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Home My WebLink AboutL.I. Without Shoreham Power Plant. 1983 - Summary of findings - Planning Conseq.83-14/S LONG ISLAND WITHOUT THE SHOREHAM POWER PLANT: ELECTRICITY COST A~D SYSTEM PLANNING CONSEQUENCES S-wnary of Findings Prepared for the County of Suffolk L~uw OF souT~oL.o i by ENERGY SYSTEMS RESEARCH GROUP, INC. 120 Milk Street Boston, Massachusetts 02109 ($17) 426-5844 Principal Investigator Paul D. Raskin Project Team Thomas Austin Stephen Bernow Bruce Biewald David McAnulty David Nichols Richard Rosen Jonathan Wallach July, 1983 E S R 0 TABLE OF CONTENTS LIST OF TABLES AND FIGURES. 2. 3. 4. 5. 6. 7. 8. SUMMARY OF FINDINGS LOAD FORECAST . SUPPLY PLANNING SHOREHAM OPERATIONS AND COSTS COST IMPACTS OF NOT OPERATING SHOREHAM THE POTENTIAL ROLE OF CONSERVATION SENSITIVITY ANALYSIS REVIEW OF LILCO'S COST IMPACT ESTIMATES AND "CRITIQUE". TECHNICAL REPORTS A. Long Range Forecast of Electricity Requirements in the LILCO Service Area B. Shoreham Operations and Cost C. The Conservation Investment Option D. Sumary of Computer Outputs Page ii 1 19 30 40 6O 67 72 76 - i - E S R G Table No. 1 2 3 4 5 6 7 8 9 10 11 12 13 Figure No. 1 2 3 4 5 $ 7 8 9 LIST OF TABLES RATE IMPACTS OF ABANDONMENT UNDER ALTERNATIVE SCENARIOS FORECAST OF ENERGY AND PEAK DEMAND FORECAST SU~%RY DISAGGREGATED FORECAST BY SUBSECTOR COMPONENTS ANNUAL SHOREHAM REPLACEMENT POWER COSTS OPERATIONS AND MAINTENANCE COSTS FOR NUCLEAR STATIONS IN THE U.S. SHOREHAM PLANT OPERATIONS AND MAINTENANCE COSTS NET CAPITAL ADDITIONS FOR NUCLEAR STATIONS IN THE U.S. COSTS AND REVENUE REQUIREMENTS FOR SHOREHAM NET CAPITAL ADDITIONS SHOREHAM NUCLEAR POWER PLANT OPERATIONS AND COSTS SUMMARY . REVENUE REQUIREMENTS.COMPARISON: RATE WASH CASE SUMMARY REVENUE REQUIREMENTS COMPARISON: RATE WASH CASE RECONCILIATION OF LILCO COST IMPACT ESTIMATES WITH RATE WASH SCENARIO LIST OF FIGURES RATE IMPACTS OF ABANDONMENT - ALTERNATIVE SCENARIOS REVENUE REQUIREMENTS AND RATES''--'1983-2013. SHOREHAM COSTS VERSUS ABANDONMENT COSTS - SELECTED YEARS AND 20 YEAR AVERAGE COMPARISON OF HISTORIC CHANGES IN 1990 PEAK FORECAST FOPU T ON - l s -i9 2' COMPARISON OF 1983 LI O AND RSRG PEAK FORE- CASTS AND GROWTH TREND IN PEAK REQUIRED CAPACITY AND TOTAL CAPACITY, SHOREHAM-OUT SHOREHAM CAPACITY FACTORS - ESRG AND LILCO ASSUMPTIONS RECONCILIATION OF LILCO ESTIMATE OF ABANDON- MENT COSTS WITH THE RATE WASH CASE Page 4-5 25 26 27 36 46 49 52 54 59 64 66 78 Page 6 9 10 20 21 23 33 44 79 - ii - E S R G 1. SUMMARY OF FINDINGS The County of Suffolk has determined that no emergency plan "could protect the health, welfare and safety of Suffolk County's residents if there were a serious'accident at the Shoreham facility." The County goes on to conclude that the nearly completed nuclear power plant "shall not operate and must be abandoned."* The question that naturally arises is: what are the economic repercussions of not operating Shoreham? This report sum- marizes the results of a detailed analysis of the likely cost impacts on' Long Island Lighting Company (LILCO) ratepayers.** Will ratepayers' bills be higher or lower if Shorehem does not operate (compared to if it does operate)? What is the magnitude of such rate impacts? These questions are addressed by simulating the flow of revenues LILCO will derive from its ratepayers ("required revenues") under a variety of Shoreham-Out cases and comparing these to required revenues should Shoreham operate. The difference in required revenue streams is the "bottom line" * County Resolution No. 111, February, 1983. ** Parallel studies sponsored by the County of Suffolk will explore issues other than direct rate impacts such as LILCO's financial stability under alternative scenarios and property valuation and tax consequences. - 1 - E $ R G cost impact measure.* To compute these effects it is necessary to examine such issues as electrical energy and peak demand forecasts in the LILCO service area, power supply planning with and without Shoreham, and the likely performance characteristics and costs of operating Shoreham. The results of this investigation are summarized in the remainder of this section and expanded on in the sections to follow.** First, however, it is important to state one overall con- clusion: abandoning Shoreham will not result in an economic disaster for ratepayers as posited by LILCO in its recent analyses. Rather, under most scenarios considered in this report, it actually costs the ratepayers less if Shoreham is abandoned. Indeed, in the most favorable abandonment scenario to LILCO -- one where the plant never operates but LILCO gets full return on its entire Shoreham investment -- the rates incurred by LILCO ratepayers will be only a small fraction above the rates to be charged if the plant is operated. Accordingly, as this report documents, utility rates will likely increase in the future in both the Shoreham-~n and Shoreham-Out scenarios. However, the rates may in fact increase somewhat less if Shoreham never operates but, at worst, the rate impacts in the Shoreham-In and Shoreham-Out cases are largely comparable. -"*Formally stated, the cumulative present value of required revenues under alternative scenarios have been computed and compared. Present value calculations are a commonly used approach in comparing costs and benefits which occur at different points in time. The procedure discounts future costs and benefits to reflect the time value of money and underlying inflation. **Technical documentation is presented in the four companion volumes listed in the Table of Contents. E S R O Cost Impacts The average percent impact on rates and cumulative cost differentials of abandoning Shoreham are presented in Table 1. The results in terms of percent rate impacts are illustrated graphically in Figure 1. A benchmark cost comparison in which the ratepayers are on average no worse off with Shoreham out than with Shoreham in ("Rate Wash" scenario) is listed first. This case embodies the basic forecast, system planning, and power cost parameters developed in the course of this investigation (see Sections 2-5 and Technical Reports A, B, and D). - 3 - E S R G TABLE 1 RATE IMPACTS OF ABANDONMENT UNDER ALTERNATIVE SCENARIOS Scenario Rate Wash Load Forecast - High - Low Fuel Price Escalation - High - Low Energy From Power Pool - High Low Nuclear O&M Costs - High - Low Future Shoreham Investment - High - Low Shoreham Capi- tal Recovery - Full Low Description Rates unaffected by abandonment* Cost Impact of Abandonment Cumulative Change Average in Required Revenues Percent (1983 present value Change in dollars in millions) Rates 0 0.0% 1.6%/year peak growth (from base case of 0.8%) 230 0.0%/year peak growth -310 1.1 -1.6 oil at 3% real, after 1987 (from 2%) Coal at 2% (from 1%) 120 Oil at 1% real, after 1987. Coal at 0% real -100 0.6 -0.5 Double energy assumed available (Sec. 3) -50 No energy available from pool 60 -0 · 2 0.3 Double real increase in projected costs (Sec. 4) -210 No real increase in costs 210 -1.1 1.1 Double real increase in projected investments (Sec. 4) -290 No real increase in investments 290 -1 · 4 1.4 100% of Shoreham in rate base (vs. 91%) 430 65% of Shoreham in rate base -1340 2.2 -6.7 - 4 - F~ S R G TABLE 1 (Continued) RATE IMPACTS OF ABANDONMENT UNDER ALTERNATIVE SCENARIOS Scenario Time Period of Analysis - Long Description Cost Impact of Abandonment Cumulative Change in Required Revenues (1983 present value dollars in millions) 30 years, 1984-2013 (from 20 years) - 60 - Short 10 years, 1984-1993 -160 Pursue conservation to replace Shoreham generation Effects of having started the Shoreham Project in the first place Conservation Investment Option Shoreham Never Built** Average Percent Change in Rates -0.3 -1.2 -580 -2.9 -3405 -17.0 *The base data used in the Rate Wash case is described at length in the text of this report. In the sensitivity tests reported here, individual data items of the base set were modified one at a time. **This is equivalent to a case in which ratepayers are fully protected from the costs of the Shoreham investment. - 5 - £ S R G Percent Impact on Rates 4% 0 -4% -12% -16% Pate I~k%d Fuel Price Wash Forecast Escalation High High Power High Future Shoreham Nuclear Shoreham Capital O&M Investment Be~over~ Full Hi~ High Low Period vation Shoreham Never Built 10 YR The treatment of Shoreham investment costs under abandonment is an issue that would be determined by the Public Service Commission through the regulatory process. The Rate Wash scenario is based on the assumption that 91 percent of the Shoreham investment enters the rate base. Re-stated, if LILCO were allowed full return on debt service and capital costs and amortization of 91 percent of the abandoned investment, ratepayers would be no worse off than if Shoreham operated. The Rate Wash scenario is presented in this report for comparison purposes. It does not ~onstitute a recommended amount of return for LILCO on its Shoreham investment, such a decision belongs to the New York State Public Service Commission and will involve complex policy and factual questions. It is important to note, however, that the Rate wash scenario is a realistic option if Shoreham is abandoned. Many persons would argue that investors should share even more of the Shoreham costs if the plant never operates.* At any rate, the experience in other cases indicates, at a minimum, that where a major power plant investment is abandoned, a less than 100 percent return is the norm. Thus, we have chosen the 91 percent return "Rate Wash" scenario as our benchmark case. The revenue requirements over time in the Shoreham-In versus Shoreham-0ut (Rate Wash) scenario are graphed in Figure 2, along with a plot of the cost differences. The jump in costs in 1984 will be noted in both scenarios. After that the revenue *On the other hand, LILCO would have the ratepayers pay more on the Shoreham investment if it is abandoned (see Section 8). - 7 - E S R G trajectories track closely with minor ratepayer advantages to Shoreham-0ut in the earlier years, crossing over in the 1990s to favor Shoreham-In but, by design, averaging to zero effect. The breakdown by cost component is shown in Figure 3. Here, the various costs incurred by ratepayers to support Shoreham operations are compared to those incurred under abandonment. The comparisons are shown for selected years and for the 20-year average annual costs. Details are presented in Section 5. The other scenarios in Table 1 compute the impacts of adjusting various baseline assumptions. For example, it is found that if 65 percent*, rather than 91 percent, of the Shoreham investment enters the rate base, ratepayers would pay 6.7 percent less with Shoreham abandoned than with Shoreham operating and fully in the rate base. On the other hand, if Sh0reham were abandoned bat 100 percent of the investment and return were allowed, we see that rates would increase by 2.2 percent more in the abandoned scenario than in the operation scenario. This is the case most favorable to LILCO and shows that the cost impact of abandoning Shoreham is likely to be small at worst. Examining Table 1 further, we see the variation in cost impact with respect to a range of inputs -- load forecasts, Shoreham operations and maintenance cost estimates, capital expenditure projections, make-up power availability and fuel prices. In no instance, with the exception of the 65 percent recovery scenario alluded to above, are the impacts substantial. *This "Low Return" scenario is designed to maintain dividend yields, achieves a coverage ratio on debt of at least 2.4, and maintains internal generation of cash at at least 40 percent of construction requirements. Georgetown Consulting Group (report forthcoming). - 8 - FIGURE 2 REVENUE REQUIREMENTS AND .RATES - 1983-2013 Total Revenue Requirements (Million 1983 PV $) 2000 1500- 500. Shoreham operates ...................... Shoreham Abandonm~n~ 1983 1995 2003 2013 Cost Impact of (Million 1983 5 50' 25 25 1983 1995 2C 2013 FIGURE 3 SHOREHAM COSTS VERSUS ABANDONMENT COSTS SELECTED YEARS AND 20 YEAR AVERAGE Revenue Requirements (Millions 1983 PV $300 1 9 9 3 2 0 0 3 Spent Fuel and Decommissioning 20 YEAR AVERAGE Capital Makeup Energy $200 $100 Invest- m~nt Invest- ~_nt Recovery Capital New Plant Prop. Tax Shoreham Costs Abandonment Costs Inv. Shoreham Costs Inv. Bec. Abandonment Costs Shoreham Abandonment Costs Costs The. scenarios in Table 1 entitled "Time Period of Analysis" require some explanation. In the baseline runs discussed in this report, rate impact effects are computed over the twenty-year timeframe 1984-2003. The decision to base the analysis on twenty years was made because impacts beyond that time must be considered highly speculative.* In addition to the usual difficulties of performing economic and financial assessments that go beyond a fifteen to twenty year period, there is no experience at this time with commercial nuclear power plants of that age on which to base analytic judgments. Projections based on the aging patterns of currently existing facilities show severe deterioration in performance and escalating repair and upkeep costs. In an effort to assess the sensitivity of the results to a different time range, ESRG has also performed analyses of Shoreham-In vs. Shoreham-Out for a thirty-year period (1984-2013) and for a ten-year period (1984-1993). Extending the analysis over the thirty-year period 1984-2013 shows that costs in the last ten years are higher if the plant is operating rather than abandoned, thus improving the economics of abandonment (see Table 1). The same is true if one selects ten years. However, twenty years is recommended as a more reasonable period on which to focus and to base policy decisions. *LILCO's analyses have extended to forty years (see Section 8). They are presented without caveats underscoring the high degree of unreliability involved. This seems astonishing when the Company's performance on load forecasting, system requirements, and construction costs have been so strikingly inaccurate over the past ten years. - 11 - E S R G The next scenario shown in Table 1 -- Conservation Investment -- assumes that a decision to abandon Shoreham triggers an extra emphasis on promoting and financing measures to improve the efficiency of the delivery and consumption of electrical energy. There remains cost-effective conservation potential beyond the substantial efficiency improvements already incorporated in our LILCO load forecast. If vigorous conservation measures were promoted, the impacts of not operating Shoreham would be mitigated further. Later in this report (Section 6 and Technical Report C), the outlines of such a conservation program are described. The effect of adding a conservation program are seen to decrease costs to the ratepayers of abandoning Shoreham by about 2.9 percent. Finally, Table 1 presents the "Shoreham Never Built" scenario, which estimates the average impacts over time of having begun the Shoreham project in the first place -- rates will be about 17 percent higher with Shoreham than if it never were built.