ML20073G301
| ML20073G301 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 04/12/1983 |
| From: | Meehan E CONSOLIDATED EDISON CO. OF NEW YORK, INC., POWER AUTHORITY OF THE STATE OF NEW YORK (NEW YORK |
| To: | |
| Shared Package | |
| ML20073G302 | List: |
| References | |
| ISSUANCES-SP, NUDOCS 8304180245 | |
| Download: ML20073G301 (43) | |
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, Pr FETEr UNITED STATES OF AMERICA" NUCLEAR REGULATORY COMMISSION ATOMIC SAFETY AND LICI!i61PldidNRb1:35 Before Administrative Judges:
James P. Gleason, Chairman Frederick 3. Shon Dr. Oscar H. Paris l
)
In the Matter of )
)
CONSOLIDATED EDISON COMPANY OF ) Docket Nos.
NEW YORK, INC. ) 50-247 SP i (Indian Point, Unit No. 2) ) 50-286 SP
)
)
POWER AUTHORITY OF THE STATE OF )
NEW YORK ) April 12,1983 l
(Indian Point, Unit No. 3) )
L )
)
LICENSEES' TESTIMONY OF EUGENE T. MEEHAN ON COMMISSION QUESTION 6 l ATTORNEYS FILING THIS DOCUMENT:
i l
l Brent L. Brandenburg Charles M. Pratt CONSOLIDATED EDISON COMPANY POWER AUTHORITY OF THE STATE OF NEW YORK, INC. OF NEW YORK 4 Irving Place 10 Columbus Circle New York, New York 10003 New York, New York 10019 i
(212) 397-6200 (212) 460-4600 l
l 8304180245 930412 PDR ADOCK 05000247 T PDR
4 TABLE OF CONTENTS Pjtq.e
- 1. Introduction ....................................................... 1
- 2. PROM 0D III* Overview ................................................ 3
- 3. Data Assumptions ................................................... 13
- 4. Presentation of Results ............................................ 28
- 5. Conclusion ......................................................... 40 i
l
o 4
- 1. INTRODUCTION My name is Eugene T. Meehan. I am a Vice President of Energy Management !
- Associates, Inc. (EMA). A statement of my professional qualifications is attached as Appendix A.
- This testimony addresses Commission Question 6 in this proceeding which asks
What would be the energy, environmental, economic or other consequences of a shutdown of Indian Point Unit 2 and/or Unit 3?
Specifically, this testimony examines the economic production cost penalty in terms of increased dollars required to supply electricity, and the energy penalty in terms of increased oil used to generate electricity, that would result from the shutdown of the Indian Point nuclear generating units 2 and 3 (Indian Point).
Increased production costs and oil usage resulting from the shutdown of Indian Point would impose consequent damages upon the economic and energy situation.
I Other witnesses testifying on behalf of the licensees will address the consequent effects of increased production costs and oil usage of an Indian Point shutdown.
The analysis of the production cost penalty was conducted for the 1984 to 1999 period. The demand for electricity in New York State and the resources for supplying electricity in the State are forecast annually in the Report of Member !
Electric Systems of the New York Power Pool (NYPP) pursuant to Sectl>n 5-112 of the Energy Law of New York State (5-112 Report). The 1983 5-112 Report was filed on April 1,1983. This study was conducted while that report was being prepared, and the data being developed for inclusion in that report served as the basis for the demand and resource assumptions used in EMA's analysis for the reference scen ..o analyzed herein. In addition to determining the production cost penalty associated with the Indian Point shutdown for a reference scenario, the sensitivity of the penalty to load growth, fuel prices, nuclear plant capacity factor and coal conversions was analyzed.
If the energy Indian Point would normally supply is unavailaisle, there would be three major direct effects on production costs:
- 1. Increased fuel costs within NYPP resulting from the replacement of Indian Point energy by oil, gas, and coal generation; 1-
~ , - , - , , . --------e-~ . -- - - , - - , .- , - , -- ---
4
- 2. Increased purchased power costs resulting from the replacement of some Indian Point energy with additional purchases from Canada; and
- 3. Increased purchased power costs for volumes of Canadian imports common to the with and without Indian Point scenarios resulting from increases in the value of NYPP energy displaced by those imports.
The annual direct production cost penalties for the State of New York, the Consolidated Edison Company of New York, Inc. (Con Ed) and the Con Ed Service Area are reported herein. The additional quantities of oil that would be used to replace Indian Point generation are also reported.
t 4
- 2. PROMOD III' OVERVIEW The effects of the Indian Point shutdown were determined by simulating the operation of the New York Power Pool generating system with and without Indian Point. The PROMOD III System is a comprehensive tool for performing major production cost analyses. The PROMOD 111 System is capable of simulating the operation of an integrated power pool in which transmission limitations affect the commitment and dispatch of generating units.
A. General Description.
The PROMOD III program contains five basic modules:
o Input Module - This module reads all input data and performs preliminary diagnostic scans.
o Preprocessing Module - This module creates initial working files, performs detailed diagnostic checks, and provides an organized display of the basic data.
4 o Probabilistic Simulation Module. - This module simulates the operation of the generation system to meet the load and energy forecast in the most economic manner, subject to operating constraints and transmission limits.
The principal quantities computed by this module are:
Expected generation for each generating unit Expected fuel costs
- Expected fuel consumption o Energy Storage Module - This module simulates the operation of 1
energy storage projects, such as pumped storage hydro plants. It determines the optimal economic utilization of these projects, the cost of generation for energy storage, and the operating cost savings attributable to each energy storage project'. Data inputs
' to the model include the energy storage efficiency, the size of the storage reservoir, and the pumping and generating capacity of the project.
- o Billing Reconstruction Module - This module determines for internal (intra pool) economy energy transactions the associated billing costs, savings to buyers and profits to sellers. For external economy energy transacticns (between NYPP and neighboring
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. pools or utilities), this module determines total pool billing dollars and savings and allocates billing dollars and savings to individual companies. In accordance with the principle of cost minimization through central dispatch, all dispatch decisions are made on the basis of minimizing total cost. Billing reconstruction is performed after the fact, and does not interfere with total cost minimization. -
The PROMOD 111 System stands out from less sophisticated production costing programs in its treatment of forced outages of generating units and its recognition of transmission transfer limits. It is these forced outages that are the major disruption of fuel budget forecasts, operating cost forecasts, and projected utilization of high cost peaking equipment. Since these outages are random and are unpredictable, PROMOD Ill employs an advanced probabilistic technique to properly consider their resultant impact on fuel requireinents, operating costs, and reliability. Generating units can be represented by a multi-state failure model to give explicit consideration to partial loss of unit capability and forced outages of varying severities. Possible failure states of each unit are considered in combination with possible failure states of all other units in order to obtain the best forecast of expected fuel consumption, operating costs, and plant capacity factors.
B. Utility Industry Acceptance.
PROMOD 111 has been used extensively in both the public and private sectors of the utility industry.
Over fifty utilities across the country, as well as four utilities in Canada and Australia are using PROMOD III for reliability analyses, generation planning, fuel budgeting, marginal costs analyses, and load management studies. In addition to the New York Power Pool and six NYPP utilities, many major power companies use PROMOD 111. These
! include American Electric Power, Commonwealth Edison, Duke Power, Detroit Edison, Florida Power and Light, Southern California Edison, Virginia Electric and Power Company, and the P3M Power Pool.
l PROMOD III has been used in studies and testimony done by the Staff of l
the New York State Department of Public Service and is leased from EMA by the United States Department of Energy. PROMOD 111 results 4
have been accepted as evidence by numerous state regulatory commissions.
