621.3121 R6X ILENR/RE-SP-87/15 DEPOSITORY An Evaluation of the Economic Potential for Cogeneration in Illinois UNIVERSITY Or ILMNOIS AT URBAMA-P'Jai^p^iQjig ■ ■ • \ \ • E A < s \ \ V \ / / V ^ • ■' ■ ■ • .".'■■ ■• ■ '■■''.-•'' •' ■■■■■ ■ ■■■■ Printed by the Authority of the State of Illinois ItHnoia Dapmrtnmnt of Energy and Ntturmi Rmtourct ~Y CF AT I CAMPAIGN AHKS ILENR/RE-SP-87/15 Printed: October 1987 COGENERATION MARKET ASSESSMENT PHASE II An Evaluation of the Economic Potential for Cogeneration in Illinois Deborah L. Fields Illinois Department of Energy and Natural Resources Energy and Environmental Affairs Division 325 W. Adams, Room 300 Springfield, IL 62704-1892 James R. Thompson, Governor Don Etchison, Director State of Illinois Illinois Department of Energy and Natural Resources NOTE This report has been reviewed by the Illinois Department of Energy and and Natural Resources (ENR) and approved for publication. Statements made by the author may or may not represent the views of the Department. Additional copies of this report are available through ENR Clearinghouse at 800/252-8955 (within Illinois) or 217/785-2800 (outside Illinois). Printed by the Authority of the State of Illinois. Date Printed: . October 1987 Quantity Printed: 450 Referenced Printing Order: IS3 Illinois Department of Energy and Natural Resources Energy and Environmental Affairs Division 325 W. Adams, Room 300 Springfield, Illinois 62704-1892 217/785-2800 ii Zrtzuh& TABLE OF CONTENTS Pane Executive Summary v Chapter 1 Chapter 2 Chapter 3 Chapter 4 Chapter 5 Introduction 1 Technical Analysis 7 Economic Analysis 27 Sensitivity Analysis 65 The Economic Potential for Cogeneration - A Discussion 89 Appendix I: Bibliography of Sources 101 Appendix II: A Note on the Economics of Cogeneration in the Commonwealth Edison Service Territory 105 Appendix III: Cogeneration Feasibility Model 106 m Digitized by the Internet Archive in 2013 http://archive.org/details/cogenerationmark8715fiel IV EXECUTIVE SUMMARY The following report presents the results of the second phase of a cogeneration market assessment, entitled "An Evaluation of the Economic Potential for Cogeneration in Illinois." The Department's cogeneration market assessment study is designed to provide state policy makers, utilities, industries and other interested parties with information on the potential for, and the impacts of cogeneration in Illinois. The assessment is divided into three parts. Phase I, completed during the fall of 1985 is a study of the technical potential for cogeneration in Illinois. This study was designed to obtain information on existing cogeneration and on those firms which have the potential to cogenerate in the future. A survey instrument was developed and responses were obtained from 30 existing cogenerators and 159 industrial firms. The evaluation of these firms found 369 Mw of existing cogeneration and 2854 Mw of technically feasible cogeneration. Phase II is the evaluation of the economic potential for cogeneration in the state using the results obtained in Phase I. The Department contracted with QED Research, Inc., and ESC Energy Corp. of Palo Alto, California to assist with development of a "cost-benefit" model to provide information on the economics of cogeneration in service territories of the five investor-owned utilities in Illinois; Commonwealth Edison Company, Illinois Power Company, Central Illinois Light Company, Union Electric Company, and Central Illinois Public Service Company. The "cost-benefit" model used in the study was designed specifically to price out cogeneration inputs and outputs, e.g., capital and operating costs, electricity and steam, to arrive at an estimated rate of return, net present value and post tax payback period for a given cogeneration investment. The design was intended to facilitate extensive sensitivity analysis useful for evaluating cogeneration under alternative economic conditions and/or state regulatory policies. The Illinois Department of Energy and Natural Resources is Illinois' lead agency with respect to the development and implementation of energy policy. The Department manages most of the federal energy conservation programs, sponsors research into commercial application of clean coal technologies, and serves as state government's analyst of long- and short-term state and federal energy policy issues. In addition, under the Illinois Public Utilities Act, the Department is required to prepare a long-term energy utility plan based on least-cost principles. It is primarily with respect to this responsibility that the Department became involved in the study of cogeneration and its role in the Illinois' energy environment. The results of Phase II, while not definitive given certain limitations of the data base, provide an understanding of the state's present and future cogeneration environment. In summary, the results show that currently only the Commonwealth Edison and Illinois Power Company service territories have the economic characteristics necessary to VI support the development of cogeneration. Specifically, the results indicate that Commonwealth Edison Company has between 170.0 and 308.0 Mw of potentially economic cogeneration, and in the Illinois Power Company territory there is the potential for between 44 and 96 Mw. These estimates are the minimum expected since there are presumably other firms which could generate that are not included in the data base. The results indicate that the most likely technology to be employed is a simple cycle gas turbine (80 percent of cogeneration potential), followed by gas and diesel engines. Only two of the firms in the data base had steam demand requirements large enough to support coal -fired steam turbines, and only one of these firms, a 78 megawatt system, was clearly economical . Of most importance, the results suggest that each electric utility territory is a unique market for cogeneration development, and thus certain driving factors may have a larger influence on cogeneration economics in one electric utility than another. This issue and a number of others, which are identified in the study have significant implications for the electric utility industry and state regulation. It is the purpose of this study to discuss these issues and illustrate their importance, as well as to stimulate discussion on the economics of cogeneration. VI 1 When reviewing this report it is important that one take into consideration the judgemental nature of any such economic assessment. While alternative scenarios are developed to test the effects of many possible assumptions, judgement nevertheless must play a role in defining variables and projecting certain values. The Department welcomes questions or comments with regard to these assumptions or other parts of the report. vi n Chapter 1 - INTRODUCTION This study is the second phase of an analysis designed by the Illinois Department of Energy and Natural Resources to assess the cogeneration environment in Illinois. Specifically, this phase is designed to lead to a more complete understanding of the potential for, and the impacts of cogeneration as an energy resource in Illinois. Using the data base developed in Phase I of the cogeneration market assessment*, this study attempts to determine through a cost-benefit approach an accurate indicator of each firm's willingness' to undertake an investment in cogeneration and of the technology it would employ in that investment. The decision of whether to cogenerate involves technical, economic, environmental, legal and regulatory considerations. Each of these is addressed in this report. The report is organized in a step-wise basis, as depicted in Figure 1-1. Step 1 involves a technical analysis of differing types of cogeneration equipment based on capital and operating costs, and a determination of the parameters at a plant site necessary for matching a cogeneration configuration to a plant. This step entails construction of an energy profile for each of the firms in the study *For a more detailed discussion of this data base see "An Evaluation of the Technical Potential for Cogeneration in Illinois." •!-> OJ ^ <4- S_ O j2 +-> «d- C »— QJ o CL E •r— 0) 1/5 -t-> ■H i/) 03 CO CD S_ to CD oo C < CD Cn o o <+- >1 o +-> •r- 00 > •r- -f- CO l/l V c i — i/i a: 03 c c CD < oo 1 to to >> 03 co a. a> CO >> +J to ai CO Changes in Economic Conditions Change in Regulatory Conditions o cn c C M- v- •.- O .— C •»-> -4-> i— O C O +-> •— • •r- C 03 -f- <4- E ••- U <4- < Q. •i- •.- o c *+- C tO r— O •t- cn a> a> •<- +->•■- r— > +J C CO .O CD e 03 jz +-> en o o UJ =5 as to 03 CVJ a. 00 (_ 03 c: •r- an 3 Li_ CD +-> jC -M CD O 03 cc 03 E UJ <+- +-> o s- 00 o UJ 4- to >1 c CD COjr- c o CD Generic Operating Character- istics of Plants Technical and Cost Character- istics of Plants 4-> c en cu c E E -C *r- •.- ■M cr 03 UJ o 4- <-> r- CO p» O OO 00 O EO 03 , — CO CD O-.- «— it|_ 3"0 and selection of the most appropriate type of cogeneration equipment based on electricity and steam demands for each firm. Step 2 is the economic analysis. This step entails preparation of the model inputs for each of the five electric utilities included in the study to measure the economics of a cogeneration investment. These inputs include present industrial electricity rates and 20 year projected electricity rates, present industrial fuel costs including oil, gas and coal and 20 year projected fuel costs, projected inflation rates, and assorted other economic variables. These variables reflect the quantifiable costs and/or benefits of a cogeneration investment over a 20 year observation period from 1987-2007. Once determined for each of the five electric utilities, the individual firm data along with the technical cogeneration configurations developed in Step 1 are passed to the model specific to their operating electric utility. Once the net cash flow is computed, a rate of return, net present value and post tax payback for each firm is calculated. The third step in the economic assessment is the sensitivity analysis. This step focuses on the uncertainty surrounding the inputs developed in Step 1 and 2 and develops alternative assumptions to be retested in the model. This step is the most important and also the most valuable. These alternative scenarios enable one to obtain a better sense of the factors or variables that drive cogeneration economics, as well as to understand the market for cogeneration development in Illinois. Although estimates for market penetration rates are not developed in the study, the sensitivity analysis identifies the factors which appear to influence the development of cogeneration in Commonwealth Edison and Illinois Power service territories. These factors include the price of electricity, the price of fuel, the reliability of the cogeneration equipment, the financing arrangements, and the utilities' standby power charge. The results of the sensitivity analysis point to some interesting issues related to the development of cogeneration and the electric utility industry. These issues include: 1. The amount of economic cogeneration potential varies widely among utility service territories, and depends to a great extent on utility-specific conditions. 2. The actual amount of cogeneration development appears to depend upon other variables not included in the model, i.e., industry attitudes toward power generation, environmental regulations, existing boiler age, and available avoided cost payments. 3. The price of electricity appears to be a driving factor in determining the economic potential for cogeneration. 4. The long-term benefit realized from a cogeneration investment is dependent upon future fuel prices. 5. Regulatory policy with respect to standby or replacement power rates may have a large impact on the economic potential for cogeneration. 6. Debt financing is an important implement in the development of cogeneration. 7. The realized benefits from a cogeneration investment are dependent upon the actual reliability rate achieved by the cogeneration system. Chapter 2 - TECHNICAL ANALYSIS The first step in determining whether co-generation is feasible is to assemble energy profiles of each of the firms to be analyzed. These profiles are necessary for matching the appropriate cogeneration equipment to a firm, and are composed of daily electricity load variations, level of steam demand, and operation hours. These data were previously collected for the Department in its Phase I study, "An Evaluation of the Technical Potential for Cogeneration in Illinois," and are presented in Table 2-1. 1 Individual firms are identified by code number only. The next step in the technical analysis is to develop a second data base consisting of the technical and economic characteristics of the cogeneration equipment which is to be matched to the individual firms. Five types of equipment were analyzed for this match; simple cycle gas turbines, combined cycle gas turbines, gas engines, diesel engines, and coal-fired steam turbines. The characteristics of each equipment type are given in Table 2-2 and 2-3. The technical characteristics for all the equipment are from published data. 2 of primary consideration for the matching process are megawatt ^For a more detailed discussion on the mechanics of the data collection process used in Phase 1; see "An Evaluation of the Technical Potential for Cogeneration in Illinois." 1985, Phase I. ^See Bibliography of Sources listed in Appendix A. rating, heat rate, and power-to-heat ratio. Other characteristics of importance are also presented in Tables 2-2 and 2-3. These include the cost of the equipment (S/Kw), total installed costs 'S/Kw) and maintenance costs. It should be noted, however, that these costs reflect a large amount of uncertainty. Manufacturers differ considerably in what they include in equipment costs and installation costs. For instance, some may include pollution control devices or supporting equipment, while others do not. Even greater uncertainty exists with respect to manufacturers' estimated maintenance costs. Some installations may experience low downtime and thus relatively low maintenance expenses. Others, however, may experience high downtimes and costs. Effective operation of the cogeneration equipment is the all important determinant of these costs, because it affects both the maintenance costs as well as the amount of backup/standby power purchased from the electric utility. For purposes of this analysis a 95 percent reliability factor is used. Given the uncertainty surrounding the actual realized downtime experienced by a firm, alternative assumptions are used in the Sensitivity Analysis to evaluate the economics of cogeneration given lower reliability. 