* The combination of decreasing forecasts of power needs and escalating nuclear costs combined to make the Shoreham project both unnecessary and extremely costly. *Equivalently, if ratepayers were fully protected from the Shoreham investment costs if the plant does not operate (e.g., none of the Shoreham costs recuperated by LILCO), rates would be 17 percent lower than with Shoreham operating with investment costs fully recovered. However, this would likely lead to the financial collapse of the Company, with difficult-to-quantify indirect consequences. - 12 - E S R G Load Forecast Summer peak demand in the LILCO service area is likely to grow at an average rate of 0.8 percent per year over the 1982-2000 period. This forecast was developed by using a detailed end-use model analysis that has been validated in LILCO service area forecasts since 1977. Our forecast is above the 0.2 percent per year annual growth rate that would result from simple time extrapolation of recently experienced summer peaks (suitably adjusted for weather and time-of-peak fluctuations), and above the current official New York State 0.3 percent per year population growth projection. The Company's forecast (1.6 percent growth per year in summer peak load) continues to reflect remnants of the combination of overly optimistic growth judgments and model formulation problems that have over the years led LILCO to seriously overestimate load growth prospects for Long Island. Power Supply Planning Issues and Costs If Shoreham does not operate there will be a need, beginning in 1998, for additional generating capacity. This finding reasonable assumes that the other elements of the Company's supply plans remain unchanged -- the power plant additions, the retirement schedule for existing facilities, and the enhancement of transmission interconnections with other power systems. It also assumes that no additional conservation effort would occur with Shoreham not operating. In Section 8, the sensitivity of rate impacts to both earlier and later in-service dates for substitute power are examined and shown to have only minor impacts (less than one percent on rates). - 13 - £ S R G In comparing a scenario with Shoreham not operating to one with Shoreham operating, the Shoreham-Out case will require that the energy that would have been produced by Shoreham be provided by other facilities (assuming again no extra conserva- tion beyond Base Case levels). Furthermore, as indicated above, additional capacity will be required beginning in 1998. During the 1984-1997 period the make-up energy will come from two sources: LILCO's existing oil-fired power plants and, especially after the planned new transmission line comes into service in 1990, from imports from the New York Power Pool. In the primary cost comparisons discussed here, the capacity shortfalls in the late 1990s are assumed to be met by construction of two 400 MW coal plants, one in 1998 and one in 2000. LILCO also assumes such coal plants in the event Shoreham does not operate, but in 1994 and 1996, based on the Company'.s higher forecast.* From 1998, therefore, the make-up energy is coal-based. (Indeed, two such coal plants would produce more energy than Shoreham would have, leading to some oil-displacement benefit after 2000 in the Shoreham-Out case.) Additional construction is required in both the Shorehem-In and the Shoreham-Out cases, beginning in the year 2004. This fact does not affect our impact assessment, which is concerned with the differences between the two scenarios. *Section 2 discusses why this forecast is too high. The implica- tions of the higher forecast are to exaggerate the costs of abandonment by about $310 (1.1 percent rate impact) as shown in Table 1. - 14 - E S R G Before the end of the century, when additional capacity will be required in the absence of Shoreham, a number of alternatives to conventional coal may be available. The alternatives may include combinations of greater conservation, wind generated power, solar power, and modular power systems (e.g., fuel cells or fluidized bed combustion). Additionally, there is the possibility that refurbishing and extending the lifetime of aging oil-fired units may prove cost-effective. Ail these possibilities are currently under active investigation. However, because of present uncertainties concerning availability, engineering, and costs, they have not been included in this analysis. Should the uncertainties concerning these alternatives to coal be resolved favorably over the fifteen-year period before makeup capacity for Shoreham is required, then the costs of substitute power may well be less than those calculated here. Costs of Operating Shoreham If Shoreham does operate, the costs of both substitute energy and new generating capacity in the late 1990s, discussed above, can be-avoided. However, substantial other costs will be incurred to operate the plant. These include the costs of nuclear fuel, operations and maintenance costs, additional capital ex- penditures over the life of the plant, costs of decommissioning at the time of plant retirement, and costs for disposal of radioactive fuel. Additionally, the electric revenues required from customers will include Shoreham property taxes, though this is partially offset by property tax charges for the additional construction eventually required in the Shoreham-Out case. - 15 - E S R G Critique of LILCO In Section 8 of this report, LILCO's findings on the costs of not operating Shoreham are discussed. LILCO's analysis contains serious shortcomings in method (for example, the findings are expressed in inflated dollars extrapolated over a forty-year period) and flaws in judgement (costs that would be incurred whether or not Shoreham operates are charged to abandon- ment (such as the Bokum write-off and currently-planned system upgrade expenses). Furthermore, undocumented "engineering" estimates of nuclear plant performance and costs are relied on that are much more optimistic than indicated by analysis of the actual experience. There is simply no valid technical basis for LILCO's hysterical tone concerning the economic consequences of Shoreham. Indeed, of the $25 billion difference between LILCO's estimates and, say, the Rate Wash scenario, over 90 percent disappears simply by employing a common time frame and consistently discounting to common dollars (Table 13). The bulk of the remainder is related to extra costs that LILCO incorrectly charges to abandonment and the combination of high forecasts of load growth and low projections of Shoreham costs of operation. Finally, a small fraction (less than 2 percent) of the difference is related to the cost sharing scheme (91 percent of Shoreham in Rate Base) employed in the rate base. LILCO not only fails to consider a scenario where Shoreham cost recovery is shared between ratepayers and stockholders, but actually assumes that ratepayers would pay more for the Shoreham investment when the plant is abandoned than if it ran. - 16 - E S R G Finally, LILCO's critique of a preliminary version of the present document is briefly reviewed. In its critique, the Company "adjusts" the County's findings by reinserting its own assumptions and not surprisingly rederives its own estimates. A number of miscellaneous criticisms are shown to be unfounded in Section 8. LILCO's presentation, in its methods, scenario definition, and assumptions, consistently biases the estimate of cost impacts to favor Shoreham operation. The range of scenarios developed here show, contra-LILCO, that under reasonable variation of key parameters, the cost impacts of not operating Shoreham are not likely to be far from zero, one way or the other. Other Issues Certain other issues beyond the electric cost impacts focussed on in this analysis should also be considered to fully assess the Shoreham question. First, since in the scenario emphasized here LILCO customers are not assessed the full capital-related costs of the Shoreham plant, the impact of such partial recovery of investment on LILCO's financial health deserves consideration. Georgetown Consulting Group is developing recommendations for treating the abandoned Shoreham investment consistent with equity, sound regulatory principles, and the continued financial and operational viability of LILCO. At this time, it may be stated with confidence that in the benchmark 91 percent recovery Rate Wash scenario, the C~pany's financial health can be readily maintained. The County's final recommendation regarding the appropriate regulatory treatment of the Shoreham abandonment will be made to the PSC at a later date. - 17 - £ S R G Second, the reduced property taxes resulting from not opening Shoreham are a credit to required revenue for electricity. But at the same time they are a loss to government revenues and would have to be made up. Here, it is worth noting that the individuals most affected by the loss of Shoreham property tax revenues, those in the vicinity of the plant, benefit the most from avoiding both nuclear risk and depressed property values.* Third, we note that health and safety tradeoffs are not quantified here. Any negative impacts or costs of Shoreham abandonment would have to be weighed against the desirability of avoiding, for example, public safety risks. Fourth, for the longer term, there is a benefit to the Shoreham-Out case not included here. When Shoreham would be retired at the end of its useful life, additional construction would then be required while, on the other hand, the additional plants required toward the end of the century if Shoreham does not operate will have many operational years remaining. Finally, this analysis does not take account of the likelihood that Shoreham's in-service date will be delayed beyond January 1, 1984, nor does it consider the costs associated with such delay. The impact of one year's delay is approximately a $300 million increase in the cost of plant, which would lead to even higher base revenue requirements in the future. In this case, the economics of Shoreham abandonment on January 1, 1984 would be improved. *These matters will be discussed in forthcoming studies prepared for Suffolk County. - 18 - E S R G ' 2. LOAD FORECAST An independent forecast of the annual electrical energy requirements and peak load (mmximum demand for power during the year) has been performed.* The forecasting model used -- a detailed end-use/engineering computer system -- has been applied to forecast the demand for electricity in the LILCO service area since 1977. The forecasting model has in the past produced stable and high-confidence forecasts. It anticipated the necessity for LILCO to radically revise its long-range forecasts during the late 1970s and early 1980s. The historic pattern is illus- trated in Figure 4, which shows the precipitous drop in the LILCO forecast of the 1990 summer peak after 1974. Earlier ESRG forecasts are also shown. The dramatic decrease in LILCO's load growth forecasts (and corresponding adjustments in plans for new power plant construction) can be traced to several factors. First, the slowdown in population and economic growth prospects for Long Island from the post-World War II boom levels were gradually incorporated into the forecasts. The pattern of levelling off in population growth during the 1950-1982 period is shown in Figure 5. * Full documentation on the mathematical structure of the ESRG model, data base, assumptions, and literature references are contained in Technical Report A. - 19 - ~ S R G Figure 4 COMPARISON OF HISTORIC CHANGES IN 1990 PEAK FORECAST SO00 7000 6000 5000 4000 3000 2000 1000 0 ESRG YEAR OF FORECAST - 20 - E S R G GROWTH 1.5 1.0 POPULATION .5 OF NASSAU AND SUFFOLK COUNTIES FROM 1950 TO 1987_ 1960 1970 1980 1990 YEAR : (millions) 0 1950 Second, the changes in energy consumption patterns, conservation initiatives, and the regulatory and policy context that were ushered in by the 1973 oil embargo and energy price jolts were eventually recognized as permanent alterations to the long-term energy planning context, rather than as temporary aberrations. Third, serious methodological and conceptual pitfalls in LILCO's forecasting apparatus were identified. These were largely corrected. Despite the corrective alterations in their earlier forecast procedures, the Company retains to this day a tendency to forecast with unwarranted optimism. Figure 6 shows the Company summer peak forecast to the end of the century.* The average annual growth rate is 1.6 percent per year. For contrast, the actually experienced summer peak over the 1973-1982 period is also shown (the growth rate was 0.5 percent per year) along with a time trend on that historic experience. Finally, the forecast developed for the current invesigation (0.8 percent per year) is also shown on Figure 6. Analysis of the assumptions in LILCO's latest forecast reveals that the higher LILCO forecast is traceable to certain * The Company current long-range forecast is contained in the 1983 Report of Member Systems of the New York Power Pool (Vol. 1) submitted to the New York State Energy Office. 22 - E S R G Figure 6 COMPARISON OF 1983 LILCO AND ESRG PEAK FORECASTS AND GROWTH TREND IN PEAK 4000 3500 3000 2500 LILCO ESRG TREND NORMALIZED SUMMER PEAK EXPERIENCED (MW) - 23 - judgemental rapid-growth inputs and some continuing problems with self-consistency in their methods.