Table 2.1 contains a list of companies using PROMOD III for planning and budgeting purposes.
Since 1977, PROMOD III has been increasingly employed by EMA and its clients in developing supporting evidence for regulatory hearings. Table l
2.2 provides a partial list of such hearings. Table 2.3 illustrates the variety of applications in which utilities have used PROMOD III. No attempt has been mar,e to record each analysis performed by utilities using PROMOD III. Hence, Tables 2.2 and 2.3 present a noncomprehen-sive view of all PROMOD III applications.
C. NYPP Experience EMA has worked very closely with the member companies of the New York Power Pool to ensure that PROMOD III correctly models the pool operations and billing reconstruction procedures of NYPP. The PROMOD 111 model is currently licensed from EMA and used by:
o Central Hudson Gas and Electric Corperation o Consolidated Edison Company of New York,Inc.
o New York Power Pool o New York State Electric and Gas Corporation o Niagara Mohawk Power Corporation o Orange and Rockland Utilities,Inc.
o Rochester Gas and Electric Corporation Additionally, EMA has performed a wide variety of consulting studies employing PROMOD III for New York State clients. All New York utilities, as well as the New York State Department of Public Service, have been itivolved in these studies. Hence, the PROMOD III model has been subjected to thorough review by New York State utilities and regulatory authorities. The EMA staff has become very familiar with the NYPP generating system.
EMA's work with NYPP led to the development of billing reconstruction algorithms specifically designed to model the interaction between NYPP and Ontario Hydro (OH) and Hydro Quebec (HQ). These algorithms model the pool's use of external economy energy in the most
-. . __ ~ .._ , _ . _ _
, TABLE 2.1 PR OM OD III USERS ALLEGHENY POWER SYSTEM,INC. O NEW YORK POWER POOL AMERICAN ELECTRIC POWER COMPANY,INC. O NEW YORK STATE ELECTRIC & GAS CORP.
ATLANTIC CITY ELECTRIC COMPANY 0 NIAGARA MOHAWK POWER CORPORATION 9 BALTIMORE GAS & ELECTRIC COMPANY 0 NORTHERN INDIANA PUBLIC SERVICE CO.
CAROLINA POWER & LIGHT COMPANY 0 NORTHERN STATES POWER COMPANY CENTRAL & SOUTH WEST CORP. O NOVA SCOTIA POWER CORPORATION CENTRAL HUDSON GAS & ELECTRIC CORP. O OMAHA PUBLIC POWER DISTRICT O ORANGE AND ROCK! AND UTILITIES,INC.
CLEVELAND ELECTRIC ILLUMINATING CO.
COLORADO SPGS. DEPT. OF PUB. UTILITIES 0 PENNSYLVANIA-JERSEY-MARYLAND PWR. POOL COMMONWEALTH EDISON COMPANY 0 PENNSYLVANIA POWER & LIGHT COMPANY CONSOLIDATED EDISON CO. OF N.Y., INC. O PORTLAND GENERAL ELECTRIC COMPANY THE DAYTON POWER AND LIGHT COMPANY 0 POTOMAC ELECTRIC POWER COMPANY DELMARVA POWER & LIGHT COMPANY 0 PUBLIC SERVICE COMPANY OF COLORADO
-- DEPARTMENT OF ENERGY 0 PUBLIC SERVICE COMPANY OF INDIANA DETROIT EDISON COMPANY 0 PUBLIC SERVICE COMPANY OF NEW MEXICO DUKE POWER COMPANY 0 PUBLIC SERVICE ELECTRIC & GAS COMPANY DUQUESNE LIGHT COMPANY 0 PUERTO RICO ELECTRIC POWER AUTHORITY EL PASO ELECTRIC COMPANY 0 ROCHESTER GAS & ELECTRIC CORPORATION FLORIDA POWER CORPOR ATION O SALT RIVER PROJECT FLORIDA POWER & LIGHT COMPANY 0 SAN DIEGO GAS & ELECTRIC COMPANY GENERAL PUBLIC UTILITIES 0 SASKATCHEWAN POWER CORPORATION GULF STATES UTILITIES 0 SAVANNAH ELECTRIC AND POWER COMPANY HOUSTON LIGHTING AND POWER COMPANY 0 SIERRA PACIFIC POWER COMPANY ILLINOIS POWER COMPANY 0 SOUTH CAROLINA ELECTRIC & GAS COMPANY IOW A ELECTRIC LIGHT & POWER COMPANY 0 SOUTHERN CALIFORNIA EDISON COMPANY JACKSONVILLE ELECTRIC AUTHORITY 0 SOUTHERN ENGINEERING CO. OF GEORGIA LOS ANGELES DEPT. OF WATER & POWER 0 STATE ENERGY COMM. OF W. AUSTRALIA LOWER COLOR ADO RIVER AUTHORITY 0 TAMPA ELECTRIC COMPANY MIDDLE SOUTH SERVICES, INC. O TEXAS UTILITIES SERVICES INC.
MONTANA POWER COMPANY 0 THE TOLEDO EDISON COMPANY MUNICIPAL ELECTRIC AUTHORITY OF GA. O UTAH POWER & LIGHT COMPANY NEW BRUNSWICK ELECTRIC POWER COMM. O VIRGINIA ELECTRIC AND POWER COMPANY WISCONSIN POWER & LIGHT COMPANY O
TABLE 2.2 PROMOD III USE IN REGULATORY PROCEEDINGS YEAR CLIENT CASE DESCRIPTION 1983 Florida Power Corporation Forward Looking Fuel Clause Adjustment Hearing. Docket No.
830001 -EU.
1983 Florida Power Corporation Annual Planning Workshop for Florida Electric Utilities and the Public Service Commission. Docket No. 830004-EU.
1982 West Penn Power Company Analysis of the Economics of the Purchase by West Penn Power Company of a Share of the Bath County Pumped Storage Project. Docket No.
- A-00103260, et al, Before the Pennsylvania Public Utilities Commission.
1982 Rochester Gas and Electric Corp. Determination of Marginal Energy Costs For Use in Rate Proceedings. Case No.
28313.
1982 Pennsylvania Power and Light Co. Development of Fuel Cost Savings Associated With Addition of New Nuclear Plant. Docket No. -R-822169.
1982 Public Service Electric and Gas Development of Levelized Fuel Adjustment Fer Use in Rate Proceeding.
Docket No. 812-76.
1982 Savannah Electric Power Company Fuel Cost Recovery Clause. GA PSC Docket No. 3381-U.
1982 Savannah Electric Power Company Determination of Economic Benefits of Oil to Coal Conversion. GA PSC Docket No.3361-U.
1982 Tampa Electric Company Rate Hearings. Case No. 820007-EU, Case No. 830004-EU.
1982 Atlantic City Electric Company Levelized Energy Adjustment Clause.
Docket No. 8210-892.
TABLE 2.2 PROMOD III USE IN REGULATORY PROCEEDINGS (Continued)
YEAR CLIENT CASE DESCRIPTION 1982 Atlantic City Electric Company Marginal Energy Adjustm-nt Clause.
Docket No. 8210-904.
1981 Atlantic City Electric Company Levelized and Marginal Energy Adjustment Clause. Docket No. 7911-951.
1981 Niagara Mohawk Power Corporation Analysis of Economic and Financial Rochester Gas & Electric Corporation Implications of the Nine Mile Point 2 New York State Electric & Gas Corp. Nuclear Generating Unit. Case No.
Central Hudson Gas & Electric Corp. 28059.
Long Island Lighting Company 1981 Niagara Mohawk Power Corporation Marginal Energy Cost Analysis. Case No. 27741 - Phase II.