8 TABLE 2.1a: FIRM ENERGY PROFILE - COMMONWEALTH EDISON CO. SERVICE TERRITORY MW MW AVE.(#/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND , 7.5 DEMAND 10.0 DEMAND 12,000.00 DAY WEEK 5 YEAR 4 3' 48 6 3.0 3.3 N/A 1 5 50 7 2.0 3.5 5,000.00 1 5 50 9 15.0 18.0 54,000.00 3 7 52 19 1.6 1.7 60,000.00 3 5 52 35 4.1 4.4 20,500.00 3 5 49 57 1.1 1.5 10,000.00 2 5 50 67 2.1 2.5 48,000.00 3 7 52 70 3.2 4.2 39,000.00 3 7 50 72 0.3 0.3 500.00 1 5 49 77 2.5 2.5 11,000.00 3 6 52 82 1.1 1.4 6,500.00 3 5 52 91 2.5 3.0 N/A 3 5 50 93 1.4 1.6 10,000.00 2 6 50 98 0.7 1.0 1,000.00 3 5 52 101 3 0.3 4,800.00 3 5 50 110 0.4 0.4 400.00 1 5 52 116 0.3 0.3 5,000.00 1 5 52 119 8.0 10.0 15,000.00 3 5 48 135 0.3 0.3 5,000.00 1 5 52 147 0.7 0.8 10,000.00 3 5 52 153 2.3 2.3 13,000.00 3 5 52 158 30.0 40.0 700,000.00 3 7 52 160 1.8 2.2 6,000.00 3 7 53 171 0.9 1.0 4,000.00 1 5 52 178 N/A 0.0010 - N/A 2 5 52 180 0.1 0.2 0.00 1 5 52 181 0.6 0.7 8,000.00 2 5 50 186 1.0 1.3 15,000.00 3 7 50 188 2.0 2.5 12,000.00 3 7 52 197 1.5 2.5 6,000.00 3 5 50 209 1.0 1.1 N/A 1 5 48 210 0.5 0.6 2,600.00 3 5 50 211 9.0 10.0 81,000.00 3 7 50 215 0.3 0.5 4,000.00 3 7 52 216 3.8 4.0 4,000.00 3 5 48 219 2.8 4.6 15,000.00 2 5 50 223 71.0 85.0 22,000.00 3 7 52 227 66.0 80.0 60,000.00 3 7 50 241 3.2 4.0 75,000.00 3 7 51 244 1.0 1.2 11,000.00 2 5 52 247 2.5 3.3 0.00 1 5 52 252 0.8 0.9 200 00 1 5 50 254 1.0 1.1 1,500.00 2 4 49 255 0.1 0.1 300.00 1 4 50 264 0.5 1.0 4,000.00 3 5 52 TABLE 2.1a: FIRM ENERGY PROFILE - COMMONWEALTH EDISON CO. (continued) MW MW AVE.U/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ MEEK/ NUMBER . DEMAND 9 DEMAND 1.2 DEMAND DAY WEEK. 5 (EAR 269 15,000.00 3 52 285 1 7 ■ 1.3 30,000.00 3 7 52 287 0.3 0.4 8,000.00 2 5 52 293 5 5 9.0 35,000.00 3 7 52 313 4.5 5 1 20,000.00 3 5 49 317 8.0 9.5 30,000.00 3 5 50 320 0.5 0.6 1,200.00 2 5 48 324 4.4 5.0 38,000.00 2 6 52 325 1.4 1.5 0.00 1 5 52 327 1.2 2.1 4,500.00 3 5 52 328 1 2 2.4 1,700.00 2 5 52 335 35.5 41.5 600,000.00 3 7 52 357 9.5 12.5 40,000.00 3 5 52 363 1.5 2.0 8,600.00 3 7 52 370 0.5 0.6 3,000.00 2 5 52 373 0.5 0.6 0.00 2 5 52 380 66.0 70.0 920,000.00 2 7 52 386 8.8 10.3 250,000.00 3 7 52 391 4.0 6.2 21,000.00 3 7 52 414 3.2 4.5 70,000.00 3 6 50 415 1.5 1.8 20,000.00 3 5 52 419 1.5 2.0 18,000.00 3 7 52 424 3.2 3.4 N/A 2 6 52 430 0.9 0.9 9,300.00 3 7 52 434 34.0 45.0 72,000.00 3 7 52 448 0.9 • 1.0 14,500.00 2 5 50 454 1.8 1.8 N/A 2 5 52 467 8.6 10.3 36,000.00 3 7 52 483 9.0 10.0 30,000.00 2 6 50 488 3.0 3.4 10,000.00 3 5 50 497 2.0 8.0 5,000.00 1 5 48 500 1.3 1.6 1,800.00 3 6 50 505 0.9 1.1 22,000.00 3 7 52 507 0.2 0.2 4,000.00 1 5 52 511 0.4 0.5 3,000.00 3 5 52 513 0.4 0.5 100.00 1 5 52 516 4.8 9.5 16,000.00 3 7 52 521 2.7 4.5 20,000.00 3 7 52 531 1.4 1.5 30,000.00 3 7 52 533 4.4 5.0 34,920.00 2 5 52 537 1.9 2.3 100.00 3 5 49 544 51.0 55.0 30,000.00 3 7 52 548 12.0 23.0 110,000.00 3 7 52 558 24.0 24.0 181,000.00 3 5 49 559 15.0 22.0 60,000.00 2 5 49 10 TABLE 2.1a: FIRM ENERGY PROFILE - COMMONWEALTH EDISON CO. (conti nued) MW MW AVE.(#/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND 11.0 DEMAND 16.0 DEMAND DAY WEEK 5 YEAR 568 158,000.00 2 50 580 10.0 13.0 45,000.00 2 5 50 592 8.0 15.5 70,500.00 3 6 52 594 4.0 4.1 115,000.00 2 5 48 613 11.0 19.0 138,000.00 3 7 52 700 2.5 4.0 0.00 3 7 52 704 N/A N/A N/A 3 7 52 707 N/A N/A N/A 3 7 52 708 N/A N/A N/A 3 7 52 710 1.0 1.2 7,000.00 3 7 52 715 5 0.6 0.00 1 5 52 716 1.0 1.4 4,000.00 3 7 52 721 3.00 3.50 90,000.00 3 7 52 11 Tabl e 2-lb: FIRM ENERGY PROFILE - ILLINOIS POWER SERVICE TERRITORY MW MW AVE.U/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND 49 DEMAND 55 DEMAND DAY WEEK 7 fEAP 2 600,000.00 3 52 15 9.60 10.00 18,500.00 3 5 45 25 2.50 3.00 10,000.00 3 7 52 53 3.60 5.60 70,000.00 85 1.30 1.40 12,000.00 3 6 52 95 9.00 12.00 90,000.00 3 7 52 103 2.50 2.60 6,000.00 2 5 51 111 1.50 2.00 18,000.00 3 5 52 115 2.40 2.70 7,000.00 3 5 52 133 2.00 2.20 100.00 1 5 52 140 1.90 2.40 40,000.00 1 5 50 193 1.00 1.10 14,000.00 3 5 52 204 2.60 3.70 15,000.00 1 5 50 230 50.00 95.00 470,000.00 3 7 52 277 N/A 0.60 N/A 3 6 33 348 4.50 6.20 2,000.00 2 5 50 376 2.80 2.90 100,000.00 3 5 48 385 30.00 40.00 65,000.00 3 7 49 422 2.00 3.70 13,000.00 3 5 50 433 1.60 2.00 5,000.00 3 5 50 510 0.90 1.00 8,000.00 3 5 50 546 N/A 0.0010 N/A 561 15.00 25.00 60,000.00 3 5 50 578 4.00 5.00 17,000.00 3 5 50 583 8.50 12.00 75,000.00 3 7 52 607 3.90 5.00 104,000.00 3 7 52 709 N/A N/A N/A 3 7 52 713 N/A N/A N/A 12 Table 2-lc: FIRM ENERGY PROFILE - UNION ELECTRIC CO. SERVICE TERRITORY MW MW AVE.U/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND 60.0 DEMAND 120.0 DEMAND DAY WEEK 6 YEAR 303 22,800.00 3 52 342 24.0 29.0 325,000.00 3 7 52 411 5.0 5.5 80,000.00 3 7 52 701 77.0 85.0 1,600,000.0 3 7 52 702 N/A N/A N/A 3 7 52 Table 2-ld: FIRM I INERGY PROFILE - CENTRAL ILLINOIS PUBLIC SERVICE CO . SERVICI TERRITORY MW MW AVE.(#/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND 11.0 DEMAND 14.0 DEMAND DAY WEEK 7 YEAR 24 20,000.00 3 50 257 4.4 5.8 45,000.00 3 5 52 295 2.0 2.2 8,000.00 3 5 52 319 46.00 54.00 880,000.00 3 7 52 367 1.9 2.6 19,000.00 3 5 52 378 3.2 4.6 12,500.00 3 5 50 389 2.8 4.8 30,000.00 1 5 52 462 1.0 1.3 4,000.00 1 5 52 496 0.4 0.9 1,155,000.0 2 6 20 615 29.5 31.0 124,000.00 3 7 52 84 0.32 0.38 6,000.00 1 5 52 124 3.30 5.50 105,000.00 3 7 52 473 0.40 0.90 58,000.00 2 6 20 554 0.50 0.60 18,000.00 1 4 52 Table 2-le: FIRM ENERGY PROFILE - CENTRAL ILLINOIS LIGHT COMPANY SERVICE TERRITORY MW MW AVE.(#/HR) PLANT AVE. ELEC PK. ELEC. STEAM SHIFTS/ DAYS/ WEEK/ NUMBER DEMAND 9.00 DEMAND 11.00 DEMAND DAY WEEK 7.00 YEAR 80 80,000.00 3.00 52.00 89 2.40 3.10 58,000.00 3.00 5.00 50.00 330 4.40 5.20 80,000.00 3.00 7.00 52.00 404 15.00 16.00 500,000.00 1.00 5.00 50.00 421 0.70 1.00 26,000.00 3.00 5.00 49.00 495 0.04 0.60 0.00 1.00 5.00 52.00 512 1.40 2.00 3,000.00 3.00 5.00 39.00 555 70.00 81.00 3,000.00 3.00 5.00 50.00 713 N/A N/A N/A N/A N/A N/A 13 Table 2-2 EQUIPMENT SPECIFICATIONS - GAS TURBINES AND ENGINE: 1 POWER TO TOTAL ilAINT KW HEAT RATE HEAT RATIO INSTALLED COSTS RATING BTUH/KWH KW/MMBTUH S/KW S/KWH Simple Cycle Gas Turbines: 2 1,100 15,000.0 142.85 1,121 0.0070 3,130 12,942.5 163.87 1,000 0.0065 3,860 12,240.0 168.71 900 0.0065 4,000 11,300.0 239.00 750 0.0080 5,000 10,000.0 228.00 750 0.0080 8,840 10,979.6 205.29 700 0.0065 10,000 13,000.0 149.25 690 0.0070 20,000 10,000.0 216.00 575 0.0050 21,440 9,500.0 252.00 680 0.0016 38,500 10,709.0 236.00 500 0.0013 Combined Cycle Gas Turbines: 3 4,750 9,224.0 949.00 777 0.0100 6,437 7,763.0 2,518.00 716 0.0100 26,940 7,561.0 2,694.00 854 0.0030 52,500 7,853.0 2,625.00 670 0.0020 Reciprocating Gas Engines: * 1,100 11,718.2 193.46 900 0.0130 1,165 10,410.0 241.00 754 0.0100 1,415 10,035.0 261.00 702 0.0100 1,475 11,977.6 190.99 750 0.0125 1,555 10,399.0 276.00 690 0.0100 1,875 10,035.0 292.00 609 0.0100 3,075 9,498.0 422.00 803 0.0100 3,600 8,431.0 427.00 760 0.0100 4,100 8,542.0 421.00 667 0.0100 4,805 8,422.0 428.00 655 0.0100 5,125 8,551.0 422.00 598 0.0075 6,000 8,430.0 427.00 580 0.0075 14 KW RATING HEAT RATE BTUH/KWH Table 2-3 POWER TO HEAT RATIO KW/MMBTUH TOTAL MAI NT INSTALLED COSTS $/KW S/KWH Diesel Engines 5 6 1,020 9,176.5 309.00 315 0.0100 1,265 9,109.1 271.00 310 0.0100 1,360 9,040.4 230.00 305 0.0100 1,600 9,253.8 323.00 300 0.0100 3,075 9,218.5 378.00 803 0.0100 3,600 9,011.9 394.26 760 0.0100 4,100 9,215.9 383.46 667 0.0100 4,805 9,007.1 394.66 655 0.0100 5,125 9,220.7 384.18 598 0.0075 6,000 9,014.8 394.27 580 0.0075 Fluidized Bed Coal -Fired Turbines: 7 8 POWER TO TOTAL MAINT. PROCESS HEAT KW HEAT RATE HEAT RATIO INSTALLED COSTS AVAILABLE RATING BTUH/KWH 25,053.00 KW/MMBTUH 71.2 $/KW 1,615 $/KWH 0.0012 (#/HR) 5,237 110,000 6,690 19,234.00 65.6 1,287 0.0013 115,000 7,550 29,678.00 64.3 1,201 0.0017 124,000 12,840 26,223.00 54.4 1,040 0.0020 181,000 31,480 26,766.00 52.0 788 0.0021 400,000 78,260 20,839.00 41.9 723 0.0026 920,000 Notes: * Above technologies meet the PURPA requirements and qualify as cogeneration equipment. 2 Manufacturers include: Kawasaki, Solar, GE, Allison and Sulzer (see bibliography). 3 Manufacturers include: GE and Allison (see bibliography). 4 Manufacturers include: Waukesha, Superior, and Cooper (see bibliography). 5 Manufacturers include: Caterpillar and Cooper (see bibliography). 15 6 At present, technology for pollution control for diesel engines is not available. 7 Manufacturers include Transam (see bibliography). 3 Assume 35% boiler efficiency, 74% steam turbine efficiency, assume process heat is extracted for steam condensate, maintenance cost is 2.5% of capital cost, and S/KWH include boiler, turbine generator and pollution control . 16 The final step in the technical analysis is the actual matching of the data bases constructed. That is, each of the firms in the energy data base is matched to a cogeneration configuration from the technical data base. This step was completed by ESC, Inc., for the Department and was based upon the technical characteristics of each firm's electricity demand, steam demand, and variations in these demands as well as the power-to-heat ratio, fuel -use efficiency, the incremental heat rate. ESC matched the firms to cogeneration equipment based on a two-step sizing methodology. First, firms were screened based on their ability to cogenerate at least one megawatt of electricity. Firms whose electricity demand was less than one megawatt, those whose steam demand was too low to produce one MW, and those who already cogenerated to meet their average electricity demand were segregated from the data base. 3 The remaining firms were then evaluated against the technical characteristic of the cogeneration equipment in the second step. During the second step equipment was approximately sized to the average heat load or average electric load whichever was the operative constraint given the equipment's power to heat ratio. The matching was to existing equipment rather than a technological frontier since the study is primarily focused upon the likely cogeneration installations in the year 1987. Since existing equipment only comes in certain sizes ^Exi sting cogenerators were also matched to a cogeneration configuration if only one-half of their electricity demand was being served presently by the existing system, and their steam demands were large enough to support another unit. 17 with given technical characteristics, there was often the issue of whether to slightly oversize or undersize the equipment. This *as a decision made by the engineers of ESC, Inc., ^nd .vas based on relevant information in the database including peak loads, level of load variability, and so on. An example of the matching process is depicted in Table 2-4. All equipment was matched assuming a cogeneration mode of operation. No electric only configurations, e.g., peak shaving, were analyzed because of the lack of detailed operation information in the Phase I data base. ^ The final results of the sizing process, given in Table 2-5, comprises the technical input data base which will be used in the Economic Analysis. As depicted in Table 2-5, the most common cogeneration configuration is the simple cycle technology followed by diesel engines and coal -fired technology. 5 The size of simple cycle technologies matched to the firms ranged from 1.1 mw to 38.50 mw units and represents 83% of the firms which were matched to cogeneration equipment, while 13% were matched to diesel engines (12 firms), and only 2 firms matched to coal -fired technology. ^Matching was also based upon meeting the requirement to qualify as a cogenerator according to Sec. 210 PURPA. ^For a more detailed discussion on different cogeneration modes of operation refer to Phase 1 study, "An Evaluation of the Technical Potential for Cogeneration in Illinois." 18 Table 2-4 COGENERATION POTENTIAL FIRM NO. 241 Avg. Steam #/HR Electric Avg. Low High Demand Peak (MW) (MW) Pressure Pressure Comments 4 3.2 None 75,000 COGENERATION ALTERNATIVES 1. Reciprocating Engine Reciprocating engines cannot produce high pressure steam. Solar GSC-400, 1 unit to meet electric demand. GE LM 2500, 1 unit to meet steam demand. GE LM 2500, 7 units. Cost per KW too high. 3. Coal The smallest coal plant produces over 200,000 #/hour. Gas Turbine Electric (MW) Ste am Avg. #/HR a) Simple 3.13 19,200 Cycle 21.4 85,000 b) Combined 188.58 70,000 Result : 241 match to a) Simple Cycle 3.13. The 21.4 MW gas turbine, while a closer match to steam demand would have resulted in the system producing 18 MW more power than needed. Given existing buyback rates in Illinois, it is not likely that rates to a utility could justify the additional expense. 19 TABLE 2.5: INPUT DATA - COMMONWEALTH EDISON COMPANY SERVICE TERRITORY PLANT POWER TO HEAT TOTAL MA I NT. MW SHIFT DAYS WEEK COGEN NUMBER HEAT RAT 142.85 10 RATE 15,000.0 . , KW 1,121 5/KWH 0.0070 PRODUCE 2.20 DAY 3 ,-ltlY 5 'EAR MATCH 4 48 1 9 228.00 10 ,000.0 750 0.0080 10.00 3 7 52 1 19' 142.85 15 ,000.0 1,121 0.0070 1.10 3 5 52 1 35 239.00 11 ,300.0 750 0.0080 4.00 3 5 49 1 57 271.00 9 ,109.1 310 0.0100 1.27 2 5 50 2 67 142.85 15 ,000.0 1,121 0.0070 2.20 3 7 52 1 70 163.87 12. ,942.5 1,000 0.0065 3.13 3 7 50 1 77 271.00 9 ,109.1 310 0.0100 2.53 3 6 52 2 82 142.85 15, ,000.0 1,121 0.0070 1.10 3 5 52 1 93 142.85 15 ,000.0 1,121 0.0070 1.10 2 6 50 1 153 142.85 15. ,000.0 1,121 0.0070 2.20 3 5 52 1 160 142.85 15. ,000.0 1,121 0.0070 1.10 3 7 53 1 186 142.85 15. 000.0 1,121 0.0070 1.10 3 7 50 1 188 142.85 15 ,000.0 1,121 0.0070 1.10 3 7 52 1 197 142.85 15, ,000.0 1,121 0.0070 1.10 3 5 50 1 211 205.29 10. ,979.6 700 0.0060 8.84 3 7 50 1 219 239.00 11. 300.0 750 0.0080 4.00 2 5 50 1 223 228.00 10. ,000.0 750 0.0080 5.00 3 7 52 1 227 252.00 9. ,500.0 680 0.0016 21.40 3 7 50 1 241 163.87 12. ,942.5 1,000 0.0065 3.13 3 7 51 1 244 142.85 15, 000.0 1,121 0.0070 1.10 2 5 52 1 285 142.85 15. ,000.0 1,121 0.0070 1.10 3 7 52 1 293 228.00 10, 000.0 750 0.0080 5.00 3 7 52 1 313 228.00 10, ,000.0 750 0.0080 5.00 3 5 49 1 317 228.00 10. 