Nine Mile Point II costs should be charged to the ratepayers if the project is terminated.

A. Expenditures to Date and Penalty Charges As of December 3I, 1981, Staff estimated that the Co-Tenants will have spent approximately $1.0?2 billion in direct costs and acerued $290 million in AFDC. In addition to these costs, Stone and Webster estimates the sunk costs would increase by approximately $312 million for cancella' tion costs, should the project be terminated. These cancellation costs are outlined in Table V'I. These three items total to $1.674 billion" In addition to these items, other costs associated with restoring the site push the sunk cost estimate to $1.735 billion. The AFDC for the years l9B2 and 1983 total $322 million, bringing the total sunk cost of Nine Mile Point II to $2.057 billion.

B. Ratemaking Impacts Staff's economic study assumed that the Co-Tenants will recover through rates 100 percent of the sunk costs associated with Nine Mile Point II including the carrying costs on the unamortized balance over a 15 year amortization period. This methodolory results in total sunk cost revenue requirements of $5.125 billion in nominal dollars and $t.9ll billionin I98l dollars.* Thisamorti- zation applies to Plans B, D and F. The amortization will commence in l9B4 and continue through 1998 on a declining basis due to the decrease in the carrying costs owing to the commensurate reduction in the unamortized loss balance. The impact on operating revenues for the individual Co-Tenants appears on Table V-2 for the years 1984 through f 998. The impact ranges in the initial year from a high of 15.? percent for the Rochester Gas and Electric Corporation to a low of 5.8 percent for the Long Island Lighting Company. Table V-2 indicates a declining percentage over time. A levelized schedule would shift the rate impacts during the early years of the study to achieve a more even distibution over time.

C. Financial Impacts A number of financial issues most likely will develop if Nine Mile Point II is cancelled and an amortization plan as outlined above is implemented. It is reasonable to assume that due to the length of regulatory proceedinp, the amortization would not commence until f984. If that occurs, AFDC of $146 million and $1?6 million would be accrued in 1982 and 1983, respectively.** In

* See Chapter VII-B for details. **The Nine Mile Point II project zunk costs can be reduced to $1.970 billion if the federal income tax effect of the loss associated with the abandonment of the project is considered when deriving the AFDC for the years 1982 and 1983. ThiE level of sunk cost will result in a $4.BlI billion revenue requirement in nominal dollars and a $I.794 billion in fgBl dollars. v-l Exhibit__(JDS-12) Page 25 of 90

addition to these charges, the Co-Tenants would have to pay cancellation charges and other costs associated with abandonment. These costs could be as high as $3?3 million during the next 2 years. Also, duringL9B2 and 1983, there would most likely be concernbyinvestorsthat all, or aportion of the Nine Mile Point II costs may not be recovered. This could cause investors to shy away from New York utilities-an event that would not be desirable. This problem could be ameliorated if any plans to cancel Nine Mile Point tr àre aceompanied by an immediate plan to begin cost recovery. The study assumes that PSC hearings and possibly other legal proceedings extending to 1983 would most likely be necessary before the Public Service Commission could make a credible commitment to such a plan. There are a number of positive benefits that would result if Nine Mile Point II were termi- nated. First, if Nine Mile Point [I is completed, the Co-Tenants must undertake an amount of additional construction exceeding $3 billion by 198?. If this finaneial burden were alleviated, the short-run financial condition of each Co-Tenant would improve. Also, the rate recovery mechanism would provide immediate cash flow to eaeh Co-Tenant.

TABTE V"T

Nine Mile Point II Cancellation Costs Through l9B0 ($ mittions) Invoices in progress $35 Contract cancellations I5

Remove reactor pressure vessel 3 Remove stator I

Fill lake tunnels and screenwall .)

Renloye perylalenl plant equipment and demolish buildinp lÐ

Backfill and landscape 7

Cherry Hill purchase order cancellationg 90

Cancel contacts with General Electric, Nuclear Stean Supply System, l0 Power Generation Control Complex 30

Shutdown Stone and Webster headquarters 15

Contingency 60

Niagara Mohawk and Co-Tenant costs (

Total: $3s0

Total Salvage Value 3B

Net Total: $312

Source: Niagara ùlohawk letter to Stone and Webster, February 10, 19Bl

Stone and Webster letter to Niagara Nlohawk, February 25, 1981

Y-2 Exhibit__(JDS-12) Page 26 of 90

TABLE V.2

Nine Mile Point II Nuclear Power Plant

Co-Tenants % of hoiected Revenues to the Amortization of Sunk Costs

Year NMPC CHG&E RG&E LILCO NYSE&G

L984 9.8 r0.3 t5.7 5.8 11.9 r985 8.6 9.0 r3.6 5.0 r0.3 r986 7.4 7.8 II.9 4.4 9.0 r987 o.b o. I 10.3 3.8 7.8

I98B s.6 5.8 8"9 3.3 6.7 r989 4.8 5.0 7"7 2.8 5.8 r990 4.2 4.3 6.6 2"4 5.0

D t', I99I 3.5 ¿). ¡ b.o 2.L 4.3 r992 3.0 3.t 4.8 1.8 3.6

r993 2"5 ,F7 4.1 I.5 3.1

t994 ,, 2.3 3.4 1.3 2"6

1995 I.8 1.9 to 1"1 ,,

r996 1.5 r.6 2"4 9 1.8

,7 L997 1.3 r.3 2.0 1.5

I99B I.0 1.I r.6 6 r.2

v-3 Exhibit__(JDS-12) Page 27 of 90

CHAPTER VI

PRODUCTION SIMUTATION

A. General Inputs The generation expansion plans result in differing types and amounts of capacity available through irgg4., thus there will be differences in the system production costs. Production cost simulations of the. entire New York Power Pool (NYPP) system were conducted for all the plans to illustrate the effects of the different generation expansion schedules on the Pool's production costs. The produetion costs include: fuel costs, operating and maintenance costs, and internal and external transactions of the statewide electric system. The basic assumptions, except as noted in the follow- ing sections, are those submitted in the NYPP's IgBl 5-112 Report to the State Energy Office (SEO). These assumptions include load models, generation model inputs (except for the changes proposed), purchases from Quebec and Ontario and coal conversion schedules. Production simulations were not necessary beyond 1998, after the new units have reached maturity. Any generation additions beyond that time would be common to all plans. It was further assumed that any production cost differentials that exist after l99B are inherent to the respective plans and will continue to exist through the life of the ptan. The differentials were escalated at the rate of inflation (7 percent per year) after 1998.

B. Fuel Costs The study presents the implications of both Staff's and the Co-Tenants'fuel estimates. The Fuel Planning Advisory Sub-Committee (FPAS) of the New York Power Pool used the services of ICF Inc. to develop fuel cost estimates. These esti.mates were endorsed by the Co'Tenants for the purposes of the Nine Mile Point tr study. Staff has based fuel price increases on the assumption of long-term orderly markets. Both the Staff and ICF/NYPP fuel price escalation rates are linked to staff's annual GNP Implicit Price Deflator forecasts of 8.5 percent during the 1980 to l9B5 period, 7.5 percent during the 1986 through 1990 period, and ?.0 percent during the years from l99l to 2000. A comparison of Staff and ICF/NYPP fuel cost escalation rates are presented in Table VI'l. The fuel costs whieh these rates apply appear in Table VI"2" Appendix B provides a more detailed breakdown of the fuel costs. Staff's oil prices are expected to escalate at a rate 2.0 percent faster than Staff's estimate of inflation (i.e. forecasts of the GNP Delator) during the entire forecast period. This assumes that OPEC will implement a long term pricing policy which will result in oil prices advancing at a rate slightly above the general rate of inflation. The projected rate of increase in oil prices is significantly lesi than that experienced by New York State utilities during the l9?5 to t9B0 period when the real price of oil increased at a 9.2 percent annual rate. Oil prices are forecast by ICF to rise rapidly by 1985, refleeting the assumption that world crude oil prices will increase at 2 percent per year (above inflation) and the elimination of oil price controls. After 1985, the delivered prices are forecast to increase at a rate consistent with world oil prices. Coal prices, during the l9B0 to I9B5 period are projected by Staff to increase at a rate of 2.0 percent per year faster than the rate of inflation. This increase is due entirely to real price

VI.I Exhibit__(JDS-12) Page 28 of 90

TABTE IV.I

Comparison of Fuel Cost Escalation Rates Staff vs. ICF/NYPP

Annual Escalation Rate Fuel Type r98r"r9B5 r986"r990 r99r-2000

Staff Assumptions Oil Íf 6 and/á2 l0.s 9.s 9.0 Nuclear r0.5 8.5 8.0 Coal 10.5 ("Ð 7.0 ICF/NYPP Assumptions Oil (#.-ó and-ffZ)* r2.7-r9.2 9.5-9.8 9.0.9.3 Nuclear 8.5 /.Ð 7 Coal* r8.6-20.9 7"4-10.r 7.1-8.1 *The ranges reflect the fact that ICF forecasts different escalation rates for oil and coal depending upon sulfur content. See Appendix B for more detailed information.

TABLE VI"z

Comparison of Fuel Costs Staff vs" ICF/I\YPP

Fuel Costs r985$/I06Btu Sulfur Staff ICF/NYPP Type of Fuel Content te Downstate Upstate Downstate oil .3% N.A. 10.t4 N.A. 9.78 "7 v,o'( 9.52 9.68 9.33 t.0 9.3ó 9"20 9.43 9.07 2"0 8"27 B.1r 8.76 8.34 2.8 7.80 7.64 8.33 7.92

Distillate r0.92 t I.08 10.44 L0.64

Coal 1.0 3.2s 3"86 3.45 3.73 ot.l t.4 a"¿4 3.09 3.13 3"64 2.0 2.32 3.09 2"89 3.41 2"0 rlt 3.09 2"56 3"06

Nuciear 64 78

vr-2 Exhibit__(JDS-12) Page 29 of 90

increases of 6.0 percent per year for transporting coal to New York State utilities. Since transportation costs account for roughly 30 percent of the delivered cost of coal, a 6 percent per year real increase results in a 2 percent per year real increase in delivered coal costs. During the 1975 to 1980 period, the real price of coal delivered to New York State utilities declined by 4.2 percent per year. No real increases in the eost of transporting coal are expected after 1985 because of continuing railroad improvements. Thus, Staff believes coal costs are expected to increase at the rate of inflation during the t9B6 to 2000 period. These assumptions result in expected increases in the cost of coal of I0.5 percent per year during lg8l to 1985,7.5 percent per year during 1986 to 1990, and 7.0 per- cent during 199I to 2000. ICF's coal prices are forecasted to increase substantially by 1985, reflecting a firming of the market as current excess productive capacity is used up through the closing of inefficient operations and increases in market demand. After 1985, coal prices are forecasted to increase about I percent per year (above inflation), reflecting the Nation's enormous reserve base and capability to expand production without substantial mining cost increases. Staff projected nuclear fuel to esealate at annual rates of 10.5 percent during 1980 to 1985' 8.5 percent during 1986 to 1990, and 8.0 percent during the 1991 to 2000 period. Given Staff's projections for oil and coal prices, our estimates of nuclear fueI costg are consistent with the Depart' ment of Energy's (DOE) projections of the relative inerease in fuel costs during the l9?0 and 2000 period.s That is, DOE has projected nuclear fuel costs to.increase somewhat faster.than coal prices and somewhat slower than oil prices from the present to the year 2000. The nuclear fuel prices shown were developed by FPAS and are assumed to escalate at the rate of inflation for the study period. It should be noted the FPAS assumed that the upward pricing pressures evident on a global basis for fossil fuels do not appear to be present to the same degree for nuclear.

C. Load Forecast The member systems of the New York Power Pool submitted their projeetions of long term energy requirements on April l, 1981, pursuant to SectionS-1f2 of the Energy Law of New York State. The projected growth rates for the 1980 to 1996 period are presented in Table VI-3.

