Chapter 5 Industrial, Commercial, and Rural Cogeneration Opportunities

Chapter 5

Industrial, Commercial, andRural Cogeneration Opportunities

Page

Industrial Cogeneration . . . . . . . . . . . . . . . . . . . 171Industrial Cogeneration Technologies and

Applications . . . . . . . . . . . . . . . . . . . . . . . . 171Potential for Industrial Cogeneration . . . . . . 178Market Penetration Estimates . . . . . . . . . . . . 184

Commercial Cogeneration . . . . . . . . . . . . . . . . 189Previous Studies of Commercial

Cogeneration. . . . . . . . . . . . . . . . . . . . . . . . 189Critical Assumptions and Limits of the

DELTA Model . . . . . . . . . . . . . . . . . . . . . . . 191Commercial Cogeneration Opportunities . . . 198

Rural Cogeneration . . . . . . . . . . . . . . . . . . . . . . 210Potential Applications . . . . . . . . . . . . . . . . . . 211Fuel Savings . . . . . . . . . . . . . . . . . . . . . . . . . . 213Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215

Chapter 5 References . . . . . . . . . . . . . . . . . . . . 216

Tables

Table No. Page

31.Fuel Utilization Characteristics of

3233

3435

Cogeneration Systems . . . . . . . . . . . . . . . . . 172Cogeneration Projects by Region . . . . . . . . 179Existing Industrial Cogeneration bySIC Code . . . . . . . . . . . . . . . . . . . . . . . . . . . 179Sample Industrial Electric Rates by State.. 182Early Estimates of the Potential forindustrial Cogeneration. . . . . . . . . . . . . . . . 185

36. Range of Utility Buyback Rates Analyzedby RPA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187

37. Typical Days Used in the DELTA Model . . 19238. Fuel Prices . . . . . . . . . . . . . . . . . . . . . . . . . . 19639. Technology Characteristics . . . . . . . . . . . . . 19740. Sample Utility Configurations . . . . . . . . . . . 19841. Description of Scenarios Used . . . . . . . . . . 19942. New Capacity installed for Coal-Limited

Scenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 20143. Capacity Factors for Baseload and

Cogeneration Plants . . . . . . . . . . . . . . . . . . 202

44,

45.

46.

47.

Page

Base-Case Standard Scenario Fuel Use,by Generation Type and Year . . . . . . . . . . 206Comparison of Fuel Use for Coal-LimitedScenarios . . . . . . . . . . . . . . . . . . . . . . . . . . . 209Distribution of Waste Heat From aSupercharged Diesel Engine . . . . . . . . . . . . 210Model Community Gasification/DieselElectric Generation Energy CostEstimate . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214

Figures

Figure No. Page

45.

46.

47.

48.

49.

50.

51.

52.

53.54.55.56.

57.58.

59.

60.

Potlatch Corp. –Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 173Celanese Chemical Co./SouthwesternPublic Service Co.—Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 173Gulf States Utility Co.-Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 174Union Carbide Corp.—Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 174Holly Sugar Corp. –Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 175Riverside Cement Co.–Schematic of theCogeneration System . . . . . . . . . . . . . . . . . 175Cogeneration Potential at CaliforniaState Facilities . . . . . . . . . . . . . . . . . . . . . . . 191Comparison of EIectric Demand forThree Types of Days.... . . . . . . . . . . . . . . 1931990 Heating Demands for Scenario 1 .. 1941990 Cooling Demands . . . . . . . . . . . . . . . 195Electrical Capacity Additions 1990-2000 . . 200Thermal Supply and Demand for WinterPeak Day . . . . . . . . . . . . . . . . . . . . . . . . . . . 203Electricity Supply for Winter Peak Day . . . 203Fuel Used in 1990 and 2000 forCoal-Limited Scenarios . . . . . . . . . . . . . . . . 208EthanoI Cogeneration With Diesel EngineWaste Heat Recovery . . . . . . . . . . . . . . . . . 212Anaerobic Digester Svstem. . . . . . . . . . . . . 215

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Chapter 5

Industrial, Commercial, andRural Cogeneration Opportunities

INDUSTRIAL COGENERATION

Large amounts of fuel are used to produce ther-mal energy for U.S. industries and this energyrepresents a potential for fuel savings throughcogeneration. Industrial cogeneration is firmlyestablished as an energy supply option in theUnited States, with a total installed capacity ofabout 9,000 to 15,000 megawatts (MW), or about3 percent of the total U.S. electricity generatingcapacity (1 2). Industrial cogeneration currentlysaves at least 0.5 Quad of fuel each year.

The onsite production of electricity in industry(not necessarily cogeneration) has declinedsteadily throughout the 20th century. This declinewas the result of a number of economic and in-stitutional considerations that made it more ad-vantageous for industries to buy electricity fromutilities than to generate it themselves. At thesame time, however, the technical potential forcogeneration (the number of industrial siteswhere the demand for thermal energy is sufficientto justify a cogeneration system) has been grow-ing, and today may be as high as 200 gigawatts(GW) of capacity (equal to about 33 percent oftotal U.S. electricity generating capacity; seebelow). But, just as economic and institutionalissues were responsible for the decline of onsitegeneration during the 20th century, these issues,rather than technical constraints, mean that themarket potential (the number of sites at whichinvestment in cogeneration will be sufficiently at-tractive) is much lower than the technical poten-tial–perhaps 40 to 100 GW by 2000.

Industrial cogeneration systems may use anyof the possible technology and fuel combinationsdescribed in chapter 4. These systems generallyare smaller than baseload utility powerplants, butstill vary considerably in size. Examples of pro-posed cogeneration units now under considera-tion illustrate this range: A 125-kW wood-firedunit being built in Pennsylvania to burn the scrapsfrom a furniture company plant; a 5.8-MW com-bustion turbine system being built to serve a box-

board company on the west coast; a 60-MW bio-mass- and coal-fired system proposed for a puIpand paper mill in northern Mississippi; and a140-MW coal-burning unit proposed by a majoroil company to serve a complex of refineries andchemical plants on the gulf coast of Louisiana.This section will describe the industrial cogenera-tion technologies and applications, discuss thecriteria for implementing an industrial cogenera-tion system, and review estimates of the marketpotential for industrial cogeneration.

Industrial Cogeneration Technologiesand Applications

The cogeneration systems in place today pri-marily use steam turbine technology in a toppingcycle. Steam is raised in a high-pressure boilerand then piped through a turbine to generateelectricity before heat is extracted for the in-dustrial process (see ch. 4). The thermal outputof the turbine generally ranges from less than 50to over 1,000 psig, which is appropriate for manytypes of industrial steam processes. The steam tur-bine topping cycle is extremely versatile, in thatit can use any fuel that can be burned in a boiler;oil, gas, coal, and biomass are routinely used. Butwhen the steam turbine technology is used forcogeneration, only 5 to 15 percent of the fuel isturned into electricity. Thus, these cogeneratorsusually are sized to fit an industry’s steam load,and they produce less electricity than other co-generation technologies.