000.0 750 0.0080 5.00 3 5 50 1 324 239.00 11 ,300.0 750 0.0080 4.00 2 6 52 1 327 309.00 9 ,176.5 315 0.0010 1.02 3 5 52 2 335 236.00 10. ,709.0 500 0.0013 38.50 3 7 52 1 357 205.29 10. ,979.6 700 .006 8.84 3 5 52 1 363 142.85 15. ,000.0 1,121 0.0070 1.10 3 7 52 1 380 41.90 20. ,839.0 723 0.0026 78.25 2 7 52 3 386 205.29 10. ,979.6 700 0.0060 8.84 3 7 52 1 391 228.00 10. ,000.0 750 0.0080 5.00 3 7 52 1 414 168.71 12. ,240.0 900 0.0065 3.86 3 6 50 1 415 142.85 15. ,000.0 1,121 0.0070 1.10 3 5 52 1 419 142.85 15. ,000.0 1,121 0.0070 1.10 3 7 52 1 434 252.00 9. ,500.0 680 0.0016 21.40 3 7 52 1 454 142.85 15. ,000.0 1,121 0.0070 1.10 2 5 52 1 467 205.29 10. ,979.6 700 0.0060 8.84 3 7 52 1 * 1) Simple Cycle Gas Turbine 2) Diesel Engine 3) Coal Fluidized Bed 4) Steam Load too low 5) Below 1 MW 6) Already Cogenerates 7) No information 20 TABLE 2 .5: INPUT DATA - ( :0MM0NWEA LTH EDISON COMPANY (con tinued ) PLANT POWER TO HEAT TUTAL MA I NT. MW SHIFT DAYS WEEK COGEN NUMBER HEAT RATIO RATE 5/KW S/KWH PRODUCE DAY WEEK YEAR MATCH* 483 394.27 9,014.8 580 0.0075 12.00 2 6 50 2 488 271.00 9,109.1 310 0.0100 2.53 3 5 50 2 516 239.00 11,300.0 750 0.0080 4.00 3 7 52 2 521 230.00 9,040.4 305 0.0100 2.72 3 7 52 1 531 142.85 15,000.0 1,121 0.0070 1.10 3 7 52 2 533 428.00 8,422.0 655 0.0075 4.80 2 5 52 544 228.00 10,000.0 750 0.0080 5.00 3 7 52 548 228.00 10,000.0 750 0.0080 15.00 3 7 52 558 252.00 9,500.0 680 0.0016 21.44 3 5 49 568 149.25 13,000.0 690 0.0070 10.00 2 5 50 580 205.29 10,979.6 700 0.0065 8.84 2 5 50 592 149.25 13,000.0 690 0.0070 10.00 3 6 52 594 65.60 19,234.0 1,287 0.0013 6.69 2 5 48 613 149.25 13,000.0 690 0.0070 10.00 3 7 52 719 228.00 10,000.0 750 0.0080 5.00 3 7 52 721 142.85 15,000.0 1,121 0.0070 2.20 3 7 52 6 - - - - - 1 5 50 4 7 - - - - - 1 5 50 4 72 - - - - - 1 5 49 5 91 - - - - - 3 5 50 4 98 - - - - - 3 5 52 5 101 - - - - - 3 5 50 5 110 - - - - - 1 5 52 5 116 - - - - - 1 5 52 5 119 - - - - - 3 5 48 6 135 - - - - - 1 5 52 5 147 - - - - - 3 5 52 5 158 - - - - - 3 7 52 6 171 - - - - - 1 5 52 5 178 - - - - - 2 5 52 7 180 - - - - - 1 5 52 5 181 - - - - - 2 5 50 5 209 - - - - - 1 5 48 4 210 - - - - - 3 5 50 5 215 - - - - - 3 7 52 5 216 - - - - - 3 5 48 4 247 - - - - - 1 5 52 4 252 - - - - - 1 5 50 5 254 - - - - - 2 4 49 4 255 - - - - - 1 4 50 5 264 - - - - - 3 5 52 5 * 1) Simple Cyc" e Gas Turb ine 2) Diesel Eng- ne 3) Coal Fluid" 'zed Bed 4) Steam Load too low 5) Below 1 MW * 6) Al ready Cogenerates * 7) No information 21 TABLE 2.5: INPUT DATA - COMMONWEALTH EDISON COMPANY (continued) PLANT POWER TO NUMBER HEAT RAT I 'J 269 287 320 325 328 370 373 424 430 448 497 505 507 511 513 537 559 700 704 707 708 710 715 716 500 1) Simple Cycle Gas Turbine 2) Diesel Engine 3) Coal Fluidized Bed 4) Steam Load too low 5) Below 1 MW 6) Already Cogenerates 7) No information HEAT TOTAL MAINT. MW SHIFT DAYS WEEK COGEN RATE S/KW 5/KWH PRODUCE DAY ■VEEK 'EAR ••• - - - - 3 5 52 - - - - 2 5 52 5 - - - - 2 5 5 - - - - 1 5 52 4 - - - - 2 5 52 4 - - - - 2 5 52 5 - - - - 2 5 52 5 - - - - 2 6 52 4 - - - - 3 7 52 5 - - - - 2 5 50 5 - - - - 1 5 48 4 - - - - 3 7 52 5 - - - — 1 5 52 5 - - - - 3 5 52 5 - - - - 1 5 52 5 - - - - 3 5 49 4 - - - - 2 5 49 6 - - - - 3 7 52 4 - - - - 3 7 52 6 - - - - 3 7 52 6 - - - - 3 7 52 6 - - - - 3 7 52 6 - - - - 1 5 52 5 - - - - 3 7 52 6 - - - - 3 6 5 22 TABLE 2.5: INPUT DATA - ILLINOIS POWER SERVICE TERRITORY PLANT POWER TO HEAT TOTAL MAINT. MW SHIFT DAYS WEEK COGEN NUMBER HEAT RAT 10 3ATE $/KW S/KWH PRODUCE DAY WEEK V EAR MATCH* 2 252.00 9,500.0 680 0.0016 21.44 3 7 52 15 239.00 11,300.0 750 0.0080 4.00 3 5 45 25 142.85 15,000.0 1,121 0.0070 1.10 3 7 52 85 271.00 9,109.1 310 0.0100 1.27 3 6 52 95 205.29 10,979.6 700 0.0065 8.84 3 7 52 103 309.00 9,176.5 315 0.0100 2.04 2 5 51 111 142.85 15,000.0 1,121 0.0070 1.10 3 5 52 115 142.85 15,000.0 1,121 0.0070 1.10 3 5 52 140 142.85 15,000.0 1,121 0.0070 1.10 1 5 50 193 142.85 15,000.0 1,121 0.0070 1.10 3 5 52 204 271.00 9,109.1 310 0.0100 2.53 1 5 50 230 236.00 10,709.0 500 0.0013 38.50 3 7 52 376 163.87 12,942.5 1,000 0.0065 3.13 3 5 48 385 252.00 9,500.0 680 0.0016 21.44 3 7 49 422 142.85 15,000.0 1,121 0.0070 2.20 3 5 50 510 142.85 15,000.0 1,121 0.0070 1.10 3 5 50 561 228.00 10,000.0 750 0.0080 15.00 3 5 50 578 239.00 11,300.0 750 0.0080 4.00 3 5 50 583 228.00 10,000.0 750 0.0080 5.00 3 7 52 607 239.00 11,300.0 750 0.0080 4.00 3 7 52 709 - - - - - 3 7 52 6 713 - - - - - - - - 6 53 - - - - - - - - 6 133 - - - - - 1 5 52 4 277 - - - - - 3 6 33 7 348 - - - - - 2 5 50 4 433 - - - - - 3 5 50 4 546 - - - - - - - - 7 * 1) Si mple Cyc' le Gas Turb ine 2) Diesel Eng ine 3) Coal Fluid ized Bed 4) Steam Load too low 5) Below 1 MW 6) Al ready Cogenerates 7) No information 23 TABLE 2.5: INPUT DATA - UNION ELECTRIC* SERVICE TERRITORY PLANT POWER TO HEAT NUMBER HEAT RATIO RATE TOTAL S/KW MAINT. S/KWH MW PRODUCE SHIFT DAY DAYS WEEK WEEK YEAR COGEN MATCH* 303 228.00 iO,000 342 228.00 10,000 411 228.00 10,000 701 149.25 13,000 702 750 750 750 690 0.0080 0.0080 0.0080 0.0007 5.00 5.00 5.00 10.00 3 3 3 3 3 6 7 7 7 7 o2 52 52 52 52 1 1 1 1 6 * 1) Simple Cycle Gas Turb 2) Diesel Engine 3) Coal Fluidized Bed 4) Steam Load too low 5) Below 1 MW 6) Already Cogenerates 7) No information ine TABLE 2.5: INPUT DATA - CENTRAL ILLINOIS PUBLIC SERVICE CO. SERVICE TERRITORY PLANT POWER TO HEAT TOTAL MAINT. MW SHIFT DAYS WEEK COGEN NUMBER HEAT RATIO RATE $/KW $/KWH PRODUCE DAY WEEK YEAR MATCH* 24 228.00 10,000.0 750 0.0080 5.00 3 7 50 1 257 239.00 11,300.0 750 0.0080 4.00 3 5 52 1 295 232.00 9,253.8 300 0.0100 1.60 3 5 52 2 367 142.85 15,000.0 1,121 0.0070 1.10 3 5 52 1 378 142.85 15,000.0 1,121 0.0070 2.20 3 5 50 1 389 163.87 12,942.5 1,000 0.0065 3.13 1 5 52 8 462 309.00 9,276.5 315 0.0100 1.02 1 5 52 2 496 54.40 26,223.0 1,040 0.0020 12.84 2 6 20 3 615 228.00 10,000 750 0.0080 5.00 3 7 52 1 84 - - - - - - - - 5 124 - - - - - - - - 6 473 - - - - - - - - 5 554 - - - - - - - - 5 * 1) Si mple Cycl e Gas Turb ine 2) Diesel Engine 3) Coal Fluidized Bed 4) Steam Load too low • 5) Below 1 MW 6) Al ready Cogenerates 7) No information 8) Reciprocati ng Gas Eng ine 24 TABLE 2.5: INPUT DATA - CENTRAL ILLINOIS LIGHT COMPANY SERVICE TERRITORY PLANT POWER TO HEAT TOTAL MAINT. MW SHIFT DAYS WEEK COG EN NUMBER HEAT RATIO RATE 205 29 10,979.60 S/KW 700 S/KWH 0.0065 PRODUCE 8.84 DAY 3 WEEK 7 YEAR 52 MATCH* 80 1 X 319 216 00 10,000.00 575 0.0050 20.00 3 7 52 I 89 - - - - - - - 6 330 - - - - - - - 6 404 - - - - - - - 6 421 - - - - - - - 6 495 - - - - - - - 5 512 - - - - - - - 4 555 - - - - - - - 4 713 - - - - - - - - 7 * 1) Simple Cycle Gas Turb ine 2) Diesel Engine 3) Coal Fluidized Bed 4) Steam Load too low 5) Below 1 MW 6) Al ready Cogenerates 7) No information 25 26 Chapter 3 - ECONOMIC ANALYSIS This chapter involves discussion of the economic inputs that were used in the cost-benefit moael to evaluate the economics of cogeneration for each of the firms matched to cogeneration equipment in the technical analysis. A firm's investment in cogeneration equipment is based largely* on the economic benefits it would produce over a certain time frame. The most commonly used method to evaluate a cogeneration project's benefits or returns is a cost-benefit technique, similar to a make or buy decision process. Basically, if the benefits of producing a product internally exceed the cost of buying it, then a firm should produce the product internally. This decision process is applicable for evaluating investment decisions regarding cogeneration. If it is profitable for a firm to cogenerate its own power and steam from one fuel source, then a firm might choose to forego purchased power from its utility and invest in cogeneration. *As noted above, firms' decisions are also influenced by attitudes regarding inhouse electricity production as well as other organizational considerations. 27 Given however, that most firms have a number of competing investments available at one time, the benefits of a cogeneration investment may be less than an alternative investment. Thus, even though a cogeneration investment provides economic benefits, a firm may not invest because other investments appear more suitable for the firm's short- and long-term objectives. To effectively evaluate whether a cogeneration investment meets a firm's short- and long-term objectives, most firms use a capital budgeting evaluation process which employs such techniques as determining a net present value, an internal rate of return or a post tax payback period. These techniques allow a firm to compare a cogeneration investment to its other available investment choices and determine which investment provides the best returns. 28 Since the individual firms' investment opportunities and their estimated returns are unknown, economic cogeneration potential is defined in this study using a post-tax payback period method. Investments with a post-tax payback period of 4 years or less are considered economic. Briefly, the post-tax payback period method of analysis determines the number of years it takes for the cash inflows to equal the initial investment.^ While use of the payback period method is considered very limited because it ignores the time value of money and project earnings after the initial investment has been recovered, it is a quick method to gauge the early recovery of funds invested. The net present value method and internal rates of return are considered life cycle costing techniques. Both approaches consider total relevant costs and revenues over the life of system, in this case the cogeneration system. The internal rate of return equates the present value of the expected cash outflows with the present value of the expected inflows. Once computed it represents the discount rate n I = CFt - CI t t = 29 for the cogeneration investment. 2 Generally, a company would invest in cogeneration if the IRR computed is greater than its opportunity cost of capital (r) . In comparison, the net present value is equal to the present ^alue of future returns, discounted at the marginal cost of capital, minus the present value of the cost of the investment. 3 In general, the larger the net present value in absolute terms, the more attractive the cogeneration investment is over purchased power. 2 IRR = n ( CFt ) - Ci = t = (1 + r^) where, t = years, r = interest rate, n = total years 3 NPV = n ( CFt ) - Ci t = (1 + r^) wner e, t = years, r = interest rate, n = total years. 30 Using this framework the cost-benefit model simulates 20 year projected 4 net cash flows for a cogeneration investment, and based on these net cash flows computes the project's internal rate of return, net present value and post-tax payback period. The model's base year is 1987 and projections are made to simulate the year 2007. Net cash flows are calculated by the model by subtracting all the cash inflows due to the project from the cash outflows. Cash inflows include project revenues, revenues from the sale or lease of project assets, and any revenues generated from tax credits. 5 Typical cash outflows include capital expenditures, interest and principle payments, operating and maintenance costs, lease payments, and projected income taxes. It is important to note that project revenues do not include revenues from sale of electricity to a utility at avoided costs. At some later point in time inputs can be developed to determine the changes in the economics of a cogeneration investment using the avoided cost payment as a revenue. However, no attempt has been made to do so in this study. ^ All cogeneration investments are assumed to be for self-generation. ^The model assumes a 20 year life for cogeneration equipment. Some manufacture suppliers, however, would say that if properly upgraded the life of the cogeneration system is unlimited. 5 Given the Tax Act of 1986 does not allow for investment tax credits after 1987 except on a transitional period for cogeneration systems using renewable resources, the model does not account for tax credits as an inflow, ^The assumption to exclude avoided costs as a revenue was based upon the low avoided cost rates available to cogenerated power. 31 32 Description of the Model The functional form of the model used to simulate the cash inflows and outflows of a cogeneration investment in this study is presented in Figure 3-1. Figure 3-1: n ( (CF1 + CF2 + CF3)t (C01 + C02 + C03 + C04 + C05 + C06)t ) ( ) t=0 ( (1 + r)* (1 + r)t ) where: n = last year in which cash flow is expected t = year of cash flow r = discount rate, equivalent to a firm's cost of capital or minimum desired rate of return, cutoff rate, target rate, hurdle rate and financial standard CF1 = the project's revenues or savings from a reduction in operating costs CF2 = revenues from the sale or lease of project assets CF3 = revenues generated from tax credits C01 = capital expenditures C02 = interest and principle payments C03 = & M costs C04 = lease payments C05 = project income taxes C06 = standby power costs Once the net after tax cash flows are computed for each of the cogeneration investments analyzed in the technical input data base, the model calculates the values for the project's internal rate of return, its net present value and the post-tax payback period. 33 Cash Inflows As outlined above, cash inflows represented in the model are those associated with the project's revenue, tax credits, and lease or sale of assets. The model generates the projected revenues resulting from a cogeneration investment by calculating the expected revenues from displaced electric utility purchased power and from replacement of existing boiler systems. The first component of a system's project revenues, the total electric sales, accrues from displacing the costs previously allocated to power purchased from the electric utility. These sales are computed by the model based on the 1987 industrial rate structure of each utility and 20 year price projections. This component therefore, is not based on actual sales of electricity, but on avoiding purchases of power from the servicing utility. 34 Electricity prices and projections are presented in Tables 3-1, 3-2, 3-3, 3-4 and 3-5 for each of the five utilities. These prices are expressed in nominal terms. The inflation rate used, presented in' Tables 3-6, 3-7, and 3-d, is aerivea from the rate of inflation anticipated oy the electric utilities in their demand forecasts^ as well as other generally available sources. ^ These forecasts are subject to a large amount of uncertainty. While the extent of this uncertainty is not the same for each of the five utilities, it is a significant factor in evaluating the economics of cogeneration investments. In the case of Commonwealth Edison Company (CWE) and Illinois Power Company (IP), the uncertainty surrounding their projected price increases is considered more significant than that for Central Illinois Light Company (CILCO), Central Illinois Public Service (CIPS) and Union Electric Company (UE). Price projections for CWE and IP are influenced by large nuclear construction programs^ and thus are dependent on the actual cost of 7 See General Order 215 filed for each of the respective electric utilities and Appendix A - Bibliography of Sources Electric Utility Data. ^See for instance DRI. ^While UE is also in the midst of phasing in a nuclear facility, their rate structure and projections are more certain and are relatively low in comparison to CWE and IP. 35 cost of completing the plants within the next year and a half and on the regulatory treatment of these costs by the Illinois Commerce Commission. Scenarios accounting for different price increases and possible regulator/ treatment are developed in more detail in the Sensitivity Analysis. However, we stress that the baseline price forecasts are those provided by the utilities. No attempt has been made to independently examine those projections. 