TABLE VI.3

Long Term Energy Growth Rate hojections (Member Systems)

Projections of Compound Annual Company Gron'th in Energy Requirements (%)

Central Hudson t"2 tILco r.6 NYSE&G 3.r NIMO L.4 RG&E ,, Co-Tenants I.8 NYPP 1.5

*Energy Information Administration, l9B0 Annual Report to Congress, Volume Three: Forecasts, U.S. Department of Energy. vI-3 Exhibit__(JDS-12) Page 30 of 90

The latest projections of energy requirements by the member systems are, on average, about .5 percent per year lower than the l9B0 forecasts. Staff believes that the 1981 forecast of energy requirements should be used for the purpose of running base-cost production simulations.* In determining the sensitivity of the production cost estimates to differing energy requirements, Staff considered the effects of both higher and lower than expected increases in the real price of electricity. The Co-Tenant's projected rate of real electric prices embedded in their forecasts range from approximately 2.4 percent to 7 percent per year through the mid-eighties" For example, the J.5 percent per year varianee from the base-case forecast can be interpreted as a quantification of the effect of a .t 1.0 percent per year variation in the projected rate of real electric prices embedded in the member systems foreeast of energy requirements given a long-run price response (i.e. price elasticity) of -.5 all else equal. That is, for every I percent increase in real electric prices, energy requirements can be expected to decline on average about .5 percent. Since the main concern was to assess the sensitivity of production costs to differing levels of energy requirements, Staff believes the 3.5 variances are appropriate.

D. füpaeity Factors The capacity faetors for the future units that were used in the production simulation computer calculations are shown in Table VI-4.

TABLE VI.4

'Capacity Factors

Immature Mature (F irst 3 yrs) (After 3rd yr)

Nine Nlile Point II 62% 69% Jamesport - 800 MW 67% 7L% 850 IVIW units 67% 7L% 625 MW units 70% 73%

With the exception of the 625 MW units, these capacity factors are the same as those used in the Co-Tenant's January Nine NIile Point II economic study. Staff concurs that these values are reasonable. For the 625 MW units, the values of 70 percent and 73 percent were based on the recent New York State Electric and Gas Corporation's report on the 625 MW Somerset plant. For the purpose of a sensitivity study, a 60 percent capacity factor v¡as assumed for all the nuelear units in New York State. The affected units and representative capacity factors are shown in Table VI-S.

*Acceptance of these projections for the limited purpose of running production simulations should not be viewed as a general approval of the utilities forecasts and/or forecasting methodologies by the Staff of the Department of Public Service.

VI.4 Exhibit__(JDS-12) Page 31 of 90

TABLE VI.5

Nuclear Unit Capacity Factors (%')

Unit Base Sensitivity

Ginna 67 60 Fitzpatrick (J 60 Nine Mile Point I 70 60 Nine Mile Point II 69 ó0 Indian Point II 7l 60 Indian Point III 74 60 Shoreham 69 60

E. Statewide Coal Conversion The production simulation assumes that 3665 MW of existing oil units would be converted to coal-fired units. These units are shown in Table VI-6.

TABTE YI.6

Coal Conversion Units

Utility Current Total Rating Unit Rating (rvrw)

Arthur Kill 2 Consolidated Edison 335 tuthur Kill 3 Consolidated Edison 49r Ravenswood 3 Consolidated Edison 928 Lovett 4 Orange & Rockland t97 Lovett 5 Orange & Rockland 202 Danskammer 3 Central Hudson 126 Danskammer 4' Central Hudson 226 Albany I through 4 Niagara Mohawk 400 P. Jefferson 3 and 4 Long Island Lighting 380 E. F. Barrett I and 2 Long Island Lighting 380 366s MW

For the statewide coal conversion sensitivity simulations,a total of 1225 MW were assumed to be converted. These numbers were comprised of the total megawatts of the Arthur Kill Units 2 & 3 and the Lovett Units 4 &5. In choosing the low coal eonversion number, Staff's purpose was strictly to test the effect coal conversion has on the production simulation. It was not intended to endorse any level or particular units for coal conversion.

VI.5 Exhibit__(JDS-12) Page 32 of 90

CHAPTER Ytr

ECONOMIC ANATYSIS

A. Economic Comparisons The economic implications of Plans A through F* were assessed by discounting the lifetime flow of revenue requirements relating to the capital, production and sunk costs. This approach demonstrates the relative cost benefits (or penalties) of the_ plans. Sensitivity analyses describing the effects of varying key assumptions, such as fuel costs, load forecasts, nuclear unit capacity factors, the number of units to undergo coal conversion, fufure generation unit size, the level and amortization of sunk costs, and Nine Mile Point II in-service dates, were conducted in order to provide a comprehensive picture. The results of the following comparisons are shown with both Staff and ICF/NYPP fuel estimates (see Chapter VI for further details). The life of the study extends 30 years beyond the aszumed in-service date of Nine Mile Point II and utilizes a discount rate of f 1.66 percent, which is the cost of capital. Except where noted, all dollar amounts shown in this chapter are I98I dolla¡s.

l. Plan A versus Plan B Table Vtr-2 presents the total cumulative present worth revenue requirements for Plans A and B. These results are based on the New York Power Pool's Statewide l98l load growth forecast of 1.5 percent as frled with the State Energy Office (SEO). The analysis also assumes 3665 MW of coal conversions and a Nine Mile Point II in-service date of L987.

TABTE Vtr.z Economic Comparison - Plan A vs. Plan B Revenue Requirements $ (Millions) l9B1 Present Yalue Staff Fuel Capital hoduction Sunk Total Assumptions Costs Costs Costs Costs Plan A 5501 53,963 -0- 59,464 Plan B 3500 55,3M l,9l l 60,7L5 Difference (A-B) 200r (1,341) (1,9r r) (1,251) % Change 36.4 (2.s) (2.1)

ICF/NYPP Aszumptions Plan A 5501 58,735 -0- 64,236 Plan B 3500 60,266 1,91r 65,677 Difference (A-B) 2001 (1,53r) (t,9 r l) (1,44r) % Change 36.4 (2.6) (2.2>

( ) Denotes negative.

"See Table VII-1

Vtr.1 Exhibit__(JDS-12) Page 33 of 90

TABI,E VII.T

PSC STAFF OPTIONS (Unit Size-MW)

Year A B C D E F

1987 1085 (NI\{Pil) rOBs (NMPII) 10Bs (NMPtr)

r.988

625 (Jarnesport) Ioeo Ir'n ó25 (TEGSI)

Irqqo 800 (Jarnesport) 625 (Jamesport) 625 (LEGSII)

|,,,0 850 (LEGSI) 625 (TEGSI) I\9 fTqqr 800 (Jamesport)

|',n, 850 (LÐGSI)

r992 850 (IEGSII) 400 (LEGSII)tÈ',Ê 625 (COAL I)

r993 235 (Coal I)* 235 (Coal II)8* 625 (Jamesport)

t994 460 (LEGSI)'Ê*

Total (Mw) 2735 2735 2735 2735 1085 1085

*Characteristics of an 850 MW unit **Characteristics of a 625 MW unit Exhibit__(JDS-12) Page 34 of 90

The results indicate that Plan A is less costly than Plan B under Staff and ICF/NYPP fuel assumptions by $1,251 million and $1,441 million, respectively. These cost differences represent about 2.1 percent and. 2.2percent, respectively, of the total revenue requirements under the two fuel aszumptions. la. Sensitivity Analysis of Key Assumptions The production costs account for over 90 percent of total revenue requirement for any of the studied optiottr. Therefore, sensitivity analyses were performed on the key assumptions in the production simulation model. These include load forecasts, Nine Mile Point II in-service dates, nuclear unit capacity factors, and t}e amount of existing oil fired units to be converted to coal- fired units. Additional sensitivity runs were performed on the level and amortization of the sunk costs.* The economic impacts of varying the Nine NIile Point II in-sewice date, statewide load growth forecasts, nuclear unit capacity factors and the amount of units to undergo coal conversion are shown in Table Vtr-3.

TABTE Vtr.3

Economic Comparison - PlanA vs. Plan B Sensitivity Impact

Net Benefit to Plan A Revenue Requirements Sensitivity . )1 981 hesent Value Staff Fuel ICF/NYPP In-Service Date Assumption Fuel Assumptions

r986 1515 1705 T987 125r L44L r988 997 1t88

Load Growth r% L224 1352 Ls% 1251 t44I 2% L322 1595

Nuclear Unit C Factor Base r251 L44L 60% 708 957

Coal Conversion 3665 MW 1251 L44L 1225 MW L349 1619

esee Section Vtr B for details.

Vtr.3 Exhibit__(JDS-12) Page 35 of 90

-In-Service Date For the Staff fuel estimate, the $1,251 million cost benefit for Plan A becomes $1,515 million for a 1986 Nine Mile Point II in-service date and $997 million for a l98B Nine Nlile Point II in-service date. For the ICF/NYPP fuel estimate, the $1,441 million cost benefit for Plan A becomes $1,705 million for a 1986 in-service date and $1,188 milli6n for a 1988 in-service date. Each year of Nine Mile Point II commercial operation slippage contributes approximately $250 million to the net revenue requirements of the plans.

-Load Forecast The New York Power Pool (NYPP) load forecast presented in the 1981 filing of the Section 5-f 12 (Long-Range Plans) to the New York State Energy Office was used for the base runs. This forecast is approximately Llzpercent annual statewide load growth (See ChapterVI-C for detail). Sensitivities using load growths of l% and 2% were performed. For the most part, the I percent load growth has minimal effect on the comparison of Plan A vs. Plan B, sinee there is orùy a $27 million and $89 million net decrease to Plan A's economic advantage under the Staff and ICF/NYPP fuel estimates, respectively. However, the total balance of production costs of each plan decrease substantially-approximately $tl billion. The 2 percent load forecast increases the net revenue requirement benefit of Plan A by $?1 millie¡¡ and $154 million for the Staff and ICF/NYPP fuel estimates, respectively. The production costs of each plan increased by approximately $11 billion for thç 2 percent load forecast. In summary, the higher the load forecast the more costly Plan B becomes as compared to Plan A. Further, the lower load forecast has minimal impact on the results of the economic comparison.

-Nuclear Unit Capacity Factor The capacity factors of all the nuclear units in New York State were lowered to 60 percent for purposes of sensitivity (see Table YI-5)" This sensitivity showed the largest impact on the economic comparisons. It lowered the benefit to Plan A by $5a3 million and $484 million under the Staff and ICF/NYPP fuel estimates, respectively. Nonetheless, Plan A was less costly than Plan B by $?08 million and $957 million for the Staff and ICF/NYPP fuel estimates, respectively.

-füal Convereion The ba,se production runs include 3665 MW of existing oil-fired units to be converted to coal-fired units-all by the end of 1987. A lower coal conversion case was run to test the revenue requirernent implications. The Lovett Units 4 & 5 and the A¡thur Kitl Uruts 2 & 3 (totaling 1225 MW) Irere assumed to be converted for the lower coal conversion ease. The results indicate a $98 million and $1?B million increased benefit to Plan A under the Staff and ICF/NYPP fuel estimates, respectively. The total production cost revenue reguirements of the lower coal conversion case for Plan A and Plan B increased approximately $9.5 billion. The net effect of the lower coal conversion to the Nine Mile Point tr economic comparison is dwa¡fed by the gross revenue requirement savings that would be recognized if the full 3665 MW were converted-rougtrly $3900/kW. The capital costs associated with converting to coal the additional 2440 MW are approximately $2251kW." This analysis produces a benefit to cost ratio of approximately 17 to 1. The economics overwhelmingly favor converting to coal the units outlined in Chapter VI-E, whieh total 3665 NIW.

*The capital costs were obtained from the lg8l "Report of Member Electric Systems of the New York Power Pool and the Empire State Electric Energy Research Corporation" (5-112 Long Range Plans) and then were re-escalated to 1981 dollars.

Vtr-4 Exhibit__(JDS-12) Page 36 of 90

2. Plan C Vs. Plan D The basic differences in Plans C and D as compared to Plans A and B are the size and the in' service dates of the future coal units (See Chapter trI). Essentially, the Plan C and Plan D compar' ison presents the revenue requirement impact of smaller future coal units. When compared with Plan A, Plan C has a $194 million advantage under the Staff fuel estimate and a $163 miìlion advantage under the ICF/NYPP fuel estimate. Therefore, the 625 MW coal units showed an eco nomic advantage over the 800 to 850 MW coal units. Since the Jamesport and LEGS units are certified for the large unit sizes shown in Plans A and B, Staff did not perform all the sensitivity runs for Plans C and D comparison as it did for the Plans A and B comparison. The relative impacts of the sensitivity runs for Plans A and B should be comparable for Plans C and D. Table Vtr-S provides the economic comparison of Plan C vs. Plan D.