1981 Arkansas Power & Light Company Power Suoply Planning Analysis. Docket No. 81-144-U.
1981 Consolidated Edison Company Analysis of Replacement Cost of Indian Point 2 Power. Case No. 27869 1981 Mississippi Power & Light Company Power Supply Planning Analb ,. Docket No. U-3967.
1981 Public Service Company of Oklahoma Power Supply Planning Analysis. Case No.27068.
1980 Florida Power & Light Company Continuing use of PROMOD 111 to Florida Power Corporation Determine Prospective Fuel Cost Tampa Electric Company Recovery Charges.
1980 Los Angeles Department of City of Los Angeles Department of Water and Power Water and Power PURPA proceedings.
1979 Virginia Electric and Power Company Continuing Use in Fuel Factor Hearing Before the Virginia State Corporation Commission.
1979 U.S. Department of Energy ICC Rail Rate Hearing. Docket #37063.
L&N Railroad.
1978 San Diego Gas & Electric Company Marginal Cost Study Before the Public l
Service Commission of the State of California.
t
s
. TABLE 2.2 PROMOD HI USE IN REGULATORY PROCEEDINGS (Continued)
YEAR CLIENT CASE DESCRIPTION 1978 Niagara Mohawk Power Corporation NYPP Long Range Generation and Transmission Plan Pursuant to Article VIII Section 149-B of the Public Service Law. Case No. 27319.
1978 Commonwealth Edison Company Illinois Commerce Commission.
Construction Program Investigation.
Docket No. 78-06'#6.
1978 Detroit Edison Company Generic Hearings to Determine the Effectiveness of Interrupting Specified Electric Services With Respect to Load Management by Major Michigan Electric Utilities. Case No. U-5845.
l 1977-78 El Paso Electric Company FERC Rate Cases. Docket Nos.
ER-78-520 and ER-77-488.
1977 Public Service Company of Colorado Generic Rate Structure Hearing. PUC Case No. 5693.
1977 Jacksonville Electric Authority Hearings Before Florida Environmental Regulatory Commission on the Existing /New Source Rule (3/27/77).
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. TABLE 2.3 PROMOD III USE IN UTILITY ANALYSIS CONSULTANT CLIENT PROJECT EMA (1981) Niagara Mohawk Power Corp. Evaluation of New York New York State Electric and Gas Corp. State Department of Rochester Gas and Electric Corp. Public Service Alterna-Long Island Lighting Company tives to Nine Mile Central Hudson Gas & Electric Company Point 2 EMA (1981) Consolidated Edison Evaluation of Replacement Power Cost due to Sustained Unit Outage Controller General of Commonwealth Edison Economic Impact of the United States (1981) Closing Zion Nuclear Facility EMA (1981) Public Service Company of Oklahoma Generation Expansion Planning Study EMA (1980) Middle South Utilities Generation Expansion Planning Study EMA (1979) Electric Power Research Institute Compressed Air Energy Storage Study EMA (1979) Electric Power Research Institute Spinning Reserve Cost Analysis EMA (1979) Gulf Mineral Resources Company Market Survey For Solvent Refined Coal EMA (1979) California Power Pool Increased Integration Study
, EMA (1979) Los Angeles Department of Marginal Energy Cost i Water and Power Study EMA (1979) Central Hudson Gas & Electric Company Marginal Energy Cost Study EMA (1978) Stone and Webster Southwest Solar Study EMA (1978) Detroit Edison Company Load Management Study
TABLE 2.3 PROMOD III USE IN UTILITY ANALYSIS (continued)
CONSULTANT CLIENT PROJECT EMA (1977) Edison Electric Institute Load Management Study Florida Power Corp. Department of Energy Ocean Thermal Energy (1979) Conversion Study Gordian Associates Carolina Power and Light Company Marginal Cost Study (1979)
National Economic Los Angeles Dept. of Water & Power Marginal Cost Studies Research Associates Public Service Company of Colorado (1976-1979) Public Service Co. of New Mexico Rochester Gas and Electric Company San Diego Gas and Electric Company Virginia Electric and Power Company Southern Engineering Big Rivers Electric Cooperative Generation Expansion (1979) Study Stone and Webster El Paso Electric Company Marginal Cost Study (1978) l I
l l
l
economic fashion, determine the payments to OH and HQ in accordance with the contracts with those parties, and determine the allocation of external energy and resultant savings to individual companies based upon the agreement among the NYPP companies.
Additionally, EMA's work with NYPP resulted in the development of billing reconstruction logic that captures the effect of the agreements governing Con Ed and the Power Authority of the State of New York (Power Authority) interchange energy. Since the Power Authority does not directly participate in N rPP internal economy interchange, it is necessary to model this accounting arrangement when conducting an analysis examining individual company production cost impacts.
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- _ - . . . - - _ - - . - - - = . ._
- 3. DATA ASSUMPTIONS There are four principal categories of data required to conduct the analysis
. of the production cost penalty of the Indian Point shutdown. These categories are:
- 1. Demand and capacity expansion forecasts;
- 2. Fuel price forecasts;
- 3. Forecasts of Canadian imports; and,
- 4. Unit and system operating characteristic data.
A description of the key items in each area follows.
t A. Demand and Capacity Expansion Forecasts.
) The demand forecast reflects the NYPP utilities' most recent available
- forecasts as of February,1983. Many of these were developed for use in the 1983 5-112 Report. This forecast reflects a compound energy consumption growth rate of 1.4% and a compound electric peak load growth rate of 1.2%. The demand forecasts were developed by the individual NYPP companies and'!nput into the PROMOD 111 System on an individual company basis.
Table 3.1 illustrates the annual NYPP peak and energy consumption forecasts for the 1984 to 1999 period.
Two sensitivity analyses were conducted with respect to load growth.
The first assumed low load growth. Low load growth was defined as a 0.7% compound energy consumption growth rate, as opposed to the 1.4% which was forecast. The second assumed a change in the compound pool energy consumption growth rate from 1.4% to 2.2%.
4 For 1998 and 1999, the pool reserve margin falls below the required NYPP minimum in scenarios without Indian Point. This occurs from 1996 onward in the high load growth scenario. For these scenarios, in addition to the added production costs computed herein, the shutdown of Indian Point would result in the need for more capacity. Ms.
Streiter's testimony addresses added capacity costs. Table 3.2 compares the NYPP energy consumption requirement for the reference case, the low load growth scenario, and the high load growth scenario for selected years.
The capacity expansion forecast was developed based upon the most recent available updates by NYPP member companies to expansion plans. The major capacity additions beyond units already in service are illustrated in Table 3.3.
l 1
l TABLE 3.1 NYPP FORECAST ANNUAL PEAK LOADS j AND ENERGY REQUIREMENTS FORECAST YEAR FORECAST ANNUAL PEAK ENERGY REQUIREMENT MW GWH 1984 21,620 120,068 1985 21,750 121,891 1986 21,990 123,609 1987 22,180 125,311 1988 22,610 126,909 1989 22,870 128,636 1990 23,150 130,370 1991 23,430 132,287 1992 23,750 134,295 1993 24,060 136,178 1994 24,410 138,195 1995 24,720 14G,260 1996 25,050 142,427 1997 25,350 144,472 1998 25,660 146,617 1999 25,980 148,818
~
Table 3.2 COMPARISON OF FORECAST NYPP ANNUAL ENERGY REQUIREMENT WITH ANNUAL ENERGY REQUIREMENT FOR SENSITIVITY ANALYSIS SCENARIOS LOW HIGH LOAD NYPP LOAD GROWTH FORECAST GROWTH
GWH----------------------------
1991 125,219 132,287 139,915 1999 132,729 148,818 167,242 I -
'o TABLE 3.3 CAPACITY EXPANSION SCHEDULE Max Capacity In-Service Unit (MW) Date Fuel Shoreham 809 1/1984 Nuclear Somerset 625 11/1984 Coal Nine Mile Point 2 1085 11/1986 Nuclear Prattsville 1000 9/1989 Pumped Storage Note: For all sensitivity analysis scenarios except the alternate fuel cost scenarios the capacity expansion schedule included the 700 MW Fossil unit in service as of May 1990 and the Jamesport (400 MW) unit in service as of January 1994.
