ML20073G549
| ML20073G549 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 04/12/1983 |
| From: | Streiter S CONSOLIDATED EDISON CO. OF NEW YORK, INC., POWER AUTHORITY OF THE STATE OF NEW YORK (NEW YORK |
| To: | |
| References | |
| ISSUANCES-SP, NUDOCS 8304180320 | |
| Download: ML20073G549 (77) | |
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- ) W fn, UNITED STATES OF AMERICA '/S NUCLEAR REGULATORY COMMISSION 'Q ,
2)
ATOMIC SAFETY AND LICENSING BOARD Before Administrative Judges:
James P. Gleason, Chairman Frederick J. Shon Dr. Oscar H. Paris
)
In the Matter of )
)
CONSOLIDATED EDISON COMPANY OF ) Docket Nos.
NEW YORK, INC. ) 50-247 SP (Indian Point, Unit No. 2) ) 50-286 SP
)
)
POWER AUTHORITY OF THE STATE OF )
NEW YORK ) April 12,1983 (Indian Point, Unit No. 3) )
)
)
LICENSEES' TESTIMONY OF SALLY HUNT STREITER ON COMMISSION QUESTION 6 ATTORNEYS FILING THIS DOCUMENT:
Brent L. Brandenburg Charles M. Pratt CONSOLIDATED EDISON COMPANY POWER AUTHORITY OF THE STATE OF NEW YORK, INC. OF NEW YORK-4 Irving Place 10 Columbus Circle New York, New York 10003 New York, New York 10019 (212) 460-4600 (212) 397-6200 8304180320 830412 PDR ADOCK 05000247 T PDR (ha
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l THE DIRECT COSTS OF CLOSING INDIAN POINT
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TABLE OF CONTENTS I. Int r od u e t ion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 II. T he R e f er ence C ase .. .. .. .. .. . . .. .. . ... .. . .. .. . . . . .. . . .. .. . . .. .. . . .. .. . . ... . . .. . . ..... . . . . . 3 III. Discussion of Important Assumptions in the Reference Case .............. 6 IV. Alternatives to Indian Point ... ................ .. ....................... ........... ...... 26 V. The Allocation of the Capital Cost of Indian Point ............................. 28 VI. Shu tdown Costs in P erspec tive ......................................................... 31 4
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- INDEX OF TABLES
- Tables 1 3 Reference Case, Summary of Costs of Closing Indian Point Table 1 New York State: Nominal Dollars Table 1.1 New York State: Constant-1982 Dollars l Table 1.2 New York State: Discounted Dollars Table 2 Con Edison: Nominal Dollars Table 2.1 Con Edison: Coiistant 1982 Dollars Table 2.2 Con Edison: Discounted Dollars Table 3 Power Authority: Nominal Dollars
- Table 3.1 Power Authority: Constant 1982 Dollars Table 3.2 Power Authority: Discounted Dollars Table 4 Rate Impact on Downstate Customers Resulting from Indian Point Closing Table 5 Sensitivity Case World Oil Price Assumptions Table 6 Sensitivity of New York State Reference Case to Oil Prices Table 7 Annual Average Capacity Factors for U.S. Nuclear Units 1970-81 Table 8 Sensitivity Case Capacity Factor Assumptions Table 9 Sensitivity of New York State Reference Case to Capacity Factors i
i Table 10 Historic and Projected O&M and Capital Expenditures at Indian Point l
Table 11 U.S. and Indian Point O&M Expenditures in Constant 1982 Dollars per KW Table 12 N umber o f Orders , Bulletins, Generic Lett ers and Circulars Issued by N RC Table 13 Sensitivity Case O&M Assumptions Table 14 Sensitivity of New York State Reference Case to O&M Table 15 Sensitivity Case Steam Generator Replacement Assumptions Table 16 Sensitivity of New York State Reference Case to Steam Generator Replacement Table 17 Sensitivity Case Load Growth Assumptions Table 18 Sensitivity of New York State Reference Case to Load Growth i
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-ii-Table 19 New York Power Pool Reserve Margins Table 20 Sensitivity of Reference Case to the Discount Rate Table 21 Other Changes in Taxes and Working Capital--Reference Case INDEX OF APPENDICES Appendix 1 Average Imported Crude Oil Price Forecasts Appendix 2 Regmssions Relating Capacity Factor to Various Characteristics of PWR Nuclear Generating Units in the U.S.
Appendix 3 Correction Factor for Demand Elasticity l
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9 My name is Sally Hunt Streiter. My business address is 123 Main Street, White Plains, New York. I am a vice president of National Economic Research Associates, an economic consulting firm, where I have been employed for the past nine years, mainly in analyzing different aspects of the electric industry.
My education and experience are attached as Exhibit 1.
The purpose of my testimony is to make estimates of the direct cost to customers of permanently closing the Indian Point Units 2 and 3.
I. INTRODUCTION AND
SUMMARY
The Indian Point Plants, located in Buchanan, New York consist of three units. Unit 1, owned by Con Edison, operated from 1962 to 1974. It has not yet been decommissioned, but can be ignored for the purposes of this study. Indian Point 2, owned by Con Edison, cost $216 million to build; it began operation in 1973. It is a pressurized water reactor (PWR) built by Westinghouse with a net maximum dependable capacity of 849 MW in the summer and 864 MW in the winter. Indian Point 3 owned by the Power Authority cost $435 million to build; it is also a Westinghouse PWR, rated at 965 MW. It began operation in '976.
The units are not identical, and are separately operated and administered by the two companies. The licenses for Units 2 and 3 expire in 2006 and 2009, respectively.
The two plants, running at a 63 percent capacity factor, produce approxi-mately 10,000 Gwh (10 billion kwh) per year. If Indian Point were to be closed, the energy normally generated by the units would have to be replaced from other sources. The sources of replacement power and the estimates of cost have been presented by Mr. Meehan. At some point, replacement capacity would be
s required to maintain minimum reserve margins. On the other hand, some fuel, operation and maintenance (O&M) and capital expenditures associated with continued operation of Indian Point could be avoided. This testimony makes projections of the costs and siings resulting from closing the units in 1984.
As with all projections, there are areas of uncertainty, and results vary widely according to the assumptions made. Therefore I present a reference case which gives a comprehensive exposition of the direct costs to consumers of closing Indian Point. The reference case projection is that the costs associated with closing both Indian Point units would amount to about $400 million per year, rising to over $2 billion a year by the end of the century. The present discounted value of the reference case shows a total cost to consumers of some $9 billion dollars. The details of this estimate are discussed below.
Estimates are by their nature more uncertain as the period increases.
Even between now and 1990, there is uncertainty as to oil prices, the schedule for coal conversions, the construction of new units and the growth in demand for electricity. In most instances the numbers presented are predicated on the plans and forecasts of the member companies of the New York Power Pool (NYPP), or on detailed studies done for the Pool members.
After 1990, estimates, including mine, become subject to the tyranny of projected growth rates. However, in considering the economic impact of closing i Indian Point it is not necessary to rely on assumptions about the distant future and on discounted present vclues, since we are not estimating the lifetime benefits of constructing a new plant, where an all or nothing choice has to be made about a multi-million dollar expenditure. In this case, the investment has l
already been made, and each year of saving is a real saving which will be lost if
! the plant is closed.
1 Some general observations about the form of my analysis are in order. The reference case is discussed in Section II. Summary reference case tables are presented in three forms: current (nominal) dollars, constant 1982 dollars and dollars discounted to 1983. The inflation rate assumed is 7 percent annually.
The discount rate is 10 percent, or 3 percent real. Summary tables are presented for New York State, Con Edison and the Power Authority separately.
Some individual components of the reference case are discussed in Sec-tion III. Because of the uncertainties, I have examined the sensitivity of the estimates to individual assumptions, and show the effect of changing these assumptions on the time path of costs, and on the total dollar impact of closing the plants. Individual components are shown in constant 1982 dollars in sensitivity tables and charts.
Section IV discusses alternatives to Indian Point.Section V discusses the allocation of capital costs of Indian Point 3.Section VI puts the shutdown costs in perspective.
II. THE REFERENCE CASE A forced closing of the Indian Point plants would require additional generation and purchased power to replace the 10,000 gwh of annual generation.
Mr. Meehan has projected these costs, in the reference case as growing from
$459 million per year in 1984 to $2,190 million per year in 1999. I have projected the per kwh cost from 1999 to 2009 as rising at 2 percent annually in real dollars, which is conservative, given the rate of increase projected by Mr. Meehan in the late 1990s. Mr. Meehan's projections take account of nuclear fuel savings from closing Indian Point, and additional O&M costs required by the fossil replacement units. His estimates do not include the following items, for which separate
s
! adjustments must be made: working capital and inventory costs, taxes, loss of 1
fuel core, decommissioning costs and costs of additional capacity, which all tend I
to increase the replacement cost; and nuclear operation and maintenance costs and capital additions at the Indian Point plants, which reduce the replacement cost.
r The estimated annual current dollar costs of the production penalty to New York State, assuming a 7 percent inflation ete, are shown in Table 1. This table identifies fuel replacement costs specifically in column 1 with all other costs shown consolidated in column 2. Savings of O&M costs, and capital additions are shown in columns 3 and 4; the final column shows the net annual total.
In Table 1.1 the same data are shown in constant 1982 dollars,1 and in 2
Table 1.2 the costs are shown discounted at 10 percent per year. The sum of the discounted values are given on Table 1.2. The present value of the cost of closing Indian Point in the reference case is $9.0 billion.
This total is not easily translated into customer rates. First, not all the costs are borne in the Con Edison Service Area in New York City and Westchester County. This is primarily because the pricing of Canadian purchases i
j by NYPP is tied to the NYPP decremental operating cost, which will rise if Indian Point is closed. Hence the price paid for Canadian energy will rise, and all purchasing utilities will bear some of that increase.
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i 1. Constant dollars remove the effects of assumed inflation after 1982.
- 2. Discounted dollars take into account the time value of money and assign a lower weight to costs in the future than to costs today. The sum of the j discounted stream of annual costs is called the "Present Value" (PV). This is the conventional means of comparing streams of costs occurring at different *;mes in the future.
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-S-Second, the systems of the Power Authority and Con Edison are very dissimilar and the closing of Indian Point would affect the systems differently.
In contrast to the typical utility pattern reflected by Con Edison, the Power Authority has an unusual system. Its customers in the Southeast New York region, which is roughly equivalent to the Con Edison service territory, are served by two plants, Indian Point 3 and Charles Polleti, an oil and gas-fired plant in New York City. In addition, certain limited additional power and energy is brought to this area from the Power Authority's upstate plants for the public customers. That transfer is subject to changes in water levels at the Power Authority's hydroelectric plants, to legislation, to con' it provisions with Con Edison and litigation by competing customers. In any event, it is not likely that it could be increased, absent legal changes and continued high water in the Great Lakes, if Indian Point 3 were closed.
To show the impact in the Con Edison service territory on both Con Edison's customers and the Power Authority's southeast New York customers, j Mr. Meehan has calculated the fuel replacement costs to the franchise area and for Con Edison. They are given in Tables 4.2 and 4.3 of his testimony. I have used these data to calculate the net impacts on Con Edison and the Power Authority separately. Table 2 shows the Con Edison impacts only, in current dollars; Table 2.1 shows the same data in constant 1982 dollars, and Table 2.2 in i
discounted dollars. These are comparable to Tables 1,1.1 and 1.2 which cover the whole of New York State. Tables 3, 3.1 and 3.2 give similar data for the Power Authority.