TABTE Vtr-5

Economie Comparison - Plan C vs. Plari D

Revenue Requirements $(Millions) 198f hesent Value Capital Production Sunk Total Costs Costs Costs Costs

Staff Fuel Assumptions Plan C 5542 53,728 -0- 59,270 Plan D 375r il,gLL 1,911 60,573 Difference (C-D) T79L (r,l83) (1,911) (1,303) % Change 32.3 _9¿L (2.2)

ICF/NYPP Fuel Assumptions Plan C 5542 58,531 -0- 64,073 Plan D 3751 60,0r9 l,9l I 65,691 Difference (C-D) 179l (1,488) (1,911) (1,608) % Change 32.3 (2.s) (2.s)

( ) Denotes Negative

Similar results occur for the Plans C and D comparison as did for the Plans A and B compar- ison. That is, for both the Staff and ICF/NYPP fuel estimates, the plan without Nine Mile Point II (Plan D) is more costly than the ptan with Nine MiIe Point II (PIan C). Plan D costs more by $f .303 billion and $1.608 billion for the Staff and ICF/NYPP fuel estimates, respectively. The Nine Mile Point II in-service date impacts are shown on Table Vtr-6. The 1986 in-service date increases the difference between Plan C and PIan D by $262 and $263 million for the Staff ancl ICF/NYPP fuel estimates, respectively. The lgBB in-service date decreases the difference between Plan C and Plan D by $253 and $251 million for the Staff and ICF/NYPP fuel estimates, respectively.

vtr-5 Exhibit__(JDS-12) Page 37 of 90

TABTE YII.6 Economic Comparison - Plan C vs. Plan D Nine Mile Point II In-Service Date Impact

Net Benefit to Plan C Revenue Requirements Sensitivity $ (Millions) 1981 Present Value Staft !uel IC!'/N YPP In-Service Date Assumption Fuel Assumptions

1986 r565 1871 r987 1303 1608 1988 1050 t357

3" Plan E vs. Plan F Plans E and F highlight the economic ramifications of only constructing Nine Mile Point II as compared to eonstructing alternative coal capacity of 1085 NIW. The timing of the altemative capacity additions were based on a composite Co-Tenant eapacity deficiency under New York Power Pool criteria. Plans E and F are separate economic scenarios than Plans A through D. Table Vtr-7 provides the revenue reguirement comparison of Plan E vs. Plan F.R

TABLE VTI.7 Economic Comparison - Pla¡r E vs. Plan F Revenue Requirements $ (Millions) 1981 hesent Yalue Capital l'roduction Sunk Total Options Costs Costs Costs Costs

Staff Fuel Assumptions Plan E 3231 58,624 -0- 61,855 Plan F L497 60,519 l,9l I 63,927 Difference (E-F) 1734 (r.B9s) ll"9r 1) (2.072\ % C)nange s3.7 _____(32)- -*s¿t ICF/NYPP Fuet Assumptions Plan E 323r 63,314 -0- 66,545 Plan F r497 65,360 1,911 68,768 Difference (E-F) 1734 (2.046\ (l,gl I) (2,223\ % Change 53.7 __iå ___lgÐ_ ( ) Denotes Negative

*Table Vtr-l shows the capacity additions under the two plans.

VII.6 Exhibit__(JDS-12) Page 38 of 90

The plan without Nine Nlile Point II (Plan F) is more costly than the plan with Nine Mile tuel estimates, point II gan n¡ by $2.0?2 billion and $2.223 billion for the Staff and ICF/NYPP respectively.

3a. Sensitivity of Key Assumptions load growth The economic impacts of u*¡ng the Nine Mile Point II in-service date, statewide are forecast, nuclear unit capacity factors and the amount of units to undergo coal conversion shown in Table Vtr-8.

TABTE Vtr-8

Economic Comparison - Plan E vs. Plan F Sensitivity ImPact

Net Benefit to Plan E Revenue Requirements Sensitivity $ (Millions 19BI hesent Yalue Staff Assumption Fuel Assumptions

In-Service Date 1986 2305 2483 L987 2072 2223 r9B8 L796 t972

T,oad Growth 2L45 T% r936 L.5% 2072 2223 2% 2L95 2374

Factor Nuclear Unit Capacity ,îrrq Base 2072 60% r395 1572

Coal Conversion 3665 MW 2072 2223 1225 MW 220L 2379

-In-Service Date The 19g6 Nine NIile point II in.service date increases the benefit of Plan E by $233 million and $260 million for the Staff and ICF/NYPP fuel estimates, respectively. The I9BB Nine Mile point II in-service date decreases the benefit of Plan E by $276 million and $25I million for the Staff and ICF/NYPP fuel estimates, respectively.

YII.7 Exhibit__(JDS-12) Page 39 of 90

-Ioad Forecast The I percent load forecast decreases the net revenue requirement benefit to Plan E by $f36 million and $78 million under the Staff and ICF/NYPP fuel estimtes, respectively. Each plan's production costs decreased approximately $12 billion for the I percent load forecast. The 2 percent load forecast inereases the net revenue requirement benefit of Plan E by $f23 million and $151 million for the Staff and ICF/NYPP fuel estimates, respectively. The production costs of each plan increased approximately $12"5 billion for the 2 percent load forecast. In summary, the higher the load forecast the more costly Plan F becomes as compared to Plan E.

-Nuclear Unit Capacity Factor The capacity factors of all the nuclear units in New York State were lowered to 60 percent for Purposes of sensitivity (see Table VI-s). Similar to the impact between Plans A and B, the sensitivity of the lower nuclear capacity factor showed the largest impact on the economic comp"rison. it lowered the benefit to Plan E by $6?? million and $65l million under the Staff and ICF/Nypp fuel estimates, respectively. Plan E still maintains its economic advantage over Plan F by $f .395 billion and $1.572 billion under the Staff and ICF/NYPp fuel estimates, reqpectively.

-Coal Conversion The total production cost of the plans for the lower coal conversion increased by approx- imately $10 million. The lower coal conversion affects Plan E by increasing the ,"u"r,rl råquire. ment penalty to PlanF by $f29 million and $156 million for the Staff and ICF/Nypp fuef esti- mates, respectively. Similar to the results under Plans A and B, the gross revenue requirement savinp that would be recognized if the fult 3665 MW were converted are substantial-appråximately $4f 00/kW converted. Again, if the capital costs associated with converting the units are factored in at approximately $225lKW," one obtains a 18 to I benefit to cost ratio. The economics over- whelmingly favor converting to coal the units outlined in Chapter VII-E, which total 3665 NIW.

B. The Economie Impact of Nine Mile Point II Sunk Costs As can be seen from Chapter VII-A, the sunk costs attúbutable to Nine Nlile point II has a $f .9f l billion revenue requirement impact" For the comparisons of PlansA through D, the sunk cost impact swings the economic advantage to those plans containing Nine Mile Point II (plans A and C). For the majority of the Plan E and Plan F comparisons, Plan E, the plan with Nine Miie Foint II, is less costly than its coal alternative, Plan F, even when the sunk .o.i, *" excluded from the analyses. l. Amortization The sunk costs amortization period Ìvas assumed to be 15 years in the base case. Table vII-4 was developed to illustrate the effects of I0 and 30 year amortization periods. The t98I present worth tevenue requirement difference for the 10, l5 or 30 year perioãs are small. However, the annua-l rate implications should be considerecl when determing the proper period. This is discussed in detail in Chapter V.

*The capital costs were obtained from the 19Bl "Report of Member Electric System's of the New York Power Pool and the Empire State Electric Energy Research Corporation" (S-ll2 Long Range Plans) and then were escalated to lg8l dollars.

vil-ö Exhibit__(JDS-12) Page 40 of 90

TABTE VII4

Economic Comparison - Sunk Cost Impact $ (Nlillions) 1981 hesent Yalue

Amortization Addition to Plans B, D and F Period Revenue Requirement

r0 $1,898 I5 l,9I l 30 1,932

2. Cancellation and Restoration Cost Impact Chapter Y details the components of the sunk costs' out of the total $2'057 billion nominal amount of sunk costs, $411 million is for cancellation and restoration costs. If these expenses are not realized, the total sunk cost would be $1.646 billion, and would have an $1.588 billion 1981 present value revenue requirement impact.

3. Recovery The study assumes a 100 percent sunk cost recovery. However, the zunk costs revenue require- ment impact is proportional to the percent recovered. For example, a 50 percent sunk cost recovery would have a $955.5 million revenue requirement impaet [t/z x $1,911 million = $955.5 millionl.

C. Break-Even Analyses An important factor in the economic analyses performed in this study is the total capital cost of Nine Mile Point II. Since the cost of this facility can change the overall economics of the project, Staff determined how high the cost of Nine Mile Point II could increase to make economics of the related plans equal. This was done by holding every.assumption in the study constant except for the capital cost of Nine Mile Point II. By varying the facility's costs, we determined the break-even point, at which, the two comparative plans would have equal revenue requirements. The break-even analyses were performed under the following assumptions: (1) a f .5 percent load growth (2) 3665 MW of coal conversion (3) a f 5 year sunk cost amortization These fixed aszumptions were then applied to various in-service dates for Nine Mile Point II using first Staff and then ICF/NYPP fuel eost projections. The break-even analysis provides boundaries to this study's economic comparison in terms of Nine Mile Point II capital costs.

Vtr-9 Exhibit__(JDS-12) Page 41 of 90 l. Plan A vs. Plan B Plan A would require less revenue than Plan B until the capital cost of Nine Mile Point II exceeded the "break-even" levels shown in Table Vtr-g. These additional costs would be generated largely by changes in the project's scope. Changes due to lower or higher escalation or AFDC rates would affect tJre economic comparison of the two plans, which would alter the break-even points"

TAtsI,E VII.g

Break-Even Analysie Plan A equals PIan B

Nine Mile Point tr Capital Cost Nine ùlile Point II $ X Million In-Service Dates Staff Fuel ICF/NYPP

r986 6,375 6,650 L987 6,900 7,I_00 r98B 7,275 7,600

For example, the results of the Plan A and B economic comparison indicated a 'fuel $l2Slmil- lion and $f44I million penalty to Plan B for the Staff and ICF/NYPP assumptions, respectively. To offset the $1251 million penalty to Plan B, the total cost of Nine Mile Point II would have to increase from $4.894 billion to approximately $6.900 billion; and to offset the $f44f million penalty to Plan B, the Nine Mile Point II total cost would have to increase from $4.894 billion to approximately $?.100 billion.

2" Plan C vs. Plan D For the Plans C and D comparison, the break-even levels are shown in Table YII-10. These increases would be mainly due to project scope ehanges.

TABTE Vtr-TO

Break-Even Analysis Plan C equals Plan D

Nine tllile Point II Capital Cost Nine Mile Point II $ X Million trn-Service Dates Staff Fuel ICF/NYPP

1986 6,450 6,875 t987 6,875 7,350 19BB 7,350 7,875

Vtr.TO Exhibit__(JDS-12) Page 42 of 90

3. Ptan E vs. Plan F A break-even analysis, similar to the one done for Plans A through D was performed on the results of the economic comparison of Plan E vs. Plan F until the capital cost of Nine Mile Point II exceeded the break-even levels shown in Table Vtr-ll. Again these increases would be associated mainly due to project scope changes.

TABTE Vtr.II

Break-Even Analysis PIan E Equals Plan F

Nine Mile Point II Capital Cost Nine Mile Point II $ X Million In-Service Dates Staff Fuel ICF/NYPP

1986 7,475 7,725 1987 8,075 8,300 1988 8,625 8,900

vtr-ll Exhibit__(JDS-12) Page 43 of 90

CHAPTER VtrI

FINANCIAT IMPLICATIONS

A. GeneralConsiderations Nine Mile Point II is a major undertaking for each of the five Co-Tenants. This section provides a financial analysis demonstrating the major financial effects that may occur if the projeet is com- pleted. This examination used each Co-Tenants' long-term financial foreeasting model to project items such as increases in electric revenues, cents per kilowatt-hour (c/Kwh), capitalization, and projected securities issues. Due to the complexity of this study, it was performed for Plans A and B ãnfy. I" addition to the detailed financial forecast for those plans, all options were compared by a cash flow analysis. This study compares the cash flows under each option to see if any significant benefits can be derived from changing options.

B. Financial Impacts and Ratemaking Effects of Plans A and B This analysis has been constructed to show the major financial effects for each Co-Tenant.* The studies ¿rssume each company witl earn its fair rate of return. AJso, the analysis assumes that financing costs for all types of capital will be reduced.in the future from the current high levels. The financing costs used in the projections vary slightly by company. They do, however, follow the trend shown in Table VtrI'I.