During the course of this analysis, two planned coal units were moved beyond the planning horizon; the 700 MW Fossil unit and the Jamesport unit. The reference scenario and the alternate fuel cost sensitivity scenarios were redone to reflect this major change to the NYPP capacity expansion plan. There was not sufficient time to redo the other sensitivity analysis scenarios. Hence, the sensitivity analysis scenarios for low and high load growth, 57 percent and 69 percent nuclear capacity factor, and no coal conversion, all contain 1100 MW of baseload capacity that has been recently deleted from the plan. For these sensitivity scenarios the effect of the shutdown on production costs is understated. Judging from the results obtained for the reference scenario, penalties associated with the shutdown would increase roughly 10%
The coal conversion schedule is based upon the most recent information available from NYPP member utilities. Table 3.4 details the coal conversion schedule.
The coal conversion process has been plagued with lengthy delays related to regulatory approval. There is a reasonable possibility that the utilities will not be able to achieve their coal conversion plans (see testimony of Sally Streiter). A sensitivity analysis has been conducted which assumes no coal conversion.
B. Fuel Price Forecasts.
The fuel prices (excluding nuclear fuel) used in the analysis were developed for NYPP by ICF, Inc. That forecast was requested from ICF for use in NYPP long-range planning studies. The forecast fuel prices and the details underlying the forecast were presented to NYPP in November,1982, in an ICF report entitled " Forecast of Fuel Markets and Prices in New York State". Nuclear fuel prices were taken from the most recent NYPP Economic Parameters Study.
Table 3.5 illustrates the fuel prices used for the reference case.
Sensitivity analyses were also performed with respect to gas and oil prices. Sensitivities were performed using the ICF low and ICF high l estimates for oil and gas prices for all years. Tables 3.6 and 3.7 l lilustrate the fuel prices used for the low and high price sensitivity l
l 1
TABLE 3.4 COAL CONVERSION SCHEDULE Unit Max Capacity (MW) Conversion Date Ravenswood 3 928 6/1983 Lovett 5 202 10/1984 Lovett 4 197 12/1984 Arthur Kill 3 501 11/1985 Arthur Kill 2 350 7/1986 Danskammer 3 126 9/1986 Port Jefferson 3 190 1/1988 Danskammer 4 227 9/1988 Lovett 3 63 1/1989 Port Jefferson 4 190 1/1989 l
TABLE 3.5 .
NYPP/ICF FIEL PRICE FORECAST (NOMINAL MIDYEAR C/MBTU) 1983 1985 1990 1995 SULFUR UPSTATE FUEL ESCALATION FUEL ESCALATION FUEL ESCALATION FUEL ESCALATION CONTENT OR DOWNSTATE Eging RATE ER1LE RATE __ Eging RATE Egir.1 RATE OIL -- RESIDUAL
.3% D 555.0 11.50 689.7 11.05 1164.9 8.08* 1718.2 9.13
.7% U 546.0 12.01 684.8 11.31 1170.1 8.32 1744.7 9.13
.7% D 526.0 12.10 660.3 11.42 1134.0 8.33 1691.7 9.17 1.0% U 528.0 12.31 666.4 11.55 1151.2 8.46 1727.9 9.15 1.0% D 508.0 12.42 641.9 11.68 1115.1 8.51 1677.3 9.16 1.5% 0 483.5 13.11 618.6 12.02 1091.0 8.7.0 1655.6 9.18 2.0% U 479.0 13.59 617.4 12.24 1099.6 8.90 1684.5 9.18 2.0% D 459.0 13.76 594.1 12.39 1065.3 8.93 1633.9 9.18 2.8% U 448.0 14.37 585.6 12.75 1067.0 9.22 1658.0 9.18 2.8% D 427.0 14.72 562.3 12.93 1032.6 9.22 1605.0 9.22 OIL -- DISTILLATE
,L -
U 683.0 10.10 828.1 8.92 1269.7 8.93 1947.2 8.94
? -
D 693.0 10.16 340.4 8.93 1288.6 8.93 1976.1 8.94 6AS -- NATURAL U 404.7 20.91 571.7 12.93 1038.5 10.48 1707.2 10.24 D 430.2 19.22 593.7 12.41 1055.5 10.30 1722.0 10.12 COAL 1.0% U 262.1 7.87 305.0 8.57 460.0 7.88 672.0 7.68 1.0% D 279.4 7.86 325.0 8.47 488.0 7.82 711.0 7.63 1.4% U 257.2 7.63 298.0 8.50 448.0 7.76 651.0 7.92 1.4% D 276.8 7.69 321.0 8.42 481.0 7.67 696.0 7.88 2.0% U 242.3 7.69 281.0 7.80 409.0 7.71 593.0 7.69 2.0% D 261.8 7.75 304.0 7.77 442.0 7.65 639.0 7.63 2.0% U 206.8 7.72 240.0 7.53 345.0 7.96 506.0 9.26 2.0% D 236.0 7.75 274.0 7.48 393.0 7.87 574.0 8.97 URANIUM l
69.6 7.00 79.6 7.00 111.7 7.00 157.2 7.00
TABLE 3,6 FUEL PRICE FORECAST (LOW PRICE SENSITIVITY AMLYSIS)
(NOMINAL MIDYEAR C/MBil9 1985 1990 1995 1983 FUEL ESCALATION FUEL ESCALATION FUEL ESCALATION SULFUR UPSTATE FUEL ESCALATION CONTENT OR DOWNST ATE ERigg RATE ERigg RATE ERiff. RATE Egici RATE OIL -- RESIDUAL 555.0 1.61 573.3 9.90 919.2 7.94 1347.1 9.13
.3% D U 546.0 1.99 568.4 10.17 922.7 8.21 1368.8 9.14
- .7%
526.0 1.88 546.4 10.29 891.7 8.21 1323.0 9.17
- .7% D U 528.0 2.15 550.0 10.48 905.5 8.38 1354.3 9.12 1.0%
508.0 2.05 529.2 10.57 874.6 8.39 1308.5 9.16 1.0% D 483.5 2.42 507.2 10.94 852.2 8.63 1289.3 9.19 1.5% D 479.0 2.68 505.9 11.21 860.8 8.86 1315.8 9.18
, 2.0% U 11.35 828.2 8.93 1270.0 9.22
. s' 2.0% D 459.0 2.69 483.9 9.25 1291.7 9.18 2.8% U 448.0 3.08 476.5 11.73 829.9 427.0 3.23 454.5 11.94 799 0 9.29 1245.9 9.22 2.8% D OIL -- DISTILLATE 683.0 1.16 699.5 7.92 1024.0. 8.87 1566.4 8.88 U
D 693.0 1.15 709.3 7.91 1037.8 8.88 1588.1 8.91 G AS -- N ATUR AL U 381,3 11.07 470.0 13.75 895.0 10.51 1475.0 9.50 408.0 9.03 485.0 13.34 907.0 10.35 1484.0 9.43 D
TABLE 3.7 FUEL PRICE FORECAST (HIGH PRICE SENSITIVITY ANALYSIS)
(NOMINAL MIDYEAR C/MBTU) 1985 1990 1995 1933 FUEL ESCALATION FUEL ESCALATION SULFUR UPSTATE Futt ESCALATION FUEL ESCALATION CONTENT OR DOWNSTATE Egig RATE ERig RATE ERKg RATE Eggg RATE Olt -- RESIDUAL 730.1 12.12 1293.8 9.21 2009.8 10.21
.3% D 590.0 11.23 725.2 12.39 1300.7 9.41 2038.7 10.22
.7% U 581.0 11.71 700.7 12.50 1262.9 9.45 1985.3 10.23
.7% D 561.0 11.78 705.6 12.65 1280.0 9.57 2021.9 10.22 1.0% U 562.0 12.08 681.1 12.77 1242.2 9.59 1964.0 10.26 1.0% D 541.0 12.20 656.6 13.12 1216.5 9.81 1942.3 10.27 1.5% D 516.0 12.80 656.6 13.32 1226.8 10.00 1976.1 10.24 2.0% U 512.0 13.19 632.1 13.47 1189.0 10.04 1918.2 10.29
, 2.0% D 491.0 13.45 13.84 1192.4 10.28 1944.7 10.29 5 2.8% U 480.0 14.02 623.5 599.0 14.02 1154.6 10.32 1886.9 10.31 2.8% D 459.0 14.24 ,
OIL -- DISTILLATE 9.96 723.0 9.88 873.5 9.87 1398.6 9.91 2243.6 U
9.87 885.7 9.92 1420.9 9.92 2279.7 9.95 D 734.0 GAS -- NATURAL 625.0 12.75 1139.0 10.26 1856.0 10.51 U 381.0 28.08 26.51 653.0 12.18 1160.0 10.04 1872.0 10.46 D '408.0
_- .-- _ ~. _ - . - --- __
,. analysis scenarios, respectively. An additional sensitivity analysis was conducted which used ICF low oil and gas prices estimates through l
1989, ICF mid-range (reference scenarios) oil prices from 1995 onward, I and interpolated oil and gas prices for the intervening years. This scenario is referred to as the delayed oil price increase scenario. Table 3.8 illustrates the oil and gas prices used in this scenario.