* The summary independent forecasts used in the Shoreham impact analysis are presented in Table 2. These are labelled Base Case forecasts since they capture evolving trends in prices, regulatory policy, technology, consumer behavior, and conservation effort. They are employed in the basic cost comparisons of Shoreham-In versus Shoreham-Out. The results are recast as growth rates in Table 3. Below we shall introduce an alternative scenario -- the Conservation Policy Case -- which shows how through a more vigorous promotional effort by LILCO, the forecast could be reduced substantially. The breakdown of Base Case energy requirements for subcategories within the residential, commercial, and industrial sectors is displayed in Table 4. As seen there, consumption increases are anticipated for most of the * The critique of LILCO's methods is spelled out in Technical Report A. The main problems are: (1) there are discontinuities in its short-range (to 1986) and long-range methods leading to inexplicable and unreasonable jumps in demand; (2) there is overestimation of residential appliance ownership levels by the year 2000 (e.g., 3.4 television sets per houshold in a period of shrinking household size); (3) there is extreme growth in electric water heat and electric space heat usage (virtually all new customers plus substantial switching by existing oil and gas users); and (4) there are no price and conservation impacts assumed in certain commercial subsectors (despite the large price increases anticipated during the 1980s) even though the time series used to generate forecasts dates back to the rapid-growth period of the 1960s. - 24 - £ S R G TABLE 2 FORECAST OF ENERGY AND PEAK DF24AND ENERGY EH GUH PEAK POUER LOAD IN LILC083 RESZ~ENT. COHHER, INDUGTR. OTHER TOTAL GUHHER WIHTER 1982 5574, 5340, 1205. 1637, 13757, 3070. 2471, 1983 5640. 5360° 1240, 1650. 13900, 3100. 2500. 1984 5700. 53G0, 1280, 1670, 14040, 3120o 2530° 1985 5760, 5410, 1320. 1680o 14170, 3140, 2560, 1986 5800, 5480. 1350, 1700, 14330, 3160, 2600. 1987 5840, 5550, 1380. 1720, 14500. 3190. 2640. 1988 5880, 5620. 1420o 1740o 14660, 3220. 2680, 1989 5920, 5690, 1450, 1760, 14820, 3240, 2710, 1990 5960, 5760, 14G0, 1770, 14980, 3270, 2750, 1991 5990, 5830, 1510, 1790. 15:30, 3300, 2790. 1992 6010, 5910, 1540, 1810, 15280, 3320, 2820, 1993 6040, 5980, 1580, 1830, 15430, 3350, 2860, 1994 6060, 6060, 1610, 1850. 15570, 3380, 2890. 1995 6080, 6130, 1640, 1870, 15720, 3410, 2930, 1996 6100, 6210, 1670, 1890, 15870, 3430, 2960, 1997 6130, 6280, 1700, 1910. 16030, 3460, 3000, 1998 6160, 6360, 1740, 1930, 16190, 3490, 3030, 1999 6200, 6440, 1770, 1960, 16360, 3520, 3070, 2000 6230. 6520, 1800, 1980. 16530, 3~60, 3110. 25 - E S R G TABLE 3 FORECAST SUMMARY Energy Requirements (million KWH) Total (includes misc. and losses) Residential Commercial Industrial Peak Power (Thousand KW) Sum~er Winter 1982 Growth Rate 2000 (%) 13,757 16,530 1.0 5,574 6,230 0.6 5,340 6,520 1.1 1,205 1,800 2.3 3,070 3,560 0.8 2,471 3,110 1.3 - 26 - E S R G TABLE 4 DISAGGREGATED FORECAST BY SUBSECTOR COMPONENTS LILCO LILCG83 BAS~' CASE - ~ESIDENTIAL SECIOR - ENER(~Y IN OWH 1991 1994 1997 1982 ~985 1988 1339, 1.348, 1332, 268, 276, 283, 822. 841. 858, 366, 369. 375, 424, 441, 62, 64, 65, 290, 303, 307, 342, 342, 337, 291. 3~8, 337, 254, 30~, 351, i REFRIGERATORS 2 FREEZERS RANGES 4 LIGHI'ING TELEVISIONS 61 CLOTHES D~YERS 71 CLOTHES WASHERS DISH WASHERS WATER HEATERS 10: ROOM A/C CENTRAL. A/C SPACE H~AI*ERS HFATINGAUXII. IARY 14t HISCELLANE~US 1295, ]236, 3¢)6, 300, 289, 2¥5, 87%~. 882, ~85, 396, 67. 6~, 311. 315, 359 381. 396 436, 345 342, 418 452~ 1175, 291 · 301 . 889. 409, ?0, 140, 321, 404 · 472, 487 · LILI;08~ BASE CASE - COHMERCIAL 1982 1985 It OFFICES HEATING COOl. INS L. IGHIING AOX ~ POWER 21 ~ETAIL HEATING COOLING LIGHTING AUX ~ P~WER HOSPITALS 1 HEATING 2 COOL[NS LIGHTING AUX ~ POWER SCHOOLS 1: HEATING 2: COOLING 3: LIGHTING 4: AUX ~ POWER OTHER HEATING COOLING LIGHTING 4: AIJX i POWER 49. 61. 337, 341, 466, 461. 387, 399, 23. 28. 330. 337, 1237. 1260, 445, 46l, 146. 145. 29, 79, 16, 17. 76, 66, 317, 277, 187. 164, 22. 27, 249, 255. 553. 581. 364. 389. SECTOR - ENERI~Y 1N I~WH 1988 1991 1.994 1~97 2000 i151, 280, 306. 894, 423, 518, 142~ 328, 329. 427. 507~ 335. 524. 2000 73, 85, ?8. 11:~. 124, 352, 362, 373. 383, ~93. 476, 491, 507, 523, 538, 421, 444, 468. 493. 520. 33, 39, 44, 50, 56, 348, 360, 371, 383, 395, 1294, 1328, 1362, 1396, 1431, 488, 517, 547, 578, 6ll, 7, 8, 9, 10. li. 51, 51, 51, 51, 51, 146. 147, 148, 148, 149, 82, 85, . 88. 90, 93, LIt. C083 BASE CASE - INDUSTRIAl. 1982 1985 20: FOOD 58. 65. 22: TEXTILES 21. 22, 231 APPAREL 16. 18. 24: LUMBER 7, 25: FURNITURE 15. 16, 261 PAPER PROI)UCTS 47. 53, 27: PRINTING & PUBL. 90° 116. 28: CHEHICALG 58. 59. 29~ PETROLEUM ~ COAL 5. 33t PRIMARY METALS 40. 43. 34: FABRICAT. HETALS 73. 76. 35t MACHINERY 122. 13l. 36: ELECTRIC EQUIP. 255. 280. 37t TRANSPGRTAYION 176. 184. 30: RUBBER & PLASTIC 3ti LEATHER ~. 4. 32~ STONE,CLAY,GLASS 11. 12o 38: INSTRUMENTS 118. 129. 39: DTHER 33. 34. 21, 24. 28. ~1. 35. 67. 68, 69, 70. 71. 278. 278. 279. 279, 280. 169, 173, 177, 18/, 185. 32, 38, 4~, 49, 262, 268, 27~, 282, 289, 604, 627, 649, 672, 695, 415, 44~, 471. 502. :534. SE[:IOR kN~R~Y IN GWH 1988 1991 1994 1997 7~. 77 82. 88. 21. 21 2l, 20, 20, 22 24, 26, 11, 13 15, 17, 16o 17 17o 18. 57. 62 66, 70, 142, 169 196. 224. 59. 59 58, 58, 6. 7 8. 9. 45. 48 50~ 52° 78. 80. 82. 84. 1~8o 145. 152. 300, 321. 342, 365, 189, t91, 192, 192, 75, 84, 94, 105. 4. 4. 5. 12, 13. 13. 1~7. 147, 156, 166. 34, 34, 34, 34. 2000 ?3, 19. 28, 19, 18. 252, 57, 10, 54, 86. 167, 388, 190, 116, 6, ~4, 177, - 27 - E $ R G residential end-uses. This results from folding together the anticipated increases in appliance ownership, the number of households*, and usage of electric space and water heat, on the one hand, and improvements in the efficiency of new residential equipment and structure, on the other hand. The commercial sector growth is driven primarily by rapid employment growth rates in certain sectors (2.2 percent per year in finance, insurance, and real estate, and 1.6 percent per year in service industries), and increasing use of electric space and water heat. Demand growth is moderated by slow employment growth projections in government sectors (0.5 percent per year), and in those which directly service local populations (e.g., schools and hospitals). At 2.3 percent per year, fastest growing demand. This industry is the sector with the is due to a small degree to increasing employment (about 0.1 percent per year), but due primarily to projected increases'in the electrification and automation of the production process. For example, the amount of electricity consumed per employee in 1990 versus 1982 is projected to increase by 70 percent in the printing and publications subsector, and 20 percent in the electrical equipment sector and the transportation sector. * Households are projected to grow at an average rate of 0.7 percent per year to the year 2000 on Long Island, with multi- family units growing somewhat faster (1.3 percent per year) than single-family units (0.5 percent per year). The reason that the number of households grows faster than population (0.3 percent per yearl is that the size of households -- the average number of persons per household -- is projected to decrease. - 28 - £ S R G The summer peak, the most critical forecast in determining the need for additional generating capacity, is seen from Table 2 to have a forecast growth of 0.8 percent per year. This is somewhat less than the 1.0 percent per year forecast for total energy requirements for energy as a whole, for several reasons. First, the various end-uses of demand contribute differentially to peak load (for example, on average a KWH consumed for cooking contributes much more than one used for lighting). But the most rapidly increasing end-use, electric space heating, does not contribute at all to summer peak. Second, there is an intersectoral effect: the industrial sector which has the most rapidly growing energy use also has the most evenly spread demand due to its relatively regularized operations over both daily and annual cycles. The above factors contribute to a more rapid increase in total energy consumption (1.0 percent per year) and winter peak demand (1.3 percent per year), than in summer peak demand (0.8 percent per year). 29 - E $ R 3. SUPPLY PLANNING In this section, the current and planned supply situation in the LILCO service area are summarized. It is found that if Shoreham is abandoned and no additional conservation is achieved, LILCO, in addition to capacity additions already planned, will need to add capacity beginning in 1998. For purposes of this study, two extra coal plants are assumed, one in 1998 and one in 2000. Currently, the supply of electricity to LILCO's customers derives from three sources. The main share (about 64 percent) of this energy is generated by LILCO's own residual oil-fired power plants. Another 20 percent of LILCO's energy requirement is purchased from the New York Power Pool (NYPP) and is transmitted to Long Island over LILCO's existing tie-line to Con Edison.* The remaining generation is from LILCO's gas-fired stations. Installed capacity currently consists of a total of 3,767 MW: consisting of oil-fired units (2,672 MW), combustion turbines (1,037 MW), diesel units (12 MW), and several hundred megawatts of interties to other power systems (46 MW of which is currently considered as available for meeting peak demand). Apart from bringing Shoreham on-line in 1984, LILCO's current supply plans include some oil-to-coal conversions, a small refuse burning plant at Mitchell Gardens, a share of the *Currently, LILCO's share is about 300 MW. There is a plan to upgrade this 345 KV transmission line by 1986 so that LILCO's share would becomes600 MW. There is, in addition, curently an an interconnect to the New England Power Pool of about 75 MW sustainable with upgrade to about 300 MW planned for the late 1980s. - 30 - E $ R upstate Nine Mile Point 2 nuclear facility, upgraded transmission interties to the New York Power Pool (NYPP), and a sequence of oil plant retirements. In this study two basic scenarios have been developed to meet LILCO's capacity requirements, one with and one without Shoreham operating. Thus two different power plant investment programs were developed for LILCO to fit the needs of these two scenarios. The aim of these programs is to keep the cost of the electricity supply as low as possible for ratepayers in either scenario. In addition, the transmission system links between LILCO and the rest of the NYPP were reviewed in light of their potential for transporting additional electric power to Long Island to replace the power that would have come from Shoreham. In performing this supply assessment, all recent LILCO studies that attempt to quantify the economic impact of not allowing Shoreham to operate have been reviewed along with the most recent NYPP generation planning and power flow computer simulations. The two scenarios embody the following findings and assumptions. Capacity Requirements The New York Power Pool (NYPP) required reserve margin of 18 percent is a reasonable basis on which to phase in new power plants to LILCO's supply mix. On the basis of the ESRG demand forecast, and utilizing LILCO's "extended retirement" dates - 31 - E S R G for its existing generation units, LILCO's capacity for meeting summer peak demand will fall below its capacity requirements, without Shoreham operating, by 1998. With Shoreham operational, this will not happen until 2004. Figure 7 illustrates the summer capacity requirements against total capacity for the scenario with Shoreham not operating. Additional 400 MW coal plants, one in 1998 and one in 2000, are thus included beyond what would be needed in the Shoreham-In cas e. Planned Generation and Transmission System Upgrade Given the significant level of oil consumption by LILCO generating plants expected during the period from 1985-1997, LILCO is assumed to invest in the coal conversion of Port Jefferson units #3 and #4, and in a new 600 MW transmission line in 1990 to the Con Edison service territory in all scenarios. Both of these major upgrades are currently part of LILCO's official power supply plans as submitted this year to the New York State Energy Master Planning Board. Additional coal conversions are not judged to be cost effective or necessary in either scenario. In this study it is not assumed that the converted coal plants at Port Jefferson will be used to make up the power that would have come from Shoreham. In the years from 1984 through 1997 most of the power required to replace the output of Shoreham will derive from LILCO's own residual - 32 - E S R G Dk~4A/~D (~,~) Figure 7 REQUIRED CAPACITY AND TOTAL CAPACITY~ SHORENAM-OUT 4750 IN THE YEARS 1998, 2000, and 20 400 MW COAL ~ITS ADDED TOTAL 4500 CAPACITY REQUIRED CAPAC I TY 4250 4000 3750 SUMMER PEAK D~4AND 3500 3250 3000 YEAR *FOR THE YEARS 2004 AND BEYOND, CONSTRUCTION PROGRAMS WOULD BE COMPARABLE WITH, OR WITHOUT, SHOREHAM - 33- oil-fired units, though some is projected to come from other NYPP member utilities. However, with the completion of the new transmission link to Con Edison by 1991, the portion from each will change significantly. After the new transmission line is completed, the transmission capacity from the New York Power Pool to LILCO will at least double. During the 1990s, at least one-third of the power needed to replace the output of Shoreham, if it does not operate, is projected to be available from the power pool at a price of about 85 percent of the cost of power from LILCO's oil-fired units which otherwise would be needed. This replacement power for Shoreham will be available in addition to the significant amount of power that LILCO currently purchases from the Power Pool (about 20 percent of total energy requirements in 1981 and 1982). These estimates result from a review of the outputs of LILCO's own dispatch model (a model which simulates the generation system) and the output of runs on the new and more sophisticated MAPS multi-area dispatch model used by NYPP. The MAPS outputs show considerably more power available than does LILCO, but more conservative assumptions, consistent with LILco'S findings, are utilized in the basic runs here. In Section 7, the effects of assuming no NYPP power to replace Shoreham are quantified and found to be small (see Table 1). - 34 - £ S R G New Power Plant Construction Given uncertainties as to the costs of less conventional sources of power in the next 15 years, it has been assumed that without Shoreham, LILCO builds a 400 megawatt (MW) coal unit with scrubbers in 1998 and 2000 for a total of 800 MW, to replace the 809 MW of capacity lost from Shoreham. The output of these units will replace the lost output from Shoreham after 1997, when the additional power is needed. Interestingly, with both coal plants in place there is more oil displacement than would have been provided by Shoreham. The construction costs projected for these coal units using statistical techniques are $2040 million in 1998 and $2399 million in 2000, comparable to those LILCO has assumed recently for new coal units. The annual required revenues for these units were calculated using a financial model. They appear in the column "Coal Plant Cost" in Table 5 below. Assumptions on the operating characteristics of these new coal units were taken from the 1982 version of the Electric Power Research Institute (EPRI) Technical Assessment Guide. These include operations and maintenance (O&M) costs of 7.72 mills per KWH in 1983 (escalated at 1 percent above inflation), a capacity factor of 70 percent*, and an annual average heat rate of 10,060 BTU's of coal per KWH generated. After the year 2000, when the second 400 MW coal plant will be required, the LILCO construction program is assumed to be the same whether or not Shoreham operates. *The EPRI availability of 74.3 percent was reduced to a 70 percent capacity factor to allow for some degree of load following. Since Shoreham's capacity factor is projected to be somewhat lower this, these two coal units will more than replace the energy from Shoreham after 2000. 