36 Table 3-la: Electricity Rate Input - Commonwealth Edison Company 1987 NOMINAL ELECTRICITY RATES (1)(2)(3) Monthly Charge S547.06 Demand Charge (avg. over the year) (up to 10,000 kW) $ 12.59/kW (above 10,000 kW) Energy Charge On-Peak (avg. /year) Off-Peak (avg. /year) $ 5.43/kW $ 6.560/kWh $ 3.111/kWh 1987 AVOIDED COST RATES (4) Energy Payment On-Peak (avg. /year) Off-Peak (avg. /year) $ 0.0406/kWh $ 0.0308/kWh 1987 STANDBY POWER RATES (1)(5) Demand Charge (average over the year) $ 5.83 Footnotes 1. The 1987 rate includes the proposed rate increase under CWE subsidiary plan. 2. Rate 6 L, Large General Service effective 1987. Part of direct testimony filed by Ri fakes as CWE Exhibit 1.0. 3. Fuel Adjustment Charge assumed to average zero over several years. 4. Rider 4, Parallel Operation of Customer's Qualifying Facilities August 1986. 5. Rider 4, Parallel Operation of Customer's Qualifying Facilities August 1986. 37 Table 3-lb: Commonwealth Edison INDUSTRIAL ESCALATION RATES (1) 1988-2007 Nominal % Year Increase 1988 0.00% 1989 0.00% 1990 0.00% 1991 0.00% 1992 0.00% 1993 4.00% 1994 4.00% 1995 4.00% 1996 4.00% 1997 4.00% 1998 4.00% 1999 4.00% 2000 4.00% 2001 4.00% 2002 4.00% 2003 4.00% 2004 4.00% 2005 4.00% 2006 4.00% 2007 4.00% Footnote ^Settlement Proposal rates and growth rates calculated by CWE Rate Department. 38 Table 3-3a: Electricity Rate Input - Illinois Power Company 1987 NOMINAL ELECTRICITY RATES (1) (2) (3) (4) Monthly Charge 3632.04 Demand Charge (average over the year) - $ 7.32/kW Energy Charge On-Peak (avg./year) Off-Peak (avg./year) $ 0.0405/kWh $ 0.0269/kWh 1987 AVOIDED COST RATES (5) Energy Payment On-Peak (avg./year) Off-Peak (avg./year) $ 0.0195/kWh $ 0.0155/kWh 1987 STANDBY POWER RATES (1)(6) Customer Charge $632.04 Demand Charge $ 7.80/kW (average over the year) Required Facilities Charge $ 0.95/kv Footnotes 1. Assumes that the 1987 rates include the 2.84% real rate increase projected by Illinois Power (see IP General Order 215), plus inflation. 2. IP Service Classification 24 and 21, Large Power Service effective for 1986. 3. Fuel Adjustment Charge assumed to average zero over several years. 4. Assume 138 kv, 69 kv, or 34.5 kv. 5. Rider P, Parallel Generation Service, September 8, 1986. 6. Service Classification 22, Standby Service, January 10, 1986. 39 Table 3-2b: Illinois Power Co. INDUSTRIAL ESCALATION RATES (1)(2 1988-2007 Nominal % Year Increase 1988 5.84% 1989 6.84% 1990 6.84% 1991 3.23% 1992 3.23% 1993 3.23% 1994 3.23% 1995 3.23% 1996 3.23% 1997 3.23% 1998 3.23% 1999 3.23% 2000 3.23% 2001 3.23% 2002 . 3.23% 2003 3.23% 2004 3.23% 2005 3.23% 2006 3.23% 2007 3.23% Footnotes 1. General Order 215 filed with the ICC 1986, Avg. Annual compound growth rates of real electric energy prices by customer class. 40 Table 3-3a: Electricity Rate Input - Union Electric 1987 NOMINAL ELECTRICITY RATES (1) Monthly Charge $53.70 (average over the year) Demand Charge (average over the year) $ 10.17/kW Energy Charge On-Peak (avg./year) Off-Peak (avg./year) $ 0.0274/kWh $ 0.0226/kWh 1987 AVOIDED COST RATES (2) Energy Payment On-Peak (avg./year) Off-Peak (avg./year) $ 0.0179/kWh $ 0.0169/kWh 1987 STANDBY POWER RATES (3) Customer Charge Demand Charge (average over the year) $ 53.70 $ 10.17/kW Footnotes 1. Union Electric Service Classification No. 3(1), effective May 19, plus 7.4% nominal increase allowed from phase-in of Calway Unit. 2. Union Electric Co. Expenditures year dollars, Avoided Energy Costs UE Rate Department. 41 Table 3-3b: Union Electric Co, INDUSTRIAL ESCALATION RATES (1 1988-2007 Nominal % Year Increase 1988 10.20% 1989 4.00% 1990 4.00% 1991 4.00% 1992 4.00% 1993 4.00% 1994 4.00% 1995 4.00% 1996 4.00% 1997 4.00% 1998 4.00% 1999 4.00% 2000 4.00% 2001 4.00% 2002 4.00% 2003 4.00% 2004 4.00% 2005 4.00% 2006 4.00% 2007 4.00% Footnotes 1. General Order 215 filed with the ICC 1986 and projection given by Union Electric Rate Department, Phase-in Revenue, Sept. 1986. See Appendix A for sources at utilities. 42 Table 3-4a: Electricity Rate Input - Central Illinois Public Service Co, 1987 NOMINAL ELECTRICITY RATES (1) Monthly Charge $24.23 (average over the year) Demand Charge (average over the year) $ 12.05/kW Energy Charge On-Peak (avg./year) Off-Peak (avg./year) $ 0.0227/kWh $ 0.0068/kWh 1987 AVOIDED COST RATES (2) Energy Payment On-Peak (avg./year) Off-Peak (avg./year) $ 0.0236/kWh $ 0.0226/kWh 1987 STANDBY POWER RATES (3) Customer Charge Demand Charge (average over the year) $ 24.23 $ 12.05/kW Footnotes 1. Rate 9, Large Light and Power, effective Jan., 1983. 2. Rate 14, Electric Power Purchases from Qualifying Facility (8th revised sheet no. 16.11) 3. Standby rates are the same as industrial rates. 43 Table 3-4b: Central Illinois Public Service Co, INDUSTRIAL ESCALATION RATES (1 1988-2007 Nominal % Year Increase 1988 3.00% 1989 4.00% 1990 4.00% 1991 4.00% 1992 4.00% 1993 4.00% 1994 4.00% 1995 4.00% 1996 4.00% 1997 4.00% 1998 4.00% 1999 4.00% 2000 '4.00% 2001 4.00% 2002 4.00% 2003 4.00% 2004 4.00% 2005 4.00% 2006 4.00% 2007 4.00% Footnotes 1. General Order 215 filed with the ICC 1986, Avg. Annual compound growth rates of real electric energy prices by customer class. 44 Table 3-5a: Electricity Rate Input - Central Illinois Light Co, 1987 NOMINAL ELECTRICITY RATES (1) Monthly Charge $510.34 (average over the year) Capacity Charge (average over the year) $ 8.23/kv Energy Charge On-Peak (avg./year) Off-Peak (avg./year) $ 0.0243/kWh $ 0.0143/kWh 1987 AVOIDED COST RATES (2) Energy Payment On-Peak (avg./year) Off-Peak (avg./year) $ 0.0276/kWh $ 0.0229/kWh 1987 STANDBY POWER RATES (3) Customer Charge (Monthly) Demand Charge (average over the year) $234.76 $ 6.11/kv Footnotes 1. Large Power and Rate 23, effective Dec. 83. 2. Purchases of Alternative Power from Qualifying Facilities Rate 26, Sixth Revised Sheet. 3. Auxiliary or Standby Rate 27, effective December 1983. 45 Table 3-5b: Central Illinois Light Co. INDUSTRIAL ESCALATION RATES (1 1988-2007 Year 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 Norm inal % Increase 3, .20% 3, .20% 3. .20% 3, .20% 3, .20% 3, .20% 3. .20% 3, .20% 3. .20% 3. .20% 3, .20% 3, ,20% 3, ,20% 3. ,20% 3. ,20% 3. ,20% 3, ,20% 3. ,20% 3. ,20% 3. ,20% Footnotes 1. General Order 215 filed with the ICC 1986, Avg. Annual compound growth rates of real electric energy prices by customer class. 46 The second component of a project's revenues is the thermal savings associated with a new steam generation system (replacing the existing boiler system). A 70% boiler efficiency rate is used in the model to represent the efficiency of the existing system. The revenue generated is also based on the price of the energy used in the system, i.e., oil, gas or coal. These energy prices were obtained from a number of published sources. 9 Table 3-6, 3-7, and 3-8 present the fuel price projections used in the model. These prices are expressed in both real and nominal terms. Given the large degree of uncertainty associated with projected energy prices, the estimates depicted in Tables 3-6, 3-7 and 3-8, should only be considered as a base upon which a number of other possible price scenarios can be constructed.^ Later in Chapter 4, alternative scenarios are developed and the uncertainty of these variables on the economics of cogeneration is analyzed. l°See source listing on footnotes to Table 3-6, 3-7 and 3-8. UNote the Department does not claim to estimate the most likely scenario. The base represents what the Department perceives to be the most accepted projection by the parties directly involved. 47 Table 3-6: Fuel Price Input - Fuel Oil #2 (1987-2007) FUEL OIL f2 REAL •JOMIWAl NOMINAL PRICE GROWTH I GROWTH INFLATION RATE (PER MMBTU) RATE RATE 1987 3.00% $ 3.55 1988 4.00% 3.35 -9 . 50% -5.50% 1989 4.00% 3.20 -8.50% -4.50% 1990 4.00% 3.06 -8.50% -4.50% 1991 4.00% 3.41 7.50% LI. 50% 1992 4.00% 3.80 7.50% LI. 50% 1993 .4.00% 4.24 7.50% LI. 50% 1994 4.00% 4.73 7 . 50% LI. 50% 1995 4.00% 5.27 7.50% LI. 50% 1996 4.00% 5.88 7.50% 11.50% 1997 4.00% 6.56 7 . 50% LI. 50% 1998 4.00% 7.31 7.50% 11.50% 1999 4.00% 8.15 7 . 50% LI. 50% 2000 4.00% 9.09 7 . 50% 11.50% 2001 4.00% 10.13 7 . 50% LI. 50% 2002 4.00% 11.30 7.50% 11.50% 2003 4.00% 12.60 7.50% LI. 50% 2004 4.00% 14.04 7.50% 11.50% 2005 4.00% 15.66 7 . 50% LI. 50% 2006 4.00% 17.46 7.50% 11.50% 2007 4.00% 19.47 7.50% LI. 50% Sources 1. Data Resources, Inc., "Energy Review" Autumn 1986 U.S. Oil Outlook, p. 57 2. Institute of Gas Technology, "Energy Statistics" Vol., No. 3, Third Quarter, 1986, Table 53 3. Department of Energy, "Monthly Energy Review" July 1986 Energy Information Administration, Washington, DC 48 Table 3-7: Fuel Price Input - Natural Gas (1987-2007) NATURAL GAS REAL NOMINAL NOMINAL PRICE GROWTH GROWTH INFLATION RATE (PER MMBTU) RATE RATE 1987 3.00% $ 2.89 1988 4.00% 2.72 -9.80% -5.80% 1989 4.00% 2.59 -8.80% -4.80% 1990 4.00% 2.47 -8.80% -4.80% 1991 4.00% 2.76 8.00% 12.00% 1992 4.00% 3.09 8.00% 12.00% 1993 4.00% 3.47 8.00% 12.00% 1994 4.00% 3.88 8.00% 12.00% 1995 4.00% 4.35 8.00% 12.00% 1996 4.00% 4.87 8.00% 12.00% 1997 4.00% 5.45 8.00% 12.00% 1998 4.00% 6.11 8.00% 12.00% 1999 4.00% 6.84 8.00% 12.00% 2000 4.00% 7.66 8.00% 12.00% 2001 4.00% 8.58 8.00% 12.00% 2002 4.00% 9.61 8.00% 12.00% 2003 4.00% 10.77 8.00% 12.00% 2004 4.00% 12.06 8.00% 12.00% 2005 4.00% 13.50 8.00% 12.00% 2006 4.00% 15.13 8.00% 12.00% 2007 4.00% 16.94 8.00% 12.00% Sources Data Resources, Inc., "Energy Review" Autumn 1986 Natural Gas Outlook, p. 69 Institute of Gas Technology, "Energy Statistics" Vol., No. 3, Third Quarter, 1986, Table 32 Department of Energy, "Monthly Energy Review" July 1986 Energy Information Administration, Washington, DC 49 Table 3-8: Fuel Price Input - Coal (1987-2007) COAL REAL NOMINAL NOMINAL PRICE GROWTH GROWTH INFLATION RATE (PER MMBTU) RATE RATE 1987 3.00% $ 1.11 1988 4.00% 1.08 -6.60% -2.60% 1989 4.00% 1.06 -5.60% -1.60% 1990 4.00% 1.05 -5.60% -1.60% 1991 4.00% 1.06 -2.99% 1.01% 1992 4.00% 1.07 -2.99% 1.01% 1993 4.00% 1.08 -2.99% 1.01% 1994 4.00% 1.09 -2.99% 1.01% 1995 4.00% 1.10 -2.99% 1.01% 1996 4.00% 1.11 -2.99% 1.01% 1997 4.00% 1.12 -2.99% 1.01% 1998 4.00% 1.13 -2.99% 1.01% 1999 4.00% 1.15 -2.99% 1.01% 2000 4.00% 1.16 -2.99% 1.01% 2001 4.00% 1.17 -2.99% 1.01% 2002 4.00% 1.18 -2.99% 1.01% 2003 4.00% 1.19 -2.99% 1.01% 2004 4.00% 1.20 -2.99% 1.01% 2005 4.00% 1.22 -2.99% 1.01% 2006 4.00% 1.23 -2.99% 1.01% 2007 4.00% 1.24 -2.99% 1.01% Sources Data Resources, Inc., "Energy Review" Autumn 1986 Coal Outlook, p. 95 Institute of Gas Technology, "Energy Statistics" Vol., No. 3, Third Quarter, 1986, Table 71 Department of Energy, "Monthly Energy Review" July 1986 Energy Information Administration, Washington, DC 50 The revenues associated with the sale of electricity to the electric utility are usually counted as project cash inflows. These revenues are determined based on the electric utilities' 1987 avoided cost payments. Each of the electric utilities' 1987 avoided cost payments is presented in Tables 3-1, 3-2, 3-3, 3-4, and 3-5. Since Illinois utilities' avoided cost payments are relatively low, and the technical cogeneration match in Chapter 2 is not based on the sale of electricity to the electric utility, as noted earlier, the model does not simulate revenues from sale of electricity, although it has that capability. The final two components of a cogeneration project's revenues are the revenues generated from tax credits and those generated from sale or lease of the project's assets. While the model itself has the capability to measure these cash flows as revenues, they are not included as part of this evaluation process. The tax credits granted under the Tax Reform Act of 1981 have been withdrawn under the Tax Act of 1986. Therefore, it is assumed that no investment tax credits are generated as of 1987 to cogeneration investments. As a result of the losses in tax credits, the benefits of leasing cogeneration to a third party are more speculative. The model, therefore, assumes that the cogeneration investment is made on the basis of an ordinary sale.H l^Note, however, that alternative financing options were evaluated in the Sensitivity Analysis using differing amounts of debt to finance the cogeneration project. 51 Also as a result of the Tax Act of 1986, the corporate tax rate as of 1987 has been decreased, and the depreciation schedule has been lengthened. These changes are included in the model. 12 ^Corporate tax rate = 34%, and a 150% double-deceiving balance with a 15 year life is assumed. 