C. Forecasts of Energy imports.
l Hydro Quebec and Ontario Hydro are the largest external power suppliers to NYPP. From 1984 through 1996, it is forecast that 12,000 GWH will be imported from Hydro Quebec. The HQ imports will fall into three categories -- firm, prescheduled economy, and economy. An
! annual schedule of the imports for each category is presented in Table 3.9.
Imports from Hydro Quebec consist of hydro power that remains constant in quantity in both the scenarios with and without Indian Point.
4 The price for economy energy from Hydro Quebec is based upon the value of NYPP generation displaced by the HQ economy energy. The price of prescheduled economy energy and firm energy from HQ is determined primarily by the NYPP average cost of fossil generation.
I Hence, payments to HQ for firm, economy and prescheduled energy increase in the scenario without Indian Point as a result of the increase in cost of NYPP average fossil generation, and the increase in the value
{
of the energy displaced by HQ imports.
l Ontario Hydro coal-fired economy energy for 1984 through 1986 is
! modeled with a potential annual energy of 6800 GWH; from 1987 l onward 10,000 GWH is available. For 1984 through 1986 an additional 3,504 GWH of firm energy is imported by Niagara Mohawk Power Corporation from Ontario Hydro. Using lower estimates of economy power from OH would increase the production cost penalties and additional oil usage associated with an Indian Point shutdown.
- The Ontario Hydro purchase is scheduled economically (subject to transmission system constraints) using a dispatch cost in the range of the more expensive NYPP upstate coal generation. This dispatch cost is substantially less expensive than the cost of NYPP oil generation.
TABLE 3.8 FUEL PRICE FORECAST (DELAYED Dil PRIE lEREASE SENSITIVITY ANALYSIS)
(NOMINAL HIDYEAR C/HBTU) 1983 1985 1989 1995 SULFUR UPSTATE FUEL ESCALATION FUEL ESCALATION FUEL ESCALATION FUEL ESCALATION CONTENT OR DOWNSTATE ERicI RATE Egiti RATE Egiff. RATE Eg1II RATE OIL -- RESIDUAL
.3% D 555.0 1.61 573.3 9.90 919.2 10.99 1718.2 9.13
.7% U 546.0 1.99 568.4 10.17 922.7 11.20 1744.7 9.13
.7% D 526.0 1.88 546.4 10.29 891.7 11.26 1691.7 9.17 1.0% U 528.0 2.15 550.0 10.48 905.5 11.37 1727.9 9.15
, 1.0% D 508.0 2.05 529.2 10.57 874.6 11.46 1677.3 9.16 U' l.5% D 483.5 2.42 507.2 10.94 852.2 11.70 1655.6 9.18 2.0% U 479.0 2.68 505.9 11.21 860.8 11.84 1684.5 9.18 2.0% D 459.0 2.69 483.9 11.35 828.2 11.99 1633.9 9.18 2.8% U 448.0 3.08 476.5 11.73 829.9 12.23 1658.0 9.18 2.8% D 427.0 3.23 454.5 11.94 799.0 12.33 1605.0 9.22 OIL -- DISTILLATE U 683.0 1.16 699.5 7.92 1024.0 11.31 1947.2 8.94 D 693.0 1.15 709.3 7.91 1037.8 11.33 19761 8.94 GAS -- NATURAL U 381.0 11.07 470.0 13.75 895.0 11.36 1707.2' 10.24 D 408.0 9.03 485.0 13.34 907.0 11.28 1722.0 10.12 I
TABLE 3.9 ANNUAL HYDRO QUEBEC IMPORTS YEAR FIRM PRESCHEDULED ECONOMY g -------------------( G W H) --------- - - - - -
19S4 3000 7000 2000 1985 3000 7000 2000 1986 3000 7000 2000 1987 3000 9000 0 1988 3000 9000 0 1989 3000 9000 0
1990 3000 9000 0 1991 3000 9000 0 1992 3000 9000 0 1993 3000 9000 0 1994 3000 9000 0 1995 3000 9000 0 1996 3000 9000 0 i 1997 3000 0 3000 l
1998 3000 0 3000 1999 3000 0 3000 l
t i
l t
t e
a .
Since the OH purchase is scheduled economically, its usage expands in the scenario without Indian Point.
The cost of Ontario Hydro imports is based on the value of energy displaced by those imports on a split-the-savings basis. The payment for OH economy energy would increase if Indian Point were shut down.
There are two reasons why the Ontirio Hydro payments will increase as a result of the shutdown. First, payments will increase as a result of additional OH imports; second, payments will increase for the OH
~
imports common to both scenarios due to .the increased value of the "I
energy displaced by the purchase as a consequence of the sbdtdown.
The cost of replacing Indian Point power, and the amount of additional oil that will be used to replace Indian Point power, are potentially understated in the EMA analysis. This understatement results from the conservative assumption that there are no economy sales that will be made to neighboring (New England and Pennsylvania-New Jersey-Maryland) power pocis heavily dependent upon ol!. In 1982 NYPP economy sales to neighboring power pools exceeded 4000 GWH. If such sales were considered, b'oth the cost to New York State of the shutdown, and the amount of additional oil usage resulting from the shutdown, would increase.
D. Unit and System Operating Characteristic Data.
i In order to simulate the operation of NYPP, both unit and system operating data are required. The principal unit data consist of: .
' {
- 1. Unit capacities; i ,
F
- 2. Heat rates; ,
Availabilities; and,
- 3. '
- 4. Maintenance requirements.
t These data have been supplied by the individual utilities to the.NYPP planning staff. The data are reviewed and updated annually (more frequently if necessary) by the utilities and the NYPP staff. The
- utilities derive these data from the operating experience of existing 1
units e.nd from projections of operating charactcristics of new units.