35 - E S R G TABLE 5 ANNUAL SHOREHAM REPLACEMENT POWER COSTS* Plant, Fuel and O&M Cost (in millions of current $) Coal Plant Fuel and Total Year Cost O&M Cost Cost (1) (2) (3) (4) 1984 0 177 177 1985 0 199 199 1986 0 224 224 1987 0 251 251 1988 0 283 283 1989 0 321 321 1990 0 347 347 1991 0 359 359 1992 0 388 388 1993 0 419 419 1994 0 453 453 1995 0 489 489 1996 0 529 529 1997 0 571 571 1998 418 505 923 1999 397 544 941 2000 865 451 1,316 2001 820 469 1,289 2002 773 502 1,275 2003 730 521 lr251 Total 4,003 8,002 12,005 * Costs include a 2.4 percent allowance for working capital and a 4 percent revenue tax. - 36 - E S R G Fuel Prices In the absence of Shoreham, LILCO's existing oil-fired steam plants will generate additional power (at least until the substitute coal plants come in-service).* The fuel prices for this make up power vary with sulfur content. In i983, the average prices will be about $25.2/barrel for relatively high sulfur oil and $27.4/barrel for medium sulfur oil (burned primarily at the Barrett and Glenwood facilities). The make-up oil generation is comprised of a mixture of plants using the higher (about 30 percent) and lower (about 70 percent) price oil at an average heat rate of 10,400 BTU's per KWH. This translates into a fuel cost per KWH of 42.3 mills. To this, 3.8 mills per KWH have been added for oil plant operations and maintenance costs, as well as 1.0 mill per KWH as an allowance for working capital related to fuel storage and 2.0 mills per KWH for revenue taxes. This yields a total of 49.1 mills per kilowatt-hour for additional oil power in 1983. It is further estimated that the price of oil will escalate at the rate of inflation through 1987, and then at 2 percent above the rate of inflation for the long term. This yields significantly higher oil prices in the future than LILCO has recently projected, and is based on a tightening of the oil market with international economic recovery. *A very small increase in combustion turbines output 150 GWH) would also occur. - 37 - (approximately E S R G With respect to coal prices, it is estimated, along with the 1983 NYPP report, that a mid-range price of coal in 1983 to LILCO will be $2.24 per million BTUs. Coal prices are projected to escalate at 1 percent above inflation. In computing revenue requirements for each scenario, an allowance is made for working capital on fuel inventories at a rate of 2.4 percent of annual fuel costs, and a revenue tax of percent is also included. Thus, for example, the total cost of oil replacement power for Shoreham is assumed to be 52.2 mills per KWH in 1984. Results Using the preceding findings and estimates concerning LILCO capacity requirements and new power plant construction, coal conversions, transmission line upgrading, and fuel prices, the quantity and cost of replacement power required in the absence of Shoreham were computed. Table 5 presents the annual replacement power costs for the basic scenarios when Shoreham is not operating. The electric energy generation which would have been produced by Shoreham and must be replaced rises from 3.4 billion kwh in 1984 to 4.47 billion kwh in 1989 and subsequent years (see Section 4). The annual fixed costs of the new coal plants beginning in 1998 appear in column 2. Column 3 provides the annual fuel and operations and maintenance costs of the replacement power, which when added to the fixed costs in column 2, yields the total annual cost of - 38 - £ S R G the replacement power, shown in column 4. These costs begin at $177 million in 1984, and reach $1,251 million in 2003. Note the reduction in fuel and O&M costs in 1998 and 2000 when the operation of the new coal units displaces oil-fired generation. Alternative Power Sources Before the end of the century, when additional capacity will be required, a number of alternatives to conventional coal plants may be available. The alternatives may include greater conservation, wind generated power, prefabricated modular units (fuel cells, batteries, integrated gasification-combined cycle coal units, pressurized fluidized bed combustion), and solar power. Additionally, there is the possibility that refurbishing and extending the lifetime of aging oil-fired units may prove cost-effective. These non-conventional approaches to planning are at various stages in the research, development, and demonstration process. Because uncertainties concerning availability, engineering, and costs remain at this time, these alternatives have not been included in this analysis.* Should the remaining uncertainties concerning these alternatives to coal be resolved favorably over the fifteen-year period before makeup capacity for Shoreham is required, then the costs of substitute power may well be less than calculated here. *An exception is utility based conservation investment programs which are being actively pursued in a number of states. A conservation-oriented scenario for LILCO has been developed in Technical Report C and summarized in Section 6 below. - 39 - E S R G 4. SHOREHAM OPERATIONS AND COSTS In this section, a summary of the analysis and assumptions employed in estimating the costs and characteristics associated with Shoreham operations is presented.* Included are annual capacity factors, operations and maintenance costs, net capital additions, fuel costs, spent fuel disposal costs, and decommissioning costs. The results provided here are input assumptions to the complete required revenues impact analysis presented in Section 5. Capacity Factors The capacity factor of a power plant is defined as the net annual generation divided by the maximum potential annual generation. Maximum potential generation is the rated capacity of the plant times 8,760 (hours in a year). Thus, the annual capacity factor can be thought of as the fraction of the year that the plant will operate at the equivalent of the full rated capacity. For nuclear power plants there are several factors which lead to experienced capacity factors well below 100 percent. These include both forced and scheduled outages for maintenance and equipment repair, refuelling outages, and outages mandated by the U.S. Nuclear Regulatory Commission (NRC) for safety, training and licensing. According to data published *Full documentation for the results summarized in this section is presented in Technical Report B: Shoreham Operations and Costs. - 40 - E S R G by the U.S. Department of Energy, average capacity factors for operating nuclear power plants in the U.S. during the 1973-1982 period have ranged from a low of 43.5 percent (1974) to a high of 63.9 percent (1978). The industry-wide average over this period was 56.7 percent, and the average for the last four years was 56.1 percent. There has been, however, a wide variation around these averages depending on the particular plant and year considered. In order to understand the basis for this variation, we divided outages into two sets. One set consists of outages for re- fueling, regulatory restriction (i.e.~ NRC mandated), and operator training and licensing (hereafter referred to as "refuelling and NRC" outages). The other set consists of all other outages, including those associated with equipment failure and maintenance (hereafter referred to as "maintenance and repair" outages). To explain the maintenance and repair outages~ statistical procedures were employed in the present study. The result of these procedures -- multivariate regression analysis -- provides the magnitude of contributions to observed capacity factors (adjusted to exclude refueling and NRC outages) from each of several explanatory variables associated with the characteristics of the nuclear power plants in the data base. Once these magnitudes are established they can be applied to any specific nuclear plant (such as Shoreham) whose characteristics are known, as one tool to predict future maintenance and repair outages. - 41 - E S R G The data base used in the statistical analysis consists of annual capacity factors and outage information for 68 nuclear power plants, essentially all commercially operating units in the U.S., over the years 1975-1981. Detailed data for those years were available from the Nuclear Regulatory Commission (NRC) in its published "Grey Books" and computer tapes. Data on plant characteristics were also obtained from the NRC. A comprehensive series of multivariate regression analyses were carried out. Among the explanatory variables which were explored for statistical significance were plant size (in Megawatts), reactor type (PWR or BWR*), age or year of operation, presence of cooling towers, saltwater cooling, reactor manufacturer, multiple unit siting, and whether the observation was in the years immediately following the Three Mile Island (TMI) accident. Some anomalously low adjusted capacity factors were excluded, e.g.r those of the Diablo Canyon facility (which received a low power license but never has operated) and of TMI after its accident. No statistical significance in explaining adjusted (maintenance and repair based) capacity factors was found for multiple unit siting and the TMI years. Significant aging effects were found, however, including both capacity factor increases during the early years of "maturation," and long-term capacity factor decreases for saltwater-cooled plants. The refueling and NRC-mandated outages, being less clearly related to long-term plant performance characteristics, were analyzed separately. Year-by-year data were collected *Pressurized water reactor or boiling water reactor. - 42 E S R G on such outages for all BWR plants, and a weighted average of such outages was developed for the years 1975-81. The annual rate among BWRs was found to be 14 percent, almost all of it attributable to refueling outages. The results of the analyses are graphed in Figure 8, where the regression results, modified to incorporate a 14 percent annual refueling and NRC outage rate, beginning in the second year, are shown through the eleventh year of operation. Figure 8 also shows LILCO's assumptions concerning total Shoreham capacity factors, as well as the assumptions employed by ESRG in the present study. While there are indications of a rather rapid decline in Shoreham capacity factors after its tenth year of operation, the assumption actually used in this study is that the Shoreham capacity factor will rise to 63 percent by its sixth year of operation and then remain constant at that level for the remaining 20 years of its planned operating life. Operations and Maintenance The operations and maintenance costs for electric utility power plants are passed on to ratepayers as expense items. For nuclear power plants these costs include eight subcategories in the Operations category, and five sub-categories in the Maintenance category, as reported in the annual Form 1 submitted to the Federal Energy Regulatory Co~u~ission (FERC). These costs are also reported by the U.S. Department of Energy. - 43 Figure 8 SHOREHAM CAPACITY FACTORS ESRG AND LILCO ASSUMPTIONS 70 60 5O 40 CAPACITY FACTOR PERCENT) 30 20 10 ~ LILC0 ASSUMPTION~ . .......... -j~-r~-~-r~-- ..... ~ ESRG ASSUMPTIONS ..." ,, REGRESSION RESULTS 1 2 3 4 5 6 7 8 9 10 11 12 YEAR OF OPERATION - 44 Industry-wide operations and maintenance costs for commercially operating nuclear power plants in the U.S. have increased dramatically over the past decade, from about $20 million in 1970 to about $1.4 billion in 1980. Since both inflation and an increase in installed nuclear generating capacity have occurred during this period, it is useful to recast these figures in constant (i.e., inflation-adjusted) dollars per kilowatt of installed capacity. The increase was from about $12.50 per KW in 1970 to about $35.90 per KW in 1980, expressed in 1983 dollars. Thus, over the 1970-1980 period, average industry-wide nuclear plant operations and maintenance costs escalated at about 11 percent per year above the general rate of inflation. In fact, after correcting for economies associated with increasing plant sizes during this period, one finds that the per unit costs increased at a rate of about 15 percent per year above inflation. Table 6 below shows industry-wide average operations and maintenance costs per kilowatt for nuclear stations in the U.S. for each year in the 1970-1980 period in both nominal and constant (1983) dollars. The table also shows percentage changes from year to year and average growth rates over the period. The real growth rate was 9.3 percent per year from 1970 through 1978 (the last full year before the TMI reactor accident) and 11.0 percent/year from 1970 through 1980. While the average operations and maintenance cost in the industry was - 45 - £ S R G $35.9 per KW (1983 dollars), the costs of individual stations ranged as high as about $75 per KW (1983 dollars).