The measure of the ability of cogeneration tech-nologies to produce electricity is the ratio of elec-trical output (measured in kWh) to steam output(measured in million Btu), or the electricity-to-steam (E/S) ratio. A steam turbine cogenerator willproduce 30 to 75 kWh/MMBtu, For some indus-tries, this is only enough electricity to satisfy on-site needs, but, in others a modest amount maybe available for export offsite as well. Higher E/S

171

172 . Industrial and Commercial Cogeneration

ratio technologies that have been proven in in-dustrial uses are combustion turbines, diesels,and combined cycles. The combustion turbinecan generate two to seven times as much elec-tricity with a given quantity of fuel as the steamturbine, and the diesel five to twenty times asmuch. Combined-cycle systems perform in arange between combustion turbines and diesels.Typical E/S ratios for these technologies are givenin table 31 (see also ch. 4). Shifts in future co-generation projects to these higher E/S systemswould increase the amount of electricity thatcould be provided to the grid, and would savemore fuel than with the use of lower E/S tech-nologies.

Fuel savings is one important advantage ofcogeneration. All of the proven cogenerationtechnologies use about 50 to 60 percent as muchfuel to generate a kilowatt-hour of electricity(beyond the fuel otherwise needed to produceprocess steam) as is required by a conventionalsteam generating station. Whereas a central sta-tion powerplant requires 10,000 to 11,000 Btu/kwh, the proven cogeneration systems requireonly about 4,500 to 7,500 Btu/kWh (see table 31).There is no particular fuel savings in the steamproduction part of the cogeneration process; rais-ing steam by cogeneration usually is allocated thesame amount of fuel as required by a conven-tional boiler. Therefore, overall fuel savings areroughly proportional to the total electricity pro-duction achievable with each technology.

However, while the higher E/S technologiesproduce more electricity and save more fuel thanthe standard steam turbines, their fuel versatili-ty is more limited. Higher E/S systems can only

Table 31.—Fuel Utilization Characteristics ofCogeneration Systems

Heat ratea Second law E/S ratio(Btu/kWh) efflciencyb (kWh/MhfBtu)

Steam turbine . . . . . . . . . 4,500-6,0(N) 0.40 (0.32) 30-75Combustion turbine . . . . 5,500-6,5fxl 0.47 (0.34) 140-225Combined cycle . . . . . . . 5,000-6,000 0.49 (0.35) 175-320Diesel . . . . . . . . . . . . . . . . 6,000-7,500 0.46 (0.35) 350-700

The fuel required to generate elactrklty, In excess of that required for processsteam production alone, assuming a boiler efficiency of 88 percent for processsteam production.

%he second law efficiency for separate process steam and central station elec-tricity generation Is shown In parentheses (see ch. 4).

SOURCE: Office of Technology Assessment from material in ch. 4.

use liquid or gaseous fuels of uniform composi-tion and high purity, or turbine parts or engineparts may be corroded or eroded. Although thereis some experimental work with coal and coal-derived fuels for use in high E/S cogenerationtechnologies, the only proven cogeneration tech-nology using coal today is the steam turbine.Some of the technologies under developmentthat could use coal in industrial applications arediscussed below.

Systems Design

The characteristics of presently employed sys-tems vary enormously. Rather than try to gener-alize the system configurations that might be usedin different industries, six examples of successfullyoperating cogeneration plants are described brief-ly below.

A pulp and paper industry cogenerationsystem at the Potlatch Corp. plant in Lewiston,Idaho, burns various woodwastes and the “blackliquor” from the first stage of the pulping opera-tion, plus natural gas. This plant began to cogen-erate in 1951, when the company installed a10-MW steam turbine, which was supplementedby another 10 MW of capacity in 1971. The co-generation system produces steam at both 170and 70 psig, plus 23 percent of the plant’s elec-trical needs. The system generates less than’ theelectric load needed onsite because of the ex-tremely low retail electricity rates and purchasepower rates in the region (see tables 19 and 34),but will be upgraded in the 1980’s with an addi-tional 30 MW of capacity, at a cost of $89 million(1980 dollars), to supply almost all the onsite de-mand. The system is extremely reliable, operating24 hours per day 360 days per year, giving a sys-tem availability of over 90 percent. Electrical ef-ficiency (fraction of fuel Btu converted to elec-tricity) is 64 percent, and the maintenance costis 3 to 4 milIs/kWh (29). A schematic of the co-generation system is shown in figure 45.

An example of a chemicai industry cogenera-tion system, that is sized to export electricity tothe grid, is the system installed by the CelaneseChemical Co. at its Pampa, Tex., plant in 1979.The system burns pulverized low-sulfur Wyomingcoal in two large high-pressure boilers, each

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 173

Figure 46.— Celanese Chemical Co./SouthwesternPublic Service Co.—Schematic of the

Cogeneration System

To feed water heating

Pulverized*

— *coal

SOURCE: Synergic Resources Corp., /rrdustr/a/ Cogenerator Case Stud/es(Palo Alto, Cahf : Electric Power Research Institute, EPRI EM.1531,1980).

refinery, as well as a chemical manufacturer thatproduces ethyl lead for increasing gasoline oc-tane. The system (Louisiana Station #l at BatonRouge, La.) was built by the Gulf States UtilityCo. in 193o and upgraded several times over thedecades to a present capacity of 129 MW of elec-tricity and 3.6 million lb/hr of steam. It has nowbeen- cogenerating successfully for almost half acentury with only one unscheduled outage (dur-ing an electrical storm in 1960) (29).

This cogeneration plant uses natural gas andrefinery waste gas as fuel for its boilers, whichproduce both 600 and 135 psig steam for sale bythe company to its industrial customers. The over-all efficiency of the system is 73 percent, and theindustrial customers consider the system extreme-ly reliable. Exxon, the refinery owner, has a 7-yearcontract for steam supply. The utility sells boththe electricity and steam from the station (saleof the steam is unregulated), and the industrialusers provide most of the fuel and pay the oper-ating costs (29). Figure 47 presents a diagram ofthe Gulf States system.

Due to natural gas price increases, LouisianaStation #1 may be phased out soon. Until 1979,Gulf States had long-term gas contracts for $0.30/MMBtu, and when these contracts expired theprice rose to $2.60/MMBtu. At the same time thattheir fuel prices were increasing, energy conser-vation by their industrial customers substantial-ly reduced the demand for steam, which now

174 ● Industrial and Commercial Cogeneration

Figure 47.—Gulf States Utility Co.—Schematic ofthe Cogeneration System

Natural gas, refinery gas

SOURCE: Synergic Resources Corp., Indusfrial Cogeneration Case Studies(Palo Alto, Callf Electrlc Power Research Institute, EPRI EM-1531,1980)

stands at one-half or two-thirds of the level thatprevailed 2 to 3 years ago, according to GulfStates (29).