These data are routinely used in a variety of generation planning analyses conducted by NYPP.
l
k .
i The maintenance schedule used in the analysis was developed by the NYPP staff. Minor modifications to the maintenance schedule were made to ensure that the schedule was in general conformance with the cooling tower settlement agreement concerning the operation of units on the Hudson River.
The availability of all nuclear units (including Indian Point) was set so that those units had a maximum possible mature capacity factor of 63 percent. Sensitivity analyses were conducted in which the nuclear unit availabilities we a adjusted to restrict the maximum possible capacity factor for those units to 57 and 69 percent.
Figure 3.1 illustrates the NYPP transmission areas and critical upstate to downstate interfaces which were modeled. Eleven transmission a'reas and ten critical interfaces are modeled. Within each transmission area there are several load areas. These load areas represent each company's load within the transmission area. Limits for the Total East and the UPNY/SENY interfaces are illustrated in Table 3.10. These limits assume construction of a major transmission reinforcement between Central and Southeast New York, now planned for Fall of 1986.
Without this reinforcement, all production cost penalties will increase.
i l
t
NYPP TRANSMISSION AREA "D" 1 NORTH g NORTH I Qh h NYPP TRANSMISSION
^"'" "'"
c:s:""ogs @'
($!h V0?.NEY i
- 13) 1*
DYS. EAST WEST CENT EAST TOTAL EAST I T F-
- b I I I
/ UPNY/SENY gg l PAS J
YS CENT. Jl PAS C l l EAST NYS lI PAS E I y/ :
EST I
i h NYPP NYPP TRANSMISSION NYPP AREA "E" t M E dE h l
)$
y AREA "B" AREA "C" asa
~
~
p g g! g .p W PNY/ CONED SS*'%%GI*.42
.[Ph g f NYPP 8 g I @ o.
- CE l 8 } ". o I 8 " AREA
- %' 49 x & % v, @ 4% %@ H ., I H NRTH l t@ 8 8 KE 3&20 " 8. 3o g g #23 l +W P Q#22 M
3 St.
a j g 4 g ", f E ", s MILLWOOD SOUTH 5
gg Cl g g3n io 3, n g g g
$ i I j
%m j"
- 3. yCj
- o n o gj j a
m 5
,, I ,,
@ EEE CENTg
_ g SPRAINBROOK/DUNWOODIE SOUTH 2 g ." a "a n NYPP 5 o - C @ ,, 3. /
s - 3 o P"
w n AREA "J"
g CE l f M0 PAS E 5
@EE m m C2 2 'LILC0 NYPP TRANSMISSION
- E o
$ AREA "K"
TABLE 3.10 INTERFACE POWER TRANSFER LIMITS (MW)
TOTAL EAST UPNY/SENY Year West-to-East East-to-West North-to-Soutil South-to-North 1984 3850 3850 2000 2000 1985 3850 3850 2000 2000 1986 3850 3850 2000 2000 1987 6350 6350 5000 5000 1988 6350 6350 5000 5000 1989 6350 6350 5000 5000 1990 6350 6350 5000 5000 1991 6350 6350 5000 5000 1992 6350 6350 5000 5000 1993 6350 6350 5000 5000 1994 6350 6350 5000 5000 1995 6350 6350 5000 5000 1996 6350 6350 5000 5000 1997 6350 6350 5000 5000 1998 6350 6350 5000 5000 1999 6350 6350 5000 5000
o
- 4. PRESENTATION OF RESULTS ,
The Statewide, Con Ed Service Area, and Con Ed penalties for the reference -
case and the various sensitivity analysis scenarios are presented in Tables 4.1, 4.2 and 4.3, respectively. Sensitivity analyses were conducted primarily for the years
!)91 and 1999.
The production cost penalties in the tables referenced above include:
- 1. Increased fuel costs within NYPP;
- 2. Increased purchased power costs for additional volumes of Ontario Hydro energy imported as a result of the Indian Point shutdown; and,
- 3. Increased purchased power costs for volumes of Canadian energy common to the scenarios with and without Indian Point resulting from an increase in the value of the energy displaced by Canadian imports in the scenario without Indian Point.
Changes in operation and maintenance costs, or any revenue and fuel tax effects, are not included in the analysis conducted by EMA. Production cost penalties for the Con Ed Service Area and Con Ed are also affected by changes in the cost of internal economy transactions.
The shutdown of Indian Point also has adverse effects on other utilities in the state. Table 4.4 illustrates the year-by-year effect on Orange and Rockland Utililities, Inc. (O&R). While O&R receives some small benefit from the shutdown in several years, the overall effect is increased production costs for O&R. This effect predominates because O&R is primarily a purchaser of economy energy, and the removal of Indian Point increases the cost of the economy energy available to O&R.
The Indian Point shutdown will increase the usage of oil to generate electricity in New York State. Table 4.5 illustrates cumulative increased oil usage by year for the reference case. Table 4.6 illustrates for the sensitivity analysis scenarios the increased oil usage for the years 1991 and 1999.
The composition of the energy used to replace Indian Point is of substantial interest. Table 4.7 presents for oil, coal, gas and Ontario Hydro imports, the increase in generation in each category as a percentage of the total generation increase. Table 4.8 illustrates for 1991 and 1999 the percentage composition of additional energy production resulting from the Indian Point shutdown for the reference case and the various sensitivity analysis cases.
~
TABLE 4.1 .
EW YORK STATE PRODUCTION COST PENA!.TY RESULTlHG FROM INDIAN POINT SHUTDOWN Scruantos DELAYED LOW HIGH LOW OIL HIGH NO 57% 69%
REFERENCE LOAD LOAD FUEL PRICE FUEL COAL CAPACITY CAPACITY CASE GROWTH 6ROWTH PRICES INCREASE PRICES CONVERSION FACTOR FACTOR
(MILLIONS OF DOLLARS)------------------------------------------------
1984 463 -- --
412 412 498 -- -- --
1985 533 -- --
423 423 572 -- -- --
1986 549 -- --
437 437 592 620 -- --
1987 503 -- --
415 415 541 -- -- --
1988 576 -- --
469 469 625 700 -- --
y 1989 650 -- --
528 528 712 -- -- --
1990 819 -- --
642 657 927 -- -- --
1991 965 -
750 971 731 788 1101 1011 832 926 1992 1073 -- --
810 920 1239 -- -- --
1993 1188 -- --
890 1070 1381 -- -- --
1994 1306 -- --
976 1238 1547 -- -- --
1995 1438 -- --
1073 1438 1724 -- -- --
1996 1604 -- --* 1195 1604 1944 -- -- --
1997 1859 -- --* 1395 1859 2271 -- -- --
1998 2090* -- --* 1568* 2090* 2582* --* --* --*
1999 2339' 1917 2705* 1758* 2339* 2916* 2247* 2048' 2388*
NOTE: LOAD GROWTH, COAL CONVERSION AND NUCLEAR CAPACITY FACTOR SENSITIVITY SCENARIOS ASSUME 700 MW FOSSIL AND JAMESPORT IN-SERVICE. PRODUCTION COST PCNALTIES FOR THESE SCENARIOS ARE UNDERSTATED.
INDICATES THAT REMOVING INDIAN POINT FROM SERVICE WILL RESULT IN AN ADDED CAPACITY NEED IF MINIMUM POOL RELIABILITY TARGE1 IS TO BE MET.