* For a plant the size of Shoreham, the 1980 industry-wide experience indicates an annual cost of $29.4 million (1983 dollars). Escalating by the 1970-80 average real rate of 11.0 percent per year, and adding an additional year of 6 percent inflation, would give a 1984 operations and maintenance cost of $47.3 million ($57.8 per KW). Continued escalation at these historical rates would lead to annual costs greater than $400 million ($500 per KW) by 1998. As we shall see below, the detailed statistical analysis employed here leads to much lower predicted operations and maintenance costs for Shoreham over its first fifteen years trends. OPERATIONS AND MAINTENANCE COSTS of operation than these industry-wide TABLE 6 FOR NUCLEAR STATIONS IN THE U.S. Cost Cost Year (S/KW) (19835/KW)+ 1970 5.25 12.53 1971 5.02 11.40 1972 6.91 15.08 1973 6.38 13.16 1974 8.73 16.58 1975 9.94 17.27 1976 11.98 19.78 1977 13.65 21.29 1978 16.78 24.39 1979 20.93 28.04 1980 29.21 35.93 Average Growth Rate (Percent) 1970-78 16.6 9.3 1970-80 18.6 11.0 + Using GNP deflators. *Some small old units, excluded from our data base and the above averages, had costs approaching $150 per KW (1983 dollars) in 1980. - 46 - E S R It is worthy of note that the Pennsylvania Power and Light Company (PP&L) has forecast about $62 per KW operations and maintenance costs in 1985 for its Susquehanna nuclear generating station, also a BWR, which could be expected to have somewhat lower costs than Shoreham due to its larger size (1,052 MW) and multiple unit siting. PP&L has also predicted that these costs would reach about $110 per KW by the early 1990s. As we indicated above, operations and maintenance costs have varied widely by plant and operating year. For this reason, multivariate regression analysis has been used in the present study to explain these costs and their variation in terms of independent variables expressing power plant characteristics. Numerous independent variables were explored. These included plant size, age, vintage (first year of operation), geographic location, demonstration unit, multiple unit siting, saltwater cooling, 1980 operation (post-TMI experience), cooling towers, reactor manufacturer, reactor type, turbine manufacturer, utility size, and utility experience with nuclear plant operation. No statistical significance was found for the last six variables. Increases in constant dollar costs per KW were found for both later vintage plants and older plants. Saltwater cooled plants were found to experience more rapid cost increases with age, presumably due to corrosion patterns, and larger plants were found to experience economies of scale. While cost increases above the - 47 - E S R G general rate of inflation were found, these are not nearly so rapid as the industry-wide 1970-1980 escalation experience discussed earlier. There are two principal reasons for this. First, the regression equation expresses the age effects in linear rather than exponential fashion. And second, the variable for the year 1980 (post-TMI experience) nets out this large effect from the general temporal trends, tending to attenuate the underlying rate of increase found by the regression analysis. The regression equation for nuclear operations and haintenance costs was applied to the Shoreham facility, with the following modifications. The equation was applied only to the first fifteen years of Shoreham operations. Thereafter, annual operations and maintenance costs were assumed to increase only at the general rate of inflation (6 percent). An additional cost of 4 percent was added to each year's operations and maintenance costs to account for revenue taxes. Table 7 below gives the operations and maintenance costs which result from the foregoing analyses and assumptions, on a per KW and total cost basis. During the first fifteen years of service, Shoreham operations and maintenance costs increase at a rate beginning at 5.6 percent per year above inflation and declining to 3.3 percent per year by the fifteenth year. These rates are far below those experienced in the industry during the 1970s. - 48 E S R G TABLE 7 SHOREHAM PLANT OPERATIONS AND MAINTENANCE COSTS O&M Cost Total O&M* O&M Cost Year ($ KW) ($ Millions) year (S/KW) Total O&M* ($ Millions) 1984 63.44 51.954 1999 265.65 217.570 1985 70.83 58.012 2000 281.59 230.625 1986 78.89 64.609 2001 298.49 244.462 1987 87.65 71.789 2002 316.40 259.129 1988 97.19 79.598 2003 335.38 274.677 1989 107.55 88.085 2004 355.50 291.157 1990 118.81 97.305 2005 376.83 308.627 1991 131.03 107.313 2006 399.44 327.144 1992 144.29 118.173 2007 423.41 346.772 1993 158.67 129.949 2008 448.81 367.579 1994 174.25 142.713 2009 475.74 389.633 1995 191.14 156.541 2010 504.29 413.011 1996 209.42 171.514 2011 534.54 437.791 1997 229.21 187.721 2012 566.62 464.058 1998 250.62 205.255 2013 600.61 491.901 *Revenue tax included. Net Capital Additions Nuclear power plants have continued to incur capital costs in the years following the in-service date (initial commercial operation), when the initial construction and financing costs enter the rate base. As these new costs -- for land, structures, reactor, turbogenerator, electrical and miscellaneous equipment -- are incurred, they too enter the rate base and the utility earns a return on them. Thus, required revenues are increased as these capital additions are made. - 49 - S R G Both capital additions to and retirements from cumulative nuclear plant capital costs are reported by utilities in the Form 1 submitted annually to the Federal Energy Regulatory Commission (FERC). The cumulative capital costs by nuclear station are also reported by the U.S. Department of Energy. In the present treatment only net annual capital additions are examined.* In the present study, each year's net capital addition is spread over all subsequent years by applying a levelized fixed charge factor to represent LILCO's return on rate base for the Shoreham facility% Data on nuclear power plant annual net capital additions over the period 1970-1980 have been collected from the FERC Form 1 reports and the U.S. Department of Energy documents, on a station-specific and year-by-year basis. Industry-wide totals over this period increased from about $2.6 million in 1970 to about $840 million in 1980. Expressed in constant 1983 dollars per kilowatt of installed capacity, these costs increased from about $3.5 per KW to $24.7 per KW over this decade. Thus, the real per-unit costs of net capital additions to nuclear stations increased sevenfold during the 1970s. *The result of this is to somewhat underestimate the additional required revenues from capital additions. This is because the capital removals are reported at original rather than depreci- ated costs and rate base reductions are thereby overstated. Futhermore, retired plant can still impact revenue requirements through continued amortization, or as expensed items after removal from rate base. - 50 - E S R G Table 8 below shows the average net capital additions costs per kilowatt for nuclear stations in the U.S. for each year in the 1970-80 period. Also shown are the annual percentage changes, and average escalation rates over the entire decade. The real escalation rate was 17.5 percent per year from 1970-1978 (the last full year before the TMI reactor accident) and 15.9 percent per year from 1970-1980. While the industry-wide average net capital additions cost in 1980 was $24.7 per KW (1983 dollars), costs at individual stations ranged as high as $126 per KW (1983 dollars) in that year.* For a plant the size of Shoreham the 1980 industry-wide average costs for capital additions were $20.2 million (1983 dollars). Escalating this by the 1970-80 industry-wide growth rate of 15.9 percent per year, and an additional 6 percent inflation for one year, would give $39 million ($47.2 per KW) in 1984, Shoreham's first year of operation. Continued escalation at the rates experienced during the 1970s would imply costs reaching about $135 million ($165 per KW) by 1990 and about $700 million ($850 per KW) by 1998. By contrast, as shall be seen below, a more detailed analysis gives much lower projected net capital additions costs for Shoreham. * During 1980 six nuclear stations incurred net capital additions costs in excess of $49 per KW (1983 dollars), i.e. more than twice industry-wide average in that year. These were the Beaver Valley, Davis Besse, Oyster Creek, Pilgrim, San Onofre, and and Surrey facilities. Four of these incurred costs of $90 per KW (1983 dollars) or greater. the - 51 E S R G TABLE 8 NET CAPITAL ADDITIONS FOR NUCLEAR STATIONS IN THE U.S. Cost Cost Year (S/KW) (19835/KW)+ 1970 1.46 3.49 1971 1.84 4.18 1972 3.96 8.65 1973 5.30 10.93 1974 4.74 8.99 1975 4.72 8.20 1976 6.51 10.75 1977 10.63 16.58 1978 9.24 13.43 1979 8.65 11.59 1980 20.08 24.70 Average Growth Rate (Percent) 1970-78 25.3 17.5 1970-80 23.9 15.9 +Using GNP deflators. The present study has employed multivariate regression analysis to help explain the net capital additions costs and their variation over stations and operating years. Among the independent variables explored for statistical significance were plant size, vintage, age, multiple unit siting, geographic location, cooling towers, saltwater cooling, demonstration unit, and reactor manufacturer. A simple equation in which each of four independent variables showed strong statistical significance was selected from the regression study. These variables were plant vintage, plant age, multiple unit siting, and saltwater cooling. - 52 The results of the statistical analysis were applied to the Shoreham facility with the following modifications. Net annual additions in each year of operation, obtained from the regression equation, are applied for only the first fifteen years of Shoreham operations. Thereafter, the net additions are assumed to increase only at the general rate of inflation (6 percent) through the twenty-fifth year of operation. Expenditures are then assumed to decline linearly over the last five years of operation. A four percent revenue tax was added to each year's net capital additions cost. Finally, each year's cost was spread over the life of the Shoreham facility by applying a 17.87 percent levelized fixed charge rate. Table 9 below shows both the annual net capital additions per kilowatt and the annual revenue requirements as forecasted on the basis of the results and assumptions employed. As the figures in Table 8 show, the real escalation rate of Shoreham net capital additions is about 14 percent after its first year of operation, lower than the average experience of nuclear plants in the 1970s. By its fifteenth year of operation this rate falls to about 5 percent. - 53 - E S R G COSTS TABLE 9 AND REVENUE REQUIREMENTS FOR SHOREHAM NET CAPITAL ADDITIONS (Current Dollars) Net Capital Annual Re- Net Capital Additions quired Revenue Additions Year (S/KW) ($ Millions) Year (S/KW) 1984 35.3 1985 42 4 1986 50 2 1987 58 7 1988 68 1 1989 78 5 1990 89 9 1991 102 3 1992 116 0 1993 130 8 1994 147 0 1995 164 7 1996 184 0 1997 205.1 1998 228.0 5 4 11 8 19 5 28 4 38 8 50 8 64 5 80 1 97 8 117 7 140 1 165 3 193 3 224 6 259 3 Annual Re- quired Revenue ($ Millions) 1999 241.6 296.2 2000 256.2 335.2 2001 271.6 376.6 2002 287.8 420.5 2003 305.1 467.0 2004 323.4 '516.3 2005 342.9 568.6 2006 363.4 624.0 2007 385.2 682.7 2008 408.3 745.0 2009 340.3 796.8 2010 272.2 838.3 2011 204.2' 869.5 2012 136.1 890.2 2013 68.0 900.6 Nuclear Fuel Costs The cost of nuclear fuel for the Shoreham facility was estimated to begin at a base value of 6.02 mills/KWH in 1983, and escalate at 1.6 percent per year above the general rate of inflation (itself 6 percent per year) thereafter. Both the base value and the escalation rate are derived from LILCO estimates (Madsen, Exhibit 1, PSC Case No. 28252). The base value of 6.02 mills/KWH is LILCO's 1983 nuclear fuel cost with its spent fuel disposal component subtracted. The 1.6 percent/year real escalation rate is the average real rate of growth assumed by LILCO for nuclear fuel costs from 1983-2000. - 54 - E S R G Disposal of Spent Fuel At present, spent nuclear fuel is temporarily stored on-site in storage pools, after a several year stay in nuclear reactor assemblies. Since the capacity of these pools is limited, permanent and safe disposal will ultimately be required. The cost of ultimate disposal has not been reflected in utility costs and electricity rates, as have other elements of the nuclear fuel cycle. Indeed, both the costs and technology of disposal have been subject to continuing discussion and debate. The federal government has taken responsibility for the ultimate disposal of spent nuclear fuel. The current plan is to make a deep geologic repository available for spent fuel shipments near the end of the century. The costs for this service will include construction, operation, research and development, regulation, and licensing. They are to be recovered in full from electric utilities. Recent legislation has provided for utility payment for all electricity generated by nuclear facilities after April 7, 1983. The fee .of 1 mill per KWH (0.1C/KWH), is designed to cover all costs expected to be incurred by the government. This fee, developed from U.S. Department of Energy estimates, is consistent with a total disposal cost of $190 per kilogram dollars). However, we estimate the costs from the Shoreham plant at $350 per kilogram (in (KgU) of spent fuel (in 1983 for spent fuel disposal 1983 dollars), - 55 - E S R G about 1.8 times the Department of Energy figure. Several factors enter i~to our estimate. First, the DOE estimate itself does not account for inflation. Beyond inflation, it does not account for real escalation from initial engineering estimates. Indeed, the system of cost collection embodied in the legislation includes yearly review so that changes in costs can be reflected in changes in the fee. This is especially important since the costs of new complex technologies (e.g., nuclear power plants themselves) have often ultimately been many times higher than initial engineering estimates. Other estimates have put ultimate