Table Ym-l

hojected Financing Costs

Common Long-Term Preferred Short-Term Equity Debt Stock Debt

r98r L6"0% rs.0% Ls.0% L5.0% r982 rb.b 13.0 r3.0 12.0 r983 r5.0 11.0 r1.0 10.0 l9B4 15.0 r 1.0 11.0 r0.0 198s r5.0 I I.0 11.0 10.0 r986-r990 L4.5 r0.5 10.5 9.s r99r-2000 14.0 10.5 r0.5 9.0

The costs of new debt and preferred stock are important variables in this analysis since the lower these costs, the better the financial position of each Co-Tenant. Another important assump- tion is that each Co-Tenant will earn its fair cost of common equity. If any of the Co'Tenants fail to earn their fair equity return, their financial position would decline from the levels shown in these studies unless the Commission provides additional rate relief.

*StatÏ requested each Co-Tenant to present scenarios with output assumptions needed to support an A bond rating.

VItr-T Exhibit__(JDS-12) Page 44 of 90

In addition to the cost of money assumptions, these studies assume certain federal income tax normalization procedures including full normalization of new investment tax credits and prospective accelerated depreciation, capitalized consbuction overheads, and normalization of the debt component associated with AFDC. fn some cases, eonstruction-work-in"progress (CWIP) is placed in rate base to maintain adequate finaneial parameters. The financial analysis follows the basic format outlined below: (1) Historical (1976-f980) *d projected increases in electric revenuese cost per kilowatt hour (a/Kwh), and capitalization are shown. (2) Historical and projected finaneinp are shown for Plan A to illustrate how projeeted new financinp compare to the amount of securities issued in the past. (3) Projected interest eoverages and pereentages of allowance for funds used during construction in common equity earnings (AFDC Ratio) are presented. (4) Financial parameters, assuming Staff's break-even cost for Nine Mile Point II, are presented. As the financial studies are examined it is important to consider that they include all construc- tion for each company. When viewing the study's results, the reader should consider that other projects besides Nine Mile Point II contribute to the financial pressure of individual Co-Tenants. For instance, NYSE&G (Somerset generating unit), LICO (Shoreham nuclear unit), and Central Hudson (Danskammer coal conversion), have other major projeets contributing to their cash flow requirements. Another factor to consider is the sequence of future construction. This is important since a company with large imminent rate base additions should generate increased cash flow during the l9B0's. An example of this situation is LILCO. If the company's Shoreham unit is completed on schedule, it will generate cash floï permitting TILCO to finance other projects later in the 1980's. Companies such as NYSE&G and Central Hudson have major projects scheduled to be completed later during the Nine Mile Point II construction period. The timing of these construction projects can affect the ability of both companies to finance Nine Mile Point tr. l. Niagara Mohawk Power Corporation Table VtrI-z shows historica-l and projected financial information for Niagara Nlohawk assuming the assets under Plans A and B are eonstuucted. Nine Mile Point II is the only major generating unit eonstructed in Pla¡i A by 1987.

VIII.2 Exhibit__(JDS-12) Page 45 of 90

Table VtrI-2

Niagara Mohawk Historical and Projected Data $(ooo)

Plan A Plan B Electric c Per Electic q Per Revenues Kwh Caoitaìization Revenues Kwh Capit¿Iization

198r $r,705,398 5.40c $3,625,671 $1,705,398 5.40c $3,625,671 '6,450,069 I9B7 2,743,859 B.14 2,813,508 B.3B 5,061,020 r990 3,899,146 11.12 8,920279 3,818,363 r0.99 8,r45,598

A¡¡nual Growth Rates r976-1980 T3.L% TI.B% 6.7% L3.T% LL.B% 6.7% r98r-1987 8.2 7"t r0.1 8.7 7.6 Ð.t 1981-1990 9.6 8.4 10.5 9.4 8.2 9.4

The projection for Plan A shows that by L987, eleetric revenues increase by 8.2 percent annually. The average increase in 4 per Kwh is 7.1 percent. The price projections for Niagara Mohawk assume Staff's increases in fuel costs. Miscellaneous expenses such as O&M expenses increase at levels of 7 .5 to 8.5 percent through 1987. Table Ym-2 indicates that Niagara Mohawk must expand its capitalization by * average amount of 10.1 percent yearly through L987. This compares to $owth in capitalization of 6.7 per cent from 1976 to 1980. The studies indicate that no CWIP in rate base is needed to finance construction. The analysis of Plan B shows higher electricity costs by 198? than would be incurred under Plan A. Note, however, that by 1990, the cost per kilowatt hour is about identieal in the two plans. Plan B requires less capital than Plan A.

VItr.3 Exhibit__(JDS-12) Page 46 of 90

Table VtrI-3 presents Niagara Mohawk's historical and projected financings under Plan A.

Table VIII-3

Niagara Mohawk Historical & Projected Financinp and Projected Financial Parameters Plan A 1978 - 1990 $(Millions)

Interest Coverage Long-Term Preferred Common Retained Total Mortgage AFDC Debt Stock Eq"ity Earninp Financings SEC Indenture Ratio

I97B $32 fi74 $ 70 $ 30 $ 206 r979 119 75 36 230 1980 66 26 94 26 2r2

198r ß2@ $58 $ 108 $ 5l $ 481 2"7x 2"7x 38% Ðry t9B2 B4 7B B6 248 3.3 d"¡ 40 I9B3 n5 * 95 79 509 3.2 3"2 4? r9B4 256 6B 110 79 5r3 3.2 3"r 50 t9B5 299 79 l15 BB 581 3.1 3.0 53 1986 3s4 B9 180 87 710 3.0 ,,7 6r L9B7 347 BB 154 t0r 690 3.0 2"8 bo 19BB 254 M Ðt 113 ltgg 3.5 3"6 24 1989 473 134 29L L25 1,023 3.4 3.1 3B r990 s62 IM 308 r43 1,157 3.3 3.0 4A 198r-1990 $3,168 $784 $r.496 $952 $6,400

The yearþ financial requirements after t98l are substantially higher than those occurring from 1978 to 1980. Table VtrI-3 shows that if Niagara Mohawk earns its fair rate of return, interest coverage would be suitable. Nonetheless, the company is required to raise iarge amounts of new capital during the 1980's.

VIII-4 Exhibit__(JDS-12) Page 47 of 90

Staff's economic studies (Chapter VII) indicated that Nine Mile Point tr would be economie with a break-even cost exceeding $6 billion. Table VtrI-4 shows Plan A's growth rates in electric revenues, c per Kwh and capitalization if the cost of Nine Mile Point II exeeeded $6 billion.

Table VItr-4

Niagara Mohawk Projected Financial Data Plan A Break-Even Option $(000)

Electric q Per Revenues Kwh Capitalization

r981 $1,705,398 5.40c $3,625,671 L987 2,771,084 8.22 6,983,908 r990 4,000,625 11.41 9,270,324

AnnuaI Growth Rates

r976-r980 L3.t% LL.B% 6.7% t9Br-1987 8.4 7.3 11.6 r98r-1990 9.9 8.7 lr.0

This analysis shows that Niagara Mohawk's capitalization would be about $9.3 billion in 1990. If Plan A is analyzed using Staff's Nine Mile Point II cost ($4.9 billion), the capitalization by 1990 was $8.9 billion (Table VIII-2). This indicates that Niagara Mohawk would be required to raise an additional g400 million in capital during the 1980's should the cost of Nine Mile Point tr equal approximately $6.3 billion. This occurrence means that capitalization must grow at a compounded rate of ll percent yearly. In summary, the financial models presented for Niagara Mohawk indicate that the cost of electricity is about equal under Plan A and B by 1990. PIan A requires more capital than Plan B by f990. Table VItr-3 (Plan A) shows that Niagara Mohawk can expect to face heavy amounts of financing through the 1980's if Nine Mile Point II is constructed. Shoutd the project be terminated, the level of financinp would be relatively low during the early to mid-1980's. Another fact to consider is the projected increases in electric revenues and e per Kwh cost for each plan during the 1980's. The projections contained herein appear reasonable. Note (Table VItr-2) that revenues and electricity prices both increase by levels below l0 percent yearly.

vilI-5 Exhibit__(JDS-12) Page 48 of 90

2. Central Hudson Gas & Electrie Corporation The finaneial analysis for Central Hudson assumes construction of the Danskammer 3 and 4 coal conversion (352 MW) and Nine Mile PointII (98 MW) during the period 1982 through 1987. Central Hudson's projected increase in electric revenues, c per Kwh, and capitalization Íue pre- sented in Table Vltr-s. Also, histor{cal and projected growth rates are shown.

Table VIII-S

Central Hudson Historical and Projected Data $(000)

Plan A B Electric + Per Electric c Per Revenues Kwh Capitalization Revenues Kwh Capitalization

1981 $298,925 8.46c $532,082 $298,925 8"46c $532,082 L9B7 438,379 r2"60 B66,B1B 455,629 13"10 634,749 1990 563,812 15.52 80L,277 567,L57 15.6r 773,485

Annual Growth Rates r9761980 LB.L% L2.0% B"s% LB"L% L2"0% 8"5% 1981-1987 6.6 6.9 8.5 7"3 7.6 3"0 198r.r990 7.3 7.0 4.7 7"4 7.0 4.2

This analysis shows that under Plans A and B, projected growth in electric revenues and q per Kwh will be less than the level experienced during L976 to 1980. Under Plan A, Central Hudson must expand its eapitalization by 8.5 percent yearly through L987 " This is the same growth rate experienced by Central Hudson from 1976-1980. The analysis for Plan B indicates that electricity prices are higher than for Plan A by 1987. The costs âre, however, about the same by 1990. Plan B requires less capital by 1987 as evideneed by the 3.0 percent projected growth rate. The amount of new capital required under Plan B does accelerate, however, after 1987. Table VIII-6 shows historical and projected financings, and projected financial parameters for Central Hudson assuming construction of the assets under Plan A.

VItr.6 Exhibit__(JDS-12) Page 49 of 90

Table YIII-6

Cenbal Hudson Historical & Projected Financings and Projected Financial Pararneters Plan A I97B - 1990 $(Millions)

Interest Coverage LongTerm Preferred Common Retained Total Mortgage AFDC Debt Stock ESotty Earnings Financinp SEC Indenture Ratio

L97B $ 35 $10 $6 ö 51 r979 20 7 27 l9B0 50 t9 6 lÐ

19Bl $30 $ $15 $ 10 $ 5b 2.5x 2.7x 53% 1982 25 ; 19 L4 64 3.2 3.s 36 1983 T7 5 11 11 44 3.0 3.0 51 LgBÁ 3B I 13 T2 70 3.0 3.0 49 r9B5 42 11 24 r3 90 3.0 to 49 r986 26 6 L4 54 3.0 3.0 52 q 1987 : t5 25 3.1 3.2 50 19BB : 16 16 3.9 4.2 2 t9B9 r6 I6 4.2 4.3 3 1990 L7 L7 4.8 4.6 3 198r-1990 $186 $37 $90 $138 $451

Central Hudson's total recent financinp are generally below those projected for the future. It should be noted that during the l9B4 to 1986 period, Central Hudson's analysis assumed CWIP in rate base of $30 million (1984), $60 million (1985), and $85 million (1986). These three years plaee heavy financial burdens on Central Hudson since large amounts of funds must be expended for Nine Mile tr and Danskammer at the same time. Staff's break-even analysis indicated that Nine Mile Point II would be economic if the project cost exceeded $6 billion. Table VIII-? shows growth rates in electric revenues, c per Kwh, and capitalization, if such an increase occurs within the 1987 time period.

YIII.7 Exhibit__(JDS-12) Page 50 of 90

Table VtrI-?

Central Hudson Projected Financial Data Plan A - Break Even Option $(ooo¡

Electric q Per Revenues Kwh Capitrlization

198r $298,925 8.46c $532,082 1987 45L,052 12.97 954,782 1990 585,975 r6.13 871,738

Annual Growth Rates

1976-1980 IB.L% L2"0% B.s% 1981-1987 7.r 7"4. 10"2 198l-1990 7"8 7"4 5.6

Table 'YItr-7 indicates that projected finurcinp would increase if the cost overruns occur. The projected growth rate in capital structure through 1987 is I0"2 percent in this analysis versus 8"5 percent under the original Plan A (Table VIII-5). In summary, the comparison of Plans A and B indicates that each plan requires a 7"0 percent increase in electricity costs through the 1980's. Thise projected costs are contingent upon the successful completion of the Danskammer coal conversion and Nine Mile Point II. Since the Danskammer units (352 MW) are large compared to Central Hudson's Nine Mile Point II invest- ment (98 MW), it is reasonable to expeet that a large portion of Central Hudson's projected fuel savinp come from the Danskammer conversion. As stated earlier, another consideration is the size and timing of financings a.ssociated with specific generating units. Plan A requires that large amounts of new securities be sold by Central Hurlson at the same time to finance Nine Mile Point II and the Danskammer coal eonversions. This situation does not occur under Plan B sinee large new capacity additions are deferred until the 1990's. It is desirable, therefore, for the Commission to consider the ability of Central Hudson to construct both the Danskammer coal conversions and Nine Mile Point II in the same time period.*

"On July 3, 1981, the Commission institr-rted a separate proceeding (Case 28026) to investigate Central Hudson's ability to continue to participate in the Nine Mile Point II project.

vm-8 Exhibit__(JDS-12) Page 51 of 90

3. New York State Electric & Gas Corporation NYSE&G's projected increases in electric revenues, c per Kwh, and capitalization for Plars A and B are shown in Table VtrI-8. This table also contains historical (1976-1980) and projected (f ggl-fgg?, lgBI-1990) growth rates for the three variables. In addition to Nine Mile Point II, PIan A assumes NYSE&G constuucts the Somerset coal unit by 1984.