Gulf States reports that it is not in a positionto raise the capital for a new system easily (themost recently added increment of capacity is now27 years old), so the present system may beretired and a new one built by Exxon. Exxon isplanning a 150- to 180-MW coal-fired cogener-ator nearby. The proposed new cogenerationplant would produce 6 million to 8 million lb/hrof process steam and potentially could supplymore industrial customers than the existingsystem.

Another cogeneration system associated witha chemical company in the southern part of thecountry is the Texas City, Tex., plant of the UnionCarbide Corp. The Texas City cogeneration sys-tem is owned by the chemical company, whichproduces a wide variety of products from alcoholsto plastics, and uses natural gas for fuel. Thesystem is a complex network of both steam andcombustion turbines that was started in 1941. Itproduces up to 70 MW of electricity, but histor-ically has not sold any for use offsite due toregulatory restrictions, The peak demand for theplant is 40 MW. Union Carbide reports that it issatisfied with its return on investment, but thatrising natural gas prices make future cogenera-tion questionable, especially with combustion

turbines, Union Carbide is now concentrating onconservation through heat recovery applicationsand waste heat utilization, rather than cogenera-tion (29). This system is sketched in figure 48.

The operating patterns of food plants are con-siderably different from those of chemical or pulpplants. An example of a food plant that only op-erates 4 months per year is the Holly Sugar Corp.plant at Brawley, Cal if. The plant’s 7.5-MW steamturbine system provides all the steam and elec-tricity needed onsite. The company reports thatit installed the cogeneration system for economicsand reliability—there had been interruptions inpower when it drew electricity from the localgrid. Now the system is isolated from the grid andoperates to provide the electrical load requiredfor the plant. Holly Sugar reports that reliabilityis very high (99,9 percent) for the 120 days peryear that the plant operates. The reported annualcapacity factor is expectedly low for such a plantschedule—25 percent. This may be too low foreconomic cogeneration under most circum-stances, but the alternative is charges for utility-generated power during the summer months,which would be seasonably high—a factor thatimproves cogeneration economics (29). A sche-matic for the system is shown in figure 49.

Figure 48.—Union Carbide Corp.—Schematicof the Cogeneration System

Natural gas

1 J1,000 psig/600°F

oI

u I

SOURCE: Synergic Resources Corp., Industrial Cogeneration Case Studies(Palo Alto, Calif,: Electric Power Research Institute, EPRI EM.1531,1980)

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities 175

Figure 49.—Holly Sugar Corp.—Schematic of theCogeneration System

Boilers

An example of a bottoming-cycle cogeneratoris the system at the Riverside Cement Co. plantat Oro Grande, Calif. The plant has five wasteheat boilers to recover energy from its cementkiln exhaust gases. These produce 100,000 lb/hrof steam for cogeneration via steam turbines.Because the production of steam in the wasteheat boilers varies with the production rate of thecement kilns, the system also has two oil-firedboilers for use when the output of the waste heatboilers diminishes. At present, oil provides 21 per-cent of the energy for cogeneration. In order toreduce its oil consumption (the cement kilns op-erate on coal and natural gas), the company plansto add two additional waste heat boilers. Thecompany reports that the system (see fig. 50) nor-mally operates 24 hours per day, 365 days peryear, and that there have been only two briefunscheduled outages since 1954. Because 80 per-cent of the energy that is used for cogenerationwould otherwise be wasted, system efficiency cal-culations are not significant in this situation (seediscussion of bottoming cycles in ch. 4). The co-generation capacity available to the local utilityis 15 MW (29).

Advanced Systems

Most of the existing cogeneration systems de-scribed above are limited to the use of cleanpremium fuels such as natural gas and distillatefuel oil, which are much more expensive thanalternative solid fuels, and which may be in short

Figure 50.— Riverside Cement Co.—Schematicof the Cogeneration System

supply in the coming decades. The only proventechnology appropriate for a wide range of in-dustrial sites that can use solid fuels (e.g., coal,biomass, urban refuse) is the steam turbine top-ping cycle, which has limited electrical produc-tion for a given amount of steam. However, anumber of technologies now under developmentoffer more fuel flexibility for cogeneration thanthe steam topping turbine with a conventionalboiler.

The primary problem with these emerging tech-nologies is the difficulty in handling and storingthe solid fuel and disposing of its ash. Comparedwith the ease of handling traditional liquid andgaseous fuels, solid fuels—particularly coal—arecost intensive and complex to use. Small, medi-um-sized, and perhaps even large industrialplants would prefer to avoid the investment andoperating costs associated with burning coal.These factors are likely to limit conventional coalcogeneration systems to units 30 to 40 MW orlarger, according to sources surveyed by OTA.

CENTRAL GASIFIER, REMOTEGENERATION SYSTEMS

An alternate system now under intensive development would eliminate the need for in-dustrial firms to handle coal on their plant sites.Utilizing a central gasifier to serve a region, it


would be possible to provide medium-Btu gas- premium synthetic natural gas. Onsite, the in-eous fuel to 50 to 100 industrial plants. Medium- dustrial plants associated with such centralBtu gas has an energy content between that of gasifiers would only have relatively compactlow-Btu power gas and synthetic natural gas (see cogeneration systems that would entail no morech. 4). It can be transported economically over accessory buildings and equipment than presenta reasonable distance, and is cheaper than oil or gas fueled cogeneration systems. A central

Photo credit: Department of Energy, Schneider

A prototype downdraft, airblown gasifier using wood chips as the fuel


gasifier that produced medium-Btu gas (about 300Btu per standard cubic foot) could serve a regionup to about 100 miles in radius—the distance overwhich medium-Btu gas can be transported eco-nomically.

An example of the central gasifier/remote gen-eration concept is the system proposed for cen-tral and southern Arkansas to serve as many as35 industrial sites from a central coal gasificationfacility located at the Arkansas Power& Light Co.(AP&L) White Bluff coal-fired generating station.The initial central gasifier module would burnpetroleum coke or Illinois #6 coal to produce ap-proximately 120 billion Btu of gas per day. Theas-spent cost of this module, for a design and con-struction time of 76 months, and with commer-cial operation beginning in mid-1988, is estimatedat $1.8 billion. This initial module could supplyfuel for combined-cycle cogenerators that wouldproduce 400 to 475 MW of electricity and 1.6million to 2 million lb/hr of steam, depending onthe conditions at each industrial site. Four centralgasifier modules of this size–producing 460billion to 480 billion Btu per day of medium-Btugas–would be required to supply the 35 indus-trial steam users identified by AP&L as the primarycogeneration candidates in its service area. Withthe central gasifier concept, these 35 cogener-ators would use 6 million lb/hr of process steamand produce up to 1,700 MW of cogeneratedelectricity. The synthetic gas would be piped asfar as 100 miles to user sites with combined-cyclecogeneration systems (14).