disposal costs well above the $190 per KgU figure, and as high as $3000 per KgU (see Section 5 of Technical Report B for a review of the literature). Further indication of the likelihood that the 1 mill per KWH fee will prove too low is the fact that at least one utility (Commonwealth EdiSon) has arranged for disposal funds to be collected at 2 mills per KWH. In the analysis of Shoreham required revenues, we assumed that 1 mill per KWH will be collected initially, but that this will increase annually until ultimately $350 per KgU (in 1983 dollars) is collected for Shoreham spent fuel. Total funds collected will be about $283 million (1983 dollars). Thus payments will escalate from 1 mill per KWH in 1983 to about 27 mills per KWH by 2013, averaging about 8 mills per KWH over the 30-year operating life of the plant. The average in 1983 dollars is about 2.2 mills per KWH. - 56 - Decommissioning Significant costs are associated with all three major options for nuclear plant decommissioning: entombment, mothballing, and immediate dismantlement. The immediate dismantlement method appears, at this time, to be the least costly approach. It entails cleaning the radioactive components to the extent that decontamination is practical, then cutting the radioactive structures into pieces suitable for transport to a permanent radioactive waste disposal site. Experience with dismantling nuclear reactors has been limited to only very small units thus far. Therefore, cost estimates for large commercial nuclear power plants remain speculative. With larger units, both economies of scale and diseconomies associated with much higher levels of radiation can be expected. Based upon estimates in the literature, which put the costs in the $50-500 million (1983 dollars) range, a figure of $200 million (1983 dollars) has been selected to represent the decommissioning costs for Shoreham (see discussion in Technical Report B). A recent estimate by the Pennsylvania Power and Light Company for a boiling water reactor was $123 million. By contrast, LILCO has assumed that decommissioning Shoreham will cost about $50 million (1983 dollars). In evaluating utility estimates, it is necessary to consider the likelihood of a real escalation rate above inflation caused by growing factor input costs and the increases from initial engineering estimates which have been typical in the nuclear industry. - 57 - E S R G At the 6 percent inflation rate our $200 million (1983 dollars) decommissioning estimate becomes $1,150 million in year 2013, the assumed end of Shoreham's operating life. Revenues were assumed to be collected from ratepayers taking account of Federal income tax effects and interest credit for decommissioning funds received. Our computerized simulation collects funds at a rate beginning at LILCO's assumed initial rate and increasing over the plant life to achieve full collection of the $1,150 million estimated decommissioning cost. The resulting required revenue stream, comprised of ratepayer contribution to the decommissioning fund (net of interest accrued on the contribution) and incremental Federal taxes incurred, is reported in the next section. Summary of Shoreham Operations and Costs Table 10 below summarizes the projections of Shoreham power plant operations and costs in nominal dollars. These results, properly discounted to common present value dollars, are included as part of the cost impact analysis of the last section. - 58 - E S R G the Year TABLE 10 SHOREHAM NUCLEAR POWER PLANT OPERATIONS AND COSTS SUMMARY SHOREHAM OPERATIONS SHOREHAM COSTS: REQUIRED REVENUES IMPACTS (Millions of Dollars) Net Opera- Capacity Genera- tions & Net De- Factor tion Mainten- Capital Nuclear Co,mis- Spent (Percent) (GWH) ance Additions Fuel sionin~ Fuel 1984 48.0 3402 52.0 5.4 1985 51.0 3614 58.0 11.8 1986 54.0 3827 64.6 19.5 1987 57.0 4039 71.8 28.4 1988 60.0 4252 79.6 38.8 1989 63.0 4465 88.1 50.8 1990 63.0 4465 97.3 64.5 1991 63.0 4465 107.3 80.1 1992 63.0 4465 118.2 97.8 1993 63.0 4465 129.9 117.7 1994 63.0 4465 142.7 140.1 1995 63.0 4465 156.5 165.3 1996 63.0 4465 171.5 193.3 1997 63.0 4465 187.7 224.6 1998 63.0 4465 205.3 259.3 1999 63.0 4465 217.6 296.2 2000 63.0 4465 230.6 335.2 2001 63.0 4465 244.5 376.6 2002 63.0 4465 259.1 420.5 2003 63.0 4465 274.7 467.0 2004 63.0 4465 291.2 516.3 2005 63.0 4465 308.6 568.6 2006 63.0 4465 327.1 624.0 2007 63.0 4465 346.8 682.7 2008 63.0 4465 367.6 745.0 2009 63.0 4465 389.6 796.8 2010 63.0 4465 413.0 838.3 2011 63.0 4465 437.8 369.5 2012 63.0 4465 464.6 890.2 2013 63.0 4465 491.9 900.6 23.0 26.3 30.0 34.1 38.6 43.7 47.0 50.7 54.6 58.8 63.3 68.2 73.4 79.0 85.1 91.7 98.7 106.3 114.5 123.3 132.8 143 1 154 1 165 9 178 7 192 4 207 2 223 2 240 4 258.9 1.2 3.8 1.3 4.2 1.4 4.8 1.5 5.4 1.7 6.1 3.3 6.8 3.5 7.7 3.9 8.7 4.2 9.8 4.6 11.0 7.9 12.4 8.6 13.9 9.4 15.7 10.2 17.7 11.2 19.9 18.5 22.5 20.1 25.3 22.0 28.5 24.0 32.1 26.3 36.2 43.6 40.8 47.6 46.0 52.0 51.8 56.9 58.3 62.2 65.7 115.2 74.1 125.7 83.4 137.3 94.0 150.1 105.9 164.2 119.3 - 59 - £ $ R G 5. COST IMPACTS OF NOT OPERATING SHOREHAM . A basic aim of this study is to quantify the changes in the costs to ratepayers resulting from not operating the Shoreham facility. This was done by considering LILCO's annual required revenues under various scenarios. Required revenues consist of the amount utilities need to collect from their customers to cover operating expenses, taxes, capital amortization, and return on investment. As an overall measure of ratepayer expenditures, required revenues are an appropriate indicator of cost effects. Cost Components The required revenues for a given year are composed of many elements reflecting the operations of the entire electric system under consideration. However, the ratepayer impact of not operating Shoreham is the difference of two required revenue streams: one with the plant operating and the other with it nonoperational. Consequently, costs common to both cases cancel out in computing the incremental impacts of a plant closing, and need not be considered further. There remain seven significant components of the required revenues that would be differentially affected by plant abandonment. These are: - 60 - E S R G Make-up Generation. In the absence of the nuclear plant, the electricity generation requirements must be provided by the existing system, by purchased power, by new plant construction, or by conservation. The costs of these make-up power alternatives constitute the major penalty of early power plant retirement. To analyze them, it is necessary to specify the system responses to the loss of the facility (discussed in Section 3). Projections of nuclear plant generation (capacity factors) to determine how much generation must be replaced are an important ingredient in this analysis (discussed in Section 4). Direct Capital Related Costs. These include recovery of the sunk capital, return on investment, taxes and insurance. The amount and method of recovery is to some extent a regulatory policy issue. In this investigation, capital related costs have been computed using a financial model to simulate LILCO characteristics and practices. In the Shorehem-In case, it is assumed that the full investment is recovered with interest. In the Shorehem-Out case, a range of cost recovery scenarios were evaluated. For example, in the benchmark "Rate Wash" Shoreham-Out case, the recovery was reduced by an amount sufficient to make the present value of revenue requirements the same as in the Shorehem-In case. Nuclear Fuel. running the plant. dependent on assumptions on This is an avoided cost (i.e., a benefit) of not As with make-up generation, its value is likely future plant capacity factors. - 61 - E S R G Nuclear Operations and Maintenance. This is another avoided cost. As discussed in Section 4, there is statistical evidence for projecting escalating nuclear O&M costs related in part to aging- related equipment problems. Radioactive Waste Storage and Disposal. In the case where the plant operates, it is necessary to store and to finally dispose of highly radioactive spent fuel. Decommissioning. If the plant operates, expenses will be incurred in dismantling or encapsulating the radioactive facility after its useful life has ended. Capital Additions. and safety modifications operated. In Section 4, Certain costs for major plant repairs are avoided if the plant is not statistical estimates of these costs were developed based on actual experience with nuclear facilities. These costs are significant and have not been properly considered in Shoreham cost evaluations to date. Cost Accounting System The complexity of these issues -- as well as the desire to have a flexible capability for developing scenarios, performing sensitivity analyses, and synthesizing results -- warranted the development of a computer-based costing model. The result, the Rate Impact of Shoreham Not Operating (RISNO) System, is designed to simulate the required revenue impacts in both current and discounted dollars and over variable time periods. It provides a flexible framework for testing the effects for various scenarios and parameter ranges so that uncertainty in both technology variables (e.g., future plant performances) and policy or economic variables (e.g.~ - 62 - E S R G conservation activity) may be adequately explored. In addition, as described earlier, several ancillary models were used in developing 'inputs on make-up generation, capacity factors, O&M costs, and capital additions. Time Period of the Analysis The focus here will be on the first twenty years of Shoreham's operations, 1984-2003. In the next section, the effects of extending the study time period by ten years (the assumed plant lifetime) will be analyzed. Projections past twenty years must be considered highly speculative. Beyond the inherent uncertainties in such a long range prognosis, there is the problem that commercial nuclear facilities are all twenty years old or younger. There is thus very little concrete experience on which to base estimates of nuclear plant performance and cost consequences out to the third decade of power production. Sensitivity projections over both thirty years and ten years indicate cost penalties for the Shoreham-In scenario (see Sections 1 and 8), but twenty years is suggested as a more reliable period for estimation and policy deliberations. Results The cost streams of the Shoreham-In and Shoreham-Out cases are shown in present value terms in Table 11. The assumptions - 63 - E S R G TABLE 11 REVENUE REQUIREMENTS COMPARISON: RATE WASH CASE (Millions of Dollars Present Valued to 1983) 1986 632.6 43.1 46,2 4.8 3.4 1.1 20.4 751.6 1985 534.5 42.2 45.7 9.3 3.3 1.0 20.7 636.7 1986 447.8 41.5 45.2 13.6 3.6 1.0 21.0 573.5 1987 376.2 40.8 44.6 17.6 3.4 0.9 21.2 504.7 1988 316.1 40,1 43.9 21.4 3.4 0.9 21.3 467.1 1989 264.7 39.2 43.1 24.9 3.3 1.6 21.4 ' 398.2 1990 221.2 :38.3 42.3 28.0 3.3 1.9 20.4 355.0 1991 184.6 37.4 41.4 30.9 3.4 1.3 19.6 318.8 1992 153.4 36.5 60.5 33.5 3.4 1.4 18.7 287.4 1993 126.9 34.3 39.5 35.8 3.3 1.4 17.9 259.1 1994 106,7 32.3 38.5 37,8 3.3 2.1 17.1 237.8 1995 91.5 30.4 37.5 39.6 3.3 2.1 16.3 220.7 1996 78.3 28.6 36.5 41.1 3.3 2.0 15.6 205.4 1997 67.0 26,9 35.5 42.4 3.3 1.9 16.9 191.9 1998 57.2 25.3 34.4 43.5 3.3 1.9 14.3 179.9 1999 48.8 23.8 32.4 44.1 3.4 2.8 13.7 169.0 2000 61.5 22.4 30.5 44.3 3.3 2.7 13.0 157.7 2001 35.3 21.1 28.7 44.2 3.3 2.6 12.5 147.7 2002 29.9 19,9 27.0 63.8 3.3 2.5 11.9 138.3 2003 25.3 18.7 25.4 43.2 3.3 2.4 11.4 129.7 TOTALS 3839.5 642.8 758.8 643.8 66.7 35.3 343.3 6330.2 *Excludes revenues 570.0 0 157.0 727.0 480.4 0 157.2 637.6 601.0 0 156.7 557.7 335.8 0 155.8 491.6 . 281.1 0 156.2 437.3 234.6 0 157.3 391.9 199.3 0 150.9 346.2 162.3 0 138.6 300.9 13~.2 0 132.9 267.1 110.4 0 127.5 237.9 92.5 0 122.3 214.8 79.3 0 117.3 196.6 '68.0 0 112.5 180.5 58.1 0 107.9 166.0 49.6 12.6 154.8 217.0 '41:9 11,9 140.1 193.9 36.0 22.4 173.9 232.3 30~6 21,1 151.3 203.0 25.9 19.9 132.9 178.7 21.9 18.2 113.7 156.3 3608.9 106.6 2818.8 6334.3 revenues required whether or not Shorehamoperates ( e.g., $1,052.4 are required in both the "In" and "Out" scenarios in 1984.) million additional and inputs have been discussed in previous sections.