W
TABLE 4.2 ',
CON ED SERVICE AREA PRODUCTION COST PENALTY RESULTING FROM INDIAN POINT SHUTDONN SCENARIOS DELAYED LOW HIGH LOW OIL HIGH NO 57% 69%
REFERENCE LOAD L8AD FUEL PRICE FUEL COAL CAPACITY CAPACITY CASE GROWTH 6ROWTH PRICES INCREASE PRICES CONVERSION FACTOR FACTOR
(MILLIONS OF DOLLARS)------------------------== --------------------
t 1984 455 -- --
409 409 488 -- --
1985 529 -- --
423 423 564 -- -- --
1986 510 -- --
414 414 545 636 -- --
1987 489 -- --
405 405 524 -- -- --
1988 564 -- --
463 463 612 729 -- --
^
, 1989 641 -- --
519 519 701 --
y 1990 731 -- --
586 599 820 -- -- --
1991 836 685 853 653 679 940 880 718 820 1992 931 -- --
724 814 1060 --
1993 1043 -- --
806 952 1202 --
1994 1170 -- --
900 1115 1365 --
1995 1304 -- --
1000 1304 1543 --
1996 1469 -- --
1123 1469 1758 -- --
1997 1570 -- --
.1214 1570 1885 --
1998 1781 -- --
1372 1781 2165 -- --
1999 2009 1526 2403 15fi7 2009 2472 1920 1738 2006 NOTE: LOAD GROWTH, COAL CONVERSION AND NUCLEAR CAPACITY FACTOR SENSITIVITY SCENARIOS ASSuNz 700 MW FOSSIL AND JAMESPORT IN-SERVICE.
~
TABLE 4.3 ,
CON ED PRODUCTION COST PENALTY RESULTING FROM INDIAN POINT SHUTDOWN SCFNARIOS DELAYED LOW HIGH LOW Olt HIGH No 57% 69%
REFERENCE LOAD LOAD FUEL PRICE FUEL COAL CAPACITY CAPACITY CASE GROWTH GROWTH PRICES INCREASE PRICES CONVERSION FACTOR FACTOR
- - - - -- -- - --- - - - -- - - - - - --- - - - - - - - - - - - - -- ---- - - -- --- --- -- ( M I L L I O N S O F DO L L A R S ) - --- --- -- -- ---- ---- - ----- -- ---- ---- - - - ---- ---- --
1984 200 -- --
182 182 213 -- -- --
1985 227 -- --
187 187 240 -- -- --
1986 211 -- --
179 179 222 262 -- --
1987 227 -- --
193 193 241 -- -- --
a 1988 271 -- --
226 226 293 204 -- --
i* 1989 312 -- --
256 256 340 -- -- --
1990 347 -- --
286 292 393 -- -- --
1991 404 328 426 319 340 453 378 347 403 1992 446 -- --
350 392 506 -- -- --
1993 502 -- --
391 460 576 -- -- --
1994 572 -- --
443 546 666 -- -- --
1995 639 -- --
492 639 755 -- -- --
1996 728 -- --
558 728 870 -- -- --
1997 692 -- --
548 692 817 -- -- --
1993 798 -- --
629 798 956 -- -- --
1999 918 653 1200 722 918 1114 870 806 920 NOTE: LOAD GROWTH, COAL CONVERSION AND NUCLEAR CAPACITY FACTOR SENSITIVITY SCENARICS ASSUME 700 MW FOSSIL AND JAMESPORT IN-SERVICE.
9 e
b TABLE 4.4 ORANGE AND ROCKLAND PRODUCTION COST PENALTY RESULTING FROM INDIAN POINT SHUTDOWN t
REFERENCE CASE PENALTY YEAR ($ MILLIONS) 1984 5 1985 0 1986 4 1987 -2 1988 -3 1989 -3 1990 4 1991 4 1992 6 1993 7 1994 10 1995 9 1996 11 1997 21 1998 27 1999 31
TABLE 4.5 CUMULATIVE INCREASED OIL USAGE RESULTING FROM INDIAN POINT SHUTDOWN REFERENCE CASE Thousands of Bbis.
1984 13,904 1985 27,997 1986 39,852 1987 45,745 1988 51,975 1989 58,260 1990 67,475 1991 78,640 1992 90,487 1993 103,280 1994 116,677 1995 130,475 1996 144,728 1997 160,066 1998 175,696 1999 191,607
TABLE 4.6 INCREASED Dil USAGE RESULTING FROM INDIAN POINT SHilTDOWN ;
l SCFNARIOS DELAYED LOW HIGH LOWER Dit HIGHER NO 57% 69%
REFERENCE LOAD LOAD FUEL PRICE FUEL COAL CAPACITV NUCLEAR CASE GROWTH GROWTH PRICES INCREASE PRICES CONVERSION FACTOR CAPACITY
(THOUSANDS OF BBLS) ----------------------------------------------
1931 11165 4875 11210 i1165 11165 11165 13380 8912 8306 1933 15911 12660 18197 15911 15911 15911 15778 13979 16288 NOTE: LOAD GROWTH. COAL CONVERSION AND NUCLEAR CAPACITY FACTOR SENSITIVITY SCENARIOS ASSUNE 700 MW FOSSIL AND JAMESPORT IN-SERVICE.
TABLE 4.7 PERCENTAGE OF INCREMENTAL GENERATION OCCASIONED BY INDIAN POINT SHUTDOWN BY RESOURCE CATEGORY REFERENCE CASE Ontario Oil Coal Gas Hydro
-(Percent)- - - - -
1984 92 4 3 1 1985 92 6 2 0 1986 78 17 2 3 1987 37 35 4 24 1988 39 34 5 22 1989 40 37 4 19 1990 61 27 7 5 1991 75 16 7 2 1992 80 13 6 1 1993 86 10 3 1 l
1994 90 8 1 1 1995 92 6 1 1 1996 94 5 1 0 1997 98 1 1 0 1998 98 1 1 0 l 1999 99 0 1 0 l
l
TABLE 4.8 ',
PER&NTAGE OF IEREENTAL GEERATION OCCASIDED BY INDIAN POINT SHUTDONN BY RES00R& CATEGORY Scrunnios
! YEAR DELAYED AND LOW HIGH LOWER OIL HIGHER NO 'i7% 59%
itESOURCE REFERENCE LOAD LOAD FUEL PRICE FUEL COAL CAPACITY NUCLEAR CATEGORY CASE GROWTH GROWTH PRICES INCREASE PRICES CONVERSION FACTOR CAPACITY l
l931
, Oil 75 30 75 75 75 75 90 66 49 COAL 16 48 15 16 16 16 3 24 36 T
, GAS 7 2 7 7 7 7 6 6 4 ti' ONTARIO HYDRO 2 20 3 2 2 2 1 4 11 i
- Olt 99 85 100 99 99 99 99 98 96 COAL 0 14 0 0 0 0 0 1 3 GAS 1 0 0 1 1 1 1 1 1
- 1 ONTARIO HYDRO 0 1 0 0 0 0 0 0 0 NOTE: LOAD GROWTH, COAL CONVERSION AND NUCLEAR CAPACITY FACTOR SENSITIVITY SCENARIOS ASSUME 700 MW FOSSIL AND JAMESPORT IN-SERVICE.
Qualitative analysis was applied to the potential adjustment to the penalty in cases that would combine the most optimistic and pessimistic assumptions from the various sensitivity analysis scenarios. There are two important findings of that analysis.
First, it is necessary to recognize that it is highly unlikely that all the events that tend to either increase or decrease the penalty from that derived for the reference case would occur simultaneously. For example, if low load growth and low oil prices materialized, the possibility that the utilities would not achieve their coal conversion plans would increase. The economic attra,ctiveness of those plans would decrease as load growth and fuel prices fell below forecast values. Hence, a combined analysis of low load growth, low fuel prices, and full realization of coal conversion plans is not realistic. Similarly, given high load growth and high fuel prices, the utilities would most probably be compelled to achieve their plans.