The medium-Btu gas for the system would beproduced in a gasifier fed by streams of air oroxygen and coal/water slurry, both pumped intothe system at controlled rates under pressure.Both streams enter a reactor vessel where par-tial oxidation of the fuel occurs, The product gasleaves the vessel at very high temperature, thenpasses through a series of heat exchangers thatcool the gas to 400° F. Ash from the burning fuelis separated at the exit of the gasifier and directedinto a water-quench that produces a glassy wasteproduct that can be used as an asphalt filler.Because the gasifier operates above the meltingtemperature of the ash, the quenched ash is inertand the plant does not require scrubbers.

A 150-ton-per-day Texaco entrained-processgasifier (similar to that proposed by AP&L) hasbeen operating for more than 2 years, produc-ing synthesis gas for the Ruhr Chimie chemicalplant near Oberhausen, Germany. In addition,the Tennessee Valley Authority is building a200-ton-per-day Texaco gasifier at Muscle Shoals,Ala., and the Electric Power Research Institute–inconjunction with Southern California EdisonCo.–is in the final stages of planning a 1,OOO-ton-per-day gasifier (the Coolwater project) that willbe used to produce 100 MW of power. None ofthese projects is intended to cogenerate, but thetechnology could be used to do so (4).

FLUIDIZED BED SYSTEMS

Another advanced coal technology is thefluidized bed combustor, which can be used toburn coal or other solid fuels, including urbanrefuse, in a more compact system than a conven-tional coal boiler. The fluidized bed combustorcan burn coal of any quality, including that witha high ash content, and it can operate at a tem-perature (1 ,500° F) only about half as high as aconventional pulverized coal boiler. At theselower temperatures, the sulfur dioxide formedduring combustion can be removed easily byadding limestone to the bed, and the combus-tion gases may be suitable for driving a combus-tion turbine with minimal erosion damage, be-cause the coal ash is softer at lower temperatures.Two types of fluidized beds currently are beingdeveloped–those that work at atmospheric pres-sure and those that work at considerably higherpressures (see ch. 4).

At present, fluidized bed systems are used tofire boilers, and thus can be readily used forcogeneration with conventional steam turbines.Fluidized bed systems incorporating combustionturbines, which have higher E/S ratios, are in anearlier stage of development and are just ap-proaching commercial status. But, combustionturbines require a high-temperature gas at apressure considerably above atmospheric pres-sure, so the output of an atmospheric fluidizedbed combustor cannot be used as the input tothe turbine. Instead, the fluidized bed output canbe used in conjunction with air heater tubes for


heat recovery in the fluidized bed, and the air,delivered from the turbine compressor to beheated in these tubes, can be used to indirectlyfire a combustion turbine (either open or closedcycle).

The Curtiss-Wright Corp. in Woodbridge,N. J., is offering a prototype indirectly fired systemon a semicommercial basis, sized to produce 2to 10 MW of electricity and 25,000 to 150,000lb/hr of steam. A spokesman for the companysays that 20 MW is probably the maximum feasi-ble size for such a system using an atmosphericbed combustor, the bed size being the limitingfactor. Pressurized bed systems could be larger,however. The crucial factor in this technology,according to Curtiss-Wright, is the choice of alloyfor the heater tubes. These tubes pass throughthe bed itself, operate at temperatures up to2,000° F, and can be subject to corrosion, ox-idation, and sulfurization. After “working thebugs out” of the first few demonstration units,Curtiss-Wright plans to offer the system on a com-mercial basis (4).

Pressurized fluidized bed combustors have out-put gases that exit at high enough pressures thatthese gases may be used directly to drive a tur-bine. These systems are also just approachingcommercial status. The German Babcock Co. isplanning a demonstration of a medium-sizedsystem of this type in Great Britain. The majordifficulty in the successful demonstration of suchsystems is perfecting the technology for cleaningthe fluidized bed output gas so that it does noterode the turbine blades and shorten the lifetimeof the system (4).

Shell Oil Co. recently decided to build a coal-fired fluidized bed cogeneration system near Rot-terdam, Netherlands, a relatively small unit thatwill produce 110,000 lb/hr of steam. A con-siderably larger fluidized bed project is beingundertaken by the American Electric Power Co.(AEP) at Brilliant, Ohio. The AEP system, beingbuilt in conjunction with Babcock& Wilcox, Ltd.of Great Britain and Stal-Laval Turbin AB ofSweden, uses a pressurized fluidized bed tooperate a combustion turbine topping cycle inconjunction with an existing steam turbine. Thecapacity of the combined system (which will not

cogenerate in this instance but which would beappropriate for cogeneration applications) will be170 MW (4).

Other technologies also are receiving attentionfor use with coal. The Thermo Electron Corp. hastested the performance of a two-cycle marinediesel engine fired with a coal/water slurry. Theengine, which is a low-speed tanker motor (seech. 4), could achieve in principle 40 percent ef-ficiency in generating electricity. Coal also canbe used to fuel externally fired engines such asthe Stirling-cycle engine. N.V. Philips, of Ein-hoven, Netherlands, has initiated work in apply-ing fluidized bed coal systems to use with Stir-ling engines.

Potential for Industrial Cogeneration

Cogeneration’s market potential depends ona wide range of technical, economic, and institu-tional considerations, including a plant’s steamdemand and electric needs, the relative cost ofcogenerated power, the fuel used and its cost,tax treatment, rates for utility purchases of co-generated electricity, and perceived risks such asregulatory uncertainty. The criteria for investmentin an industrial cogeneration system is discussedbelow, including a description of the industrialsectors where cogeneration is likely to be attrac-tive, and a brief review of the industrial cogenera-tion projections in the literature.

Appropriate Industries

A summary of cogeneration projects by regionin the United States is given in table 32. The 371projects in this table are those that are positivelyidentified as cogeneration systems in a recent De-partment of Energy (DOE) survey (12). A break-down by industry type is given in table 33. Anadditional 98 projects-representing at least 3,300MW of capacity–have been proposed, are underconstruction, or are being added to existingcogeneration units.

The pulp and paper industry has, for sometime, been a leader in cogeneration due to thelarge amounts of burnable process wastes thatcan supply energy needed for plant requirements.Integrated pulp and paper plants find cogenera-


Table 32—Cogeneration Projects by Region

Capacityb

Regiona Number of plants (MW)

New York , . . . . . . . . . . . . . . 27 913New York/New Jersey . . . . 23 498Mid-Atlantic . . . . . . . . . . . . . 39 1,512South Atlantic . . . . . . . . . . . 62 2,200Midwest . . . . . . . . . . . . . . . . 89 3,176Southwest . . . . . . . . . . . . . . 57 4,812Central . . . . . . . . . . . . . . . . . 14 259North Central. . . . . . . . . . . . 14 413West . . . . . . . . . . . . . . . . . . . 25 629Northwest . . . . . . . . . . . . . . 21 445

Total . . . . . . . . . . . . . . . . . 371 14,858aStandard EIA/DOE regions.bTotal may not agree due to rounding.