Table 4 then shows the rate impact on each of the ecmpanies through 1990.
The expected level of revenues with Indian Point open is shown for Con Edison and for the downstate portion of the Power Authority, and the company
0 increases and percentage increases are shown. The increased costs reflect increase over existing revenues. Because the Authority has a relatively greater reliance on Indian Point as a source of energy for its downstate customers, the percentage effect on these customers is considerably greater than the effect on Con Edison's customers. Dr. Dunbar will discuss the effect of this magnitude of rate increase on the Power Authority's largest customer, the MTA. Other witnesses wul discuss the other impacts of the Power Authority's resulting rate increase.
III. DISCUSSION OF IMPORTANT ASSUMPTIONS IN THE REFERENCE CASE
- a. Oil Prices Oil represents 92 percent of total replacement fuel in 1984, or 13.9 million barrels of oil annually. This percentage will drop in later years if the coal conversions and transmission reinforcements presently scheduled take place. It will then rise with load growth to reach 99 percent of replacement fuel by 1999.
Accordingly the production cost results presented are very sensitive to the oil price assumptions used in the projection of replacement power penalties.
The reference case employs forecasts prepared by ICF Inc. for the NYPP in November 1982. These forecasts were used in NYPPs April 1983 submission to i
the State Energy Office. This forecast assumes 6.7 percent decline from the then current world price of $34 a barrel during 1983, a return to the real 1982 price by 1985 and a 2 percent annualincrease in real terms thereafter.
From this world oil price base, the product prices were derived by ICF for oil delivered to New York Harbor and upstate New York. A 7 percent annual inflation rate was assumed.
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It is notoriously difficult to forecast the price of oil. In recent years a i number of fairly sophisticated models have been developed. Their common
, thread is that they view the power of OPEC to set prices as being dependent on
} world demand for oil; if OPEC is operating at a high percentage of its capacity, it will be able to reach agreement on restricting production and keeping the price high. But higher prices induce conservation and fuel substitution, and also 1
induce recession in the Western economies, thereby reducing demand and reducing OPEC's power. High prices also lead to more exploration for alterna-tive sources of oil. Major political events which reduce supply (such as the Iraq-i Iran war of 1979) or increase the cohesiveness of OPEC (such as the Yom Kippur war) induce much higher prices, but these are generally viewed as short term shocks on an underlying price path, which in turn depends on world economic
- growth assumptions and assumptions about the ultimate availability of as yet undiscovered reserves. See the testimony of Melvin A. Conant for additional
, detail on these matters.
All estimates of future oil prices are subject to wide variations.
i Appendix 1 shows the recent reference case projections of 18 different analysts; the more recent the projection the lower the short-run price increase projected.
ICF's predictions in the reference case were reduced about 10 percent from the previous (February 1982) forecast for NYPP. ICF's high and low cases were similarly reduced in the November 1982 forecast, and represent alternative assumptions about the course of the major variables.
The consensus of experts that oil prices will be flat or declining to 1985 is based on the excess oil production capacity currently available, and in pessimism about quick recovery from the world recession. But it is noticeable how much expert opinions have changed in just 12 months.
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. In 1978, following four years of stable real prices, many analysts were predicting declining real prices: the following year the price doubled, following a 4 million barrel per day reduction in supply from Iran. Similar upheavals are quite possible but not specifically predictable and are not generally considered in reference case forecasts. ICF estimated the effect of a shock in world supplies corresponding to a revolution in Saudi Arabia and a consequent reduction of world production by 7 million barrels per day in 1990. The estimated effect in a world where western economic growth had resumed, was a 63 percent increase in price in one year. This is not the largest conceivable shock, but gives some idea, if any is needed after 1974 and 1979, of the magnitude of shock-induced increases which could occur despite the general consensus on lower oil prices in the absence of shocks. Nevertheless people are talking about oil prices even lower than the low ICF case: a $28 real oil price in 1986 is perceived by some analysts as a distinct possibility.
OIL PRICE SENSITIVITIES 1984 -
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. ICF High Ou Price case Sensitivity Source: Table 6.
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It is this aspect of vulnerability and uncertainty which has the greatest impact on the projections of the cost of closing Indian Point. The sensitivity of direct cost estimates to the ICF alternative oil prices are shown in Figure 1 and also Table 5. Figure 1 also shows the low low case of $28 real oil prices throughout the 1980s and thereafter.
- b. Capacity Factors A second major item in estimating the replacement cost for Indian Point is the expected output of the units, which is directly related to the capacity factor.
The major difficulty in projecting Indian Point capacity factors beyond the age of 10 years is that no large unit, of the size of Indian Point, is over 10 years old.
So any estimate, including my own, must be based on informed judgment.
The companies' own capacity factors have averaged 53 percent and 51 per-cent at Indian Point 2 and Indian Point 3 respectively to the end of 1981. Both units have had serious problems with major components. In projecting a 63 percent capacity factor in the reference case, I have assumed that these problems can be solved. There is support in the national data for this assessment.
Analysis of the U.S. data on unit annual capacity factors is particularly complicated. [In all data analysis subsequently referred to, I have eliminated the data on the very small old units (Big Rock Point, Humboldt Bay, Yankee 1, Dresden 1, Indian Point 1, Fort St. Vrain and Lacrosse) since I consider any 1 experience with those units to be irrelevant to expectations about the subsequent !
I generations of units. Annual data from 1968-1981 are used.]
The remaining 62 units have been in service for up to 14 years, although only six units and only two PWRs have been in service for longer than ten years.
The annual average performance of these units is shown in Table 7. The standard
deviation of the mean values in the annual data is close to 17 percentage points, which is due partly to the refueling cycle. However, since refueling outages are used to perform many types of maintenance, the exclusion of reported refueling outages from the data is almost certain to introduce more errors in any statistical analysis than it corrects, and I have not attempted to adjust the data in this way.
What is immediately apparent from the annual averages is the sharp drop between 1978 and 1980. Some analysts have ascribed this to outages following the Three Mile Island accident and no doubt it was due to this, at least in part.
There was however a major outage at Surry 2 for steam generator replacement in 1979-80, and San Onofre, one of the two oldest of the PWRs, had very low capacity factors in 1980 and 1981 due to steam generator problems quite unrelated to the Three Mile Island accident. Indian Point 3 also had low capacity factors in this period, again due to steam generator problems.
The changes in the data from year to year, and the heavy weight that a few units can exert on the averages, make it very difficult to analyze the data adequately, particularly for small subsets of the data. The small subset of salt water cooled PWRs, for example has only 14 units, and the three units mentioned above, which are all salt water PWRs, pulled down the average for these units in 1980 from 63.8 to 56.6 percent and in 1981 from 63.2 to 58.2 percent. Prior to that, this subset had performed similarly to other subsets. There are undoubtedly problems associated with steam generators. Con Edison and the Power Authority have faced these problems and are spending considerable sums to ameliorate them.
The effect of age after the initial maturation is very ambiguous in the data. Some analysts have claimed to discover a very substantial decline with age in salt water cooled PWRs. I have examined the data using regression analysis techniques, and find that in the data to 1981 an " age" decline in salt water PWRs
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does indeed show up in the data. However, on the data to 1980 only, the effect is smaller and less significant, and on the data to 1979 it is much smaller and not significant. Therefore it is fair to asert that this "effect" has only shown up in 1980 and 1981. [The regression analyses are given in Appendix 2 of the testimony.] And in fact, by careful inspection, it appears that the " age effect" is almost entirely due to the recent steam generator problems discussed above at Surry, San Onofre and Indian Point 3. Removing these six data points removes the statistical significance of " age." In fact the San Onofre data alone impart most of the statistical significance of the age "effect": since this is the only salt water cooled PWR unit with an age greater than 10 years, inclusion of two very low capacity factors in the 13th and 14th years is comparable to putting two heavy weights on the very end of a seesaw when all the other weights are close to the middle. Exclusion of only these two points removes half the statistical significance from the " age" effer. in the 1980 and 1981 data.
My own view is that there have been widespread problems with steam generators, but that this cannot be taken to indicate monotonic decline for the next 20 years in capacity factors. It is an identified problem, and to assume that it cannot and will not be solved suggests a certain technological helplessness in the face of known difficulties. In fact Con Edison achieved a 62 percent capacity factor in the last refueling cycle from May 1981 to January 1983.
l In the reference case, I have used 63 percent as the projected capacity l
factor over the lives of the units. This reflects some optimism about the industry's ability to recover from the relatively poor performance in recent years; the nuclear industry has made great efforts to improve response time to technical problems, through sharing of data and thorough pre-outage technical analyses. The reference case also reflects the companies' extensive expenditures on repairs and capital replacements, which are expected to continue; these are
included in the estimates of O&M and capital expenditure discussed below.
After the 25th year of life the capacity factors in the reference case are reduced to reflect reduced capital expenditures towards the end of the life.
The low capacity factor in the sensitivity case is set at 57 percent, which is more in line with recent industry experience. The high case is set at 69 percent, which has been used by the NYPP in its projections of nuclear output, and which was the industry experience in the early 1970s. Table 8 shows the capacity factors assumed for each year in the base and reference cases.
Table 9 and Figure 2 show sensitivity to capacity factor assumptions.
LOW AND HIGH CAPACITY FACTOR SENSITIVITY 1984 -
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Low Capacity Factor Sensitivity Source: Table 9.
- c. Coeration and Maintenance Costs In the reference case, I have used the companies' own detailed estimates of operation and maintenance costs through 1986 together with their estimates of required capital additions to 1986 annualized over the remaininglife of the units.
1 The companies' estimates assume that the level of required base staffing will not increase beyond present levels. I have assumed that if economic growth resumes, after 1986 the real costs will increase at 1 percent per year, due to real increases in wages, partially offset by productivity improvements and turnover of employees. Historic and projected costs are given in Table 10.
Expenditures on nuclear operation and maintenance have risen sharply all over the U.S. since 1978. It appears that a large part of the change is due to a step increase caused by increased NRC requirements which rose very rapidly following the Three Mile Island accident. The annual average O&M expenditure per kilowatt in constant 1982 dollars for the U.S. is given in Figure 3 and Table 11, and the actual expenditure for Indian Point 2 and 3 in the same units.
ANNUAL AVERAGE OPERATION AND MAINTENANCE EXPENDITURES PER KILOWATT OF CAPACITY 1969 - 1981 60 ,
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--- Indian Point 2 Indian Point 3 Source: Table 11. _
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The companies have provided me with analyses of their O&M expenditures, which suggest that there are two major regulatory etements to the sharp recent increase over the 1972-77 levels: first, there were step increases in basic staffing levels, including guards, training and operating personnel, and in security and other contracts, which are expected to continue, but not grow in the future; these annual expenditures have been estimated by Con Edison at sonne
$14 million in 1993;3 second, there was a series of one time expenditures related to regulatory requirements, which are expected to decline gradually. These represent some $6 million of increase in 1983 over the 1976 levels for the Power Authority.4 If Con Edison and the Power Authority's experience were valid for all utilities, these numbers would explain a large part of the average United States increase in O&M, from about $21 per kilowatt (in 1982 dollars) in 1973-74, to about $47 per kilowatt in 1981.