Tabte YIII-B

New York State Electric and Gas Historical and Proþcted Data $(0oo)

Plan A Plan B uectric q Per Ulectric q Per Revenueg Kwh Capitalization Revenues Kwh Capitalization

t9Bl $ 588,000 5.40c $1,864,000 $ 588,000 5.40c $I,Bó4,ooo L9B7 I,269,ooo 9.82 3,387,000 1,316,000 l0.lB 3,062,000 r990 1,674,000 II.57 4,231,000 r,774,000 12.27 4,230,000

Annual Growth Rates

1976-1980 rL.2% 9.0% 9.s% Ll.X/o 9.0% 9.s% 19Br-r987 r3.7 r0.5 r0.5 14.4 11.2 B.ó r9Br-1990 r2.3 8.8 9.5 13.r 9.6 9.5

This analysis shows that under Plan A, NYSE&G's electric revenues increase at a 13.7 percent yearly rate through 1987. This compares to historical growth of lI.2 percent. Electricity prices are projected to increase at 10.5 percent yearly through 1987. Duúng 1976 to 1980, electricity prices increased at an average rate of 9.0 percent. Capitalization is projected to grow at 10.5 percent ihtorgh l9B?. This is more than the 9.5 percent growth expeúenced by NYSE&G from 1976 to 1980. Table VItr-$ indicates that through 1987 and 1990, electric reYenues and c per Kwh prices grow faster under Plan B than Plan A. One reason for this is the large sunk cost writeoff associated with PIan B. Plan B requires less capital than Plan A through l9B? as evidenced by the capitalization growth rate of 8.6 percent. By 1990, however, the amounts of capital under both plans are almost identical. The increases in electricity prices through 198? under Plan A (I0.5 percent) and Plan B (1I.2 percent) reflect Staff's escalation rates for fuel. Operation and maintenance expenses were projected to increase at levels of approximately B to 9 percent.

VIII.9 Exhibit__(JDS-12) Page 52 of 90

Table VtrI-g shows historical and projected frnaneial parameters for NYSE&G assuming the Plan A assets are constructed.

Table VItr-9

New York State Electric and Gas Historicat & Projected Financings and Projected Financial Pararneters Plan A 1978 - 1990 $(Minions)

Interest Coverage Long-Term Preferred Common Retained Total Mortgage AFDC Debt Stoek Eqoity Eamings Financings SEC Indenture Ratio

T97B ö 50 $ ß72 $ 1B $ r40 LW9 50 20 7 9() r06 r9B0 4n 25 73 r9Bt $ 200 $ 40 $ 90 $2r $ 351 2.4x 2.2x 4L% r9B2 tr,< 60 120 3ó MT 2.8 2.3 47 1983 r75 50 90 47 362 3.0 2.3 ß 1984 L75 30 50 53 308 to oa õ( 1985 25 Ð( B2 3"0 2.8 42 r986 r75 70 59 304 to 2"5 52 T9B7 L25 40 uo 63 258 2"8 2"4 54 oÉ 19BB 67 92 3.0 3.1 32 r989 250 50 40 7L 411 2.9 ¿"Ð M r990 t75 60 BO ta 392 2.8 2"3 5B r98r-r990 $1,550 $400 $500 $551 $3,001

This table shows that NYSE&G's finaneing activity is expected to increase sharply in lg8l and remain at high levels throughout the l980's. In order to achieve the interest coverages shown, the NYSE&G projection included CWIP in rate base amounting to $91 million in 1981, $250 million in 1982, $395 million in 1983, and $183 million during f 984. The amounts of CWIP in rate base are needed until NYSE&G's Somerset generating unit is completed during 1984. Should that unit be delayed, it is expected that CWIP would have to remain in rate base until the project is completed.

vm.10 Exhibit__(JDS-12) Page 53 of 90

Table Vltr-fQ shows NYSE&G's projected eleetric revenues, electricity prices, and capitaliza- tion assuming that Nine Mile Point II is built by L987 with a cost of approximately $6.3 billion.

Table VIII'l0

NYSE&G hojected Financial Data Ptan A - Break Even Option $(000)

Electric 4 Per Revenues Kwh Capitalization

I98T $ 588,000 5.40c $I,964,000 L9B7 L,279,000 9"90 3,600,000 r990 l,726,ooo r 1.93 4,416,000

Annual Growth Rates

1976-r980 LL.2% 9.0% 9.s% 1981-r987 13.8 r0.6 r 1.6 r98r-r990 t2.7 ot 10.1

These projections show that through LgB7, elechic revenues and energy prices would be higher if the break-even capital cost is incurred. NYSE&G's capitalization growth rate is 11.6 percent through 1987. This compares to I0.5 percent a.ssuming Nine Mile Point II costs about 4.9 billion (Table VItr-8).

In conclusion, NYSE&G's projections indicate that the company will experience financial pressures throughout the I980's. Assuming that Somerset is completed on time (1984)' the ãompletion of ihat project contributes cash flow to help finance Nine Mile Point II. The com- parisons for Plans A and B indicate that equal amounts of capital are required under both plans and that energy prices are higher under Plan B.

VItr.11 Exhibit__(JDS-12) Page 54 of 90

4" Rochester Gas & Electric Corporation Table Vm-lI outlines RG&E's historical and projected financial information under Plans A and B. Nine Mile Point II is the only major generating project being eonstructed by RG&E during the 1980's.

Table YtrI-Il

Rochester Gas and Electric Ilistorical and Projected Data $(ooo)

Plan A Plan B Electric c Per Electric c Per Revenues Kwh Capitalization Revenues Kwh Capitalization r9B1 ß3r4,947 5.67+ $1,04Í1,950 83L4,947 5"67q $1,045,941 198? 556,n1 9.38 L,4g7,r7B 634,607 10.70 1,234,015 1990 BIB,7B7 13"13 r,4gg,BM 7W,758 r2.63 r,469,25r

Annual Growth Rates

19761980 t2.t% 8"6% 9"Bo/o t2"L% 8.6% 9"8% 1981.r987 9"9 B.B 6.2 t2.4 11.2 2.8 r9Br-r990 TT.2 9.8 4.1 10.7 9"3 3.9

The projections shown in Table VIII-If indicate that Plans A and B require about the same amounts of capital throughout the period. Plan A's + per Kwh calculation is higher than that for Plan B by 1990" CWIP in rate base was not required under either plan" Table Vm-I2 shows RG&E's historical and projected financings under Plan A"

VIII.T2 Exhibit__(JDS-12) Page 55 of 90

Table VIII-I2

Rochester Gas and Electric Historical & Projected Financings and Projected Financial Parameters Plan A 1978 - 1990 $(Millions)

Interest Coverage Long-Term Preferred Common Retained Total Mortgage AT'DC Debt Stock Eq"ity Earningg Financings sEc Indenture Ratio

IETB $ 40 $- 927 ù t5 $82 L979 10 25 6 11 52 1980 55 25 25 11 116 r98r Ð 40 $ $26 $ 19 $85 3.lx 3.9x 40% 1982 40 34 74 Ð.t 4.2 ö( r983 bb 3r B6 3.4 4.0 M ÐÐ LgB4 40 30 70 3.9 50 oÉ 1985 40 A.) to 94 3.2 3.8 bb r986 40 20 27 87 3.1 3.6 64 r9B7 40 29 69 2.8 3.4 53 I9BB 35 35 ó.1 5.3 4 1989 33 33 4.r s.6 4 r990 3s 35 4.3 5.9 4 1981-1990 $295 $45 $26 $302 $668

This table indicates that RG&E's amount of financing associated with Plan A is reasonable and that interest coverages are adequate.

VItr-I3 Exhibit__(JDS-12) Page 56 of 90

If Nine Mile Point II were to cost in excess of $6 billion, Plan A's financial projection wouid appear as follows:

Table VIII-fB

RG&E hojected Financial Data Plan A - Break Even Option $(00û)

Electric q Per Revenues Kwh Capitalization

r98I fi3].4,947 5.O /c $1,063,96I L9B7iF. N/A N/A N/A r990 858,540 13.76 1,665,939

Annual Growth Rates

r976.1980 L2.r% 8.6% 9"8% 1981-1987'É N/A N/A N/A r98r-1990 1r.B r0"4 5.I

Table Vm-13 shows that by 1990, RG&E experiences elecbic revenue growth of lI.8 percent yearly. This compares to ll.2 percent (Table VIII-1f ) should Nine Mile Point II cost $4.9 billion. Growth in c per Kwh cost is 10.4 percent under the breaþeven option versus 9.8 percent under Plan A (Table VIII-I f). AIso, capitalization grows at 5.1 percent yearly through 1990 under the break-even option versus 4.1 percent if Nine Mile Point II costs $4.9 billion. A summary of RG&E's financial projection indicates that capitalization should grow at reason- able levels through the l980's under both Plans A and B. Increases in eleetricity prices should be just below l0 percent during the 1980's while electric revenues grow at about ll percent yearly. These projections and the interest coverages shown indicate that both Flans A and B can be financed at reasonable terms by RG&E.

*Correct figures for 1987 are not available.

VItr-14 Exhibit__(JDS-12) Page 57 of 90

5. Long Island Lighting ComPanY LILCO's financiJ analysis is dominated in the 1980's by the continued construction and projected completion of the Shoreham nuclear unit (1983). LILCO requires CWIP in rate base urrúl Shor"ham is completed. After Shoreham's completion, cash flow is improved dramatically. Table VIII-I4 shows historical and financial statistics for Plans A and B.

Table VtrI-I4

Long Island Lighting Historical and Projected Data $(ooo)

Plan A Plan B q Electric c Per Electric Per Revenues Kwh Capitalization Revenues Kwh Capitalization

I98T $1,371,000 11.04e $4,I58,000 $1,371,000 tl.Me $4,138,000 1987 2,453,000 18.00 5,I78,ooo 2,374,000 t7.43 4,668,000 1990 2,670,000 L8.77 5,655,000 2,927,000 20.57 5,343,000

Annual Growth Rates

197ó-1980 ts.2% 12.3% t4.B% I 5.X/o 12.3% 14.V/o 19Br-1987 r0.2 8.5 d.¿ÐF' 9.6 7.9 2.0 ,7, 2.9 1981-1990 f"f 6.r 3.5 B.B

This analysis shows that LILCO's electric revenues and energy costs are projected to increase during the l9g0's at levels below those experienced during L976 to 1980. Plan A shows a higher cost per Kwh than plan B by l9BZ. By 1990, however, Plan B has a higher cost. Plan B requires less capital during the 1980's. Under Plan B, however, LILCO is required to finanee a portion of LEGS II after r990.

{

Yru.T5 Exhibit__(JDS-12) Page 58 of 90

Table Vm-15 shows LILCO's projected financingrs and financial statistics including interest coverages through the 1980's. This projection indicates that once Shoreham is completed, LILCO's amount of financing is reduced and interest coverages improve. Also, the amount of AFDC in earnings declines rapidly"

Table Vm-f 5

IILCO llistorical and Projected Financings and hojected Financial Parameters Plan A r978-r990 $(millions)

Interest Coverage Retained External Total Mortgage AFDC Earnings Financing Financings SEC Indenture Ratio

1978 $32 $ 362 $ 394 L979 35 4t4 449 1980 45 334 379

198r $ 63 $ 5ll $ 574 z"5x 2.3x 70% 1982 80 6L4 694 2"6 2"3 73 1983 M 25 r09 3"1 3"6 31 t98ø, 8l 51 132 to 3.5 l6 1985 BI (20) 6l 3"s 4"2 23 r986 B3 195 278 3.3 3.6 34 1987 M 354 438 3.3 3.4 23 1988 87 l15 202 3"1 3.3 crn 1989 B9 24 rl3 3.1 3.3 30 rg90 ot r45 237 3I 3.I 3q 198r-1990 $eZ+ $2,014 $2,838

VII].I6 Exhibit__(JDS-12) Page 59 of 90

LICO's projected elecûic revenues, c per Kwh, and capitalizalion assuming Staff's break-even cost for Nine Mile Point II is as shown in Table VtrI-16.