52 Cash Outflows The cash outflows represented in the model are computed on the basis of a cogeneration system's capital expenditures and operation and maintenance costs. The capital costs represent the initial investment funds required from the firm for the investment in a cogeneration system. These costs are usually the largest component of the cogeneration systems costs and are derived from the total installed costs included in the technical data base. In some cases it may be feasible for a firm to finance some of these costs through debt, and therefore the initial costs borne by the firm will be smaller. While debt-financing is not considered in the base run, its importance in financing cogeneration investments is recognized, and the economics of cogeneration as an investment alternative are evaluated using debt-financing in the sensitivity analysis. The second cash outflow represented in the model is the cogeneration system's operating and maintenance costs. The relevant S* M costs analyzed in the model are the fuel costs, the electricity costs, and the labor and overhead costs associated with operating and maintaining the system. The cost of fuel is a dominant factor in cogeneration system economics because the plant may burn more fuel when generating its own electricity. The annual fuel costs are determined by the model based upon the cogeneration equipment's megawatt rating and heat rate, the firm's total operating hours 53 per year and the price of the fuel used. As discussed earlier, three fuels are evaluated — natural gas, fuel oil #2 and coal. The prices used oy the model to calculate fuel costs for a cogeneration system are those wnich were presented in Tables 3-6, 3-7 and 3-8. Also, as discussed previously, these price projections are uncertain. Given the importance of these costs to the total costs of a cogeneration system, it is imperative that the economics of a cogeneration investment be analyzed using alternative fuel price scenarios. The Sensitivity Analysis section develops possible alternative scenarios for these prices. The second component of & M costs for a cogeneration system is the firm's purchased electricity costs. These costs represent the additional electricity that is supplied to the firm from the electric utility for standby/backup power or supplemental power. The model calculates these costs based upon each utility's applicable rate schedule and the reliability of the cogeneration system. These rates are presented as part of each utilities' rate schedule given in Tables 3-1, 3-2, 3-3, 3-4 and 3-5. The model assumes that each firm will require standby power to match the amount of cogenerated electricity. In addition, the model accounts for the reliability of the cogeneration system. Recall from the discussion in the Technical Analysis that a 95 percent reliability factor is assumed. The amount of actual standby /backup power needed by a firm will depend on this reliability factor. Therefore, as the reliability factor decreases the 54 costs associated with the cogeneration investment increase. Conversely, as reliability increases, costs decrease. A large amount of uncertainty exists with respect to a system's reliability. These rates are affected by a number of variables including proper maintenance of the equipment. The impacts of this uncertainty may be considerable economics of cogeneration, and therefore, are examined in the Sensitivity Analysis. The model also accounts for other operation and maintenance costs associated with the cogeneration system. Recall from the Technical Analysis, that a maintenance cost per kwh was attached to each type of cogeneration equipment. This cost represents a cash outflow in the model. Given that operation and maintenance costs will increase as a result of inflation over the years, a 5 percent annual increase is assumed in the model. Insurance, the cost of property taxes and other labor costs are also accounted for as expenses. The model assumes that insurance and taxes will be approximately 3 percent of the total installed costs of the cogeneration equipment. The model also assumes a 5 percent escalation rate for these costs. 55 Depreciation is also included as an expense for the cogeneration investment. A 150 percent Double-Declining Balance with a 15 year life is assumed in the model. This cost is, however, added back to the after-tax income to calculate the net cash flows of the cogeneration investment. If more firm specific data were available, it would be appropriate to determine the difference between the firm's remaining depreciation expense on its existing boiler and the new depreciation expense associated with the cogeneration equipment. However, given the lack of firm specification on depreciation it is assumed that the firm's existing boilers were depreciated^ and no salvage value is applied.* 4 l^The assumption that all existing boilers are old enough to depreciate completely is very presumptuous. Some firms, for instance, may have recently installed new boilers. This is discussed in more detail in Appendix C. 1 4 A 5% salvage value is attached, however, to the cogeneration equipment at the end of the 20 year period. 56 The Final Model The model inputs including all the relevant costs and revenues identified above, as well as the technical inputs developed in Chapter 2 are built into the respective cost-benefit model for each electric utility service territory. An example of the model in its entirety appears in the Appendix. 15 The model simulates a 20 year period for the cogeneration system with a base year 1987, and computes the economics of a cogeneration investment. The model results are presented in the following section. They are provided in tabular form by electric utility, type of equipment, range of payback period, and total megawatts produced. Also given is the model's estimated 20 year internal rate of return, 10 year internal rate of return, 20 year net present value and 10 year net present value for each of the firms by electric utility. The post-tax payback periods are of particular interest to this study. These estimates are used to define economic potential and are also used during Sensitivity Analysis to identify those variables which may have an impact on the economics of a cogeneration investment. As mentioned earlier, a system which yields a post-tax payback period of 4 years or less is considered to be economic. 15Note that the values are not representative of actual values used, This table is only for illustrative purposes. 57 Model Results The initial results generated by each specific utility service territory cost benefit model suggest that only the CWE and IP service territories currently have potential for economic cogeneration development. The model results for these utility service areas are presented in this section. With regard to Central Illinois Light Company, Central Illinois Public Service Company and Union Electric, the long payback periods 16 and negative IRRs and NPVs suggest that cogeneration development for the firms included in the database is not feasible regardless of the uncertainty surrounding the parameters influencing the economics. Consequently, the results presented in this section and the sensitivity analysis performed in the following chapter focus on Commonwealth Edison and Illinois Power. Commonwealth Edison Company Service Territory The results computed by the model for CWE service territory are presented in Table 3-11. Each firm is ranked according to its post-tax payback period. In summary, the results show that CWE has between 169.62 megawatts and 308.42 megawatts of economic cogeneration potential .17 Most of this potential is for simple cycle gas technology, followed by diesel and 16post-tax paybacks were greater than 20 years. ^Economic potential is defined as less than 2 years and no greater than 4 years. 58 Table 3-11: Model Results - Commonwealth Edison Company Service Territory Firm Payback MW 'lumber Period IRR 20 yrs. NPV 20 yrs. IRR 10 yrs. NPV 10 yrs. 1 °roduced 488 2 54.17% 1,040,303 53.63% 378,274 2.53 77 2 56.73% 1,059, ,826 56.32% 932, 206 2.53 521 2 66.43% 1,517 ,184 66.11% 1,296 ,347 2.72 380 2 56.37% 123,549. ,886 55.20% 80,302 ,910 78.25 57 2 51.48% 518. ,487 50.72% 412 ,247 1.265 . 327 2 65.62% 597. ,680 65.27% 505 ,148 1.02 227 3 33.27% 7,501 ,653 31.73% 5,483 ,569 21.44 434 3 33.84% 7,784. ,918 32.36% 5,781. ,489 10.00 335 3 43.67% 16,677. ,130 42.93% 14,300 ,194 38.50 548 4 23.05% 1,164. ,294 21.33% 446. ,550 15.0 592 • 4 26.46% 1,651. ,517 24.49% 953 ,812 10.0 467 4 26.46% 1,372. ,358 24.97% 932. ,655 8.84 483 4 24.02% 982. ,333 22.16% 453 ,432 12.0 9 4 23.08% 783. 833 21.36% 303 ,936 10.0 719 4 23.17% 403 ,373 21.44% 161 ,323 5.0 357 4 29.46% 2,341. ,031 27.39% 1,463 ,325 8.84 211 4 26.5% 1,321. ,462 24.58% 860 ,389 8.84 223 4 23.17% 403 373 21.44% 161. ,323 5.0 391 4 23.17% 403 ,373 21.44% 161 ,323 5.0 544 4 23.17% 403. ,373 21.44% 161. ,323 5.0 558 4 29.15% 5,387 ,171 26.97% 3,255 ,202 21.44 293 4 23.17% 403 , ,373 21.44% 161. ,323 5.0 613 4 27.70% 1,907. ,900 26.04% 1,279 ,720 10.0 386 4 26.46% 1,372. ,358 24.97% 932. ,655 8.84 516 5 10.15% -510 ,914 14.70% -429 ,620 4.00 580 5 22.30% 566 ,227 19.19% -153 ,830 8.84 317 5 21.50% 209. ,330 18.84% -130 ,715 5.00 568 5 23.33% 935. 207 20.20% 43 ,142 10.00 324 5 16.28% -364 ,828 14.10% -508 ,871 4.00 219 5 16.93% -326. 121 13.95% -529 ,869 4.00 35 5 15.56% -399 ,477 14.23% -490 ,074 4.00 313 5 21.44% 200 , ,778 18.73% -143. ,558 5.00 414 5 18.29% -209. ,205 15.63% -445 ,597 3.86 533 5 21.57% 183. 326 18.93% -101. ,341 4.80 70 6 13.87% -581 ,361 12.25% -682 ,751 3.13 241 6 13.88% -575 519 12.36% -672 ,215 3.13 594 6 18.79% -485 ,599 13.15% -1,843 ,240 6.69 419 7 NC* -454 ,424 6.26% -442 ,905 1.10 363 7 NC -454 ,424 6.26% -442 ,905 1.10 67 7 5.66% -931. ,761 5.91% -904 ,519 2.20 721 7 5.66% -931 ,761 5.91% -904 ,519 2.20 285 7 NC -454 ,424 6.26% -442 ,905 1.10 1) Assumes a 10% interest rate. 2) NC denotes that the model could not calculate the internal rate of return 59 Table 3-11: Model Results - Commonwea 1th Edison Company (continued) Firm Payback MW Number Period IRR 20 yrs. NPV 20 yrs. IRR 10 yrs. , NPV 10 yrs. Produced 160 7 NC -455,108 6.29% -441,384 1.10 531 7 NIC -454,424 6.26% -442,905 1.10 188 7 NC -454,424 6.26% -442,905 1.10 186 7 NIC -453,058 6.20% -446,546 1.10 153 8 6.33% -911,464 5.49% -958,616 2.20 197 8 7.35% -443,300 5.78% -472,554 1.10 19 8 6.94% -444,276 5.82% -469,953 1.10 93 8 8.89% -438,420 5.59% -485,558 1.10 454 8 9.50% -435,818 5.48% -492,494 1.10 82 8 6.94% -444,276 5.82% -469,953 1.10 415 8 6.94% -444,276 5.82% -469,953 1.10 244 8 8.53% -348,522 5.48% -383,044 1.10 4 8 3.07% -732,968 5.38% -750,120 2.20 60 coal -fired technology. Of particular interest is that the 1.1 MW simple cycle gas technology ranks relatively low in terms of paybacks. Summaries of the results by technology are given in Table 3-12.18 Illinois Power Service Territory Similarly, the results generated for IP service territory are presented in Table 3-13 and a summary is given in Table 3-14. Using the same criteria to measure economic potential, the results indicate that the IP service territory has between 44 MW and 96 MW. This estimate, however, is considered low, resulting from the exclusion of large firms such as Archer Daniels Midland, A. E. Staley's and Lauhoff Grain. These firms are included in the data base as existing cogenerators presently undertaking cogeneration projects. ^Estimates are minimum expected since there are presumably other firms which could cogenerate that are not included in the database. 61 Table 3-12 Summary - Commonwealth Edison Company Service Territory 62 Table 3-13: Model Resi jits - Illinois Power Se rvice Territory Firm Payback m Number Period IRR 20 yrs. MPV 20 yrs. IRR 10 yrs. NPV 10 yrs. 3y, oauced 204 3 38.43% 703,533 35.90% 432,455 2.53 230 3 40.23% 16,805,911 38.51% 12,320,980 38.50 85 3 48.06% 481,934 46.84% 376,320 1.27 103 3 39.45% 561,097 37.48% 388,684 2.04 95 4 24.68% 1,144,288 21.68% 328,278 8.84 385 4 30.97% 7,001,942 28.10% 3,896,468 21.44 2 4 31.88% 7,575,783 29.15% 4,424,819 21.44 607 5 14.61% -474,563 13.46% -573,507 4.00 561 5 19.66% -154,457 15.26% -1,613,212 15.00 583 5 22.23% 327,719 18.87% -131,232 5.00 578 6 14.68% -548,205 11.35% -752,763 4.00 15 6 14.70% -564,354 10.88% -792,073 4.00 376 7 12.89% -834,048 7.55% -1,101,692 3.13 25 7 6.13% -463,526 5.13% -500,034 1.10 422 8 7.49% -1,000,874 3.09% -1,122,456 2.20 510 8 7.46% -501,289 3.07% -561,888 1.10 111 8 7 . 38% -497,976 3.25% -556,462 1.10 115 8 7.38% -497,976 3.25% -556,462 1.10 193 8 7.38% -497,976 '3.25% -556,462 1.10 140 10 8.40% -556,497 -0.07% -652,316 1.10 63 Table 3-14: Summary - Illinois Power Service Territory 64 Chater 4 - SENSITIVITY ANALYSIS The outcomes of the cogeneration investment analysis can be quite sensitive to the values used and assumptions made in the analysis. In particular, a great deal of uncertainty is associated with estimating future escalations for fuel, electricity, standby power and maintenance costs. Sensitivity analysis or parametric analysis provides a systematic means for determining the importance of each independent factor to the end result. With sensitivity analysis, one value is varied over its expected range of values while all other factors are held constant and value of the investment is recalculated. In this way variables that appear to impact the economics of cogeneration investments are identified. An understanding of the potential impacts of uncertainties on cogeneration economics is critical. Following is a discussion and analysis of the factors which could potentially impact the economics of a cogeneration investment, including electricity prices, fuel prices, standby power rates, reliability, debt-financing, and operation and maintenance costs. Take note that the values chosen are used to illustrate sensitivity and do not necessarily reflect expectations. However, where the economics of cogeneration show sensitivity to changes, the importance of gathering as good information as possible is made clear. 65 - Electricity Price - The first of these factors involves projections of future electricity prices. In general, if electricity rates increase over projected values all other things constant, one would assume that cogeneration investments become more attractive. On the other hand, if electricity rates decrease in the future, one would assume that purchased power from utilities becomes more attractive. To analyze the impacts of changes in electricity rates seven scenarios were developed to represent the range of possible future electricity rate projections (including standby power). Each projection is a function of increasing/decreasing the rate of escalation developed as the base. These rates include a 1% increase, a 1% decrease, a 2.5% increase, a 2.5% decrease, a 5% increase, a 5% decrease, and a 10% increase and a 10% decrease. 66 The results of the electricity price sensitivity analysis for firms in the Commonwealth Edison Co. and Illinois Power Co. service territories are given in Tables 4-3 and 4-4. The results are provided in summary form for ease of comparing the economic potential for cogeneration generated in the base case with the economic potential for cogeneration that is computed using alternative rate escalation scenarios. Again cogeneration investments considered economic are those with a post- tax payback period of four years or less. The results suggest that the economic cogeneration potential in the Commonwealth Edison Co. and Illinois Power service territories are affected by changes in the rate of escalation for the electricity price. Of most importance the results suggest that the economics of cogeneration for firms in the Commonwealth Edison service territory differs from that in Illinois Power's service territory in its sensitivity to these price rate changes. For instance, the results for Commonwealth Edison indicate that a 1% increase in the rate of escalation will increase the total amount of economic potential by 8% over the base estimate, while a 1% increase in the rate of price escalation for Illinois Power has no impact on the economic cogeneration potential. 1 Similarly, a 2.5% increase in the rate of price Iwhile there is no impact on economic cogeneration potential (4 years or less) there is an affect on the marginal firms (5, 6, and 7 years). 