SOURCE: General Energy Associates, Industrial Cogeneration Potential.’ Target-ing of Opportunltles at the Plant Site (Washington, DC.: U.S. Depart-ment of Energy, 1982).

tion particularly attractive. These plants disposeof woodwastes (e. g., bark, scraps, forestry resi-dues unsuitable for pulp) and processing fluids(“black liquor”), and recover process chemicalsin furnaces that can supply about half of a plant’senergy needs. For at least two decades, the in-dustry has considered power production an in-tegral part of the manufacturing process, and newpulp and paper plants are likely candidates forcogeneration.

The chemical industry is another major steam-using industry that has great cogeneration poten-tial. It uses about as much steam per year as thepulp and paper industry (1.4 Quads in 1976) andhistorically has ranked third in installed cogenera-tion capacity. The steel industry is also a majorcogenerator, because the off-gases from theopen-hearth steel making process provide a readysource of fuel, which is burned in boilers to makesteam for blast furnace air compressors and formiscellaneous uses in the rest of the plant. Al-though the steel industry has been a major co-generator in the past, most analysts project thatit will not build more integrated stand-aloneplants. Instead it is expected to build minimillsthat run with electric arcs and have little or nopotential for cogeneration unless a market canbe found for the thermal energy. Thus, new steelmills probably have considerably less cogenera-tion potential than the chemical industry. How-ever, on the gulf coast substantial cogenerationcapacity has been proposed for existing primarymetals facilities (34)0

petroleum refining also is an industry that is,in many ways, ideal for cogeneration. Existingrefineries could be upgraded over the next

Table 33.—Existing Industrial Cogeneration by SIC Code

Percent Capacity PercentSIC code Number of total (MW) of total20—Food . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4221 —Tobacco products . . . . . . . . . . . . . . . . . . . . . . .22—Textile mill products. . . . . . . . . . . . . . . . . . . . . 923—Apparel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 024—Lumber and wood products. . . . . . . . . . . . . . . 1925—Furniture and fixtures. . . . . . . . . . . . . . . . . . . . 126—Paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13627—Printing and publishing . . . . . . . . . . . . . . . . . . 128—Chemicals. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6229—Petroleum and coal products . . . . . . . . . . . . . 2430—Rubber, miscellaneous plastic products . . . . 331—Leather . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —32—Stone, clay, and glass products . . . . . . . . . . . 633—Primary metals. . . . . . . . . . . . . . . . . . . . . . . . . . 3934-Fabricated metal products. . . . . . . . . . . . . . . . 1035—Machinery, except electrical . . . . . . . . . . . . . . 1136—Electric and electronic equipment . . . . . . . . . 337—Transportation equipment . . . . . . . . . . . . . . . . 138—instruments and related products . . . . . . . . . 339—Miscellaneous manufacturing . . . . . . . . . . . . . —

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 371

1 1 . 3 %< 1 . 0

2.4

5.1<1.036.7

<1.016.76.5

<1.0—

1.610.5

2.73.0

< 1.0< 1.0< 1 .0

100.0

39833

224

4792

4,246

3,4381,244

76

1153,589

304134

83345137

14,858

2.7<1.0

1.5

3.2<1 .028.6

<1 .023.1

8.4< 1 .0

—< 1 . 0

24.22.01.01.0

<2.3< 1 .0

100.0SOURCE: General Energy Associates, Industrial Cogeneration Potential: Targeting of Opportunities at the Plant Site (Washington,

DC,: U.S. Department of Energy, 1982).

decade to increase gasoline and diesel fuel out-put and decrease residual oil production. Abyproduct of this upgrading would be the pro-duction of low-Btu gas that might be used i ncogeneration systems. One report estimates thatsuch upgrading could produce 0.5 Quad/yr ofgas, to meet about 40 percent of the refineries’1976 process steam demand and provide 9 GWof electricity generating capacity (34). However,new refineries are not likely to be built in the nearfuture except on the Pacific coast in conjunctionwith enhanced oil recovery in the Kern Countyheavy oilfields.

An industry in which cogeneration and con-servation are in head-to-head competition is thecement industry. It has been identified as a can-didate for bottoming-cycle cogeneration, an ap-plication in which the heat of the kiln exhaust

gas is recovered and used to produce steam forelectricity generation. But because the industryis highly energy intensive, it has improved its ef-ficiency substantially in recent years, reducing thetemperature of its exhaust gases from 9000 to1,000° F to 300° to 400° F. One plant hasreported exhaust temperatures as low as 180° F(28). In plants where conservation measures arethat effective, it probably will not be economicto cogenerate.

Criteria for Implementation

A wide range of considerations must be takeninto account in deciding whether to invest in anindustrial cogeneration system. These includeboth internal and exogenous economic factors,fuel cost and availability, ownership and financ-ing, tax incentives, utility capacity expansion

Ch 5—Industrial, Commercial, and Rural Cogeneration Opportunities 181

Photo credit: Department of Energy

Low-Btu gas suitable for fueling cogeneration systems is a byproduct at many petroleum refining facilities

plans and rates for purchases of cogeneratedpower, and a variety of perceived risks in suchan investment.

ECONOMIC CONSIDERATIONS

For any potential cogenerator, the desirabilityof cogenerating depends on the price of powerfrom the utility plus the cost of producing ther-mal energy, versus the cost of cogenerating. His-torically, industrial and commercial users havepaid different amounts for utility-producedpower. Compared to the case for commercial co-generation (see below), industrial facilities typical-ly have lower electric rates, averaging up to about1.5cents/kWh lower than commercial and residen-tial users (see table 34) (9). Nevertheless, in someregions of the country, rates for utility purchasesof cogenerated electricity have reached 8.3cents/kWh (see table 19), higher than the national aver-age for either commercial or industrial retail elec-tricity rates. These areas are prime targets for ex-panded industrial cogeneration (see discussionsof purchase power rates and simultaneous pur-chase and sale, below).

The current costs of cogeneration for industrialusers often are below the rates for utility pur-chases from industrial customers. A study for theFederal Energy Regulatory Commission (FERC)(28) found that the price of cogenerated electricityranged from 4.4 to 5.6cents/kWh (1979 dollars) forvarious regions of the country, assuring the useof steam topping and gas turbine technologies.Diesel cogeneration was found to cost 7.2 to7.6cents/kWh, assuming small, distillate-fired systemsoperating at a relatively low capacity factor.Larger systems using natural gas and operatingat higher capacity factors should be able to com-pete at the busbar with new coal plants in manyinstances (34). While utility rates for purchasesof cogenerated power vary widely by region (seetable 19), the costs of cogeneration vary only 10to 20 percent among the regions of the country,This is a strong indication that the rates for salesof cogenerated electricity will be important indetermining the economic viability of industrialcogeneration over the next few years. More spe-cifically, external economic factors, rather thantechnical breakthroughs that would reduce theintrinsic costs of cogeneration, are likely to be


Table 34.-Sample Industrial Electric Ratesby State (costs per kWh for industries using 1.5 milllon

kWh per year with a peak demand of 5 MW.