* The total required.revenues, which include all production, operating and capital-related costs, reflect the assumptions on demand forecast, fuel prices, and Shoreham costs developed in this analysis. If Shoreham operates, cumulative costs of $6.3 billion are incurred This total is composed of carrying charges on the full Shoreham investment ($3.8 billion), property taxes ($0.6 billion), Shoreham operations and maintenance ($0.8 billion), net capital additions ($0.6 billion), spent fuel disposal ($.07 billion), decommissioning ($.04 billion), and nuclear fuel costs ($0.3 billion). Under abandonment~ the total cost is also $6.3 billion, here composed of makeup power ($2.8 billion, including fuel, operations and maintenance, and the cost of coal plants), property taxes on the new coal plants ($0.1 billion), and carrying charges on the 91.5 percent of the Shoreham investment which is charged to LILCO customers ($3.4 billion). For ease of comparison, we have extracted from Table 11 the total required revenue streams of the Shoreham-In and Shoreham- Out cases (see also Figure 2). These are shown in Table 12. While the required revenues vary between cases in individual years, the total over twenty years is essentially the same in both cases. *The discount rate in computing the present value of future costs is taken at 12.64 percent to reflect LILCO's assumed cost of capital, again a conventional procedure. The underlying annual inflation rate assumed is 6 percent. Shoreham property taxes are taken from Company estimates (Direct Testimony of A. Madsen, PSC Case No. 28252, Ex. 1, p. 13). Property taxes for the two 400 MW coal plants (in-service 1998 and 2000) are assumed to be roughly comparable. all items. A four percent revenue tax is applied to - 65 - TABLE 12 SUMMARY REVENUE REgUIREMENTS COMPARISON: RATE WASH CASE (1983 Present Value in Millions of Dollars) Total Total Year Shoreham-In* Shoreham-Out* 1984 751.6 727.0 1985 656.7 637.6 1986 573.5 557.7 1987 504.7 491.6 1988 447.1 437.3 1989 398.2 391.9 1990 355.0 346.2 1991 318.8 300.9 1992 287.4 267.1 1993 259.1 237.9 1994 237.8 214.8 1995 220..7 196.7 1996 205.4 180.5 1997 191.9 166.0 1998 179.9 217.0 1999 169.0 193.9 2000 157.7 232.3 2001 147.7 203.0 2002 138.3 178.7 2003 129.7 156.3 Total 6,330.2 6,334.3 *Excludes revenues required whether or not Shoreham operates. - 66 E S R G 6. THE POTENTIAL ROLE OF CONSERVATION An acceleration of the rate of customer adoption of energy conservation measures can contribute to an overall strategy for abandoning the Shoreham generating station. There are two ways in which additional conservation can help. First, it will reduce the growth in demand for power, and can thus make it easier, technically and economically, for Long Island Lighting Company to meet its customers' demands for electricity. Second, it can contribute to reducing the electricity b%lls of households and businesses by reducing the amount of electricity purchased to meet the service requirements of customers. In response to increasing prices and increasing awareness, the efficiency with which electricity is used has increased over the past decade. But opportunities for cost-effective conserva- tion are far from exhausted. The policy problem is how to encourage the move to a second wave of cost-effective conservation. Here, LILCO itself can play a productive role. Through a combination of information, incentives, and practical assistance, the utility can effectively accelerate the rate of customer energy conservation. In addition, governmental agencies, including Suffolk County, can develop information, regulations, and incentives to further spur business and household conservation. The County can also accelerate its program of minimizing fuel and energy costs - 67 E S R G in its own buildings, as for example by entering into contracts with the new "shared savings" companies that install conservation measures at no cost in return for a share of the energy bill savings. For the current study, a specific strategy for accelerated conservation promotion by LILCO has been developed. This is consistent not only with the local need to minimize any economic penalties of Shoreham cancellation, but also with an ongoing Docket (Case No. 28223) convened by the New York State Public Service Commission to inquire into ways in which utilities can bring economic benefits to ratepayers through appropriately designed conservation incentives. An accelerated LILCO conservation program can be one component of a set of conservation promotion actions undertaken privately and by public agencies in the region. The goal is to design a practical, economical program by which LILCO can bring about the benefits of a reduction in the amount of revenues it would otherwise collect from its customers through attainment of a target level of additional conservation.* Because certain utilities in the Northeast and elsewhere have experimented with accelerated customer conservation and peak- period demand reduction programs, it has been possible, in developing this program design, elsewhere and apply it to Long circumstances. to draw upon practical experience Island in ways that reflect local *Documented in Technical Report C. - 68 - E S R G A number of specific LILCO program elements have been included in the Conservation Investment Option which would contribute to saving electricity at a fraction of the cost of providing it. These included a significantly stepped-up program of information and public education for households and business enterprises in the region; cash incentives to encourage customers to acquire the most efficient types of lighting, cooling, refrigeration, and other electrical equipment available on the market; a program to install low-cost weatherization and conservation measures directly in the residential dwellin~ stock in the area; and promotion of controlled, off-peak water heating. In addition to this conservation program aimed at "the customer's side of the meter," LILCO can undertake low-cost engineering steps to reduce the amount of power sent out to the distribution circuits that serve customers, with no degradation in effective service to customers. Specifically, efforts to reduce maximum service voltages (while retaining current minimum standards) are included. Initial results indicate that by beginning this program immediately and continuing it, within a decade LILCO can reduce overall energy consumption by eight percent, and summer peak period system demand by six percent. Such a conservation and "load management" investment program, continued through the year 1999, will reduce the revenues LILCO will need to collect from customers by $580 million dollars (1983 present value), compared - 69 - E S R G to required revenues without the accelerated conservation program. Quantitative findings on the cost and planning impacts of not operating Shoreham and simultaneously achieving such "deeper" conservation levels are presented in Technical Report C. Previous ESRG investigations, including a report presented before The New York Public Service Commission in Case 27774, have shown that the potential for cost-effective additional customer energy conservation is greater than that which the program recommended here for the LILCO area would achieve. However, the effort here has been to design a specific practical program with a high likely ratio of benefits to costs and a high level of administrative feasibility. It must be remembered that LILCO has a small and narrow customer conservation effort at the current time, focussed largely on the state-mandated "Saving Power" home energy audits. Moreover, LILCO has no plans for significant expansion of efforts in this direction. In addition, no plans appear to be afoot to realize the energy conservation benefits of more careful control of maximum service voltages. Therefore, the several elements outlined above (and detailed in the technical report on conservation) constitute a realistic "first generation" expanded conservation program through which LILCO can play a part in the effort to bring the economic benefits of improved efficiency to the region. Policy action, legislative or regulatory, will probably be necessary for LILCO to assume this - 70 - E S R G role. Experience elsewhere has shown that, once given firm direction, even utilities that have been reluctant to promote conservation can develop responsive management plans to effect the mandated goals. - 71 - E S R G 7. SENSITIVITY ANALYSIS In order to test the sensitivity of the results to alternative sets of assumptions, a number of cost comparisons were made based on different assumptions.* The results of these comparisons are shown earlier in this report in Table 1 and Figure 1. In performing the sensitivity analysis, individual assumptions of the Rate Wash case were modified as described below. In each of these alternative scenarios, all assumptions except those noted retain their base values from the Rate Wash case. Load Forecast If peak loads grows more quickly than forecast, at 1.6 percent annually rather than 0.8 percent, the revenue requirements under abandonment are 1.1 percent greater than if the plant operates. This is equivalent to an increase of $230 million (1983 P.V) over twenty years. The increase occurs because coal plants will be needed in 1994 and 1996 rather than 1998 and 2000 as in the Rate Wash scenario. If peak loads do not grow, however, abandonment is less costly than operations. Under abandonment, rates would decline by 1.6 percent ($310 million in 1983 P.V.). As in the high growth case, the revenue impact results from a change in the on-line dates of new generation plants. With no load growth, new capacity would not be needed until 2002. No growth in peak loads *Scenario results are presented in detail in Technical Report D. - 72 - E S R G might occur if demand for electricity is curtailed as a result of forthcoming rate increases related to recovering the Shoreham investment, regardless of whether the plant operates. In developing the base load forecast, "business-as-usual" projections of important determinants of demand, e.g., industrial activity, employment, and population, were employed. If large increases in electric rates reduce growth in these items, demand growth could also be sharply reduced. Fuel Price Escalation In the Rate Wash scenario, oil prices were assumed to increase at the general inflation rate '(6 percent) until 1987 and at a 2 percent real (above inflation) rate thereafter. Coal prices were assumed to grow at a constant 1 percent real rate. If fuel prices rise more quickly, oil at 3 percent after 1987 and coal at a constant 2 percent, the abandonment is found to increase rates by 0.6 percent ($120 million 1983 P.V.). On the other hand, if there are lower growth rates (oil at 1 percent real and coal at 0 percent real), electricity costs under abandonment would decline (0.5 percent or $100 million 1983 P.V.). New York Power Pool Energy The assumptions on the availability of pool energy are described in Section 3. If twice that amount is available, rates are reduced by 0.2 percent ($50 million 1983 P.V.). Conversely, if no makeup energy is available from the pool, rates increase by 0.3 percent or $60 million 1983 P.V. 73 - E S R G Shoreham Operations and Maintenance Expense To test the sensitivity of operations and maintenance expenses, a case was considered in which the real escalation (after inflation) of these costs was twice as great as predicted by the model. A second case, with no real growth in these costs, was considered. The results were symmetric about the Rate Wash scenario. In the high escalation case, abandonment results in rates which are 1.1 percent ($290 million 1983 P.V.) lower. In the low cost case, abandonment raises rates by the same amount. Future Shoreham Investments The sensitivity of the results to different future investment streams was analyzed in a similar manner. When future capital additions increase at twice the real rate used in the Rate Wash case, abandonment is found to yield a reduction in rates of 1.4 percent ($290 million 1983 P.V.). With no real increase, abandonment results in an increase in revenue requirements of 1.4 percent, or $290 million. Shoreham Capital Recovery The Rate Wash case assumes that under abandonment LILCO will receive depreciation and return on about 91 percent of its investment in the Shoreham unit. Of course, the actual level of recovery is an issue of regulatory policy.* If full recovery is *The financial computations assume that both depreciation and return would be reduced uniformly each year. In practice, the PSC would have to consider two major issues: the amount of the Shoreham investment to be recovered from LILCO customers and the timing of that recovery. The decision would presumably be based on an equitable sharing of the Shoreham investment costs and on implications for LILCO's financial conditions. - 74 E S R G allowed, rates would increase under abandonment by 2.2 percent, or $430 million 1983 P.V. Conversely, if less than 91 percent is allowed, abandonment leads to a reduction in required revenues. The work of another of the County's consultants, Georgetown Consulting Group, indicates that if LILCO were allowed 55 percent of Shoreham related depreciation and return, it would maintain reasonable financial health. Fifty-five percent recovery would lead to rates 9.2 percent lower ($1840 million 1983 P.V.) under abandonment. Time Period of Analysis In the analysis, impacts are calculated over the twenty-year period 1984-2003. When the period under consideration is increased to thirty years, abandonment is found to reduce rates by 0.3 percent or $60 million (1983 P.V.). When the period is shortened to ten years, abandonment also leads to a reduction in required revenues; in this instance by 1.2 percent, or $120 million 1983 P.V. What If Shoreham Had Never Been Built? Finally, a case in which no recovery of Shoreham investment costs is assigned to rate payers. This is equivalent to asking the question: ~ow much better off would rate payers be if Shoreham had never been started? The answer is that rates would be 17 percent lower on average over twenty years. This is equivalent to a reduction in revenue requirements of $3400 million in 1983 present value. - 75 - E S R G 8. REVIEW OF LILCO'S COST IMPACT ESTIMATES AND "CRITIpUE" ~ The Long Island Lighting Company staff recently developed its own estimates of the economic consequences of not operating the Shoreham facility.* LILCO's primary conclusion -- that electric bills would be some $25 billion higher over the 1984 to 2023 time period -- is in summarized above that the worst (see Table 1). striking contrast to the findings impacts on ratepayers would be small at The question naturally arises: why are LILCO's estimates so much higher than those presented in the current report? The two reports can be reconciled in several straightforward steps, as will be demonstrated quantitatively below. The main difference between the results -- indeed 90 percent of the difference -- is traceable to differences in method. LILCO's estimates are inflated ("nominal") dollars over a forty-year period, imappropriately ignoring the time-value of money. Recasting their results in common (1983 "present value") dollars reduces the impact from $25 to $2.8 billion. Focusing on the twenty-year timeframe advocated in this report reduces LILCO's estimated impact to $2.3 billion. The disparity largely vanishes by correcting the Company's failure to report its results in proper monetary units and its inclusion of highly speculative effects past the year 2003.** The *"Shoreham Operation Versus Shoreham Abandonment (An Economic Analysis)", LILCO Office of Engineering, April, 1983. **Indeed, it was reported earlier that extrapolating beyond twenty years had the opposite effect claimed by LILCO. Due primarily to nuclear aging phenomena and decreasing carrying costs for substitute power plants, the impact on ratepayers diminishes in the extended timeframe (see Sections 1 and 7). - 76 - E S R G remaining difference has to do with certain extra costs that LILCO charges, we believe erroneously, to the Shoreham-Out case (e.g.~ an unneeded coal conversion, a premature coal plant, extra capital-related Shoreham costs when the plant does not operate, the Bokum write-off). Finally, LILCO failed to account properly for future expenditures that would be incurred to keep Shoreham operating, particularly downstream capital expenditures on plant and equipment. To illustrate, Table 13 presents the reconciliation of LILCO's estimate to the Rate Wash scenario developed earlier in this report.