TABTE VM.I6

tItCO hojected Financial Data Plan A Break-even Option $ (ooo)

Electric + Per Revenues Kwh Capitalization

r98l $1,371,000 I1.04q $4,180,210 t987 2,520,690 18.50 5,372,950 1990 2,695,390 r8.94 5,790,390

Annual Growth Rates r976-1980 t5.2% L23% t4.B% 198r-r987 10.7 9.0 4.3 t4 1981-r990 7.8 6.2 d.¡

This indicates that revenues, c per Kwh growth rates, and capitalization will increase from the levels shown in Table VItr-I4 for Plan A. To summarize, once LILCO's Shoreham nuclear unit is completed, the company's cash flow will improve and Nine Mile Point II could be financed with reasonable increases in eleetric revenues and capitalization. One factor that could alter this frnding is the Northport coal conversions. At this time, however, the status of the Northport conversions is in doubt.

VIII.IT Exhibit__(JDS-12) Page 60 of 90

C. Financial Implications - Ptans A through F This seetion comp¡res the incremental construction requirements (including AFDC) for Plans A through F. The discussion outlines total construction requirements for each option. Plans A through D provide 2?35 MW of capacity during the period. Plans E and F contain a scaled down construction program containing 1085 MW of new capacity by 1994. The total incremental construction additions for Plans A through F are listed in Table Yltr-l7.

TABTE VM"17

Incremental Construction Requirements $ (Millions)

A B C D E F

1981 372 $ 373 $o $ 369 $2 $ $+ q t982 489 4 490 L4 486 r983 ilr t8 551 31 s36 2 t984 616 40 630 L69 s96 6 r9B5 677 301 82r 400 63s 6 1986 997 499 r,105 765 668 20 1987 L,r57 880 1,310 L,22r 611 45 r98B 879 1,482 l,l5l L,620 244 r9B9 1,412 1,665 1,220 1,572 365 r990 l,3gl 1,815 1,091 1,157 6s6 r99r 1,027 970 343 945 901 t992 730 t96 623 1,226 r993 lBl L25 l,0Bg r994 347

Total $9,548 $8,589 $g,2gl $8,648 $3,901 $4,911

% change /1 1 0/_\ lQol\ I-l Ãol\ Roca /9\ ,601 from A/E Base (l) \L L/a I \v /u I \Lv/u , ssvv \ar,

The construction costs shown in Table VtrI-l? indieate that reductions in the level of construction found under Plan A can result if Plans B through D are employed. These reductions are 11 percent under Plan B, 3 percent under Plan C, and 10 percent under Plan D. Furthermore, Plans B and D defer major corstruction until 1-984, It should be noted, however, that the issue of sunk cost financing should be considered when evaluating the financial requirements among the various plans. As noted in the sunk cost section of this report (Chapter V) the Co-Tenants could suffer cancellation charges as high as $3?3 million if Nine Mile Point II were terminated. Also, AFDC would most likely be accrued on the existing Nine Nlile Point II balance until the Commission determined the disposition of the sunk costs. This indicates that the 1l percent savings from building Plan B versus Plan A (Table VtrI-l?), or Plan D versus Plan C, would be much lower. In fact, Plans A and B are approximately equal in total financing requirements.

VtrI.IB Exhibit__(JDS-12) Page 61 of 90

Table Vm-f ? also outlines construction requirements for Plans E and F. Plan E assumes Nine Mile Point II is completed and that no other construction projects are undertaken. Plan F assumes Nine Mile Point II ii cancelled and that Jamesport I and LEGS I are completed in the 1990's. If either of these plans are undertaken, the total amount of financing throughout the period is reduced, compared to Plans A through D. If Plans E and F are compared, F can be termed a con- stn¡ction deferral scenario since large amounts of capital are not expended until 1988.

D. Investment Standing of New York's Utilities The financial analysis indicated the types of financial pressure that may arise during the Nine Mile Point II construction period. The discussion contained here assumes the project is completed and attempts to judge how its completion would affect the investment standing of the Co'Tenants. If Nine Mile Point II were completed, benefits would develop over the life of the unit in that electuicity prices would be reduced since less oil fired generation electricity would be eonsumed. This would increase the Co-Tenants investrnent standing since each member would have a more diversified fuel mix and a cheaper, more marketable product. Offsetting this, however, are some negatives. Assuming Nine Mile Point II costs $4.9 billion, or even $3.7 billion, this plant would represent a major portion of some Co-Tenants' assets. This means that in terms of asset concen- tration, some io-Tenants have less diversification then previousþ because large percentages of their assets are tied up in one singfe asset. Another fact to consider is that Nine Mile Point II will be the third nuclear facility contained at the present site, the others being Nine Mile Point I and the. New York State Power Authority's Fitzpatrick facility. Should any one of these three units have an accident, not l, but 3 units could be lost. Investment analysts recognize this fact and may consider it when determining the investment gra'le of electric utility securities in New York State. Earlier in this report (Chapter V) the issue of sunk costs associated with cancellation of Nine Mile Point II was discussed. If the project is cancelled, the investment standing of the Co'Tenants could be affected during Commission abandonment proceedings since the Nine Mile Point II invest- ment represents a large investment for each company. Table VIII-I8 shows the percentages of each Co-Tenants' equity capitalization compared to Nine Mile Point II sunk costs.

TABTE VIII.IS

Co-Tenants'Common Equity Vs. Sunk Costs

r980 Estimated Year-End Sunk Common Equify Cost $(000) $(0oo) Percentage

Central Hudson $ 173,375 fiL27,564 74% LILCO 1,325,213 255,r29 I9 Niagara Mohawk 1,298,001 1BL,T27 45 NYSE&G 642,217 255,129 40 RG&E 375,316 198,435 53

YtrI.19 Exhibit__(JDS-12) Page 62 of 90

This indicates that the disposition of possible Nine Mile Point II sunk costs are a major factor for the ec{uity investors of each Co-Tenant.

vm-20 Exhibit__(JDS-12) Page 63 of 90

CHAPTER IX

ASSESSMENT AND RECOMMENÐATIONS

This report examined the economic and financial implications of Nine Mile Point II. We have presented an analysis of alternatives to determine if Nine Mile Point tr should be cancelled and replaced by * alternate coal-fired capacity. Our principal finding is that Nine Mile Point II should be constructed. This finding is supported by three facts uncovered in this report:

1) The construction plans including Nine Mile Point II are the least costly in economic terms assuming sunk cost recovery.

2> On a financial basis, there are no significant long-term differences among the generating plans that provide equal megawatts of capacity.

3) If Nine Mile Point II were cancelled, the Commission would have to determine who should absorb approximately $2.0 billion in sunk costs. Even if the sunk costs were charged to the Co-Tenants' customers, t-he investment stafus of New York's utilities would most likely be negatively altered until the sunk cost disposition is determined. If $2.0 billion in sunk costs were charged to the Co-Tenants' shareholders, a negative reaction by investors would most likely occur.

The three findings supporting our conclusion were influenced by the sunk cost controversy. On an economic basis, Plans B and D, the plans excluding Nine Mile Point II, are less costly if sunk costs are ignored. They become more expensive than Plans A and C, respectively, if sunk costs are considered. Plan E, which includes Nine Mile Point II, is less costly than Plan F in most cases even when excluding sunk cost consideration. We do not believe, however, that it is prudent to ignore the sunk eost effects of this transaction. The choice is to have the customers pay the sunk costs, a situation which makes Nine Mile Point II economic in all cases, or, have the utilities absorb the zunk costs and face possible financial problems. The economic and financial analyses indicates cost and operational benefits in completing Nine Mile Point II in a timely and least costly manner. We caution, however, that if the project is continued, it is imperative that the Co-Tenants' senior management emphasize project cost control and meet the schedule for an 1986 commercial operating date.

IX.I Exhibit__(JDS-12) Page 64 of 90

APPENDIX A

Capital Costs

A. Direct Cost of Nine Mile Point Unit II Table A-l presents the year-by-year cash flows required to complete Nine Mile Point II for in-service dates of 1986, I9B? and lgBB based on Niagara Mohawk's escalation rates. The escalation rates rates used by Niagara Mohawk to develop Table A-1 are shown in Table A'2. The escalation of Table A-2 were used to de-escalate the Table A-I values to constant 1980 dollars. The results are shown in Table A-3. The constant dollar values in Table A-3 were then converted into percentages and tabulated in Table A-4. Table A-5 presents the escalation rates that were used in this report for capital costs. The cash flows in current dollars were calculated on the basis of the Theodore Barry and Associates and report, page VtrI-l, which gives Nine Mile Point II sunk costs through f980 at $810 million, tolal project costs (withoutlscalation) of g2,161 million and $2,253 million for in-service dates of date f 9g6 anã lgg7 respectively. A total cost without escalation of $2,345 million for an in-service of lggg was then extrapolated. The difference between the total cost and sunk cost was spread out over the remaining construction years on the basis of Table A-4. The results of this calculation are shown on Table A-6.

Table A-l

Nia gara Mohawk t Jtîi#i":"ËJ"l"r* In - s ervice Dates (1) $ millions (2) current dollars* (3) without AFDC

In-Service Date

11/86 ILIBT r1/88

Through 1980 $ 810 $ sro $ ero l98r 262 236 209 L982 330 294 253 332 289 255 r9B3 .tu.t 1984 ,no 287 444 r9B5 237 262 275 1986 r50 240 249 L987 145 243 r988 r61 Total $2,400 $2'563 fiz,727

Source: Theodore Barry & Associates,Management und Technical Reoiew of the Construction and Feasibility of Nine Mile Point II, Draft No. 2, February 20, 1981, Exhibit VIII-T

*That is, "nominal" or "as-spent" dollars. A-l Exhibit__(JDS-12) Page 65 of 90

Table A-2 Nine Mile Point tr Escalation Rates used by Niagara Mohawk

Year Rate

t9B0 t0"2%

l98l 8.8

1982 7.9

1983 7"3

1984 7.8

1985 8.0

r986 8.0

1987 8.0

1988 8.0 source; 1980-1986 Theodore B*ry & Associates, Ndne Mile point II Nuclear Station Unit Two, Volume I: Reaiew of project Cost Estimate and Construction Plnns, June I|BI, Tabte III-S

I9B7 and l9B8 Niagara Mohawk Escalation Rates obtained from Niagara Mohawk

A-2 Exhibit__(JDS-12) Page 66 of 90

Table A-3 Nine Mile Point tr Niagara Mohawk Cash Flows for Alternative In'Service Dates (I) $ millions (2) constant l9B0 dollars (3) without AFDC

In-Service Date

rr/86 tLl87 rr/88

198I $ e¿r $ zrz $ rqz

r982 28L 250 2L6

r983 264 tro 202

1984 20s 2TL 200

r985 162 L79 188

1986 9s r52 L57

L987 85 L42

r988 87

Total $1,248 $1,323 $1,384

Source: Derived from Tables A-1 and A'2

A-3 Exhibit__(JDS-12) Page 67 of 90

Table A-4 Nine Mile Point tr Relative Cash Fïow for Remainder of Project (l) based on constant l9B0 dollars (2) without AFDC

In-Service Date

1r/86 LLI87 rr/88

r98r L9"3L% L6"40% 13.87%

t982 22.52 r8.90 r5.6r

r983 21.I5 17.3r 14.60

1984 L6.43 15"95 t4.45

r985 12.98 13.53 13.58

r986 7 "6r LL"49 1r.34

r987 6.42 r0.26

1988 6.29

Total r00.00% rcO.00% L00.00%

Source: Derived from Table A-3

Table A-5 Nine Mile Point tr DPS Staff Escalation Rates

Escalation Period Rate

r980-r98s T0.5%

r986-1990 9.5

r991-2000 9"0

^-4 Exhibit__(JDS-12) Page 68 of 90

Table A-6 Nine Mile Point tr Cash Flows for Alternative In'Service Dates (1) $ millions (2) current dollars using DPS escalation (3) without AFDC

In-Service Date

rr/86 LLIBT rr/88

Through l9B0 $ gro $ ero $ eto

r98r 2BB 262 235

L982 371 333 293

r983 386 337 302

r9B4 331 343 33r

1985 289 322 343

r986 r85 299 3L4

r98? 183 311

1988 209

Total $2,660 $2,889 $3,148

Cost per kilowatt fiZ,45211

Sources (I) Sunk cost of $810 million and totals without escalation of $2,16t million (1986) and $2,253 million (1987) from Theodore Barry 8i Associates, Vol. I Reaiew of Proiect Cost Estimate and ConstructionPlnns, Draft, April10, 1981, Exhibit II-2

(2) Total without escalation of $2,345 million for l98B in-service date was extrapolated from 1986 and 1987 totals.