67 escalation has a larger impact on the economic cogeneration potential for Commonwealth Edison than for Illinois Power. At the 5% and 10% increase levels however, the amount of economic potential for Illinois Power aopears more sensitive than for Commonweal tn Edison. These levels oring aoout a 16% and 37% increase for Illinois Power and a 9% and 19% increase for Commonwealth Edison, respectively. Of particular interest, the results demonstrate that the amount of economic cogeneration potential is sensitive to decreases in the rate of price escalations as well. For firms in the Commonwealth Edison Co. and Illinois Power service territories a 1% decrease in the escalation rate has no impact. A 2.5% decrease, however, results in a 20% decrease in the amount of economic cogeneration potential for firms in the Commonwealth Edison region and an 8% decrease for Illinois Power firms. The difference between the two service territories is more evident at the 5% decrease level. At this level, the economic potential for cogeneration in Commonwealth Edison's service territory decreases by 35%, whereas the decrease in the economic potential for cogeneration in Illinois Power's service territory remains at only 8%. These differences may be a result of the differences between the two utilities rate structures, and the number of industrial customers served by each. The difference between the utilities at the 10% decrease level however, is minimal. The economic cogeneration potential in both of these service territories at this level decreases by as much as 59% for Commonwealth Edison and 54% for Illinois Power. 68 TABLE 4-3: COMMONWEALTH EDISON CO. SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - ELECTRICITY PRICE MW PERCENT MW CHANGE CHANGE BASE: ECONOMIC POTENTIAL 308.43 TOTAL POTENTIAL 399.08 1% INCREASE: ECONOMIC POTENTIAL 333.23 24.80 8.04 1% DECREASE: ECONOMIC POTENTIAL 308.43 0.00 0.00 2.5% INCREASE: ECONOMIC POTENTIAL 346.07 37.64 12.2 2.5% DECREASE: ECONOMIC POTENTIAL 246.43 -62.00 -20.1 5% INCREASE: ECONOMIC POTENTIAL 357.93 49.50 16.05 5% DECREASE: ECONOMIC POTENTIAL 199.90 -108.53 -35.19 10% INCREASE: ECONOMIC POTENTIAL 368.19 59.76 19.38 10% DECREASE: ECONOMIC POTENTIAL 126.82 -181.61 -58.88 69 TABLE 4-4: ILLINOIS POWER CO. SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - ELECTRICITY PRICE MW PERCENT W CHANGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 1% INCREASE: ECONOMIC POTENTIAL 96.06 1% DECREASE: ECONOMIC POTENTIAL 96.06 2.5% INCREASE: ECONOMIC POTENTIAL 101.06 2.5% DECREASE: ECONOMIC POTENTIAL 87.22 5% INCREASE: ECONOMIC POTENTIAL 121.33 5% DECREASE: ECONOMIC POTENTIAL 87.22 10% INCREASE: ECONOMIC POTENTIAL 131.19 10% DECREASE: ECONOMIC POTENTIAL 44.34 0.00 0.000 0.00 0.000 5.00 5.21 -8.84 -9.20 25.27 26.31 -8.84 -9.2 35.13 36.57 -51.72 -53.84 70 Fuel Prices The past decade of volatile swings in fuel prices undercuts our confidence in establishes that fuel price projections. Given that fuel costs are a major cost component of the cogeneration investment, this uncertainty could translate into uneconomical cogeneration investments. In attempt to determine just how sensitive the economics of cogeneration are to changes in fuel prices, seven alternative price projections are developed. Using the same approach used to develop the range of projections for electricity prices, the seven escalation rate scenarios include a 1% increase, a 1% decrease, a 2.5% increase, a 5% increase, a 5% decrease, a 10% increase and a 10% decrease. The results of the fuel price sensitivity along with the base results are provided in summary form in Tables 4-6 and 4-7 for the Commonwealth Edison and Illinois Power service territories respectively, and again highlight the differences in cogeneration economics between the two service areas. The results suggest that changes in the rate of escalation for fuel prices do not have a significant impact on the economic cogeneration potential until the 10% level. For firms in the Commonwealth Edison Co. service territory a 10% increase in the rate of escalation results in a 20% decrease in the economic cogeneration potential, and for firms in Illinois Power service territory a 71 10% increase results in a 9% decrease. A 10% decrease, on the other hand, does not have as much of an impact on the economic potential. For instance, for Commonwealth Edison Co. and Illinois Power a 10% decrease in the r^te of escalation in fuel prices increases economic potential for cogeneration by 12% and 5% respectively. The results also indicate that while an increase in the rate of fuel price escalation does not appear to have an impact on the post- tax payback period of cogeneration investments, there are significant negative effects on the internal rates of return generated by the tenth and twentieth year. This could lead to a situation where if by the tenth year a cogeneration investment becomes unattractive and the firm has already recouped its investment cost it may decide to switch back to the local utility for its electricity needs. This of course would compound the already difficult task of utility planners. 72 TABLE 4-6: COMMONWEALTH EDISON CO. RESULTS OF SENSITIVITY ANALYSIS - FUEL PRICES MW MW CHANGE PERCENT CHANGE BASE: ECONOMIC POTENTIAL TOTAL POTENTIAL 308.43 399.08 1% INCREASE: ECONOMIC POTENTIAL 308.43 0.00 0.0000 1% DECREASE: ECONOMIC POTENTIAL 308.43 0.00 0.0000 2.5% INCREASE: ECONOMIC POTENTIAL 308.43 0.00 0.0000 2.5% DECREASE: ECONOMIC POTENTIAL 318.43 10.00 3.2 5% INCREASE: ECONOMIC POTENTIAL 308.43 0.00 0.0000 5% DECREASE: ECONOMIC POTENTIAL 328.23 19.80 6.4 10% INCREASE: ECONOMIC POTENTIAL 246.43 -62.00 -20 10% DECREASE: ECONOMIC POTENTIAL 346.07 37.64 12.2 73 TABLE 4-7: ILLINOIS POWER RESULTS UF SENSITIVITY ANALYSIS - FUEL PRICES MW PERCENT MW CHANGE NGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 1% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 U DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 2.5% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 2.5% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 5% INCREASE: ECONOMIC POTENTIAL 87.22 TOTAL POTENTIAL 139.99 5% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 10% INCREASE: ECONOMIC POTENTIAL 87.22 TOTAL POTENTIAL 139.99 10% DECREASE: ECONOMIC POTENTIAL 101.06 TOTAL POTENTIAL 139.99 0.00 0.0000 0.00 0.0000 0.00 0.0000 0.00 0.0000 -8.84 -9.2 0.00 0.0000 -8.84 -9.2 5.00 5.2 74 Standby Power Ra tes Recently, there has been increased concern over discriminatory standby/ maintenance power rates. Firms considering cogeneration charge thai some utilities may attempt to discourage the development of cogeneration by increasing standby power rates above justifiable on equitable levels. 2 in an attempt to determine the extent to which standby power rates influence the economics of cogeneration investments six scenarios are developed and analyzed. These include a 1% increase, a 1% decrease, a 2% increase, a 5% increase and a 10% increase in standby power charges. The results generated for Commonwealth Edison service territory and Illinois Power service territory are presented in Tables 4-8 and 4-9. Of particular interest is the difference between Commonwealth Edison service territory and Illinois Power service territory sensitivities to changes in the rate of potential in Illinois Power's service territory is not affected by increases or decreases in the standby power rate, whereas the economic cogeneration potential in Commonwealth Edison service territory appears to be quite sensitive to increases and decreases, especially at the 10% level. A 10% increase in the rate of escalation for standby power rates decreases economic cogeneration potential by 20%. 2 A. E. Staley Manufacturing Co. vs. Illinois Power Docket 86-0038. 75 The differences between economic cogeneration potential is Commonwealth Edison service territory and Illinois Power service territory to changes in standby rates appears to be a result of the differences between their current standby rate structures. Recall from an earlier discussion that the standby rate structure used in the model for Illinois Power is similar to its industrial rate structure, and is considerably higher than Commonwealth Edison's which is not. It is interesting to note that when Commonwealth Edison's present standby power rate structure is replaced with a hypothetical rate similar to Illinois Power, economic cogeneration potential drops to zero. 76 TABLE 4-8: COMMONWEALTH EDISON SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - STANDBY POWER RATES MW PERCENT MW CHANGE CHANGE BASE: ECONOMIC POTENTIAL 308.43 TOTAL POTENTIAL 399.08 1% INCREASE: ECONOMIC POTENTIAL 308.43 1% DECREASE: ECONOMIC POTENTIAL 308.43 2.5% INCREASE: ECONOMIC POTENTIAL 308.43 2.5% DECREASE: ECONOMIC POTENTIAL 318.43 5% INCREASE: ECONOMIC POTENTIAL 308.43 5% DECREASE: ECONOMIC POTENTIAL 328.43 10% INCREASE: ECONOMIC POTENTIAL 246.43 10% DECREASE: ECONOMIC POTENTIAL 342.07 0.00 0.0000 0.00 0.0000 0.00 0.0000 10.00 3.24 0.00 0.0000 20.00 6.48 -62.00 -20.10 33.64 10.91 77 TABLE 4-9: ILLINOIS POWER SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - STANDBY POWER RATES ■1W MW CHANGE CENT CHANGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 1% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 1% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 2.5% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 2.5% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 399.08 5% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 5% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 10% INCREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 10% DECREASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 78 Re] iabil ity The reliability of the cogeneration system is a critical determinant of the systems ' s cost. A high rate, say 95%, assumes relatively consistent operation of the system. A reliability rate below 95%, however, assumes more frequent downtimes and therefore, more power purchased from the utility. Estimating future reliability rates is difficult for two reasons. First, equipment manufacturers provided estimates ranging from 85% to 98% and second, reliability is dependent upon adequate maintenance of the system. Again, in an attempt to determine the impacts of alternative reliabilities on the economics of cogeneration, three scenarios were developed to analyze this sensitivity. These include a 98% reliability, a 90% reliability and a 85% reliability. The results from varying the reliability rates are provided in Table 4-10 and 4-11 for Commonwealth Edison service territory and Illinois Power service territory respectively. The economic potential for cogeneration in Commonwealth Edison's service territory appears to be more influenced by changes in the reliability rate than Illinois Power. For instance, a decrease in reliability from 95% to 85% decreases the economic potential in Commonwealth Edison service territory by 35%, whereas for Illinois Power service territory the decrease is 9%. Similarly, an increase in reliability to 98% increases economic potential by 11% in Commonwealth Edison service territory and only 5% in Illinois Power service territory. 79 TABLE 4-10: COMMONWEALTH EDISON CO. SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - RELIABILITY MW ^EP' IW :JGE BASE: ECONOMIC POTENTIAL 308.43 TOTAL POTENTIAL 399.08 85% RELIABILITY ECONOMIC POTENTIAL 199.90 90% RELIABILITY ECONOMIC POTENTIAL 246.43 98% RELIABILITY ECONOMIC POTENTIAL 342.07 108.53 -35.19 -62.00 -20.1 33.64 10.91 80 TABLE 4-11: ILLINOIS POWER SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - RELIABILITY 1W PERCENT MVI CHANGE CHANGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 85% RELIABILITY ECONOMIC POTENTIAL 87.22 90% RELIABILITY ECONOMIC POTENTIAL 87.22 98% RELIABILITY ECONOMIC POTENTIAL 101.06 -8.84 -9.2 -8.84 -9.2 5.00 5.2 81 - Financing - In many situations, alternative financing arrangements can r ,igni ffcant enhance the economics of cogeneration projects by providing a means to allocate risk, return an investment, and required capital investment. A number of alternative methods of financing exist including ordinary sales, sales with borrowed financing, leases and joint ventures. Because it is not possible to accurately predict how firms may finance their investments, three scenarios were developed to determine the effects of debt financing on the economics of the potential cogeneration investments. These included 20% debt financing, 50% financed and 80% debt-financing. In general, the results suggest that marginal cogeneration projects (those over 7 years) fare worse under such financing arrangements, while projects which were economical (4 years or less) as well as those which were close to being economic (5-6 year payback) under an ordinary sale transaction perform substantially better in terms of paybacks under financing arrangements. The results generated for Commonwealth Edison service territory and Illinois Power service territory under alternative financing methods are presented in Tables 4-12 and 4-13. Note that the economics of cogeneration for both Commonwealth Edison service territory and Illinois Power service territory are enhanced significantly under debt financing arrangements. 82 While these results appear intuitive, (i.e., the less you have to pay in capital, the larger will be the return), no sensitivity analysis is attempted using alternative interest rates. Recall the interest rate used in the model is only 10%, a relatively low rate. Of more interest to note, is that the 1.1 MW simple cycle cogeneration configuration is still not economic with even 80% debt financing. 83 TABLE 4-12: COMMONWEALTH EDISON CO. SERVICE TERRITORY RESULTS OF SENSITIVITY ANLAYSIS - DEBT FINANCING MW CENT MW CHANGE - 1GE BASE: ECONOMIC POTENTIAL 308.43 TOTAL POTENTIAL 399.08 20% DEBT ECONOMIC POTENTIAL 345.46 50% DEBT ECONOMIC POTENTIAL 368.19 80% DEBT ECONOMIC POTENTIAL 395.78 37.03 12.0 59.76 19.4 87.35 28.3 84 TABLE 4-13: ILLINOIS POWER SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - DEBT FINANCING MW PERCENT CHANGE CHANGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 20% DEBT ECONOMIC POTENTIAL 101.06 TOTAL POTENTIAL 139.99 50% DEBT ECONOMIC POTENTIAL 131.19 TOTAL POTENTIAL 139.99 80% DEBT ECONOMIC POTENTIAL 131.19 TOTAL POTENTIAL 139.99 5.00 5.0 35.13 37.00 35.13 37.00 85 & M Costs Another parameter which potentially could have an impact on the economic: A a coyeneration investment is the operation and maintenance cost. These costs depend largely upon whether the proper engineering skills are utilized in the operations of the equipment. The model assumes a 5% escalation rate over the twenty-year period. However, other possibilities do exist. In attempts to demonstrate the impacts of varying & M costs three other scenarios were developed, including a 3%, a 1% and a 10% rate of escalation. The results which appear on Table 4-14 and 4-15 suggest that economic cogeneration potential is not affected by small increases or decreases in & M costs. 1 1 IRR and NPV increase by less than 1%. 