. - . . .—Alabama . . . . . . . .....3.60Alaska . . . . . . . . . . . . . .3 .7Ar izona . . . . . . . . . . . . .4 .4Arkansas . ...........2.9California . ..........5.0Colorado . ...........3.4Connecticut . ........5.2Delaware . ...........5.8District of Columbia ..3.9Florida . .............3.1Georgia . . . . . . . . . . . . .3 .7Hawai i . . . . . . . . . . . . . .5 .7Idaho . . . . . . . . . . . . . . .1 .7I l l inois . . . . . . . . . . . . . .4 .0Indiana. . ............3.6I o w a . . . . . . . . . . . . . . . . 3 . 9Kansas. . . . . . . . . . . . . .3 .9Kentucky . ...........3.0Louisiana . ..........2.9Maine. . . . . . . . . . . . . . .3 .6Maryland . ...........2.7Massachusetts. .. ....5.2Michigan . ...........4.6Minnesota. . .........3.0Mississippi . .........3.9Missour i . . . . . . . . . . . .3 .8

Montana . . . . . . .....1.70Nebraska. . . . . . .. ...2.7Nevada . . . . . . . . . . . .4 .7New Hampshire .. ...4.8New Jersey. . .......4.4New Mexico . .......5.5New York .. ........7.6North Carolina .. ....2.9North Dakota . ......3.5Ohio . . . . . . . . . . . . . . .4 .1Oklahoma . .........2.6Oregon. . ...........1.7Pennsylvania . ......5.1Rhode Island . ......5.3South Carolina .. ....3.6South Dakota . ......3.3Tennessee. . ........3.2Texas . . . . . . . . . . . . . .3 .7Utah . . . . . . . . . . . . . . ,3 .1Vermont. . ..........3.3Virginia . ..........,5.2Washington ., .. ...,1.1West Virginia . .....,3.2Wisconsin .. ........3.5Wyoming . ..........1.5

aRates shown are calculated from typical bills for 455 cities with a totai popula-tion of 76.9 million as of Jan. 1, 1980. The State averages are population-basedaverages. The range among regions in the country is from 1.1 to 7.6 cents/kWh,as of Jan. 1, 1960.

SOURCE: Energy Information Administration, Typical Electric Bills, January 7,1980 (Washington, D. C.: Government Printing Office, December 1960).

the dominant factors governing the rate of co-generation implementation in the 1980’s.

In most parts of the country, the rates for pur-chases of cogenerated electricity do not exceedthe 4.5 to 5.5cents/kWh cogeneration cost quotedabove. However, the avoided cost of many util-ities may be higher than industrial electricity rates.The FERC study cited above found that in many(but not all) regions of the country this was thecase. in regions with high avoided costs, it wouldbe advantageous for industrial firms to sell all theircogenerated power to the utilities and buy backas much power as they need at the industrialwholesale price. The conditions for favorableelection of this option, known as simultaneouspurchase and sale (or arbitrage), are discussedfurther below.

FUEL VERSATILITY

The fuel used for cogeneration varies with thetype of technology installed and with the size of

the installation. The predominant fuels are coal,biomass, natural gas, and oil–usually residual(#6) and middle distillate (#2) oil. Oil and naturalgas are the most versatile fuels because they canbe used in all available cogeneration technologiesfrom the lowest E/S systems (steam topping tur-bines) to the highest (combined cycles anddiesels). However, due to the price and supplyuncertainties of oil and natural gas, over the longterm (10 years and beyond) the most attractivecogeneration investments will use solid fuels. Asdiscussed previously, of the available technol-ogies, only steam turbines presently can use suchfuels, but these systems also have relatively lowfuel savings for a given steam load, and a low E/Sratio. With the advanced technologies describedpreviously, solid fuels could be used more widelythan now possible. Both the medium-Btu gasifierand the fluidized bed systems could be used withcombustion turbines or combined cycles, pro-ducing electric power with a high E/S ratio fromcoal or biomass.

OWNERSHIP AND FINANCING

ownership arrangements may be among theprincipal determinants of the rate of developmentof cogeneration. The issue is whether cogenera-tion systems will be owned by the industry thatuses the thermal energy, whether they will beowned by the utilities that would distribute thecogenerated electricity, or whether a third partywould invest in the cogeneration equipment.Joint ventures and multiparty ventures minglingthese various players also are possible (see ch. 3).

Industrial ownership could be attractive if thesurplus electricity were purchased by a utility atrates that reflect the utility’s full avoided costs.Also ownership could assure the cogenerating in-dustry of reliable power, which can be a strongincentive for particular industries in some regions.However, the capital requirements of a cogenera-tion system are large enough that many poten-tial industrial cogenerators would like to havelong-term (i.e., 20-year) contracts for power salesto the grid. Whether this can be reasonably ex-pected under the presently applicable laws is animportant question, one that is addressed inchapter 3 of this study.

Ch. 5—Industrial, Commercial, and Rural Cogeneration Opportunities . 183

Utility ownership has the advantage that utilitiesconsider power production their primary line ofbusiness. Utility-owned cogeneration systemscould be included in the rate base, thus allow-ing the utility to earn a return on the systems.

Ut i l i t y ownersh ip a lso p rov ides a s t ra igh t fo rward

means by which utilities could maintain dispatch-ing control over the electric power entering thegrid, providing them with assurance that this newform of generating capacity would preserve sys-tem stability (see the discussion of interconnec-tion in ch. 4). Furthermore, cogeneration’s rel-atively small unit size can decrease the cost ofcapital for capacity additions and can reduce thedownside risk of unanticipated changes in de-mand growth (see ch. 6). However, as discussedin chapter 7, unregulated utility ownership raisesconcerns about possible anticompetitive effects.

Third-party ownership is most likely to occurin cases where new steam-producing equipmentis badly needed to cut energy costs but the in-dustry in question cannot raise capital for a newsystem. Novel cogeneration financing arrange-ments are emerging slowly and it is risky to makegeneralizations so early in the process. In somecases, the third party may be a separate entityset up by the utility. In other cases, it may be alarge institutional investor wooed by the industry.There appear to be few instances on the industrialscene where—as happened in the developmentof hydro power under the Public Utility Regula-tory Policies Act of 1978 (PURPA)—a small en-trepreneur identified an attractive steam load,proposed building a new plant, served as capitalmatchmaker, and then ran the facility. Third par-ties will want to reduce the risks of ownershipby negotiating long-term purchase power con-tracts with the utilities.

TAX INCENTIVES

Significant Federal tax incentives are availableto cogeneration in recognition of its fuel savingvalue. These include the investment and energytax credits, accelerated depreciation, and safeharbor leasing (see ch. 3). In some cases, co-generation may also qualify for tax-exempt financ-ing. An informal survey by OTA indicates thatthese tax incentives may promote some marginalcogeneration projects from “unattractive” to “at-

tractive,” but tax considerations are not, in mostcases, the overriding economic issue. Industrialpower cost and reliability, PURPA avoided costprices, and restrictions on capital from traditionalsources are still the dominant economic issues.On the other hand, tax considerations can havea very strong influence on ownership and financ-ing decisions for a cogeneration project. A keyissue in cogeneration tax treatment is whether ornot facilities are categorized as “public utilityproperty.” Full utility ownership is generally theleast attractive tax alternative for a cogenerationproject under either the 1978 or 1980 tax bills.