Some support for this view is provided by analysis of the Commission annual reports and summations of the number of bulletins, orders and generic letters issued by the Commission. While it is true that every utterance of the i
Commission does not require a new round of expenditures, and while the expenditures required are not uniform per publication, the increase in output from 1976-1980 was.nonetheless truly staggering. (See Figure 4 and Table 12.)
The Commission's 1981 Annual Report,5 noting the substantial reduction in
- 3. Con Edison, " Indian Point 2 Cost Data," Internal Memorandum (April 1983).
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- 4. Determining the Portion of Regulatory Burden on Indian Point Unit 3, Capital and O&M Expenditures, 1976-1986, Budget Division, Power Authority of New York, April 1983.
- 5. U.S. Nuclear Regulatory Coramission,1981 ' Annual Report, p. 92.
bulletins, circulars and generic letters that year, said:
These = reduced numbers reflect more stringent criteria in determining whether an issue is significant enough to merit industry-wide communication, and recog-nition that the NRC may have been overburdening licensees and construction permit holders with require-ments of marginal safety impact. The same philosophy led to the formation, late in 1981, of the Committee for Review of Generic Requirements.
The number of orders however did not decrease until 1982. Consideration of both the costs and benefits of each action has already reduced the amount of output, and may hold level or even reduce O&M cxpenditure.
TREND OF NRC ACTIVITIES 1973 - 1982 200 I/)
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- D ata on NRC Orders are incomplete before 1978. 1978 figure is e stimated from 3 qu arters data.
l Source: Table 12.
l A third item of the licensees' increase in O&M is attributable to specific repairs and changes, particularly maintenance work associated with the extended
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outage for the fan coolers at Indian Point 2 and the steam generator sleeving program at Indian Point 3. Projections for 1983 continue at this high level for Unit 3, for completion of the sleeving program, and are expected to decline slightly in 1984. Con Edison estimates 1983 expenditures of $48 million, in a non-refuelling year, with an additional $20 million in refueling years. I have normalized the $20 million based on a 16 month refueling cycle to $14 million for an average year for projections.
LOW AND HIGH O&M COST SE NSITIVITY 1984 - 2009 800 700 _ p' s'
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The sensitivity cases are estimated as follows. NERNs analysis of national O&M data suggests that if the reduced volume of NRC regulation lead to a stabilization of expenditures at the 1980-81 level, the companies could be expected to achieve O&M levels somewhat below their own projections by the
mid-1980s. This analysis also suggests that the cumulative experience of a utility in running nuclear units tends to offset other time related effects on the required O&M expenditures. Therefore, the low O&M case assume that after 1987 the companies O&M costs drop to $40/Kw real dollars, the mean of the U.S.
average 1980 and 1981 costs per Kw, rising at inflation. The high O&M sensitivity case assumes the companies own (higher) estimates, an additional step increase in regulatory burden of 10 percent, and 2 percent real growth. These casas are shown in Figure 5 and Table 14.
- d. Capital Expenditures at Indian Point Additional capital expenditures needed for the units were estimated by the companies af ter detailed review. The historic and annual expected capital expenditures to 1990 were given in Table 10. They include major repairs, regulatory requirements and productivity modifications which are anticipated through 1986, and estimates thereafter. In the summary tables, capital expenditures are annualized, and the costs are presented as the annualized value of each year's expenditure cumulated over time.
The main source of uncertainty is the possibility of a steam generator replacement. Both companies have been experiencing problems with the steam generators.
At Indian Point 3, a program of plugging and sleeving the steam generator tubes has been undertaken, and will be continued. $20 million of O&M were spent last year (1982) on this project. Future costs of this program are included in total O&M estimates. The Power Authority hopes to avoid the need for replacement by the sleeving program. It has however made contingency plans, which would involve replacing the steam generator in 1987 or 1989. Costs for this are estimated at $200 million dollars in that year, exclusive of replacement power costs.
Indian Point 2 has also been subject to steam generator problems. Contin-gency plans for replacement of the steam generators are under discussion, but no decision as to the need for replacement has been made. I have not included estimates in the base case for replacement at either Unit 2 or Unit 3.
STEAM GENERATOR REPLACEMENT SENSITIVITY 1984 - 2009 700 - -
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$ 2 2 e! eS ee2 2 2 2 2 2 2 2 2 aaaa2288 New York State Reference Case
- Steam Generater Replacement Sensitivity 9ource Table 16 The sensitivity of the estimates of net cost to the steam generator replacement are shown in Figure 6 and Table 15. The reference case includes no steam generator replacement. The high sensitivity case includes replacements at Unit 3 in 1988 and at Unit 2 in 1991. Fuel savings are netted out, representing 12 months of outage in each case. The difference in present value between the
reference case and the steam generator replacement case is $800 million. With capital cost projections, as with O&M, the companies' near term estimates of capital expenditures are higher than NERAs projections from national data would suggest, even leaving aside the steam generator replacement.
- e. Load Growth, Capacity Additions and Conversion (i) Load Growth In the period to 2000, load growth (growth in energy consumption) in New York State is estimated by the NYPP members to be at an average annual level of 1.4 percent. This projection is the sum of individual NYPP members' projections and includes a growth projection of 1.3 percent annually in Con Edison's franchise area. The importance of the base growth projection is that if the construction schedule is unchanged, lower growth leads to less expensive units on the margin and hence lower replacement costs. Higher growth on the other hand leads to higher cost units on the margin and higher replacement costs given the sama construction schedule.
But of course if projected growth falls, the construction schedule may also change. For example, NYPP's energy growth projections have dropped from 1.8 percent overall growth in 1982 to 1.4 percent this year, reflecting closings of upstate manufacturing facilities. The units planned for Erie, Jamesport and Arthur Kill have been cancelled or indefinitely deferred and coal conversion has been indefinitely deferred at the Albany units.
However,'if growth were projected to increase fro.n 1.4 percent, licensing and regulatory constraints make it impossible to plan with confidence for a prompt quickening of the construction schedule if that should be needed. Hence, the sensitivity to growth alone should be viewed with some perspective. Lower growth can be adjusted to and may not lead to lower replacement costs for Indian Point power. But higher growth would pose real problems of adjustment.
Mr. Meehan ran sensitivity analyses for 1991 and 1999 on alternative growth scenarios of 0.7 percent overall, and 2.1 percent overall. The low and high growth sensitivity is shown in Table 17. Unfortunately Mr. Meehan's sensitivity analyses incorporate the old expansion plan, and are therefore not sensitivities about the reference case. I have recomputed the sensitivity of the reference case to load growth after consultation with Mr. Meehan. The results of this sensitivity analysis are shown in Figure 7 and Table 18.
LOW AND HIGH LOAD GROWTH SE NSITIVITY 1984 - 2009 900
, - 7, . ,7 N s s
/ h E 800 _
a
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5 700 - ,/
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a 600 _
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E $ $ S E E S E E OE $$S eeeeeeeeeeeeeeee2 R RE$ R 85R S R 25R $$S R R 0R$
New ',ork State Reference Case
lit,n I,oad Growth Sensitivity Low Load Growth Sensitivity Source: Table la
(ii) Capacity Additions At the time of the last NYPP submission pursuant to Section 5-112,6 there were plans for constructing four new generating units in addition to the plants at Somerset, Nine Mile Point, and Shoreham, which are under construction. One of these new units, Prattsville, is now scheduled for a later in-service date (1989),
and three others, Erie, Jamesport and Arthur Kill have been cancelled or indefinitely postponed.
(iii) Coal Conversion Ten NYPP oil burning units, totalling over 2900 MW, are currently scheduled to be converted to coal-burning. The schedule for conversions is set out in the 1983 Section 5-112 submission, and reflects a number of deferrals from previous 5-112 submissions. The schedule has been slipping since 1979. In fact no ' unit in New York State has yet converted to coal. Mr. Meehan's reference case assumes the current proposed conversion schedule will be met.
The likelihood of conversion on any scale approaching this figure is doubtful, and his alternate case where none of the units are converted is quite conceivable.
- f. Canadian Imports Large amounts of energy are expected to be available from Canada at reasonable prices, and some 6,000-12,000 Gwh/ year expected to be purchased whether or not Indian Point is closed. This amount of energy is not, therefore an alternative to operation of Indian Point, as it will be imported independent of any decision concerning Indian Point. The availability of this Canadian power, on the schedule proposed, requires state and federal authorities to license promptly the Marcy-South line. The existence of opposition to the project, and the tight
- 6. Report of Member Electric Systems of the New York Power Pool and the Empire State Electric Energy Research Corporation pursuant to Section 5-112 of the Energy Law of New York State.
i licensing and construction schedule assumed, make it possible that the line will not be in service when it is now planned. The reference case projection of the costs of closing Indian Point assumes that the line will go into service on schedule and additional imports will be available. The costs of closing Indian Point would be higher if this construction did not take place.
- g. Replacement Capacity NYPP member companies keep a gross reserve margin of generating enpacity above peak requirements of 22 percent on a state-wide basis, and each company within NYPP is required to keep 18 percent above its own peak requirements.
NYPP has a substantial reserve margin over its peak requirements. As shown in Table 14, if the units currently under construction plus Prattsville are completed and put into service, and if the load growth averages 1.2 percent per year, there will be a sufficiently large margin over peak requirements that the closing of Indian Point would not of itself leave NYPP as a whole short of capacity (that is, below its 22 percent margin requirement) in the 15 year planning period.
However, if Prattsville is deferred or cancelled, NYPP would run below its reserve margin in 1999 without Indian Point, as shown in Table 19. Such an eventuality would probably lead to a rescheduling of one of the deferred units.
Hence, closing Indian Point may indeed involve new construction, most likely of a coal fired plant. Coal units are currently estimated by the NYPP Economic Parameters Report to cost $1,715 per KW. This is also the estimated cost of Somerset, due to go on line in 1984. Building a coal unit in or near New York City would probably cost more. Replacing Indian Point units 2 and 3 (which cost about $360 per kilowatt when they were built) with coal units of equivalent capacity would cost at least $3 billion today.
i
.' \
I If peak growth is higher the . predicted, the NYPP reserve margin will become inadequate even with the new units in the early 1990s. In this case, the !
closing of Indian Point would also require additional capacity.
However, the Con Edison franchise area (including the Power Authority's downstate customers as well as Con Edison's customers) would run short of capacity in the 1990s if Prattsville were not built and if Indian Point were closed. The franchise area would require the equivalent of Indian Point's capacity by the turn of the century either in new construction or firm contracts.
- h. The Discount Rate The present value of a future stream of costs is customarily calculated by applying a market discount rate to current dollar costs, or a "real" discount rate to constant dollar cost. I have discounted the current dolJar stream at 10 percent, which represents a 3 percent real discount rate above inflation of 7 percent. Discounting at 12 percent or 14 percent would of course produce lower present value estimates. The sensitivity of the present value to the discount rate is shown in Table 20.
- i. Decommissioning Costs If Indian Point Unit No. 2 were to close permanently, the plant would presumably be decommissioned, but not necessarily immediately.