86 TABLE 4-14: COMMONWEALTH EDISON CO. SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - & M ESCALATION COSTS MW MW CHANGE BASE: ECONOMIC POTENTIAL 308.43 TOTAL POTENTIAL 399.08 3% & M COSTS ECONOMIC POTENTIAL 308.43 7% & M COSTS ECONOMIC POTENTIAL 308.43 10% & M COSTS ECONOMIC POTENTIAL 308.43 0.00 0.00 0.00 87 TABLE 4-15: ILLINOIS POWER SERVICE TERRITORY RESULTS OF SENSITIVITY ANALYSIS - & M ESCALATION COSTS IW MW ,HANGE BASE: ECONOMIC POTENTIAL 96.06 TOTAL POTENTIAL 139.99 3% & M COSTS ECONOMIC POTENTIAL 96.06 7% & M COSTS ECONOMIC POTENTIAL 96.06 10% & M COSTS ECONOMIC POTENTIAL 96.06 0.00 0.00 0.00 88 Chapter 5 - THE ECONOMIC POTENTIAL FOR COGENERATION Thus far, the study has analyzed the economic potential for cogeneration for five investor-owned electric utilities in Illinois for the period 1987 to 2007 by employing a cost-benefit model to calculate the post tax payback period, net present value and internal rate of return for each plant in the sample of industrial firms collected in the Department's Phase I study. As defined throughout the study economic potential refers to those cogeneration investments assumed to be made in 1987 which achieved a post tax payback period of four years or less. The results generated by the model suggest that the Central Illinois Public Service service territory, Central Illinois Light Co. service territory and Union Electric Co. service territory do not have the economic characteristics necessary to support the development of economic industrial cogeneration or self-generation. Further, the results indicate that the Commonwealth Edison service territory and Illinois Power service territory have potential for the development of economic cogeneration. In particular, the results show that Commonwealth Edison Co. has between 170.0 and 308 MW of economic cogeneration potential and Illinois Power Co. has between 44 and 96 MW. During the development of model's inputs, it was observed that some of the projections of certain variables were subject to a great amount of uncertainty. In this case, the amount of projected economic cogeneration may be subject to change as well. In order to determine whether changes in 89 certain variables in the future would have an impact on economic cogeneration potential, sensitivity analysis was performed over six variaoles. The results of the sensitivity analysis offer some insight into the development of cogeneration in Illinois. These results suggest that the amount of cogeneration or self-generation actually developed in Illinois will depend on the behavior of several key variables, some of which are very unpredictable, and others of which fall under the direct control of state policy makers. The results of the sensitivity analysis also point to some interesting issues related to the development of cogeneration and the electric utility industry. In reviewing these issues, it is the purpose to suggest that they should be given consideration in the development of a cogeneration policy for the state. 1. The amount of economic cogeneration potential depends to a great extent on utility service territory-specific conditions. For instance, the Union Electric Co. service territory, Central Illinois Public Service Co. service territory, and Central Illinois Light Co. service territory have little or no economic potential, while Commonwealth Edison service territory and Illinois Power service territory have some economic potential. Upon further analysis, it was determined that a 35 to 45 percent increase in electricity prices would be necessary for cogeneration to become feasible for industries served by Union Electric Co., Central Illinois Public Service Co., and Central Illinois Light Co. 90 The differences in economic cogeneration potential between utility service territories are a result of existing rate structures, capacity additions, future capacity plans, and the local industrial mix. These differences resulted in unique responses to variable changes during the sensitivity analysis. This is illustrated by the different percentage increases and decreases in the amount of economic cogeneration potential in Commonwealth Edison's and Illinois Power's service territories resulting from alternative electricity price escalators, reliability rates, fuel prices, and standby power rates. These differences are important to identify and understand because of their implications for state regulation of the electric utility industry and its relationship to cogeneration. Further, the state's role in promoting the economic development of cogeneration requires an understanding of what constitutes "economic" as well as the variables which influence its development in each of the electric utility service territories. Thus, the uniqueness of each electric utility service territory suggests that cogeneration policies should be made flexible enough to accommodate the different circumstances in different areas. 91 2. The actual amount of cogeneration development is influenced by other variables not included in the model, e.g., industry attitudes toward power generation, environmental regulations, existing boiler age, and available avoided cost payments . These other factors are also important considerations in the decision of whether cogeneration is an economic investment. In fact, because these factors are not considered in this study, the results of economic cogeneration potential should be interpreted as illustrative. While these impacts are not considered directly in the model, an analysis of the initial survey comments contained in the Department's Phase I study is useful for understanding more about their possible implications on the development of economic cogeneration. The Phase I survey contained questions related to environmental concerns, industry attitudes and existing boiler age. For instance, the survey asked respondents if they have seriously considered cogeneration. If the respondent answered no, respondents were then asked why the idea of cogeneration was rejected. The questionnaire provided eight possible responses. These responses included: 1. lack of capital ; 2. low return on investment; 92 concern about maintenance requirements; concern about skill requirements possibility of utility resistance; power generation is not our business; environmental constraints; and concern with being regulated by the Illinois Commerce Commission. Of most importance for those firms with economic potential for cogeneration are responses 6, and 7. This information is useful when analyzing the results estimated by the model. For example, it is not likely that a firm with economic potential for cogeneration will invest in cogeneration if the firm is located in a non-attainment area. It is also unlikely that a firm will invest in cogeneration, even if it is economic, if the firm does not want to go in the power business. For the Commonwealth Edison service territory, of the one-hundred and five responses to the survey three firms with economic responded tht they were not interested in power generation, and four firms with economic potential responded noted that they rejected cogeneration for environmental reasons. Similarly, for Illinois Power service territory of the twenty-eight responses only two firms with economic potential answered positively to Question 6. This is also true for the responses to Question 7. 93 The survey also contains information on the age of the responding firms' existing boiler system. Of particular interest is the boiler age firms with economic potential f or cogeneration, because it is not like 1 / that a firm will invest in cogeneration if it has a relatively new boiler system. New boiler systems are defined as less than fifteen years old to reflect whether the existing system is depreciated. The survey responses for Commonwealth Edison service territory show that five of the firms with economic potential for cogeneration have boilers which are less than fifteen years old. For Illinois Power service territory only two of the firms with economic potential have existing boilers of less than fifteen years. The other factor which influences the economic potential f° r cogeneration not addressed by this study is the avoided costs payments available to cogenerated power. While avoided costs have not been included in this study, it is highly likely given experience in other states, (e.g., California) that avoided costs payments have a large impact on the development of cogeneration. It would be useful therefore, to analyze the specific implications from avoided cost payments in Illinois. While avoided costs are relatively low today 94 and perhaps would not make a large impact on the development of cogeneration, in the future as capacity supplies begin to tighten and avoided cost payments rise, their implications may be significant. Therefore, to avoid unexpected problems in the future, avoided costs and their influence on economic cogeneration potential should be given further study. The model developed for this study would be useful for such an analysis. As mentioned earlier, a variable for avoided cost payments is included in the model, but it was intentionally "turned-off" given the assumption that current rates were too low to have an effect. In order to focus specifically on the implications of avoided costs, necessary changes would need to be made to the technical matching of firms to cogeneration equipment. Specifically, each firm's cogeneration configuration would have to be altered to reflect the power produced for the firm's purposes, and the power sold to the utility. Obviously a number of possible scenarios would exist and sensitivity analysis will also need to be conducted. 3. The price of electricity appears to be a driving factor in determining the economic potential for cogeneration . The results of the sensitivity analysis on the electricity price escalator for Commonwealth Edison service territory and Illinois Power service territory indicate that the economic potential for cogeneration is highly sensitive to changes in the electricity price escalator. For 95 instance, even a 1 percent increase in the escalator in the Commonwealth Edison service territory produced an additional 24 MW of economic cogeneration potential. On the other side, however, a 11 decrease had no effect, but a 10% decrease in the escalator reduced tne amount of economic potential by 58 percent or 182 MW. Similar results are shown for Illinois Power service territory for a 10 percent decrease. This sensitivity is important to understand because state regulation does have some control over the price of electricity. Further, because state policy presumably would wish to encourage only the development of "economic" cogeneration, price increases which encourage cogeneration may actually contribute to what has been termed "uneconomic bypass." 4. The projected benefits realized from a cogeneration investment are dependent upon future input fuel prices . While at first glance, increases by as much as 10 percent in the fuel price escalator appear to have only marginal effects on the economic potential for cogeneration, this is not the case. According to the model results, a 5 and 10 percent increase only decreases the amount of economic cogeneration by 10 percent for the Commonwealth Edison service territory and 8 percent for Illinois Power. Because the study's definition of "economics" is based on a payback period, no consideration is given to the returns of a cogeneration project after 96 the initial payback is realized. However, as the input fuel price escalator increases the actual returns for cogeneration using an internal rate of return and net present value, are decreasing. Depending on the exact price increase, a firm which invested in cogeneration may not realize its required rate of return, and may also be forced to look back to the electric utility for power service. 5. Regulatory policy with respect to standby or replacement power rates may have a large impact on the economic potential for cogeneration . Specifically, ICC docket 86-0038 is interesting, because it is the state's first action which would affect the structure of the standby power rates charged to a cogeneration facility. The results of the proceeding will, therefore, be of interest to other utilities and potential cogenerators. As demonstrated in the sensitivity analysis, the impacts of the standby power rates are important to the development of cogeneration. If for example, Commonwealth Edison were to adopt a standby power rate structure similar to that proposed by Illinois Power service territory in the aforementioned docket, cogeneration economics would likely be severely impacted in that region. 97 6. Debt financing is an important element in the development of cogeneration . The sensitivity analysis demonstrated that using debt to finance a cogeneration investment increases the economic potential for cogeneration as well as the returns from a cogeneration investment. Whether or not firms would use third party financing or debt to finance a project however, is unknown. Nonetheless, consideration should be given to the amount of economic cogeneration potential which does exist under alternative financing schemes because the model's base estimate reflects ordinary sales and other financial alternatives are likely. 