Hence, examining high load growth and high fuel prices in conjunction with reduced coal conversion is not realistic. In sum, there are self-governing bounds upon combining optimistic and pessimistic assumptions, which tend to reduce the uncertainty of the range of the forecast penalty.
Second, the effects of reascnable combinations of optimistic assumptions and reasonable combinations of pessimistic assumptions would be decidedly non-symmetrical. Pessimistic assumptions (e.g., high oil prices and high load growth),
when combined, could be expected to exaggerate each other in terms of the economic impacts associated with a shutdown. Higher load growth would increase the amount of oil used to replace Indian Point generation, rendering the effect of oil prices more severe. Optimistic assumptions (e.g., low oil prices and low
!. 4 ,rowth), when combined, would tend to neutralize each other in terms of the l economic impacts associated with a shutdown. Low load growth would reduce the amount of oil used to replace Indian point generation, rendering the effect of low oil prices less beneficial. The combined increase in penalty resulting from high load growth and high oil prices would be greater than the sum of the individual effects. The combined decrease in penalty resulting from low load growth and low oil prices would be less than the sum of the individual effects. This non-symmetry is important to recognize when evaluating projections based upon data that by nature are uncertain. The amount by which the adverse economic impact of closing Indian Point could increase, if pessimistic assumptions prove true, far
f
- exceeds the decrease in the adverse economic impact that would occur if more optimistic assumptions prove true.
i Further qualitative analysis was conducted with respect to the impact that cogeneration and conservation induced by the price increase resulting from the shutdown of Indian Point may have upon the production cost penalty. With respect to cogeneration, current. policies reimburse cogenerators for 100 percent of the avoided cost associated with the supply of cogenerated electricity. Hence, the utility production costs determined for each of the scenarios that have been analyzed would not change if added cogeneration resulted from an Indian Point shutdown. Utility production costs, including payments to cogenerators, do not vary with the amount of cogeneration. Even if the policy with respect to payments to cogenerators were to change so that utilities only paid, say, 90 percent of the avoided cost, the impact on the production cost penalty would not be large. Given that assumption, which in itself would represent a major change in policy, and the assumption that cogeneration could serve as a replacement for twenty percent of the energy generated by Indian Point, the effect on the production cost penalty would be less than two percent.
Conservation is more complicated. If the rate increase that would result from an Indian Point shutdown results in additional conservation the direct production cost penalty of the shutdown would decrease. Focusing on the reduced direct production cost penalty would, however, be very misleading. The economic
- impact of the shutdown is not necessarily reduced by conservation, it is merely transferred from an increase in utility production costs to increases in costs that are borne in the first instance by ratepayers. These costs come either in the form of reduced usage and satisfaction from electricity consumption or as funds expended on devices to enable customers to reduce electricity purchases.
Substituting self generation for utility purchases is an example of one way in which customers could conserve in response to the shutdown of Indian Point. If, for -
example, all of the energy generated by Indian Point in 1984 was replaced by self generation the effect of the shutdown directly on utility production costs could be completely eliminated. The economic impact of the shutdown, however, would not be reduced it would simply have been shifted. In this particular example it is likely that in addition to being shifted the total economic impact will increase dramatically as the cost of new self generation in 1984 is significantly greater than the NYPP cost of replacing Indian Point power.
6
- 5. CONCLUSION A shutdown of the Indian Point nuclear generating station will impose severe fuel replacement and purchased power cost penalties upon New York State, Con Ed, and the Con Ed service area. The annual penalty for New York State starts at
$463 million in 1984 and increases to over $2.3 billion in 1999, with a total penalty of $18.0 billion over the 1984-1999 period. The Con Ed annual penalty begins at
$200 million in 1984 and rises to $918 million in 1999, with a total penalty of $7.5 billion. The annual penalty for the Con Ed service area is initially $455 million in 1984 escalating to over $2.0 billion in 1999, with a total penalty of $16.0 billion over the sixteen year period. The design life of the plants extends beyond the 1999
- period analyzed herein. Hence, there will be additional production cost penalties associated with the shutdown of Indian Point which are not reported herein.
- A shutdown of Indian Point would also result in substantial increased use of oil within New York State, totalling close to 192 million barrels over the sixteen-l year period between 1934 and 1999.
- In addition to sending American dollars overseas to foreign oil suppliers, $1.9 billion more dollars would be exported to Canada in the form of increased payments for purchased Canadian energy over this sixteen-year period.
L Lower than forecast oil prices and lower load growth would reduce the i
penalties associated with the Indian Point shutdown. However, even scenarios with
! low load growth or low oil prices de not result in insignificant penalties. Higher l than forecast load growth and higher than forecast oil prices would substantially increase the cost penalty associated with the Indian Point shutdown. The inability of the utilities to fully achieve their transmission capacity expansion and coal conversion plans, a distinct possibility, would serve to increase the already high costs associated with an Indian Point shutdown. The assumption that there will not be any NYPP external economy sales to neighboring power pools is conservative, and results in the potential understatement of the penalty of an Indian Point shutdown.
In sum, there would be a substantial ecornmic penalty imposed upon the State of New York, the Con Edison service area and Con Edison by the shutdown of Indian Point. The shutdown would result in higher electric rates, probably higher oil prices, and increase the state's exposure to foreign supply embargoes. The shutdown would be an obstacle to the goal of reducing dependence on oil of New York State and the nation.
. - ~ _ . - - - , ,w,--.m , . . , , - . _ - - , ---.-.,-----,.,m .
.-,eg.,.-- -
_ , - . . . _-. ... ..e-.. _ -...- - _w -, , . _ . . , ...r-,.-y
j -
APPENDIX A QUALIFICATIONS OF EUGENE T. MEEHAN Mr. Meehan joined Energy Management Associates, Inc. (EMA) in September, 1980. At EMA he has directed studies on topics including the examination of utility expansion plans, marginal costs, the determination of avoided cost for use in ratemaking proceedings, the strategic analysis of pursuing an interruptible rate program, and fuel budgeting. He has worked extensively with New York utilities.
Prior to joining EMA, Mr. Meehan was employed by National Economic Research Associates, Inc. (NERA). He joined NERA in April,1973. His work at NERA primarily concerned the development and application of methods for quantifying the marginal costs of providing electric service, engagements that required detailed knowledge of utility planning and operating procedures. He participated in NERA's research as part of the Electric Power Research Institute's study on rate design and was active in marginal cost studies for 25 electric utilities throughout the United States and Canada. He had primary responsibility for all research in 15 of those 25 studies.
Mr. Meehan co-authored and maintained the engineering economic model used by NERA to determine fixed charge rates and incremental revenue requirements. That model was used in marginal cost studies and in evaluation of the relative economics of coal and nuclear capacity alternatives.
He has testified before the Public Utilities Commission of Ohio in Case Nos.
76-823-EL-A/R and 78-92-EL-A/R, the Minnesota Public Service Commission in Docket No. E015/GA-80-76, the New York Public Service Commission in Case 27353 - Phase II, Case 28059 and Case 28223, and the Arkansas Public Service Commission in Docket No. U-2972 and Decket No. U-3108.
Mr. Meehan received a Bachelor's degree in Economics from Boston College in 1972, graduating cum laude. He has completed 38 credits of course work at the Graduate School of Business Administratian of New York University (NYU).
Among the courses that he has completed at NYU are the intensive courses in microeconomic and macroeconomic theory required as core courses for the doctoral program.