Although no large plant of this size has ever been decommissioned, several studies have estimated the decommissioning cost. A recent site specific study for Con Edison estimated the cost for dismantling Units 1 and 2 to be
$138.5 million (1980) but the PSC has allowed only $92.7 million. The additional cost of closing the plant eely depends on assumptions as to what would be done if the plant remained open as compared with what would be done if the plant were to be closed. In the reference case I have assumed that if the plant
t were to be ordered closed today, the companies would not undertake decom-missioning before 1994 and that the real costs would be the same as those estimated for decommissioning at the end of life; this means that additional cost would have to be incurred to prepare the unit 2 for safestorage and its continual care until the unit is dismantled. It is estimated that it would cost $6.3 million (1980) to prepare the unit for mothballing and would cost $6.9 million per year for continuing care of the unit, while the spent fuel is at site. After the spent fuel has been shipped, the unit continuing care cost would drop down to
$2.3 million per year. For simplicity I have estimated these costs to average
$5 million per year to 1994. To this must be added the present value of moving forward the decommissioning from 2010 to 1994, or the time value of making the expenditurcs earlier. This cost is calculated as follows:
Estimated Cost of Dismantlement: $90 million.
(1980 Dollars per unit)
Nominal Cost in 2010: $1,302 million.
(Assuming 5 percent savings for simultaneous dismantlement)
Present Value, in 1983: $99 million.
Nominal Cost in 1994: $441 million.
(Assuming 5 percent savings for .
simultaneous dismantlement)
Present Value, in 1983: $155 million.
Difference: $55 million.
(Present Value in 1983 of Cost of Early Decommissioning)
This difference in present value has been added to the 1994 costs.
There is some possibility that early closing would reduce the cost by reducing the cumulative amount of radiation. On the other hand, early closing and decommissioning would mean being among the first to do it, and would
?
probably involve a learning premium. Since the plant will have to be decom-missioned under either an early closing or full life scenario, the difference in costs due to decommissioning is a small part of the total, and I have not performed sensitivity analyses on it.
J. Disposal Costs Disposal and storage costs of spent nuclear fuel were included in Mr. Meehan's estimates of nuclear fuel costs.
- k. Loss of Fuel Core The cost per kwh of nuclear fuel, which has been estimated as 7 mills /kwh in 1984, was used in Mr. Meehan's runs to determine the net production penalty.
However, if the plant were to be closed, the value of the fuel core already installed would be lost. The core consists of three " regions," one of which is replaced at each refueling. Each region is one-third used up between refuelings.
Hence, if the unit were closed immediately after a refueling, the loss would be all of the most recent region, two-thirds of the previous region and one-third of the oldest region. If the plant were closed before a refueling, the loss would be two-thirds of one region plus one-third of another. Assuming the plant would be closed before a refueling, the loss would be a total of one fuel region, which costs about $50 million.
- 1. Tax Changes and Working Capital If Indian Point were closed, it may be anticipated that Con Edison would write off Indian Point 2 for tax purposes. The impact is very small because the tax benefits would be accrued whether or not the unit were closed: the only difference would be in the timing. It is unlikely to make any difference to customers, who get rate base credit for timing differences in any event.
Sales taxes at 8-1/4 percent and taxes on gross revenues have been included for Con Edison, at 4 percent.
The Power Authority, as a tax exempt entity has not such tax savings or penalties.
Working capital and inventory costs are calculated as prescribed by the New York Public Service Commission. These changes are all shown in Table 21.
IV. ALTERNATIVES TO INDIAN POINT
- a. Price Induced Conservation A price increase such as that projected in the reference case would induce some additional conservation. This effect would be spread over several years.
The effect on the Power Authority's customers is discussed in the testimony of Dr. Dunbar and Mr. Dean.
Adding 4 percent to Con Edison's prices every year after 1983 could be expected to reduce energy sales in the long run (by 1995) by about 1.0 percent or 350 GWH. (Long run elasticity for Con Edison's customers is estimated by Con Edison at .25.) Since only half the revenue from these 350 GWH represents fuel savings, and fixed costs still have to be recovered, an additional $26 million (1982 dollars) would have to be added to the base rates, raising prices a further
.4 percent. Af ter a second round of elasticity, and increased prices, the final price impact would be about 4.5 percent, and the final GWH reduction about 400 GWH. This would not come close to offsetting the generation from Indian Point, which is 10,000 GWH a year.
This reduction in consumption is not an economic benefit, however, unless it reflects a commensurate increase in safety. (People who give up beef because it is too expensive do not feel better off eating bologna than they did eating cheaper beef.) The reduced demand consequent on the price increase saves production costs, but there is an offsetting reduction in consumer saticfaction,
t since consumers are giving up the use of electricity which they have demon-strated, by buying it, is worth the original (pre-Indian Point closing) price. l ESRG has asserted 7 that the reduction in sales, which leads to a reduction in revenues, can be viewed as a benefit to consumers, partially offsetting the I
increased costs. They even assert that if the elasticity of demand were equal to minus one, and if marginal fuel costs were equal to average price, that there would be no impact at all from the closing, as customers would reduce demand to keep total bills constant. This latter assertion fully demonstrates the fallacy of the conclusion: if customers were paying exactly the same bill for 7 percent less i electricity, they would clearly be 7 percent worse off. Their choice to do without electricity rather than pay the additional price imposed because of an Indian Doint closing comes to virtually the same impact as paying 7 percent more money for the same amount of electricity. [Indeed, under ESRG's scenario, if demand were elastic, consumers could always be benefitted by raising the price of any good so that they vould spend less on it in total. Presumably, in this case, no consumption at all would confer the greatest benefits of all.]
The small grain of truth in ESRG's absurd assertion is demonstrated in l
Appendix 3 where I calculate the appropriate correction factor to be under 1 percent. Since it is so small, I have ignored it.
- b. Alternative Technologies for Generation NYPP members aim to minimize total production costs subject to finan-cial, regulatory and technological constraints.
- 7. Raskin, Paul D. and Rosen, Richard A., The Economics of Closing the
- Indian Point Nuclear Power Plants. The direct effect upon rate payers of early i retirement of units 2 and 3. ESRG Study 82-40, ESRG Boston,. Mass. (no date) p.70.
i I
, l t
If Indian Point were closed, the NYPP might review its construction plan.
But any dramatic changes in the economics of that plan would depend on changes in the marginal costs of fuel consequent on closing Indian Point. I a >ked Mr. Meehan to compute the change in marginal cost for 1991, a typical year, for a change in load of 100 MW. With Indian Point open the mean marginal cost is 102 mills per kilowatt-hour. With Indian Point closed it is 113 mills. This 11 percent increase in marginal costs due to the closing of Indian Point might make some generation alternatives more economic. But it is unlikely that any new technology such as solar electric generation or windmills will become dramatically more likely to be adopted if Indian Point were closed.
V. THE ALLOCATION OF THE CAPITAL COST OF INDIAN POINT Mr. Meehan's projection focuses on production costs, not the embedded capital cost of the existing Indian Point plants. Indian Point 2 is presently included in Con Edison's rate base. If that unit were closed prematurely by order of the Commission, the company expects that the unrecovered investment would be treated as an extraordinary loss, and the unamortized balance would continue in the rate base.
Indian Point 3 presents a different situation. The Power Authority now sells power from Indian Point 3 and the Poletti Plant on a melded basis, in which the rates charged its customers in Southeast New York pay for variable and fixed costs of both plants.
The Power Authority does not have any shareholders. It is required to pass on to its customers all costs of its plants, including amortization of its investment and the cost of purchasing replacement power. The customers have entered into power supply contracts with the Power Authority that specify the
, S L
terms of the individual relationships. The rates charged by the Authority for power vary substantially depending on, among other things, the source of power supplied to the particular customer. Because the power supply contracts give the customers the right to switch to a supplier other than the Power Authority, they would be expected to exercise that option if the rates of the local investor-owned utility were more attractive.
A shutdown of Indian Point would inevitably require sharp rate increases for the Power Authority's Southeast New York customers. To the extent that increases would raise rate levels above those of an alternative supplier, the possibility exists that the Power Authority's downstate customers would seek another supply source. This would threaten the Power Authority's ability to meet required payments under its bond resolution and thereby would have a substantial, direct and adverse impact on the Power Authority, its future projects and other governmental entities in New York State.
The Power Authority now expects that the embedded costs of Indian Point 3 might have to be recovered from the customers of the Authority's remaining revenue producing facilities in proportion to the ability of each of these facilities to carry such costs and still produce (and/or transmit) power at competitive rates. The major remaining facilities include:
(1) the flydroelectric Projects--Niagara and St. Lawrence-FDR generating projects and related transmission facilities, (2) the James A. FitzPatrick nuclear power plant, (3) the Blenheim-Gilboa pumped storage power project, and (4) the Gov. Charles Poletti oil and gas fueled power project.
The Power Authority has indicated to me that it is quite possible that none of the anticipated closing costs could be recovered from ratepayers served from
, \
i the Poletti plant, assuming the Power Authority would continue to operate this facility as an isolated unit. This is because on a stand-alone basis it is estimated that Poletti rates at point of delivery to ultimate customers would just barely be competitive when compared to the local retail rates for electricity produced by Con Edison.
Furthermore, based on a similar analysis of the effect on current rates and competitive position of allocating a portion of the closing costs to the FitzPatrick nuclear plant and the Blenheim-Gilboa pumped storage power project, the Power Authority has concluded that only a relatively small portion of such costs could reasonably be allocated to these facilities.
Ther,efore, the effect of recovering the closing costs from the Authority's i remaining revenue producing facilities, after competitive considerations are taken into account, could be that the customers bearing the bill would be located almost exclusively in Upstate New York, as distinguished from the Con Edison .
service territory, and for the most part such consumers would be customers of the Hydroelectric Projects.
it is estimated by the Power Authority that the Hydroelectric Project rates t
would have to be increased immediately by about $70 million annually, or by
- about 45 percent over current levels, to ensure that the costs of closing Indian Point could be met by the Authority.
i To the extent other Authority customers' rates increased as a result of shutdown, it would offset the increase to SENY customers by a corresponding amount. Every dollar of Indian Point 3 costs which is allocated to plants other than Poletti results in a dollar reduction in the amount of the increase to the downstate public customers.
I
V
(
VI. SHUTDOWN COSTS IN PERSPECTIVE How might this Commission determine whether the benefits of closing Indian Point are in any way commensurate with the costs? The risks attached to Indian Point operating are expressed by the Indian Point Probabalistic Safety Study in terms of probabilities of occurrence of certain accidents. If Indian Point were closed the benefits would be expressed in terms of avoidance of those risks. On the other hand, the direct costs of closing Indian Point are expressed here in terms of dollars, although I have not attempted to estimate environ-mental costs, or risks of war consequent on increased dependence on oil, or the effect on the financial well being of the electric utility industry. These are real costs nonetheless.
I would suggest, though, that looking only at the direct costs as I have measured them, one might reasonably frame the question as "what am I buying for $4-600 million a year?" Clearly, those arguing for closing Indian Point would characterize the costs of the closing as a purchase of safety. Independent of the merits of that sugges*lon, we should ask ourselves what the citizens of the region typically buy for $4-600 million a year, and how much they have shown themselves willing to tax themselves to purchase public goods. By way of example, the public makes comparably large payments for what are undeniably safety expenditures: the New York City Police Department budget for the fiscal i
l year 1983 is $838 million: the Corrections Department's budget is $211 million:
the Fire Department's $419 million: the department of Environmental Protection's $199 million. These are basic safety expenditures made by New York City.
For the penalty is like a tax--it is money taken from the citizens to l
purchase a public good. If it were levied as a tax, instead of through the electric
.. i '
L rates, $400 million would be roughly equivalent to raising the sales tax from 8-1/4 percent to 9 pe,rcent. Or to an 8 percent increase in the property tax. It is a substantial amount evan in the context of a multibillion dollar city.