7. The actual benefit realized by the cogeneration investment is dependent upon the reliability of the cogeneration system . As demonstrated in the sensitivity analysis, if reliability is 90% or below, the benefits from cogeneration decrease, and likewise, if reliability is above 95% the benefits increase. The actual achieved reliability is also important because of its direct effect on the electric utility. If, for example, a cogeneration system achieves 85 percent reliability, it will require supplemental or back-up power from the servicing electric utility. If not appropriately planned for, the additional expenditure for backup power could substantially increase the costs of the cogeneration investment as well as cause reliability difficulties 98 for the utility. While this may not be a problem when excess capacity supplies exist, it may become troublesome if supplies tighten in the future, or if the utility is purchasing the cogenerated power from the firm. 99 100 APPENDIX I ) Documentation of the sources used to costs and installation costs. compute cogeneratlon equipment Costs were based on the following cogeneration systems Simple Cycle Gas Turbines: Kawasaki Solar Solar GE Allison Solar Sulzer Sulzer GE GE GSC-4000 Centaur H4 LM500 571 Mars Type 7 Type 10 LM2500 MS6001 Combined Cycle Gas Turbines GE Al 1 i son GE GE LM500 571 LM2500 MS6001 Reciprocating Gas Engines Waukesha Superior Superior Waukesha Superior Superior Cooper Cooper Cooper Cooper Cooper Cooper Diesel Engines Caterpillar Caterpillar Caterpillar Caterpillar Cooper Cooper Cooper Cooper Cooper Cooper GSI9500 12GTLB 12SGTB GS19500 16GTLB 16SGTB KSV-12 LSVB-12 KSV-16 LSVB-16 KSV-20 LSVB-20 3512 3516 3516 3516 KSV-12-T LSVB-12-T KSV-16-T LSVB-16-T KSV-20-T LSVB-20-T 101 Fluidized Bed Coal -Fired Turbines Transam Transam Transam Transam Transam Transam Delaval Delaval Del aval Del aval Delaval Delaval 5237 ., 6690 KW 7550 KW 1284!, ., 31480 KW 78250 KW II) The contact persons providing the information were: Contact Person Company Representative For Lee Kosla Int'l Power Technology John Ratteree Sulzer Turbo Sulzer, Allison Systems GE Mark McElyea Equipment Assoc. Cooper-Superior EACO Energy Systems Michael O'Hegen Combustion Power — Cal Mock Babcock & Wilcox Tom Scully Keeler/Dorr-01 iver Perry Shuckner Herman VanLokeren Floyd Welch & Pyropower Corp, Assoc. Matt Wristbridge General Electric — Ross Damroe Tom Kozlowsky Solar Turbines — Bob Bangs Caterpillar Location/Phone* Palo Alto 858-1611 San Lorenzo 276-0863 Emmory vi 1 1 e 652-9040 Menlo Park 324-4744 San Francisco (800)354-4400 San Mateo 349-0077 San Francisco 546-4428 San Francisco 397-6277 San Leandro 895-8400 *Area Code (415) unless otherwise indicated 102 Contact Person Company Representative For Location/Phone* Harry Linssen American MAN MAN Technologies San Francisco Wolfgang Knoerle Corp. 391-2935 Jeff Bergqren Transamerica — San Francisco 577-7528 Stan 3anza San Francisco 577-7633 George Henning Los Angeles (213)926-4515 Orris Anson Williams & Lane Allison Benicia Kawasaki (707)746-0600 Generac Waukesha GE Diesel Detroit Diesel *Area Code (415) unless otherwise indicated III) Documentation of the sources used to compare economic variables used in the moaeTT 1. DRI, Energy Review . Autumn 1986, Vol. 10, No. 3. 2. DOE, Cogeneration Handbook Series (DOE/INBB-0057) . February 1984, Prepared Dy tne u.b. Department of Energy. 3. DOE, "Monthly Energy Review" July 1986, Energy Information Administration, Washington, D.C. 4. Survey of Current Business . United States Department of Commerce/ bureau or tconomic Analysis. 5. Institute of Gas Technology, "Energy Statistics" Vol. 14 No. 3, Third Quarter, 1986, Table 53. 6. Illinois Department of Energy and Natural Resources Coal Section. 103 APPENDIX II A NOTE ON THE ECONOMICS OF COGENERATION IN THE COMMONWEALTH EDISON SERVICE TERRITORY The results of the economic analyses presented above relied on certain assumptions regarding future electricity prices in each of the state's electric utility service territories. With the respect to the Commonwealth Edison service territory, the controlling price assumption was that a proposed settlement agreement designed to hold average price increases to roughly ten percent over a five year period would be accepted by the Illinois Commerce Commission. Following completion of this report, the ICC issued a decision rejecting the settlement agreement and the five year price freeze. Following that action, the Company has asked for a rate increase on the order of 28 percent. A decision on the request is months away, and there remains substantial uncertainty over future prices in that service area. In an effort to gauge the effect of a sharp price increase on cogeneration potential in the Edison service territory, one additional sensitivity case has been examined, that of the 28 percent increase occurring over a five year period. The results of the analysis show that the much steeper increase would result in roughly 50 additional megawatts of economic cogeneration (353 MW) . 105 PLANT POWER TO- NUMBER HEAT RATI HEAT RATE 721 142.85 15,000.0 PLANT PAYBACK NUMBER YEARS IRR 20 721 6 15.59% TOTAL $/KW 1,121 NET PRESENT VALUE 20 •359,339 MAINT. $/KW 0.0070 IRR 10 13.45% MW PROOUCEO 2.20 NET PRESENT VALUE 19 -487,877 SHIFTS/ OAY MW PROOUDED DAYS/ WEEK WEEK/ YEAR 52 2.20 Illinois Department of Energy and Natural Resources degeneration Feasibility Study EQUIPMENT EVALUATION Allison 5CC0 kW "ws Turbine Cogener Commonweal th Edison 'Megawatt Rating 2.200 *Bo tier Efficiency 70. C% *Basic Cogener^.t or • "Parasitic Power 5.00 "End of Boiler Useful Life, yrs 20 •Pol lutlon Contr ol 4 Cther -.pecial • *H<>at Rate. Stu/kWh 15,000 * D eplacement Cap' tl Cost/MMBtu $0.00 •Pollution Control 4 Cther ^ceciai . ■ *Power:Heat kW/MMBtu/hr 142.85 *St raight Line Deprec Schedule 0.0500 •Installation Co sts S/kW Heat Load, MMBtu/hr 15.40 •Total Installation Costs $/kW *Sh ifts per Day 3 1990 Total Equipment Costs $1,916,200 •Days per Week 7 *Basic Cogenerat or Equipment Cost $/kW Total Installed Cost $2,465,200 *Weeks per Year 52 •Pollution Control 4 Other Special Eqmt $/kW Initial Investment $2,466,200 *Pe ik Hours per Year 3,289 •Pollution Control 4 Other Special Eqmt $/kWh ♦Const Pymnts(l) Prncpl (0) Non -Peak Hours per Year 5,447 •Installation Cost: $/kW Constant Payment Amount $0 Tot il Hours per Year 8,736 Year: 1987 1988 1989 1990 1991 1992 Fuel Cost per MMBtu $2.89 $2.72 $2.59 $2.90 $3.25 $3.64 Fuel Price Escalator 0.942 0.952 1.120 1.120 1.120 Fuel Price Scenario Escalator 0.00% 0.942 0.952 1.120 1.120 1.120 Loan Amount $0 $0 $0 $0 $0 Principal Atnt: Constant Payments $0 $0 $0 $0 $0 Principal Amt: Constant Principal Reduct ion $0.00 $0.00 $0.00 $0.00 $0.00 Depreciation Schedule 0.0500 0.0750 0.0900 0.0800 0.0700 0.0700 Thermal Sales Price, $/MMBtu $4.13 $3.89 $3.70 $4.15 $4.64 $5.20 Electric Sales Prices: Industrial Rates: kW/Month $11.40 $13.57 $14.11 $14.67 $15.26 $15.37 Industrial Rates: Monthly Charge $484.60 $576.67 $599.74 $623.73 $648.68 $674.63 Industrial Rates: S/kWh, Peak $0.05811 0.06915 0.07192 0.07479 0.07779 0.08090 Industrial Rates: $/kWh, Non-Peak $0.02756 0.03280 0.03411 0.03547 0.03689 0.03837 Avoided Cost Rates: $/kW/Month $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Avoided Cost Rates: $/kWh, Peak $0.04060 $0.03846 $0.03419 $0.03206 $0.03206 $0.03406 Avoided Cost Rates: $/kWh, Non-Peak $0.03080 $0.02918 $0.02594 $0.02432 $0.02432 $0.02584 Standby Rates: $/kW/Month $5.69 $6.77 $7.04 $7.32 $7.62 $7.92 Standby Rates: Monthly Charge $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 Standby Rates: $/kWh, Peak $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 Standby Rates: $/kWh, Non-Peak $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 Electric Price Escalators: for Industrial Rates, kW 4 Monthly 1.190 1.040 1.040 1.040 1.040 for Industrial Rates, kWh 1.190 1.040 1.040 1.040 1.040 Industrial Rate Escalator -scenarios 00% 1.190 1.040 1.040 1.040 1.040 for Avoided Costs, kW 0.00% 0.947 0.889 0.338 1.000 1.063 for Avoided Costs, kWh 0.947 0.889 0.938 1.000 1.063 for Standby Charges, kW 4 Monthly 1.190 1.040 1.040 1.040 1.040 for Standby Charges, kWh 1.190 1.040 1.040 1.040 1.040 Standby Charge Escalator -scenarios 0.00% 1.190 1.040 1.040 1.040 1.040 ==2==S3S=======>S>S3=S>33aa=3SS-3S=3==> •M tansinsanosx m<»»»au»i : = = = =. = = = = == = = = = = = Hinaaananns mmm ■ ■ill I*» = ==333*a..= 33 Thermal Sales $523,246 $493. 13C 5557,906 $624,854 $699,337 Displaced Industrial Rate Charges $1,256,247 $1,306,497 $1,358,757 $1,413,107 $1,469,632 Avoided Cost Credit $0 $0 $0 $0 $0 Backup Charges 5187.338 $195,351 $203,165 $211,292 $219,744 Total Electric Sales $1,068,409 $1,111,146 $1,155,592 $1,201,815 $1,249,888 Total Revenue $1,591,655 $1,609,276 $1,713,497 $1,826,670 $1,949,725 Fuel Costs $824,699 $705,113 $879,327 $984,846 $1,103,028 Maintenance Costs $134,534 $141,261 $148,324 $155,740 $163,527 Other Labor Costs $0 $0 $0 $0 $0 Other Operating Costs $0 $0 $0 $0 $0 Insurance and Taxes $73,986 $77,685 $81,570 $85,648 $89,930 Total Non-Fuel Operating Costs $208,520 $213,946 $229,394 $241,388 $253,458 Interest $0 $0 $0 $0 $0 Depreciation $123,310 $184,965 $221,958 $197,296 $172,634 $172,634 Salvage Value 20th year $0 $0 $0 $0 $0 Total Operating Costs $1,218,184 $1,226,018 $1,306,517 $1,398,869 $1,529,119 Pre Tax Income $373,471 $383,258 $406,981 $427,801 $420,605 Tax $126,980 $130,308 $138,373 $145,452 $143,006 Tax Credit $0 $0 $0 $0 $0 After Tax Gain $246,491 $252,950 $268,607 $282,349 $277,599 Net After Tax Gain $246,491 $252,950 $268,607 $282,349 $277,599 Depreciation $184,955 $221,958 $197,296 $172,634 $172,634 Principal Payment $0 $0 $0 $0 $0 Cash Flow ($2,342,890) $431,456 $474,908 $465,903 $454,983 $450,233 Cumulative Cash Flow ($2,342,890) ($1,911,434) ($1,436,526) ($970,623) ($515,640) ($65,407) Internal Rate of Return 20.00? Error 30 -136.75% -22.42% -9.20% -0.93% Net Present Value ($1,983,343) ($1,653,546) ($1,383,926) ($1,164,509) ($983,571) Payback Period, Years 6 Discounted Payback Period >20 106 Basel inp Economic Assumptions Commonwealth Ed i s on APPENDIX III $371.00 •Mair tenance Cos ts S/kWh $0.0070 1 ♦Interest Rate 10 .00%j $0.00 *MC ' i Increase b y v 'r of Const % 5 . 00% *ierm of Loan, y rs I SO.GC T 0lh< ir Laoor Cos ts $/kWh $0,000 ♦Years Oepreciat ion 150.00% . 00% 20.00% 95.00% $123,310 0.00% 0.00% 100.00% $250.00 *ALC Increase by Yr of Constant % 5 . 00% Decl ining Bal . % $1,121.00 'Additional Oper ating Costs $/kwh $0,000 ♦Oebt % of Total Cos t *AOC % Increase by Yr of Const % 5.00% ♦Required Rate of P' turn $1,021.00 ♦Insurance & Tax es % of Inst Cost 3 . 00% ♦Reliability % $0.00 ♦I&T % Increase by Yr of Const % 5.00% ♦Salvage value 5% of equipt cost $0.00 ♦Tax Rate on Net Income 34.00% ♦% Nameplate Sol d ? AC, Pk $0.00 ♦Tax Credits, % of Ttl Investment 0.00% ♦% Nameplate Sol d (? AC, NonPk ♦Tax Rate on El e c/Gas Purchases 5.08% ■ 1997 ♦Standby Power R equ red - 1993 1994 1995 1996 1998 1999 2000 $4.08 $4.57 $5.12 $5.73 $6.42 $7.19 $8.05 $9.02 1.120 1.120 $0 $0 $0.00 0.0600 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 1.120 $0 $0 $0 $0 $0 $0 $0 $0 $0.00 $0 $0.00 $0 $0.00 $0 $0.00 $0 $0.00 $0 $0.00 $0 $0.00 0.0600 0.0600 0.0600 0.0600 0.0600 0.0600 0.0600 $5.83 $6.52 $7.31 $8.18 $9.17 $10.27 $11.50 $12.88 $16.51 $17.17 $17.85 $18.57 $19.31 $20.08 $20.88 $21.72 $923.27 0.11071 0.05251 $0.00 $0.04267 $0.03237 $10.84 $0.00 $0.00000 $0.00000 $701.61 $729.68 $758.86 $789.22 $820.79 $853.62 $887.76 0.08413 0.08750 0.09100 0.09464 0.09842 0.10236 0. 10645 0.03990 0.04150 0.04316 0.04488 0.04668 0.04855 0.05049 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.03406 $0.03606 $0.04003 $0.04203 $0.04203 $0.04245 $0.04267 $0.02584 $0.02736 $0.03037 $0.03189 $0.03189 $0.03221 $0.03237 $8.24 $8.57 $8.91 $9.27 $9.64 $10.02 $10.42 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 '$0.00000 $0.00000 $0.00000 $0.00000 $0.00000" $0.00000 $0.00000 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.000 1.059 1.110 1.050 1.000 1.010 1.005 1.000 1.000 1.059 1.110 1.050 1.000 1.010 1.005 1.000 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1 . 040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 1.040 $783,817 $877,875 $983,220 $1,101,207 $1,233,352 $1,381,354 $1,547,116 $1,732,770 $1,528,417 $1,589,554 $1,653,136 $1,719,261 $1,788,032 $1,859,553 $1,933,935 $2,011,292 $0 $0 $0 $0 $0 $0 $0 $0 $228,534 $237,675 $247,182 $257,069 $267,352 $278,046 - $289,168 $300,735 $1,299,883 $1,351,879 $1,405,954 $1,462,192 $1,520,680 $1,581,507 $1,644,767 $1,710,558 $2,083,701 $2,229..754 $2,389,174 $2,563,399 $2,754,031 $2,962,861 $3,191,883 $3,443,328 $1,235,391 $1,383,623 $1,549,674 $1,735,635 $1,943,912 $2,177,181 $2,438,443 $2,731,056 $171,704 $180,289 $189,303 $198,769 $208,707 $219,142 $230,099 $241,604 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $94,427 $99,148 $104,106 $109,311 $114,777 $120,515 $126,541 $132,868 $266,131 $279,437 $293,409 $308,080 $323,484 $339,658 $356,641 $374,473 $0 $0 $0 $0 $0 $0 $C $0 $147,972 $147,972 $147,972 $147,972 $147,972 $147,972 $147,972 $147,972 $0 $0 $0 $0 $0 $0 $0 $0 $1,649,494 $1,811,047 $1,991,056 $2,191,687 $2,415,367 $2,664,811 $2,943,055 $3,253,500 $434,207 $418,707 $398,119 $371,712 $338,664 $298,050 $248,828 $189,828 $147,630 $142,360 $135,360 $126,382 $115,146 $101,337 $84,602 $64,541 $0 $0 $0 $0 $0 $0 $0 $0 $286,577 $276,347 $262,758 $245,330 $223,518 $196,713 $164,227 $125,286 $286,577 $276,347 $262, 758 $245,330 $223,518 $196,713 $164,227 $125,286 $147,972 $147,972 $147,972 $147,972 $147,972 $147,972 $147,9/2 $147,972 $0 $0 $0 $0 $0 $0 $0 $0 $434,549 $424,319 $410,730 $393,302 $371,490 $344,685 $312,199 $273,258 $369,142 $793,461 $1,204,191 $1,597,493 $1,968,983 $2,313,668 $2,625,866 $2,899,125 4.36?! 7.95'/ 10.44% 12.19% 13.45% 14.35' 14.99% 15.44% ($838,041) ($719,622) ($624,099) ($547,874) ($487,877) ($441,486 ($406,471) ($380,931) 107 30277 -1Q1 REPORT DOCUMENTATION PAGE 1. REPORT NO. " ILENR/RE-SP-87/15 4. Titi« .~j suMiti. COGENERATION MARKET ASSESSMENT PHASE II An Evaluation of the Economic Potential for regeneration in Illinois 7. Authorts) Deborah L. Fields 3. Raopi«nt'» Accession No. S. Report Oat* October, 1987 i. Performing Organization Rapt. No. 9. Par-forming Organisation Nama and Address 10. Proiect/Taak/Wortr. Unit No. Illinois Department of Energy & Natural Resources 325 W. Adams St. Springfield, IL 62704 11. ContreetCC) or Grent(G) No. (C> (G) 12. Sponsoring Organization Nama and Address 11. Typ« of Raport & Period Covered 14. IS. Supplementary Notti 16. Abstract (Limit: 200 wordt) The economic potential for cogeneration in Illinois was estimated using a cost-benefit mode'l developed in cooperation with QED Research, and a database of technical plant characteristics prepared by Synergic Resources Corporation in a separate study for the Department. Using the Technical data, cogeneration system characteristics and matches provided by QED, economic/financial assumptions and price projections for major utility service territories in Illinois, the economic potential for individual firms was estimated and then aggregated for each service territory. The sensitivity of these estimates was assessed by varying key parameters. Based on the limited sample of firms included in the study, total economic potential was estimated to be between 214 and 400 megawatts. The technology most likely to be used for industrial cogeneration was estimated to be a simple .cycle gas turbine. 17. Document Analysis a. Descriptors Electric Power Production, Electric Power Generational ectric Power Demand, Industrial Energy, Competition b. Identifiers/Open-Ended Ttrmt Cogeneration, Cost-Benefit Analysis, Self-Generation, Bypass c. COSATl Field/Group it. Ava.iabii.ty statement n restrictions on distribution. Available at IL Depository Libraries or from National Technical Information Services, Springfield, VA 2216 19. Security. Class (This Report) -|20. Security Class (This Page) 21. No. of Pages 107 22. Price Set ANSI-239.18) See Instructions on Reverse OPTIONAL FORM 272 (4-77) (Formerly NTIS-35) Department of Commerce