FLEXIBILITY IN LOAD EXPANSION

One of the major reasons that cogenerationwould be attractive to utilities in the short termis its suitability for adding new capacity in smallincrements that are deployable in a relativelyshort time. Cogeneration capacity sizes in in-dustrial settings range from 100 kw, minisculeby utility standards, to over 150 MW, about halfthe size of the smallest unit of baseload capacitya large utility would consider installing. Manyutilities favor 300-MW coal units as small in-cremental additions for central plant capacity.Adding Ieadtime for planning, the total time toput a cogeneration facility in place is 3 to 6years–much less than the 5- to 12-year periodrequired for utility baseload plants. As a result,cogeneration can represent an “insurancepolicy” against unanticipated changes in demandgrowth-a much less costly form of insurancethan overbuilding central station capacity.

The planned cogeneration strategy of AP&L (de-scribed above) illustrates the flexibility in capacitygrowth that can be attained with cogeneration.AP&L’s proposed 1,700-MW remote gasificationsystem (described above) would be based oncombined-cycle units at each plant site (up to 35sites), which would allow the utility to decouplesteam and electricity production. Thus, the utili-ty could build a system to supply the industrialsteam load of its customers, and then turn onelectrical capacity as needed. In this way, AP&Lcould gradually augment its system capacity fromzero to 1,700 MW over several years in a smooth-ly increasing trend (14).


PURCHASE POWER RATES

The critical economic considerations in a deci-sion whether to invest in an industrial cogenera-tion system include the rates and terms for utili-ty purchases of cogenerated power. As discussedbelow, the utility buyback rates are a primarydeterminant not only of the number of cogenera-tion systems installed, but also of the amount ofelectricity they will produce. However, Federaland State policies on this issue are in great fluxjust now, and the regional variability in purchaserates is quite high (see ch. 3). As a result, manypotential cogenerators are caught in a “squeeze”between the regulatory uncertainty surroundingsales of electricity to the grid and the desire toinvest during 1982 before the energy tax creditexpires.

SIMULTANEOUS PURCHASE AND SALE

The regulations implementing PURPA section210 allow industrial cogenerators to simultane-ously buy all their needed power from the utilities(at rates that do not discriminate against themrelative to other industrial customers), while sell-ing all their cogenerated electricity at the utili-ty’s purchase power rate. In effect, this provisiondecouples a cogenerator’s thermal and electricenergy production (see ch. 3). Utilities, which areseeing their load growth diminish drastically asa result of price-induced conservation, may findthis option attractive because it does not reducetheir load base. Moreover, industries generallyare less willing to project their steam or heat loadsas far into the future as utilities. Systems that allowsome decoupling of steam and electric produc-tion thus have potentially greater appeal to in-dustry, under industry ownership. industries mayalso find simultaneous purchase and sale attrac-tive because it does not require them to paystandby charges for electricity they would usewhen the cogeneration system was shut downfor maintenance or unplanned outages.

REGULATORY UNCERTAINTY ANDPERCEIVED RISKS

At present, probably the greatest deterrent toinvestment in cogeneration systems is regulatoryuncertainty. Utility rates for purchases of cogen-erated power under PURPA and the FERC regula-

tions on interconnection of cogenerators with thegrid are uncertain pending a final court ruling onthe existing regulations (see ch. 3). Other regu-latory or legislative items that may affect cogen-eration implementation but are in a state of fluxinclude: the Fuel Use Act regulations on exemp-tions for cogenerators; natural gas prices, theschedule for deregulation, and its effect on in-cremental pricing; and the expiration of theenergy tax credit at the end of 1982.

Industrial companies also are concerned aboutlimited capital resources and high interest rates,and may favor investments in process improve-ments that would contribute to plant efficiencyover investments in new energy systems. Com-panies also are hesitant to invest until the paybackperiods are more firmly established, given uncer-tainties in fuel prices. Some companies also haveexpressed concern about a lack of technical ex-pertise in the use of solid fuels, as well as aboutthe possibility of using up air pollution incrementsthat may be needed for future plant expansions.

Market Penetration Estimates

A number of recent studies have estimated thetechnical and/or market potential for cogenera-tion based either on the Quads of energy thatmight be saved by the substitution of cogen-erators for separate conventional electric andthermal energy systems, or on the Quads of steamand megawatts of installed capacity that couldbe supplied by industrial cogeneration. The rangeof estimates given in these studies is large, extend-ing from 6 to 10 Quads of energy saved annual-ly by 1985, and from 20 to 200 GW of installedgenerating capacity by 2000. Differing assump-tions about energy prices, ownership, and returnon investment, whether the cogeneration facilitieswould export electricity to the utility grid, andthe types of technologies employed account forthe large range. The early projections of thepotential for industrial cogeneration are sum-marized in table 35.

The general methodology in each of these stud-ies was to estimate the industrial steam load andthen quantify what portion of that load would betechnically and economically exploitable forcogeneration. The choice of cogeneration tech-

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities . 185

Table 35.—Early Estimates of the Potential for Industrial Cogeneration

Installed capacity Expected annual steamStudy Ownership Cogenerator Off site distribution in 1985 (GW) load growth

DOW Industry Steam turbine No 61 3.5 % (1968-80)4.5% (after 1980)

RPA Industry Steam turbine No 10-16 4.1% (1976-85)Thermo Electron Industry Steam turbine Yes 20-34 a 4.1 % (1975-85)

Combustion turbine 85-128Diesel 107-209

Utility Steam turbine 34-37a

Combustion turbine 131-137Diesel 218-249

Williams Utility Steam turbine 28 (in 2000) 20/0 (1974-2000)Combustion turbine or

combined cycle:Oil-fired 28Coal w/FBC 95

Diesel 57Total 208 (in 2000)

Yes

aThe Thermo Electron estimates assume only one technology Is developed and are thus not additive.

SOURCE: OTA from Robert H. Willlams, “lndustrlal Cogeneration,” 3 Annual Review of Energy 313-3S6 (Palo Alto, CalIf.: Annual Reviews, Inc., 1978).

nologies, among other considerations, thenwould determine the electrical capacity achiev-able with such a steam load. In general, thosestudies that assumed the use of only steam tur-bine topping cycles (sized so there was no off-site export of electricity) arrived at much lowerestimates of cogeneration electric capacity.

A DOW Chemical Co. study (6) projected 61GW of electrical cogeneration capacity in 1985(including existing capacity), corresponding toabout 50 percent of the projected process steamdemand for that year. The DOW study assumedindustrial ownership (with a 20-percent rate ofreturn) of steam turbine topping cycles installedin plants using over 400,000 lb/hr of steam. Thesecogenerators would produce the minimumamount of electricity for a given steam load(about 40 kWh/MMBtu) and would not exportany electricity offsite. Even with this rather con-servative choice of technologies, there were in-stances in which the study found that more elec-tricity would be generated than could be usedonsite, and so the estimated market potential forcogeneration was scaled down accordingly.