}
l
C Y' 4
8 Testimony of Sally Hunt Streiter TABLES, APPENDICES & EXHIBITS
r
-s o Tobla 1 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT New York State Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs 01arges Cost (Millions of Nominal Dollars)
(1) (2) (3) (4) (5) 1984 $ 463 $ 176 $ 131 $ 27 $ 482 1985 533 87 144 43 433 1986 549 88 150 56 431 1987 503 76 165 75 340 1988 576 87 178 86 400 1989 650 98 192 99 456 1990 819 125 207 114 622 1991 965 148 224 130 760 1992 1,073 165 242 146 850 1993 1,188 184 261 164 947 1994 1,306 350 282 182 1,192 1995 1,438 213 305 183 1,164 1996 1,604 238 329 222 1,291 1997 1,859 276 355 244 1,537 1998 2,090 310 384 262 1,754 1999 2,339 347 414 277 1,994 2000 2,550 378 448 289 2,191 2001 2,779 412 483 293 2,415 2002 2,943 436 508 284 2,586 2003 3,113 462 534 268 2,772 2004 3,290 488 561 247 2,971 2005 3,362 499 573 223 3,C65 2006 3,421 507 591 200 3,137 2007 1,931 286 332 117 1,768 2008 1,959 291 361 105 1,784 2009 1,978 293 398 94 1,779 Present Value $10,736 $1,768 $2,313 $1,190 $9,001
.s e Tcbla 1.1 1
REFERENCE CASE
SUMMARY
OF COSTS '
I OF CLOSING INDIAN POINT New York State Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs Charges Cost (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) (4) (5) 1984 $ 418 $ 159 $ 118 $ 24 $ 435 1985 450 73 122 36 365 1986 433 69 118 45 340 1987 371 56 121 56 250 1988 397 60 123 59 276 1989 419 63 124 64 294 1990 493 75 125 69 375 1991 543 83 126 73 427 1992 564 87 127 77 447 1993 534 91 128 81 465 1994 600 161 130 84 548 1995 617 91 131 78 500 1996 643 95 132 89 518 1997 697 104 133 91 576 1998 732 109 134 92 615 1999 766 114 136 91 653 2000 780 116 137 89 670 2001 795 118 138 84 691 2002 787 117 136 76 691 2003 778 115 133 67 693 2004 768 114 131 58 694 2005 734 109 125 49 669 2006 698 103 121 41 640 2007 368 55 63 22 337 2008 349 52 64 19 318 2009 329 49 66 16 296 Present Value $10,736 $1,768 $2,313 $1,190 $9,001
- Tabla 1.2 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT New York State Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs Charges Gost (Millions of 1983 Discounted Dollars)
(1) (2) (3) (4) (5) 1984 $ 421 $ 160 $ 119 $ 24 $ 438 1985 440 72 119 36 357 1986 412 66 112 42 324 1987 344 52 112 51 232 1988 358 54 110 53 248 1989 367 55 108 56 258 1990 420 64 106 59 319 1991 450 69 104 61 354 1992 455 70 103 62 360 1993 458 71 101 63 365 1994 458 123 99 64 418 1995 458 68 97 58 371 1996 465 69 95 64 374 1997 490 73 94 64 405 1998 500 74 92 63 420 1999 509 75 90 60 434 2000 504 75 89 57 433 2001 500 '74 87 53 434 2002 481 "e l 83 46 423 2003 463 69 79 40 412 2004 445 66 76 33 401 2005 413 61 70 27 377 2006 382 57 66 22 350 2007 196 29 34 12 180 2008 181 27 33 10 165 2009 166 25 33 8 149 Present Value $10,736 $1,768 $2,313 $1,190 $9,001 L
- Tcbla 2 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT Con Edison Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs Oiarges Cost (Millions of Nominal Dollars)-
(1) (2) (3) (4) (5) 1984 $ 200 $ 91 $ 69 $ 12 $ 210 1985 227 47 74 16 184 1986 211 43 80 23 150 1987 227 44 87 38 146 1988 271 52 94 45 184 1989 312 59 101 53 217 1990 347 67 109 62 243 1991 404 79 118 71 294 1992 446 87 128 81 325 1993 502 99 138 90 373 1994 572 186 149 100 509 l 1995 639 121 161 111 488 1996 728 138 174 122 570 1997 692 131 187 133 503 1998 798 151 202 140 607 1999 918 173 219 142 730 2000 1,001 189 236 141 813 2001 1,091 206 255 134 908 2002 1,155 218 262 120 991 2003 1,222 231 268 108 1,077 2004 1,291 244 273 95 1,167 2005 1,320 249 278 83 1,208 2006 1,343 253 281 71 1,244 Present
- Value $4,216 $884 $1,154 $583 $3,362
. Tebla 2.1 REFERENCE CASE
SUMMARY
OF COSTS t OF CLOSING INDIAN POINT Con Edison Costs Savings <
Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs 01arges Cost (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) (4) (5) 1984 $ 181 $ 83 $ 62 $ 11 $ 190 1985 192 39 63 13 155 1986 167 34 63 18 119 1987 167 32 64 28 108 1988 187 36 65 31 127 1989 201 38 65 34 139 1990 209 40 66 37 146 1991 227 44 66 40 165 1992 235 46 67 42 171 1993 247 49 68 44 183 1994 263 86 68 46 234 1995 274 52 69 48 209 1996 292 55 70 49 229 1997 259 49 70 50 189 1998 280 53 71 49 213 1999 301 57 72 47 239 2000 306 58 72 43 249 2001 312 59 73 38 260 2002 309 58 70 32 265 2003 305 58 67 27 269 2004 302 57 64 22 272 l 2005 288 54 61 18 264 l 2006 274 52 57 15 254 l
Present Value $4,216 $884 $1,154 $583 $3,362 t
l
- Tabla 2.2 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT Con Edison Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs 01arges Cost (Millions of 1983 Discounted Dollars)
(1) (2) (3) (4) (5) 1984 $ 182 $ 83 $ 63 $ 11 $ 191 1985 188 39 62 13 152 1986 159 32 60 17 113 1987 155 30 59 26 100 1988 168 32 58 28 114 1989 176 33 57 30 122 1990 178 34 56 32 125 1991 188 37 55 33 137 1992 189 37 54 34 138 1993 194 38 53 35 144 1994 200 65 52 35 178 1995 204 38 51 , 35 155 1996 211 40 50 35 165 1997 182 34 49 35 132 1998 191 36 48 33 145 1999 200 38 48 31 159 2000 198 37 47 28 161 l
2001 196 37 46 24 163 2002 189 36 43 20 162
- 2003 182 34 40 16 160 2004 175 33 37 13 158 2005 162 31 34 10 148 2006 150 28 31 8 139 I Present Value $4,216 $884 $1,154 $583 $3,362 t
I 1
. Tabla 3 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT Power Authority Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs Oiarges Cost (Millions of Nominal Dollars)
(1) (2) (3) (4) (5) 1984 $ 255 $ 64 $ 62 $ 15 $ 243 1985 30'; 16 70 27 221 1986 299 16 69 33 213 1987 262 13 78 38 159 1988 293 14 84 40 183 1989 329 15 91 46 208 1990 384 20 98 52 253 1991 432 23 106 59 290 1992 485 26 114 66 331 1993 541 29 123 74 373 1994 598 106 133 82 489 1995 665 30 144 72 479 1996 741 33 155 100 518 1997 878 42 168 111 641 1998 983 46 181 122 726 1999 1,091 51 196 135 811 2000 1,549 72 212 149 1,261 2001 1,688 79 228 159 1,379 2002 1,788 83 247 164 1,461 2003 1,891 88 266 160 1,553 2004 1,999 93 288 151 1,653 2005 2,043 95 295 140 1,703 2006 2,078 97 310 128 1,737 2007 1,931 90 332 117 1,572 2008 1,959 91 361 105 1,584 2009 1,978 92 398 94 1,578 Present Value $5,885 $358 $1,159 $606 $4,478 l
. Tcbla 3.1 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT Power Authority Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs O arges Cost (Millions of Mid 1982 Constant Dollars)-
(1) (2) (3) (4) (5) 1984 $ 230 $ 58 $ 56 $ 13 $ 220 1985 255 14 59 23 187 1986 236 13 55 26 168
. 1987 193 9 57 28 117 1988 202 10 58 28 126 1989 212 10 58 30 134 1990 231 12 59 31 153 1991 243 13 60 33 163 1992 255 14 60 35 174 1993 266 14 61 36 183 1994 275 49 61 38 224 1995 285 13 62 31 206 1996 297 13 62 40 208 1997 329 16 63 42 240 1998 344 16 64 43 254 1999 357 17 64 44 266 2000 474 22 65 46 386 2001 483 23 65 46 395 2002 478 22 66 44 390 2003 472 22 67 40 388 2004 467 22 67 35 386 2005 446 21 64 31 372 2006 424 20 63 26 354 2007 368 17 63 22 300 2008 349 16 64 19 282 2009 329 15 66 16 '263 Present Value $5,885 $358 $1,159 $606 $4,478
Tcbla 3.2 REFERENCE CASE
SUMMARY
OF COSTS OF CLOSING INDIAN POINT Power Authority Costs Savings Production Total Avoided Avoided Cost Other O&M Capital Net Year Penalty Costs Costs Oarges Cost (Millions of 1983 Discounted Dollars)
(1) (2) (3) (4) (5) 1984 $ 232 $ 58 $ 56 $ 13 $ 221 1985 250 13 57 23 183 1986 225 12 52 25 160 1987 179 9 53 26 109 1988 182 9 52 25 113 1989 186 9 51 26 117 1990 197 10 50 27 130 1991 202 11 49 27 136 1992 206 11 48 28 140 1993 209 11 48 28 144 1994 210 37 47 29 171 1995 212 10 46 23 153 1996 215 10 45 29 150 1997 231 11 44 29 169 1998 235 11 43 29 174 1999 237 11 43 29 177 2000 306 14 42 29 249 2001 304 14 41 29 248 2002 292 14 40 27 239 2003 281 13 40 24 231 2004 270 13 39 20 223 2005 251 12 36 17 209 2006 232 11 35 14 194 2007 196 9 34 12 160 2003 181 3 33 10 146 2009 166 s 33 8 132 Present Value $5,885 $358 $1,159 $606 $4,478 l
- Table 4 1' RATE IMPACT ON DOWN-STATE QJSTOWlERS RESULTING FROM I101AN POINT CLOSING Estimated Estimated Power Con Edison Rate Authority Rate Year Revenues Increase Revenues Increase
(1) (2) (3) (4) 1984 $4,600 4.6% $ 729 33.3% ,
1985 5,000 3.7 782 28.'3
\;!
1986 5,300 2.8 839 25.'4 1987 5,600 2 .'6 901 17.6 1988 5,900 3.1 967 13.9 1989 6,200 3.5 1,038 20.0 1990 6,500 3.7 1,114 22.7 Sources: Col. (1): Con Edison Projection.
Col. (2): Table 2, Col. (5) / Col. (1) x 100.
Col. (3): Power Authority Projection.
Col. (4): Table 3, Col. (5) / Col. (1) x 100.