* The results are displayed graphically in Figure 9. The adjustment areas will be discussed in turn. Methods As mentioned above, the main reason that the LILCO results differ from those here is that LILCO chose to report its results in mixed current dollars. The conventional approach is to account fOr the time value of money (a dollar in hand is worth more than a dollar next year, let alone one twenty to forty years hence) by discounting to common present worth monetary units (e.g., 1983 present value dollars). The effects of using inflated nominal dollar estimates of streams of costs are compounded by the other major differences in method of analysis. LILCO has employed a forty year timeframe (1984-2023) as opposed to the twenty years recommended here. *Other scenarios can be compared using identical procedures. - 77 - E S R G TABLE 13 RECONCILIATION OF LILCO COST IMPACT ESTIMATES WITH RATE WASH SCENARIO Adjustment (Billion $) LILCO'S ORIGINAL ESTIMATE . 1. Methods · Convert to Present Value (discount to 1983 dollars) · Compute Impacts Over 20 Years 2. Shoreham Operations Costs · Include Capital Additions Projections · Use Statistical Projections of O&M 3. Make-Up Generation Costs · Remove Uneconomic Coal Conversion · Delay Coal Plant In-Service Dates · Add Back Extra Fuel Costs 4. Recovery of Shoreham Initial Investment · Remove Extra Costs LILCO Associates with Shoreham Not Operating · Reduce Shoreham Fraction in Rate Base in Rate Wash Scenario 5. Miscellaneous* RATE WASH SCENARIO Revised Estimate of Rate Impacts (Billion $) 25.0 - 22.2 2.8 - 0.5 2.3 0.3 2.0 0.2 1.8 - 0.7 1.1 - 0.8 0.3 1.0 1.3 0.6 0.7 0.4 0.3 0.3 0.0 *Includes LILCO charge to the Shoreham-Out case of the Bokum write-off at $97 million. - 78 - E S R G 25 20 Cost Impact of ~,andonment (billions $)15 l0 5 , J~O F~GURE 9 RECONCILIATION OF LILCO ESTIMATE OF ABANDONMENT COSTS WITH i'HE RATE WASH CASE Shoreham Makeup Methods Operations Generation Recovery of Shoreham Rate Investment Wash Recast Present Use Value 20 Yr. Adjust Capital Adjust I .~sis AH~ear ................. Adjusted Add Back Remove Additional Coal COn. Delav Fuel version Coal= Costs Estimates Remove R~du~ Extra Rate- LILCO payers ' Costs Share There are strong reasons for basing today's policy decisions on no more than a twenty-year timeframe as discussed earlier.* The combined effects of not discounting and extending the time period for analysis to forty years produce extremely large contributions to LILCO's estimates (almost $23 billion of the overall $25 billion estimate). For example, fully $5 billion of the impact reported by LILCO is in the highly speculative years, 2019-2023. Simple discounting to 1983 dollars reduces this to about $60 million. Shoreham Operations Costs Table 13 shows that of the $2.3 billion variance remaining after adjusting to consistent methodological approaches, an additional difference of $0.5 billion between the two analyses is associated with estimates of Shoreham costs after it comes in- service. First, the statistically based projections of operations and maintenance costs are somewhat higher than LILCO's (about $0.2 billion). As described in Section 5, these projects are based on an analysis of the actually experienced costs in- curred at other plants and the significant variables driving those costs. We know of no sounder basis for long-range projections. The same can be said for estimates of the continuing investments once the plant comes in-service which have been required of all operating nuclear power plants and which will be required for Shoreham. LILCO appears to be employing in-house estimates that, relative to the statistical projections, are too low by about $0.3 billion. *Analytic results become far to speculative= sensitivity projections past 2003 showed that the economics of opening Shoreham actually deteriorate and the lifetime of the Shoreham plant is uncertain. (Until its April report, LILCO was assuming 30 not 40 years of operational lifetime.) E S - 8o -R O Make-Up Generation Costs This area as shown in Table 13 accounts for another $0.5 billion of difference between the studies. As indicated in Section 3 above, the approach taken in the present analysis is to bring new capacity into service as required to meet reserve requirement targets. In LILCO's study, however, the Shoreham-Out case is charged with the cost of converting four existing coal plants, while admitting that "at present these conversions don't appear economical," LILCO assumes that they will be undertaken if Shoreham does not operate, in response to fuel reliability concerns.* In this analysis, the cost of the unneeded conversions has not been charged to the abandonment case. Two of the conversions have, by the way, been included along with Shoreham in LILCO's plans, up to this point. Another difference concerns load forecasts. Using its forecast, LILCO finds it will need new coal capacity in 1994 and 1996. However, with the lower growth forecated here, it is found that these plants are not needed until 1998 and 2000. On the other hand, the extra coal units assumed by LILCO have the benefit of reducing make-up power production costs since coal generation is substituted for oil generation and power transfers from the New York Power Pool. These effects are sumarized in Table 13. *However, LILCO also assumes that new coal plants are built in 1994 and 1996 while the coal conversions are not complete until 1991. In other words, the conversions only allow substitution of coal for oil in a few years in the early 1990s. As a sensitivity check, cost impacts were computed, as LILCO would have it, with four coal conversions in the Shoreham-Out case and none in the Shoreham-In case. The additional impact on costs is $170 million, or less than a percent on rates. This is a fictitious scenario since two of the conversions are planned with Shoreham operating. - 81 - E S R G Recovery of Shoreham Initial Investment There are two components here. First of all, LILCO assumes that paying for the Shoreham plant will cost more if the plant is abandoned than if it is operated. The Shoreham investment in this study is, on the other hand, assumed to be identical if it operates or not. Indeed, it is plausible that the costs would be less if it does not run insofar as the investments are terminated prior to the date when the plant otherwise would come in-service. Secondly, LILCO assumes a ratemaking treatment which not only has ratepayers paying for 100 percent of the principle and return on Shoreham, but actually paying more (in present worth dollars) through rapid depreciation. The Rate Wash scenario assumes 91 percent recovery in the Shoreham-Out case with comparable depreciation schedules.* Miscellaneous Differences in Assumptions This relatively minor differential (about 0.3 billion) includes the effects of LILCO assuming that the Bokum Resources investment (related to an abortive uranium venture) is charged to ratepayers only if Shoreham does not operate. Whatever the merits of allowing LILCO to recover its Bokum costs, they are not the result of abandoning Shoreham and should not be charged to it. In summary, LILCO's claims concerning the impacts of Shoreham are greatly overstated. In particular, the abandonment of Shoreham would not be a catastrophe for the County or for *Indeed, the Rate W-sh scenario is conservative in that the tax write-off of the Shoreham investment is not more accelerated in the abandonment case though the Company would be eligible for such a treatment. Using a five-year write-off schedule, the fraction of Shoreham recoverable in the rate base to achieve a "rate wash" would rise from 91 percent to 96 percent. - 82 - LILCO. while the precise cost repercussions depend on variables which cannot be precisely predicted (especially the regulatory treatment of the Shoreham investment), over a range of reasonable scenarios the average rate impacts are plus or minus a few percentage points. LILCO's Critique In June 1983, LILCO released a "critique" of a preliminary version (May 1983) of the present report.* The Company's comments were reviewed briefly along with those of other technical experts in the preparation and revision of this final document. A more de- tailed treatment of LILC0's critique will be prepared in the future. The issues raised by LILCO may be segmented into two categories: (1) a series of numerical adjustments to the Rate Wash scenario that in essence reinserts the LILCO cost and planning assumptions described earlier (not surprisingly, the results ultimately resemble LILCO's cost impact assessment suitably modified into common "present worth" dollars); and (2) a number of qualitative complaints offered in passing but not used in the quantitative adjustments. The first category -- the substantive issues raised by the Company -- will be briefly reviewed below where it is concluded that, in essence, LILCO continues its now decade long pattern of over-optimism in estimating costs of the Shoreham project. In the absence of sound independent technical back-up *Preliminary Critique~ Suffolk County Study of Shoreham Abandon- ment, prepared by Office of Engineering, Long Island Lighting Company, June 1983. - 83 - E R G on assumptions and methods, LILCO's case for Shoreham rests on an appeal to faith in its own in-house engineering estimates -- estimates which have been so dramatically erroneous in the past. The qualitative side comments which pepper the report are largely incorrect, obscure or irrelevant.* These will be addressed in future reports. What does LILCO~s quantitative critique say? It attempts to "correct" the Rate Wash scenario from zero average impact on rates to an impact of about 13 percent on rates ($2.6 billion cumulatively). The 13 percent adjustment consists of several elements. A significant portion (6 percent) has to do with Shoreham capital cost recovery in the event the plant does not open. These LILCO assumptions have been discussed earlier= return should be 100 percent, amortization should be accelerated (meaning electric customers pay more when Shoreham does not operate), and Shoreham will cost more if it is abandoned than not abandoned due to regulatory delays. This latter point is illogical~ delays and litigation appear inevitable in all scenarios. If anything, the costs could be less if further *For example, the "arithmetic mistake" discovered by LILCO (p.1 ff.) of the "critique" turns out to be that the County used LILCO~s own assumption on firm interties (Report of Momber Electric Systems of the NYPP, 1983, Vol. 2, p. 34) while LILCO now wants to deny any firm capacity from interties (p. 18). The County's 'misunderstanding of complex legal/regulatory matters' (p.1) is simply that LILCO does not think investors should bear part of the costs for an abandoned facility~ but such cost-sharing is in fact the tyDical ratemaking treatment in the U.S. for abandoned equipment. LILCO claims the County used an "unreal- istically low~ capacity factor but in fact the values e~ployed are more favorable than implied by statistical analysis (Fig. 8 above). Finally, LILCO implies (9.4) that the County's use of a 20 year timeframe was chosen to bias the results against Shoreham, but sensitivity analyses for 10 and 30 years makes the Shoreham option look worse (see, e.g., Fig. 1 above). - 84 - £ S R G Shoreham investments are capped early on and amortization commences. In the Shoreham-In case there will be a period of disputation of unknown length that would be required to obtain approval over the County's objection to the plant operating in Suffolk County. Of the remaining 7 percent rate impact LILCO suggests, over 2 percent results from attempting to add to regional revenues certain "indirect" property tax consequences which have no impact on electricity costs. These are (the critique itself admits) not part of required revenue. It is simply erroneous and misleading to include them, as the purpose of the County's study was to compute rate impacts. (They were not included in LILCO's own earlier estimate of required revenue impacts.) In addition to property tax effects, there are other non-rate impacts of the Shoreham decision (e.g., property value deterioration, health and safety risks, employment consequences) which are an ongoing topic of investigation by the County (to be presented in future reports). Thus, of the original 13 percent rate impact in LILCO's "adjusted" Rate Wash case, 7 percent has been traced to LILCO's Shoreham capital cost impact treatment which assumes ratepayers will be substantially penalized if the plant does not operate and a fictitious property tax adjustment to electric rates. A further 1 percent consists of a pot pourri of minor miscellaneous adjustments. The critique presents no documentation on assumptions, methods and relative impacts of these various effects. Some of the miscellaneous adjustments are clearly - 85 E S R suspect (e.g., charging the Bokum Resources mining venture to Shoreham-Out, adding capacity charges in a scenario where adequate reserve margins are maintained, assuming no Power Pool purchases available for make-up*). Others simply cannot be evaluated without a better technical description. Finally, LILCO again asks us to accept its own in-house engineering judgements as a substitute for the empirically-based, statistical analysis of power plant performance (especially, O&M, capacity factors and future capital additions). This will be difficult for those who have followed LILCO~s track-record in projecting Shoreham costs -- a decade of revisions with current estimates 1000 percent greater than original projections. Each year, LILCO~s optimistic in-house engineering estimates have been offered, as they are now, as firm planning guidelines. *Indeed, LILCO~s own production costing runs evaluating make-up power requirements for Shoreham provided to County consultants in the ongoing NPhase-in# case before the PSC show availability of NYPP purchases at levels comparable to those used in this investigation. At any rate, the scenario with no NYPP purchases led to only a $60 million penalty (0.3 percent on rates). - 86 S R G