(3) Tables A-4 and A'5

A-5 Exhibit__(JDS-12) Page 69 of 90

B. Direct Cost of Coal Units Jamesport. The capital costs for Jamesport wereìbased on the lg8l reportsubmittedbythe Power Pool to the State Energy Office pursuant to Section 5-LL2 of the Energy Law. Table A-Z presents the annual capital expenditures in terms of constant 1980 dollars and also as a percentage of the total capital cost. The cash flows extend over ll years. The cumulative cash flows in percent are plotted on Figure A-l along with a standardized curve for coal plants from U.S. Department of Energy Report DOE/NE-0009 Power Ptnnt Capital Inuestm,ent Cost Estimates: Cunent Trend.s and Sensitiuity to Econom.ic Parameters, October lg7g, published June 1980. It is seen from Figure A-l that spending for the first three or four years is relatively small. With Table A-7 as a basis, the cash flows in constant t9B0 dollars were developed for the various Jamesport alternatives of in-service date and rating. These results are shown on Table A-8. To convert from 800 MW to 625 MW it was assumed, based on an Ebasco study, that the capital cost of a 625 MW stand-alone unit is 85% of the cost of an 800 MW stand-alone unit. This corres- ponds to a scaling factor exponent of 0.658 as displayed in the following equation: 0'658 (cost of Boo MW) = [eoo-IAUI (Cost of 625 rlIW) L62S NIWJ

The annual capital expenditures in Table A-B were then esealated according to Table A-5. These current dolla¡ amounts appear in Table A-9 for the five versions of Jamesport that were included in the various options.

Lalre Erie Generation Stution" The costs for the various alternatives involving the Lake Erie Generating Station Units Nos" I and 2 (IEGS I and LEGS 2) were developed on the basis of the cost estimates for the Somerset power plant because these include scrubbers and are the most recent available. Cash flows for the basic 625 MW and 850 MW versions of the Somerset plant are listed in Table A'I0. The Somerset values were de-escalated by the rates shown in the footnote to Table A-10 yielding the constant 1980 dollar cash flows listed in Table A-lr. fu a matter of interest, the economy of scale exponent was determined. The determination was based on the following: * $e31,6e4 ffi =16æJl!Þql from which, N = 0.808

This value, while somewhat high, is within the range of credibility. For example, data in the DOE report previously cited yield N = 0.753 and. 0"772 for the New York and United States average respectively (based on 795 MW and 1232 MW coal power plants and 1980 operation). The constant I9B0 dollar cash flows of Table A-11 were converted into relative amounts shown in Table A-12. The percentages in Table A-12 are plotted on Figure A-2. It was possible to draw "S" curves through the plotted values, as shown on Figure A-2. The Somerset "S" curves lie much closer to the DOE typical "S" curve than the Jamesport '.S" curve.

4.6 Exhibit__(JDS-12) Page 70 of 90

For estimating the relative cash flows required for the LEGS plants, the percentages for the Somerset 625 MW unit were used directly. For the 850 MW units, the smoothed "S" curve shown as dashed in Figure 4.2 was used. The percentages are listed in Table A-13. The LEGS.I alternatives were all assumed to have $fS.S million expended through 1980 as stated in the 1981 Long Range Generation and Transmíssion Plnns. Because Somerset is a stand-alone unit whereas LEGS-I is the first of two on the site, the total costs in Table A-ll were multiplied by correction factors. The correction factors were 1.0438 and f .0556 f.or 625 MW and 850 MW respectively. These factors were obtained from an Ebasco study. The sunk cost was subtacted from the corrected total cost yielding the remaining LEGS'I expenditures. These were alloted according to the percentages in Table A-13 The results are tabu- lated in Table A-f4. For the 460 MW unit, a 625 MW cost was calculated which was then decreased by a factor of 4601625. The unit, therefore, has the capital cost characteristics of a 625IVIIV unit. The annual capital expenditures for LEGS-I in Table A-14 were converted to current dollars using the Table A-5 escalation rates; the results are tabulated in Table A-f 5. For the LEGS-2 alternatives, the Somerset values were adjusted by factors of 0.7938 and 0.8056 for 625 MW and 850 MW units respectiveþ. These factors, from Ebasco curves' represent the ratio of the cost of a second unit at a site to the cost of a single unit per site. The resulting total cost was then dishibuted according to the percentages in Table A-13. The annual capital expenditures for LEGS-2, tabulated in Table A-16, were t-hen escalated-the results are tabulated in Table A-f7.

COAL-I and COAL-2 Units. The COAL-I and COAL-2 units were assumed to have thesame capital cost characteristics as that of LEGS-l and LEGS-2. The cash flows for COAL-I and COAL'2 are tabulated on Tables A-18 and A'f 9.

Comparßon For each altemative plant, the total dollars expended were divided by the rating in kilowatts. The results are plotted on Figure A-3. The U. S. Department of Energy Report DOE/NE-0009 contains capital investment costs for generic nuclear and eoal-fired units going into operation in f990. The estimated cost for a I0B5 MW nuclear unit is $1?80/kW. For comparison, extrapolating the Nine Mile Point II curve on Figure A-3 results in an approximate cost of $3400/kIV for 1990. The Department of Energy estimates for capital costs of 625 MW to 850 MW coal-fired power plants going into operation in 1990 are between $f 380 and $1550/kW. These are far below the $2000 to $2600/kW estimates for 1990 from Figure A-3; The difference might be attributed partly to higher construction costs in New York and partty to misplaced optimism by DOE.

^.7 Exhibit__(JDS-12) Page 71 of 90

Table A-7 Annual Capital Expenditures for Jamesport (1) 800 MW,In-Service Nov. l99l (2) constant l9B0 dollars (3) without AFDC

Percent $ million of total

Through f980

198r I 0.rr%

L982 I 0.lr

r983 t 0.22

r984 l1 t.2L

l98s ,, 2.42

r986 L2T I3.30

1987 r57 17.25

r988 l8l r9"89

r989 177 19"45

1990 t48 16"26

r.99r B9 9.78

L992 - Total $sro t00.00%

Source: New York Power Pool, 19BI Long Range Generatíon and Transm¿ss¿on Plnn, Aprrl l, 1981, p. 43.

A.B Exhibit__(JDS-12) Page 72 of 90

Table A-8 Annual Capital Expenditures for Jamesport Alternates (1) $ millions (2) constant 1980 dollars (3) without AFDC

In-Service D atelRatine

Nov. 1991 Nov. 1990 Nov. 1990 Nov. 1989 Nov. 1993 BOO MW BOO MW 62s MW 625 MW 625 Ntw

Through 1980

I981 I 2 , 4

L982 t ç, , 9

q 1983 t1 9 r9 , 1984 II 9' r9 r03

r985 oo t2L r03 r33 2

r986 l2r 157 133 154 I

I9B7 r57 lBl 154 r50 r9

1988 181 L77 r50 L26 103

r989 177 r48 L26 76 133

r990 14B B9 76 t54

r99r 89 150 r992 L26

1993 76

1994

r995

Total $9ro $910 fi774 #774 #zzq

Sources: (I) Derived from Table A'7

(2) (Capital Cost for 625 NIw) = 0'850 (Capital cost for 800 Mw)'

A-9 Exhibit__(JDS-12) Page 73 of 90

Table A-9 Annual Capital Expenditures for Jamesport Alternatives (1) $ millions (2) current dollars (3) without AFDC

In-Service Date/Rating

Nov. l99l Nov. 1990 Nov. 1990 Nov" 1989 Nov. 1993 800 Nrw 800 Mw 625 MW 625 MW 62s MW

Through r980

r981 I 2 , 4 l9B2 I , I ll

r983 3 t5 t2 26

1984 r6 33 28 154 3

r985 36 199 r70 2r9 3

1986 218 283 240 278 I6

T987 3r0 358 304 296 38

1988 392 383 324 273 r)rQ

r989 4t9 35r 298 r80 315

r990 384 23t 197 399

r991 252 424

L992 UUUQOO

r993 255 r994

Total $2,032 $t,BSz fir,577 $1,441 #2,064 Cost per kilowatt $2,540/kw $2,32l/kw $2,523/kw $2,306/kw $3,302/kw

Source; Table A-5 and A-B

A-10 Exhibit__(JDS-12) Page 74 of 90

Table A-10 Cash Flow From Somerset Study (l) $ Thousands (2\ current dollars* (3) without AFDC

Rating

625 MW 850 l,/TW In-Service Date In-Service Date

October 1984 October 1985

Total prior to Jan. 19Bt 92,964 66,264

r98r 16r,300 57,900

1982 294,700 190,700

I983 235,700 425,700

T984 82,500 293,000

r985 151,400

r98ó

Total 857,L64 1,L84p64

Cost per kilowatt $1,37tikw $1,394/kw

#Escalation rates: f 9B0 10.5%

l98r 9%

1982 and after,S%

Source: Somerset Study, New York State Electric & Gas Corporation, Generation Planning Department, October 2, 1980.

A.TI Exhibit__(JDS-12) Page 75 of 90

Table A-lI

Cash Fïow From Somerset Study

(l) $ thousands

(2) constant l9B0 dollars

(3) without AFDC

In-Service Date/Rating

October 1984 October 1985 625 MW 850 MW

Through 1980" 82,964 66,264

l98r l47,gg2 53,119

L982 250,340 t6l,gg5

r983 185,390 334,934

t984 60,084 213,387

r985 102,095

1986

TOTAL 726,760 931,694

Cost per Kilowatt $l,163lkw $1,096/kw

*Mixed dollars

Source: Derived from Table .{"f 0.

A-12 Exhibit__(JDS-12) Page 76 of 90

Table A-12

Relative Cash Flows From Somerset Study

(1) based on constant I9B0 dollars

(2) without AFDC

In-Service Date/Rating

October 1984 October l9B5 625 MW B5O MW

Through 1980 tr.42% 7.TT%

l98r 20.36 5.70

L982 34.45 17.39

r983 25.5r 3s.94

t98/. 8.27 22.90

1985 r0.96

r986

TOTAL rc0.0% r00.0%

Source: Derived from Table A-l I

A-13 Exhibit__(JDS-12) Page 77 of 90

Table A-13

Relative Cash Flows for 625 MW and 850 Mly Upstate Units

(l) based on constant 1980 dollars

(2) without AFDC

Years 625 MW B5O MW

I Lr.42% s%

, 20.36 I

3 34.45 t7

4 25.5r 33

b 8.27 25

6 1l

TOTAL rc0.00% r00%

Source: Table A-12 and Figure A-2

A.14 Exhibit__(JDS-12) Page 78 of 90

Table A-14

Annual Capital Expenditures for LEGS-I Alternatives

(l) $ millions

(2) constant l9B0 dollars

(3) without AFDC

In-Service Date/Rating Oct. 1991 Oct. 1990 Oct. 1990 Oct. 1989 Oct. L994 B5O MW 850 MW 625 MW 625 MW 460 MW'T

Through l9B0 rB"8 r8.8 18.8 18.8 r8.8

r98l L9B2 r983 1984 r9B5 48.2 84.5 r986 48.2 B6.B 84.5 150.6 L987 86.B 164.0 r50.6 2s4.9 r9B8 164.0 3r8.4 254.9 188.7 r989 3r8.4 24t.2 r88.7 6r.2 r990 24t.2 106.1 6t.2 6r.6 r99r 106.r 109.8 t992 185.9 r993 r37.6 L994 44.6 r995

TOTAL 983.s 983.5 758"7 758.7 558.3

*Characteristics of a625 MW Unit

Source: (I) Derived from Tables A-lI and A-13

(2) Sunk Cost from New York Power Pool, l9BI Long Range Generation and Trans- mission Plan, Apnl l, l98l, pg. 43.