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~ _._ __ _
Table 5 SENSITIVITY CASE WORLD OIL PRICE ASSUMPTIONS ICF ICF High Low Low Low Reference Oil Oil Oil Year Case Prices Prices Prices (Millions of Mid 1982 Constant Dollars per Barrel)
(1) (2) (3) (4) 1984 $32.9 $35.0 $30.0 $27.0 1985 34.0 36.1 28.0 27.0 1986 34.7 37.2 28.3 27.0 1987 35.4 38.3 28.6 27.0 1988 36.1 39.4 28.8 27.0 1989 36.8 40.6 29.1 27.0 1990 37.5 41.8 29.4 27.0 1991 38.3 43.1 30.0 27.0 1992 39.1 44.4 30.6 27.0 1993 39.8 45.7 31.2 27.0 1994 40.6 47.1 31.9 27.0 1995 41.4 48.5 32.5 27.0 1996 42.3 49.9 33.1 27.0 1997 43.1 51.4 33.8 27.0 1998 44.0 53.0 34.5 27.0 1999 44.9 54.6 35.2 27.0 2000 45.8 56.2 35.9 27.0 2001 46.7 57.9 36.6 27.0 2002 47.6 59.6 37.3 27.0 2003 48.6 61.4 38.1 27.0 2004 49.5 63.2 38.8 27.0 2005 50.5 65.1 39.6 27.0 2006 51.5 67.1 40.4 27.0 2007 52.6 69.1 41.2 27.0 2008 53.6 71.2 42.0 27.0 2009 54.7 73.3 42.9 27.0 Sources: Cols. (1) - (3): ICF Incorporated, Forecast of Fuel Markets and Prices in New York State, Volume 1, Oil and Gas Markets and Prices, Presented to New York Power Pool, November 1982, page I-1.
Table 6 SENSITIVITY OF NYS REFERENCE CASE NET COST TO OIL PRICES Net Cost of Closing ICF ICF High Low Low Low Reference Oil Oil Oil Year Case Prices Prices Prices (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) (4) 1984 $435 $464 $396 $355 1985 365 394 281 267 1986 340 368 268 253 1987 250 263 220 213 1988 276 292 239 230 1989 294 314 253 242 1990 375 414 300 277 1991 427 486 326 289 1992 447 518 335 287 1993 465 550 340 279 1994 548 646 413 339 1995 500 610 358 272 1996 518 644 368 267 283 1997 576 727 407 1998 615 783 437 296 1999 653 841 465 306 479 307 2000 670 862 2001 691 886 495 311 t
2002 691 885 498 306 2003 693 884 502 302 2004 694 882 505 299 2005 669 849 489 283 2006 640 811 468 265 2007 337 427 247 135 2008 318 403 232 122 2009 296 377 215 108 Sources: Col. (1): Table 1.1, Col. (5).
Col. (2): Table 1.1 adjusted for ICF High 011 Prices from Table 5.
Col. (3): Table 1.1 adjusted for ICF Low Oil Prices from Table 5.
Col. (4): Table 1.1 adjusted for Low Low Oil Prices from Table 5.
ANNUAL AVERAGE CAPACITY FACTORS FOR U.S. NUCLEAR UNITS, 1970 - 1981 Salt PWRs Excluding All Units All PXRs Salt EMRs Six Observations Capacity Capacity Capacity Capacity Factor Obs. Factor Obs. Factor ms. Factor Obs.
(Percent) (Percent) (Percent) (Percent) 1970 62.01 4 76.43 2 80.09 1 80.09 1 1971 73.20 6 78.45 4 86.48 1 86.48 1 1972 67.89 11 66.96 6 73.62 1 73.62 1 1973 60.62 20 58.90 10 54.10 4 54.10 4 1974 56.12 26 56.14 16 57.74 7 57.74 7 1975 62.89 38 69.12 24 70.41 7 70.41 7 1976 60.65 47 63.37 28 64.73 9 64.73 9 1977 65.87 51 69.30 32 68.60 11 68.60 11 1978 68.51 58 68.53 37 65.61 14 65.61 14 1979 63.08 59 60.27 38 55.21 le 58.76 13 1980 59.80 60 59.52 38 56.62 14 63.81 11 p 1981 61.44 62 62.79 40 58.18 14 63.19 12
- Trble 8 SENSITIVITY CASE CAPACITY FACTOR ASSUMPTIONS Higher Lower Reference Capacity Capacity Year Case Factor Factor (Percent)
(1) (2) (3) 1984 63.0% 69.0% 57.0%
1985 63.0 69.0 57.0 1986 63.0 69.0 57.0 1987 63.0 69.0 57.0 1988 63.0 69.0 57.0 1989 63.0 69.0 57.0 1990 63.0 69.0 57.0 1991 63.0 69.0 57.0 1992 63.0 69.0 57.0 1993 63.0 69.0 57.0 1994 63.0 69.0 57.0 1995 63.0 69.0 57.0 1996 63.0 69.0 57.0 1997 63.0 69.0 57.0 1998 63.0 69.0 57.0
! 1999 63.0 69.0 57.0 2000 63.0 69.0 57.0 2001 63.0 69.0 57.0 2002 61.2 66.6 55.8 2003 59.4 64.2 54.6 2004 57.6 61.8 53.4 2005 54.0 57.0 51.0 2006 50.4 52.2 48.6 2007 52.2 54.6 49.8 2008 48.6 49.8 47.4 2009 45.0 45.0 45.0 t
. _ _ _ _ e ,
Tcbla 9 f
( SENSITIVITY OF NYS REFERENCE CASE NET COST TO CAPACITY FACTORS Net Cost of Closing Higher Lower Reference Capacity Capacity Year Case Factor Factor (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) 1984 $435 $480 $390 1985 365 413 317 1986 340 336 293 1987 250 290 211 1988 276 318 233 1989 294 339 249 1990 375 428 322 1991 427 486 369 ;
1992 447 507 387 1993 465 528 403 1994 548 612 483 1995 500 566 433 1996 518 587 449 1997 576 651 501 1998 615 693 536 1999 653 735 571 2000 670 847 509 2001 691 871 527 2002 691 863 535 2003 693 855 544 2004 694 846 553 2005 669 799 548 ;
2006 640 746 539 t 2007 337 398 280 2008 318 366 271 2009 296 331 261 Sources: Col (1): Table 1.1, Col. (5).
Col. (2): Table 1.1 adjusted for higher capacity factors from Table 8.
Col. (3): Table 1.1 adjusted for lower capacity factors from Table 8.
Tc. bin 10 HISTORICAL AND PROJECTED O & M AND CAPITAL EXPENDITURES AT INDIAN POINT Indian Point 2 Indian Point 3 0&M Capital O&M Capital Year Expense Expense .
Expense Expense (Millions of Current Dollars)
(1) (2) (3) (4) 1973 $ 17 $11 na na 1974 14 5 na na 1975 14 3 na na 1976 19 8 $3 na 1977 17 6 13 $26 1978 28 8 23 15 1979 33 14 29 30 1980 33 24 50 30 1981 55 77 58 34 1982 69 59 83 16 1983 50 46 69 38 1984 69 46 62 82 1985 74 14 70 74 1986 80 31 69 36 1987 87 57 78 30 1988 94 35 84 21 1989 101 38 91 38 1990 109 41 98 41 na - not applicable.
Source: Actual Expenditures from FERC Form 1.
Projected Expenditures by Companies to 1986; Rising at 8% per year to 1990.
Tc.ble 11 U.S. AND INDUiN POINT O & M EXPENDITURES IN CONSTANT 1982 DOLLARS PER KW In O2rrent Dollars In Constant Dollars U .S. Indian Indian U .S. Indian Indian Year Average Point 2 Point 3 Average Point 2 Point 3 (Dollars per KW) -(Mid 1982 Dollars per KW)-
(1) (2) (3) (4) (5) (6) 1970 $11 na na $27 na na 1971 10 na na 24 na na 1972 11 na na 25 na na 1973 10 $ 16 na 21 $36 na 1974 11 13 na 21 26 na 1975 12 14 na 22 25 na 1976 14 19 $2 24 32 $4 1977 16 16 12 25 26 19 1978 18 28 22 26 41 32 1979 24 32 27 32 43 36 1980 30 33 47 36 38 55 1981 44 54 54 47 57 58 1982 NA 68 77 NA 68 77 1983 43 49 64 40 46 60 1984 46 68 58 40 59 50 1985 49 73 65 40 60 53 1986 52 79 65 40 61 50 1987 56 86 73 40 61 52 1988 60 93 79 40 62 52 1989 64 100 85 40 62 53 1990 68 108 92 40 63 53 na - not applicable.
NA - not available.
Note: O&M Expenditures are per KW of Nameplate Capacity.
Indian Point 2 is 1013 MW; Indian Point 3 is 1068 MW.
Source: Actual Expenditures from FERC Form 1.
Col. (1) Projections: NERA Projections.
Cols. (2) and (3) Projections: Projected by Companies to 1986; Rising at 8% per year
! to 1990.
- Table 12 NUMBER OF ORDERS, BULLETINS, GENERIC LETTERS AND CIRCULARS ISSUED BY THE NRC 1973 - 1982 Generic NRC Year Bulletins Circulars Letters Orders Total (Number)
(1) (2) (3) (4) (5) 1973 6 na na na 6 1974 16 na na na 16 1975 8 na na na 8 1976 7 7 na na 14 1977 8 17 4 na 29 1978 14 19 28 37 98 1979 28 25 56 41 150 1980 25 25 58 88 196 1981 3 15 40 132 190 1982 4 0 27 56 87 na - not applicable.
Note: Data on NRC orders are incomplete before 1978.
1978 figure is estimated from 3 quarters' data.
Source: LIS Corporation document sent to the Power Authority.
Tcbis 13 SENSITIVITY CASE O & M ASSUMPTIONS
Annual O&M Costs----------
Lower Higher Reference O&M O&M Year Case Costs Costs
-(Millions of Nominal Dollars)-
(1) (2) (3) 1984 131 131 138 1985 144 144 153 1986 149 129 159 1987 165 142 184 1988 178 152 200 1989 192 163 219 1990 207 174 238 1991 224 186 260 1992 242 199 283 1993 261 213 308 1994 282 228 335 1995 305 244 366 1996 329 261 399 1997 355 279 435 1998 383 299 474' 1999 415 320 517 2000 448 342 563 2001 483 367 614 2002 509 383 652 2003 534 401 691 2004 561 418 731 2005 573 424 753 2006 591 431 789 2007 332 268 451 2008 361 281 510 2009 398 296 588 Sources: Col. (1): Compar.y Projections Col. (2): See Text Col. (3): See Text 4
- Table 14 SENSITIVITY OF NYS REFERENCE CASE NET COST TO O & M Net Cost of Closing Lower Higher Reference O&M O&M Year Case Costs Costs (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) 1984 $435 $435 $429 1985 365 366 358 1986 340 356 332 1987 250 268 236 1988 276 294 259 1989 294 314 276 1990 375 396 355 1991 427 451 405 1992 447 472 423 1993 465 492 439 1994 548 576 519 1995 500 530 469 1996 518 550 485 1997 576 610 540 1998 615 651 576 1999 653 690 612 2000 670 709 628 2001 691 731 646 2002 691 731 646 2003 693 732 647 2004 694 732 649 2005 669 705 625 2006 640 676 596 2007 337 351 313 2008 318 333 290 2009 296 314 263 Sources: Col. (1): Table 1.1, Col. (5).
Col. (2): Col. (1) adjusted for lower O & M Expenditures from Table 13.
Col. (3): Col. (1) adjusted for higher O & M Expenditures from Table 13.
Tabla 15 SENSITIVITY CASE STEAM GENERATOR ASSUMPTIONS
Capital Expenditures-----
With Two Steam Reference Generator Year Case Replacements (Millions of Nominal Dollars)
(1) (2) 1984 128 137 1985 88 120 1986 67 99 1987 87 155 1988 56 124 1989 76 76 1990 32 82 1991 88 88 1992 96 316 1993 102 102 1994 109 109 1995 115 115 1996 123 123 1997 131 131 1998 127 127 1999 121 121 2000 116 116 2001 91 91 2002 54 54 l 2003 27 27 l
2004 7 7 l
2005 0 0 2006 0 0 l 2007 0 0 l 2008 0 0 l 2009 0 0 Sources: Col. (1): Company Projection of Capital Expenditures without replacement of Steam Generators.
Col. (2): Company Projection of Capital Expenditures with replacement of Steam Generators.
l l
a . _____
Tabla 16 SENSITIVITY OF NYS REFERENCE CASE NET COST TO STEAM GENERATOR REPLACEMENT Net Cost of Closing -
With Twa Steam Reference Generator Year Case Replacerents (Millicns of Mid 1982 Constant Dollars)
(1) (2) 1984 $435 $434 1985 365 359 1986 340 330 1987 250 232 1988 276 27 1989 294 271 1990 375 354 1991 427 409 1992 447 79 1993 465 420 1994 548 508 1995 500 466 1996 518 487 1997 576 549 1998 615 591 1999 653 632 2000 670 653 2001 691 675 2002 691 678 2003 693 681 2004 694 684 2005 669 661 2006 640 633 2007 337 335 2008 318 316 2009 296 294 i
Sources: Col. (1): Table 1.1, Col. (5).
Col. (2): Col. (1) adjusted for steam generator replacements in 1988 and 1992.
l i
L __-____ ___ _ _ _
- Table 17 l
l SENSITIVITY CASE LOAD GROWTH ASSUMPTIONS Higher Lower Reference Load Load Year Case Growth Growth (Annual NYS GWH)
(1) (2) (3) 1984 120,068 119,108 117,467 1985 121,891 121,880 118,545 1986 123,609 124,715 119,632 1987 125,311 127,617 120,729 1988 126,909 130,586 121,836 1989 128,636 133,625 122,954 1990 130,370 136,734 124,081 1991 132,287 139,915 125,219 1992 134,295 143,070 126,134 1993 136,178 146,297 127,056 1994 138,195 149,596 127,984 1995 140,260 152,969 128,919 1996 142,427 156,419 129,861 s
1997 144,472 159,947 130,810 1998 146,617 163,554 131,766 1999 148,818 167,242 132,729 Source: Testimony of Eugene Meehan.
- Table 18 j
SENSITIVITY OF NYS REFERENCE CASE NET COST TO LOAD GROWTH Net Cost of Closing Higher Lower Reference Load Load Year Case Growth Growth (Millions of Mid 1982 Constant Dollars)
(1) (2) (3) 1984 $435 $441 $427 1985 365 378 347 1986 340 358 314 1987 250 271 220 1988 276 303 235 1989 294 329 243 1990 375 423 305 1991 427 488 339 1992 447 520 356 1993 465 551 371 1994 548 645 450 1995 500 611 400 1996 518 645 414 1997 576 725 463 1998 615 784 496 1999 653 843 529 2000 670 864 544 2001 691 887 562 2002 691 886 564 2003 693 885 567 2004 694 884 569 2005 669 850 550 2006 640 812 527 2007 337 428 277 2008 318 404 261 2009 296 378 243 Sources: Col. (1): Table 1.1, Col. (5).
Col. (2): Col. (1) adjusted for higher load growth from Table 17.
l Col. (3): Col. (1) adjusted for lower i load growth from Table 17.
NEW YORK POWER POOL RESERVE MARGINS S Capacity S Capacity Less E Capacity, Less IP 2, IP 3 &
Annual Purchcase Reserve IP 2 IP 2 Reserve Reserve Year Peak & Sales Margin & IP 3 & IP3 Margin Prattsville Prattsville Wrgin (MW) (MW) (Percent) (W) (W) (Percent) (MV) (W) (Percent)
(2)-(l) (2)-(4) (5)-(l) (5)-(7) (8)-(l)
/(1) /(1) /(1)
(1) (2) (3) (4) (5) (6) (7) (8) (9) 1984 21620 31570 46.0 1829 29741 37.6 0 29741 37.6 1985 21750 32258 48.3 1829 30429 39.9 0 30429 39.9 1986 21990 32288 46.8 1829 30459 38.5 0 30459 38.5 1987 22180 32232 45.3 1829 30403 37.1 0 30403 37.1 1988 22610 33327 47.4 1829 31498 39.3 0 31498 39.3 1989 22870 34295 50.0 1829 32466 42.0 990 31476 37.6 1990 23150 34207 47.8 1829 32378 39.9 990 31388 35.6 1991 23430 34207 46.0 1829 32378 38.2 990 31388 34.0 1992 23750 34207 44.0 1829 32378 36.3 990 31388 32.2 l
1 1993 24060 34232 42.3 1829 32403 34.7 990 31413 30.6 1994 24410 34228 40.2 1829 32399 32.7 990 31409 28.7 1995 24720 34228 38.5 1829 32399 31.1 990 31409 27.1 1996
- 25050 34180 36.4 1829 32351 29.1 990 31361 25.2 1997 25350 34174 34.8 1829 32345 27.6 990 31355 23.7 l 1998 25660 34174 33.2 1829 32345 26.1 990 31355 22.2 1999 25980 34174 31.5 1829 32345 24.5 990 31355 20.7 Source: Col.(1): Testimony of Eugene Meehan.
Col.(2): Report of Member Electric Systens of the New York Power Pool and the BTpire State Electric Research Corporation Pursuant to Section 5-112 of the Energy 1.aw of New York State, 1982, Vol. 1, pp. 12 and 23, revised to reflect cancellations (see text).
4 0
Table 20 SENSITIVITY OF NYS REFERENCE CASE NET COST TO DISCOUNT RATE Present Value Discount Power Rate NYS Con Edison Authority (Millions of Discounted 1983 Dollars) 10 % $9,001 $3,362 $4,478 12 % 7,148 2,711 3,498 14 % 5,788 2,225 2,794 O
i 1
I
Tabla 21 3
OTHER CHANGES IN TAXES AND WORKING CAPITAL REFERENCE CASE New York State Lost Fuel Gross Core and Working Oil Receipts Additional Capital Inventory and Sales Decomm.
Year Addition Expense Taxes Cost (millions of current dollars)
(1) (2) (3) (4) 1984 $10 $12 $ 49 $105 1985 12 13 56 6 1986 12 12 57 6 1987 11 6 52 7 1988 13 7 60 7 1989 15 8 67 8 1990 18 13 85 8 1991 22 17 100 9 1992 24 20 112 9 1993 27 24 124 10 1994 29 27 136 158 1995 32 31 150 1996 36 34 167 1997 42 40 194 1998 47 45 218 l
1999 53 50 244 2000 57 55 266 2001 63 59 290 2002 66 63 307 l 2003 70 67 325 2004 74 70 343 2005 76 72 351 2006 77 73 357 2007 43 41 202 2008 44 42 205 2009 44 42 206 l
l 1
l
AVERAmitIFORTED CRUDR OIL FRICR FOIECASTS
- a 1980 1981 1982 Base Price x (1982 Dollars per Barrel)-------
5c:
39.30 39.27 33.55 a
f Forecasts Average Annual Growth Rate Date 1982-1990 19 6 source Published 1985 1990 200f 1982-1985
-W2 Dollars per Barrell)-- ' Percent) 41.40 44.70 7.3 3.7 Mfr (World Oil Project [ Dec.1981 47.83 4.5 Mfr (Jacoby/ Paddock)' Dec.1981 58.82 88.97 4.5 8.8 4.3 DOE /EIA (Midpricef Feb.1982 38.27 58.07 78.00 8.8 3.1 Gately' Feb.1982 48.87 4.8 IEES-OMS
- Feb.1982 39.43 57.88 2.0 3.9 IPE' Feb.1982 58.83 75.58 7.3 2.5 Selant-ICF ' Feb.1982 53.04 85.01 8.0 4.7 ETA-M ACRO' Feb.1982 50.87 73.78 5.3 3.8 WOIL " Feb.1982 80.21 82.15 7.8 3.2 Kennedy-Nehring Feb.1982 88.78 97.83 9.0 3.9 OILTAN K Feb.1982 42.08 43.99 2.9 0.4 Opeconomics " Feb.1982 87.84 92.01 9.2 3.1 OILM AR Feb.1982 May 1982 33.92 0.4 Bankers Trust
Sep.1983 37.81 4.1 Stanford
Oct.1982 33.92 9.4 IEA 3.3 32.15 38.02 53.47 -1.4 1.8 DRI " Oct.1982 o
37.54 45.78 8.4 1.4 2.0 ICF Base Nov.1982 34.00 2.9 28.90 29.43 35.87 -5.0 -1.8 Low Nov.1982 2.4 2.8 3.0 Nov.1982 38.07 41.82 58.19 High 37.10 58.30 -8.8 1.3 4.8 DOE /EIA (Prelimlruary)" Feb.1983 25.44 9
i Sources and Notes 1
U.S. Department of Energy, Energy Information Administration, Monthly Energy Review, February 1983, p. 82.1982 data from telephone conversation with Mr. Charles Riner, March 24, 1983. These prices reflect the average refiner acquisition cost of crude oils imported into the U.S. from various suppliers. Prices were adjusted to 1982 dollars with the GNP implicit price deflator. (1980 = 9.3 percent, 1981 = 9.4 percent, 1982 = 6.0 percent.
Source: 1983 Economic Report of the President, Table B-3.)
2 J. Carson, W. Christain and G. Ward, "The MIT World Oil Model," (MIT-EL 81-027WP), December 1981, p. 9. Prices were adjusted from 1979 dollars to 1982 dollars with the GNP implicit price deflator.
3 H. D. Jacoby and J. L. Paddock, "World Oil Prices and Economic Growth in the 1980's," (MIT-EL 81-060WP), December 1981, p. 39. The authors discuss a window of oil prices considered "not likely" for a smoothly changing world.
A range of likely 1990 Saudi marker crude Persian Gulf prices (in 1980 l
dollars) from $27/bb1 to $50/bb1 is forecast. To obtain a specific point forecast the mid-range of the Jacoby/ Paddock forecast was assumed. This forecast was adjusted to 1982 dollars using the GNP implicit price deflator.
The resulting price was then adjusted by $3.18/ bbl (1982 dollars) to reflect transportation and insurance costs.
4 U.S. Department of Energy, Energy Information Administration,1981 Annual Report to Congress, February 1982, Vol. 3, p. 6. Midprice case is displayed.
Prices were adjusted from 1980 dollars to 1982 dollars with the GNP implicit price deflator.
5 Energy Modeling Forum, World Oil: Summary Report, EMF Report 6, Stanford, CA, February 1982, Tables A-6, A-7. Prices were adjusted from 1981 dollars to 1982 dollars with the GNP implicit price deflator. Model designed by D. Gately, New York University and J. Kyle, Imperial Oil Ltd.