(3) (Capital Cost lst 625 MW) = 1.0438 (Cost Single 625 MW)

(Capital Cost Ist 850 MW) = 1.0556 (Cost Single 850 MW)

A.I5 Exhibit__(JDS-12) Page 79 of 90

Table A-15

Annual Capital Expenditures for LEGS-I Alternatives

(l) $ millions

(2) current dollars

(3) without AFDC

, I¡n-Service Date/Rating Oct. l99l Oct. 1990 Oct. 1990 Oct" 1989 Oct. 1994 850 MW 850 MW ó25 MW 625 MW 460 MWiF

Through l9B0 l8.B rB.8 18.8 rB.8 18.8 r9Bl r982 1983 1984 1985 79 r39 r986 87 t57 L52 Ðn, r98? L7l 324 297 504 t9B8 355 689 551 408 1989 7tu 571 447 145 1990 626 275 159 160 199r 300 310 r992 D/ö r993 462 1994 r63 r99s

Total Ðzró Lz þz,L LC Ðt,ozÐ $1,487 öI,Oö',1

Cost per kilowatt fi2,7201kw ff2,4871kw $2,600/kw $2,379/kw $3,66?lkw

#Characteristics of a 625 MW unit.

Source: Tables A-5 and A-14.

A-16 Exhibit__(JDS-12) Page 80 of 90

Table A-16

Annual Capital Expenditures for IEGS"2 A,lternatives

(1) $ million

(2) constant l9B0 dollars .

(3) without AFDC

In-Service D atelRating

B5O MW 400 Mwte 625 MW r9B5 r9B6 65.9

L987 37.5 t17.5

I9BB 67.6 42.4 r98.7 r989 r27.6 t J.4 L47.2 r990 247.7 L27.2 c(.1

1991 t87.ó 94.2

L992 82"6 30.5 r993

TOTAL $750.6 $369.3 $s77.0

*Characteristics of 625 MW Unit

Sources.' (1) Derived from Tables A-ll and A-13

(2> (Capital Cost 2nd 625 MW) = 0.7938 (Cost Single 625 NIW)

(Capital Cost 2nd 850 MW) = 0.8056 (Cost Single 850 NIW)

A-17 Exhibit__(JDS-12) Page 81 of 90

Table A-17

Annual Capital Expenditures for IEGS-2 Alternatives

(l) $ million

(2) current dollars

(3) without AFDC

In-Service Date/Rating Oct. 1992 Oct. 1992 Oct. 1990 8s0 Mw 400 Mw.,Ê 625 NrW l9B5 r986 r19

1987 74 232 r9B8 L46 91 430

1989 302 I78 349 r990 642 330 L24 t99r 530 266

1992 255 94 r993

Total $1,949 $ 9s9 $1,254

Cost per kilowatt $2,293/kw $2,398/kw $2,006/kw

*Chracteristics of a 625 ñlW unit.

Source: Tables A-5 and A-f 6.

A.r8 Exhibit__(JDS-12) Page 82 of 90

Table A-lB

Annual Capital Expenditures for COAL- I/COAL-2 Alternatives

(l) $ million

(2) constant 1980 dollars

(3) without AFDC

Unit/In-Service D atelRating COAL I COAL I COAL 2 Oct. 1993 Oct. 1992 Oct. 1993 235 MW'É 625 MW 235rÊ'{Ê, t987

1988 13.6 86.6

I9B9 24.5 LA.4 24.8

1990 46.2 26L.3 44.2 r99r 89.7 193.5 74.7

L992 68.0 62.7 Ðb.ó r993 29.9 L7.9 r994

TOTAL $271.9 $7s8.5 $2r6.9

*Characteristics of an 850 NIIV Unit.

**Characteristics of a 625 MW Unit.

Sources.' (l) Derived from Tables A-l I and A-13

(2) (Capital Cost lst 625 NIW) = 1.0438 (Cost Single 625 MW) (Capital Cost 2nd 625 NIW) = 0.7938 (Cost Single 625 NtW) (Capital Cost lst 850 MW) = 1.0556 (Cost Single 850 MW)

A.I9 Exhibit__(JDS-12) Page 83 of 90

Table A-19

Annual Capital Expenditures for COAL-UCOAI-2 Alte"natives

(l) $ miìlion

(2) current dollars

(3) without AFDC

Unit/In-Service D CO I , Oct. 1993 Oct. 1992 Oct. 1993 235 MW" 625 MW 235åÉrç r987 r988 to t8? r989 58 366 59 r990 r20 678 115 r99r zil 547 2tl

1992 2r0 r93 170

1993 100 60

1994

IUI.ÉtL Ð I lr Ðrry I I $ 6rs

Cost per kilowatt $3,281/kw $3,l54lkw fi2,6L7lkw

*Characteristics of an 850 ùIW unit.

**Characteristics of a 625 MW unit.

Source: Tables A-5 and A-18.

A-20 Exhibit__(JDS-12) Page 84 of 90

FIGURE A-I

CUTVIULATIVE CASH FLOW VS DES¡GN AND CONSTRUCTION PERIOD FOR JAMESPORT

t00 3 ,/ 90 ¡- o I- ooer{e-ï'þ ¡¡. / / o 80 7 t- z l¡J / / U 70 / Ê, l¡¡ { g / / 60 o =J l¡. / 50 Ø (_ / - JAME. ;PORT U / / l¡¡ 40 Þ J / 3 30 / / f U / / / t0 / ,/ râ ,Jò- 0 -/ 010203040506070 80 90 100

DESIGN AND CONSTRUCTION PERIOD (PERCENT)

A-21 Exhibit__(JDS-12) Page 85 of 90

F¡GURE A-2

CUMULATIVË CASH FLOW VS ÞËsIGN AND CONSTRUCT¡ON PER¡OD FOR sOMËRSET

t00 J I ¿ ÞoE/NE. 0009 PowER PLANT ,/' t- 90 (tt o , I t- ESTIMATES: CURRENl TRENDS ) ¡¡ / I 80 ,/, t o MIC PARAMETERS.. þ / z OCTOBER I979.PUBL¡SHEE I l¡¡ JUNE TgEO U.S. EIEPI. OF U 70 Ê ENERGY. gt¡ / 60 f / J=o I I b / t I 50 / UI I 625 Mr¡V I U i / 2 l¡¡ 40 / f "850 Ml,l¡ F I / Å /, I 5 30 ,r/ / a / / / ¿ / 20 / a/ @ t0 I a / rõ , - - 0 0 to 20 30 40 50 60 70 80 90 fCIo

DESTGN ANÞ CONSTRUCTTON pERtOÞ (pEReËNT)

Å -to Exhibit__(JDS-12) Page 86 of 90 FIGURE A-3

DIRECT EXPENDEÐ DOLLARS PER KILOWATT VS IN SERVICE DATE (rl DPS ESCALATION RATES l2l WTTHOUT AFDC 4000

,/

cr) t-- ôt t- 4,

=o J ,9 V 3000 UT É. t rt J .^

a \ t^- K LEGS-2l8 ;O ñ¿Wl 4F'ñ$ ¿- l\r-

2000 I 986 r 987 I 988 I 989 I 990 r 99t 1992 I 993 I 994

CALENDAR YEAR Exhibit__(JDS-12) Page 87 of 90

APPENDIX B TABTE B.I

STAFF'g FORECAST OF FUEL COST ESCATATION RATES AND BASE FUEL COSTS

Base Fuel Costs $/ 106 Btu Escalation Rates 1981 Dollars

1990-2000 A. oil % Sulfw U D l98r-85 1985-90

#6 .3 6.50 n.s% 9.5 9.0

tt tt )) ¡ 6.20 6.10

tt r.0 6.00 s.90 t)

tt tt tt 2"0 5.30 5.20

tt tt 2.8 5.00 4.90

Distillate

#, ?.00 7.10 L0.5% 9.5 9.0

B. Coal

r.0 2.10 2.50 T0.5% (.J 7.0

)) ,) r.4 r.50 2.00 ))

C. Nuclear

.4L .4r L0.5% 8.5 8.0

B-l Exhibit__(JDS-12) Page 88 of 90

Page I of 2 APPENDIX B TABTE 8.2 I. Oir

.3% S OtI "7% S Otl Year Heat Content 6.19 x 106 BTU/BBL. Heat Content 6.20 x 106 BTU/BBL. Escalation/Yr. (f) Escalation/Yr. (l)

r980 14.6% 14"4% 1985 9.6 9"6 r990 9.r 9"r 1995 9.1 9"r 2000

L.0% s oit 2.0% s où Year Heat Content6.2Zx 106 BTU/BBL. Heat Content6.25x 106 BtU/BBL. Escalation/Yr. (1) Escalation/Yr. (f )

1980 16% rB.3% r985 9.6 9.8 r990 9"1 9.2 r995 9"L 9"2 2000

2"8% S Oit No. 2 Oil Year Heat Content 6 28 x to6 BTU/BBL. 5.83 x 106 iBBL. Escalation/Yr. (f) Escalation/Yr. (f)

r980 19"2% 12.7% 1985 9.8 9"5 r990 9.3 on 1995 ot 9"0 2000

II. Eastern Coal

.3% S Coal L"4% S CoaI Year Escalalion/Yr. (1) Escalation/Yr. (l)

l9B0 18"6% 20.9% 198s 8.6 8.7 r990 8.1 7"8 QA 1995 I .at 2000

(l) Average escalation for the following S years. B-2 Exhibit__(JDS-12) Page 89 of 90

Page 2 of.2

APPENDIX B TABLE 8.2

IL Eastern Coal (continued)

2"0% S Coal 2.0% S CoaI Year Escalation/Yr. (1) Escalation/Yr. (l)

t9B0 2t.3% 20.2% l9B5 8.9 r0.I r990 7"4 (.5 t995 (.Ð 7.1 2000

il. Western Coal

.5% S CoaI Year Escalation/Yr" (l)

1980 7.4% r985 7.r r990 L995 2000

ry. Nuclear

Year Escalation/Yr. (1)

r980 8"s% 1985 t.Ð r990 7.0 r99s 7.0 2000

(I) Average escalation for the following S years.

B-3 Exhibit__(JDS-12) Page 90 of 90

APPENDIX B TABLE B-3 ..NMPC ÉÊ2 ANALYSTS''

FUEL COST COMPA,RISO¡5(I) gglryEEN NYPP'S

MODIFIED ICF VÀLUE5(2) *¿ PSC'g ESTIMATES (MrD YEAR $/M-BTU)

OIL PRICES COAL PRICES

19Bs 1990 2000 1985 1990 2000 (.3%s) (L.o%s) NYPP NYPP U N/A N/A N/A U 3.4s 5.21 11.35 D 9.78 rs.47 36.97 3"73 s.64 L2.28 PSC PSC U N/A N/A NiA U 3"25 4.65 9.1s D 10.14 t5.92 27.7L D 3.86 5.54 r0.89 (> 7.4%S> NYPP NYPP u 9.68 rs.3l 36"s8 U 3"r3 4.74 9.9L D 9.33 L4.76 35.26 D 3"64 5.s3 11.55 PSC PSC u 9.67 15.19 3s.97 U 2"32 3.32 6"53 D 9.s2 r4.9s 35.39 D 3.09 4.43 8.71 (1.0%s) (2"0%s> NYPP NYPP U g.43 t4"9L 3s.ó3 U 2.89 4"42 9.03 D 9.07 14.35 34.28 D 3"4r 5"23 r0.68 PSC PSC U 9.36 14"70 34.8r U N/A N/A N/A D 9.20 L4.46 34.15 D N/A N/A N/A (2.V/oS) (>2"v/"5) NYPP NYPP U 8.76 I3.98 33.70 U 2"56 4.L4 B.s3 D 8.34 13"3r 32"r0 D 3"06 4"9s 10.21 PSC PSC U 8.27 12"99 30"74 U N/A NiE N/n D 8.1I 12.74 30.16 D N/A NiA NiA (2.8%s) DIS'I LLAI'E 1985 1990 2000 NYPP NYPP U 8.33 13.29 32.33 U r0.44 16"43 38.89 D 7.92 t2"64 30"75 D 10.64 16.74 39.64 PSC PSC U 7.80 t2.25 29"00 U r0.92 t7"15 40.6t D 7.64 12.01 29.42 D 11.08 17.40 4L.t9 NU(¿EAR 1985 r990 2000 NYPP 0.78 1"12 ool PSC 0.64 0"94 2.03

(1) "U" designates update and "D" designates downstate

(2) ICF values modified via PSC GNP Deflators of : 8.5% L9B0 thru 1985 7.5% 1986 thm 1990 7.V/o l99l thru 2000

(3) I¡ this category, the NYPP values are for 1.4%S coal whereas the PSC values are for the category 1.4%S coal.

B-4