6 Ibid. Model designed by C. Kilgore, U.S. Department of Energy.
Ibid. Model designed by N. Choucri, Massachusetts Institute of Technology.
8 Ibid. Model designed by S. Salant, U.S. Federal Trade Commission and W.
Stitt, ICF Incorporated.
9 Ibid. Model designed by A. Manne, Stanford University.
10 Ibid. Model designed by J. Stanley-Miller, U.S. Department of Energy / Energy and Environmental Analysis, Incorporated.
11 Ibid. Model designed by M. Kennedy, University of Texas and R. Nehring, l Yaiid Corporation.
I Ibid. Model designed by L. Ervik, Chr. Michelsen Institute.
\
l 13 Ibid. Model designed by J. Mitchell, British Petroleum Co. Ltd.
14 Ibid. Model designed by F. Pott r . Energy and Power Subcommittee, U.S.
House of Representatives.
15 Bankers Trust Company, Energy Viewpoint, May 1982, Vol. III, No. 2. The report discusses the Saudi marksr price. The FOB price given was adjusted by $3/bb1 to reflect transportation and insurance costs to the U.S., then adjusted from 1981 dollars to 1982 dollars with the GNP implicit price deflator.
16 B. G. Hickman and H. G. Huntington, " EMF 7 Study Design," (EMF WP 7.1, revised) Energy Modeling Forum, Stanford, CA, September 1982. Nominal 1985 price was deflated to 1982 dollars assuming 6.0 percent escalation per year. The FOB price given was adjusted by $3.18/ bbl (1982 dollars) to reflect
, transportation and inst:rance costs.
17 Platt's Oilgram News, October 12,1982, p. 2. The $29/ bbl price quoted in the article was adjusted by $3/bb1 to reflect transportation and insurance costs, then adjusted from 1981 dollars to 1982 dollars with the GNP implicit price deflator.
18 Data Resources,Inc. Energy Review, Autumn 1982.
19 ICF Incorporated, Forecast of Fuel Markets and Prices in New York State, Volume 1: Oil and Gas Markets and Prices, Presented to New York Power Pool, November 1982, p.1-1.
20 U.S. Department of Energy, Energy Information Administration. Preliminary forecasts from telephone conversation with Mr. Daniel Butler, March 23, 1983.
i k
i
l l
Appendix 2 Table 1 REGRESSION RELATING CAPACITY FACTOR TO SELECTED UNIT CHARACTERISTICS PWRs Only To 1978 Variable Regression Variable Mean Coefficient t-Statistic (1) (2) (3)
Constant -
81.89 -
Size 6-800 MW l 0.147 -3.45 -0.91 Size 800MW and Up 1 0.479 -12.69 -4.37 One - Three Years 1 0.595 -10.12 -3.87 Cooling Towers 1 0.178 -6.85 -2.11 Salt Water Cooling 1 0.350 -0.44 -0.10 2
Salt x Age 1.196 -0.43 -0.47 SG Replacement
- 0.067 -0.66 -0.13 Turnkey 1 0.276 -4.47 -1.51 3
TM1 - - -
l Number of Observations 163 I
R-Squared 0.290 Adjusted R-Squared 0.253 Standard Error of Estimate 13.906 l
l l
- Equals 1 if the unit has the characteristic named, and 0 otherwise.
2
- Equals age if unit is salt water cooled, and 0 otherwise.
3 Equals 1 in calendar years 1979,19P0 and 1981, and 0 otherwise.
l nie/ria"
Appendix 2 Table Z REGRESSION RELATING CAPACITY FACTOR TO SELECTED UNIT CHARACTERISTICS PWRs Only To 1979 Variable Regression Variable Mean Coefficient t-Statistic (1) (2) (3)
Constant -
82.89 -
Size 6-800 MW 1 0.139 -5.91 -1.66 Size 800MW and Up 1 0.512 -14.10 -5.16 One - Three Years 1 0.537 -10.33 -4.22 Cooling Towers 1 0.184 -6.33 -2.14 Salt Water Cooling 1 0.353 1.82 0.45 Salt x Age 2 1.323 -0.77 -0.97 SG Replacement 1 0.065 -6.89 -1.47 Turnkey 1 0.254 -4.02 -1.43 TMI 3 0.189 -6.63 -2.40 Number of Observations 201 R-Squared 0.319 Adjusted R-Squared 0.287 Standard Error of Estimate 14.282 1
Equals 1 if the unit has the characteristic named, and 0 otherwise.
2 Equals age if unit is salt water cooled, and 0 otherwise.
3 Equals 1 in calendar years 1979,1980 and 1981, and 0 otherwise.
n/e/r/a
, Appendix 2 Tc bla 3 E, '
~
REGRESSION RELATING CAPACITY FACTOR TO SELECTED UNIT CHARACTERISTICS PWRs Only To 1980 Variable Regression Variable Mean Coefficient t-Statistic (1) (2) (3)
Constant -
82.69 -
Size 6-800 MW 1 0.134 -5.76 -1.68 Size 800MW and Up 1 0.536 -13.88 -5.32 One - Three Years 1 0.481 -9.39 -4.01 Cooling Towers 1 0.188 -7.79 -2.81 Salt Water Cooling 1 0.356 4.18 1.09 Salt x Age 2 1.469 -1.37 -1.96 SG Replacement 1 0.063 -9.29 -2.08 Turnkey 1 0.238 -4.68 -1.72 TMI 8 0.318 -6.70 -2.89 Number of Observations. 239 R-Squared 0.296 Adjusted R-Squared 0.268 Standard Error of Estimate 14.722 1
Equals 1 if the unit has the characteristic named, and 0 otherwise.
2 Equals age if unit is salt water cooled, and 0 otherwise.
8 Equals 1 in calendar years 1979,1980 and 1981, and 0 otherwise.
j n/e/r/a
. Appandix 2 Table 4 i
REGRESSION RELATING CAPACITY FACTOR TO SELECTED UNTP CHARACTERISTICS '
PWRs Only To 1981 Variable Regression Variable Mean Coefficient t-Statistic (1) (2) (3)
Constant -
82.91 -
Size 6-800 MW 1 0.129 -6.30 -1.91 Size 800MW and Up 1 0.556 -13.68 -5.51 One - Three Years 1 0.427 -9.66 -4.31 Cooling Towers 1 0.194 -7.95 -3.08 Salt Water Cooling 1 0.355 6.03 1.66 Salt x Age 2 1.613 -1.89 -3.10 SG Replacement 1 0.061 -8.19 -1.93 Turnkey 1 0.226 -5.18 -1.98 TMI 3 0.416 -5.53 -2.56 Number of Observations 279 R-Squared 0.272 Adjusted R-Squared 0.247 Standard Error of Estimate 15.018 1
Equals 1 if the unit has the characteristic named, and 0 otherwise.
2 Equals age if unit is salt water cooled, and 0 otherwise.
3 Equals 1 in calendar years 1979,1980 and 1981, and 0 otherwise.
nielria
Appendix 3 CORRECTION FACTOR FOR DEMAND ELASTICITY If demand elasticity equals e, a rise of Ap in price will cause a reduction of Eq in demand.
The loss to consumers is given by AP '
Loss = Ap . Q, 2 III In Diagram 1 p"
D Loss to Consumers .
^
&Q P '
A\\\\\\W a AP O Correefica Fr4 der l
D Q3 Qo
! In the diagram, DD is the demand curve for electricity, P o is the intial price, Qg is the initial quantity, P1 is the final price, Q1 is the final quantity and ;
Ap, aq are the changes in price and quantity.
1 The loss to consumers is given by the heavy shaded trapezoid, which is equal to the rectangle &p . Q9 less the small triangle, whose area is half Ap . Aq. (See the equation above.)
c-4 Since o
=h.c o Where c is the elasticity of demand Then &q = h . Q, . e o
And the equation (1) becomes Loss = 1p . Q - hp . Q ( ,j)
= &p . Q (1 - . f)
The correction factor is equal to half the percentage change in price times the elasticity of demand. After correction, the loss to consumers in the present case amounts to over 99 percent of the calculated amount. Various combinations of price change and elasticity are given below.
Fina1 Impact After Elasticity As a Percentage of Calculated Dollar Impact Elasticity c= .1 .5 - 1.0 Price Increase
.E.R P
5% .997 .987 .975 10 % .995 .975 .95 15 % .992 .962 .925 What ESRG has done is to estimate the correction factor as &q . P g rather than & q . Ap/2.
4 P 2, Pg .
% Y
/ ESRG Proposed Offset f
/
/
/ -
/l/
/ -Q 01 0 0 Aq.P iso the change in revenues, but it represents foregone electricity. This electricity was obviously worth the original price to the customers, because they were prepared to pay that much for it before the price rise. Losing it because it l
l is too expensive is in no way a benefit.
l l
i t
l
{
l t
\
6 s ,
. Exhibit 1 k
e SALLY HUNT STREITER ,
i
\ ,
\
I was an open schola) of Somerville College, Oxford, England, where I studied economics and philosofhy,,and graduated with honors. I also received my M.A. degree from Oxford. As a rerearch assistant at the London School of Economics, I took part in a large econometric study of educational productivity.
Afjer emigrating. to t'a United States, I joined Consad Research Corporation, and assisted in a study of the oil depletion allowance. I was chief investigator for an econometric study of the effects of economic development policies on unemployment in Appalachia. S
, In 1969 I joined the, New York City Budget Bureau as a planner on f education, and developed a model of the effects of different policy variables on 5
reading levels of school children. I also developed a simulation model to
, distribute funds tc school districts in the City in accordance with the new education law. I was promoted to head of the Environmental Protection section of the Budget Bureau planning staff, where I performed and directed analyses of air pollution control strategies, water pollution control strategies and refuse disposal options.
In 1972 I became Assistant Commissioner in the New York City Department of Air Resources, the agency with regulatory responsibility for fuel burning in New York. In this capacity I became familiar with the disruptions in the fuel markets in the early 1970s. In late 1973, when the OPEC embargo threatened New York, I was asigned to a$alyse ' requests for variances from the Air Pollution Control laws,'and negotiated with State and Federal Officials and with fuel users, in particular Co1 Edison, to determine prudent solutions to the i
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, impending crisis. I sat as an examiner in a public hearing, and presented testimony on behalf of the city in PSC hearings on Con Edison's request to convert to coal. I was named Deputy Director of the City Energy Office at its inception. 1 In late 1974, I joined NERA, where I have worked since then. Initially I was assigned to the task of rate structure revision, and developed a simplified model of marginal cost pricing which drew heavily on the planning process of utilities.
This became the basis for the NERA costing methodology, on which I testified in many States. I also performed many studies of the energy situation in general, and the electric industry in particular; I analyzed the economics of coal versus nuclear units for new ecastruction in a 1976 study, and prepared an analysis of Amory Lovins' proposals for alternatives to conventional generation in 1977. I was chief investigator for the plaintiffs in a case brought by Commonwealth Edison and others against the Montana Coal Severance Tax, which involved extensive studies of coal markets. I was project director of a large econometric study of the availability of large coal-fired units, and of another study of the economics of conversion of oil-fired units to coal. This latter involved an analysis of the course of oil and coal prices. I have given speeches and testified on most of these subjects.
I have also published articles on the feasibility of trending the rate base to avoid rate shock when new nuclear units come on line, and have testified in three recent cases on criteria for evaluating proposed efficiency clauses in electric ratemaking.
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