A 1977 study by Resource Planning Associates(RPA) for DOE (24) examined the potential forcogeneration development by 1985 in six majorsteam-using industries (pulp and paper, chemi-cals, steel, petroleum refining, food, and textiles).RPA only considered applications larger than

5-MW electrical capacity and assumed that all ofthe cogenerated electricity would be consumedonsite. Furthermore, approximately 70 percentof the total estimated process steam available forcogeneration development in 1985 was elimi-nated as unsuitable for cogeneration, due totechnical or economic constraints, or to conser-vation and process improvements. As a result,RPA found the 1985 potential in the six industriesto be 1.7 Quads of process steam output (10-GWcapacity) without Government action, and 2 to2.6 Quads of process steam (12- to 16-GWcapacity) with Government programs such as theenergy tax credits and the more rapid deprecia-tion now in place, or PURPA-style regulatory andeconomic incentives.

A study by Thermo Electron (30) was based onthree of the most steam-intensive industries—thechemical, pulp and paper, and petroleum refin-ing industries—which were assumed to accountfor approximately 34 percent of the total esti-mated 1985 industrial steam loads. This studyassumed that either industry or utilities might in-vest in high E/S technologies such as combustionturbines and diesels, and found that the max-imum implementation for combustion turbines—137 GW of cogeneration capacity–occurred withutility ownership, an investment tax credit of 25percent (rather than the 10 percent then avail-able), and Government financing for half theproject.

186 Industrial and Commercial Cogeneration

A 1978 study by Williams (33) assumed utilityownership, and a mix of technologies in whichsteam turbine cogenerators met 42 percent of thesteam load and higher E/S technologies the re-mainder. Williams assumed that fuel use forsteam generation in existing industries would in-crease 2 percent annually through 2000, leadingto a process steam demand of 16.1 Quads inthose industries. Williams also assumed thatabout half of the total steam demand would beassociated with cogeneration having an averageE/S ratio of 140 kWh/MMBtu and producing elec-tricity 90 percent of the time that steam is pro-duced. Based on these assumptions, Williams es-timated the total cogeneration potential in 2000to be 208 GW, saving over 2 million barrels ofoil per day.

As noted previously, each of these studiesbegan by estimating the present demand for in-dustrial process steam. These estimates includea 1974 steam load of 7.8 Quads (Williams, basedon an Exxon analysis); a 1976 industrial steam de-mand of 9.7 Quads (RPA); and a 1980 estimateof about 14 Quads (DOW). In 1981, the SolarEnergy Research Institute (SERI) attempted toreconcile the differences among these and otherestimates of industrial steam load, and found thatthe data base (disaggregated by fuel use, boilercapacity, average and peak steam loads per site,steam quality, steam load by industry, steam loadby State) is so inadequate that none of thesepublished estimates could be considered ac-curate. However, SERI was able to reject thehigher steam demand estimates in the literaturebecause they did not account accurately for fueluse in smaller boilers in less energy-intensive in-dustries. By reconciling differences in approachand accounting among the lower published num-bers, SERI arrived at an estimate equivalent to ap-proximately 5.5 Quads/yr during 1976-77 (27).

In addition to overestimating the base industrialdemand for steam, the early studies of industrialcogeneration assumed robust steam growth-onthe order of 4 percent annually. The steady prog-ress that has been made in industrial energy con-servation through the 1970’s—amounting to adecrease in energy use per unit of industrialvalue-added of approximately 2 percent peryear—makes these earlier predictions for steam

load growth highly unlikely. More recent studiesof cogeneration have projected steam growthrates that are either lower or constitute nogrowth. For instance, in 1980 SRI Internationalprojected 1.18 percent per year (28), whileWilliams now estimates zero growth in steam de-mand through 2000 (34), and SERI projected zeroor negative growth (27).

More recent estimates of the potential for in-dustrial cogeneration either have assumed amuch smaller present steam base and lower ther-mal demand growth rates, or have devised amethodology that does not begin with an esti-mate of the current steam load. However, dueto changes in the context for cogeneration sincethe earlier studies were completed, these recentstudies have not necessarily projected a lowermarket potential for industrial cogeneration.These contextual changes include the PURPAeconomic and regulatory incentives for grid-connected cogeneration, substantial increases inoil and electricity prices, special energy taxcredits, and shorter depreciation periods. As aresult of these and other considerations, cogen-eration is considered likely to be economicallyattractive at more industrial sites than in earlierstudies (despite the lower thermal demand pro-jections), and more likely to use technologies withhigher E/S ratios that produce more electricity.

A 1981 study by RPA (23) examined the 1990potential for cogeneration in five industries (thoseanalyzed previously except for textiles), beganwith a 1990 steam demand of 682 million lb/hr(approximately 6 Quads/yr, assuming 1,000Btu/lb and 24-hr operation). Of this base, RPAfound an expected investment in the five in-dustries of 155 million lb/hr (1 .36 Quads) steamproduction, or 20.8 GW of electric capacity,assuming “base case” utility buyback rates (seetable 36). This would increase to 28.7 MW of in-stalled cogeneration capacity if, as a result of utili-ty ownership, 30 percent of the steam turbineswere replaced by combustion turbines and com-bined cycles. The “high buyback rates” casewould lead to an expected investment potentialof as much as 37 GW of instaIled capacity, whilethe “low” case shows 14.2 GW (1.2 Quadssteam). The amount of electric capacity declinesmore than the steam production with lower buy-

Ch. 5—industrial, Commercial, and Rural Cogeneration Opportunities ● 1 8 7

Table 38.-Range of Utility Buyback Rates Analyzed by RPA(1980 dollars In cents/kWh)

Marginal utility Low buyback Base buyback High buybackDOE region fuel rate rate rate

1. New England . . . . . . . . Oil 4.0 5.5 7.02. New York/New Jersey. Oil 4.0 5.5 7.03. Mid-Atlantic . . . . . . . . . Oil 4.0 5.5 7.04. South Atlantic . . . . . . . Oil/coal 2.0 3.5 5.05. Midwest. . . . . . . . . . . . . Coal 2.0 3.0 4.06. Southwest. . . . . . . . . . . Natural gas 2.5 4.0 5.57. Central. . . . . . . . . . . . . . Coal 1.0 2.0 3.08. North Central . . . . . . . . Coal 1.0 1.5 2.59. West. . . . . . . . . . . . . . . . Oil 4.5 6.0 7.5

10. Northwest . . . . . . . . . . . Coal 3.5 4.5 5.5SOURCE: Resource Planning Associates, Inc., The Potential for Industrial Cogeneratlon Development by 1990 (Cambrldge,

Mass.: Resource Plannlng Associates, 1981).

back rates due to the sensitivity of technology E/Sratio to these rates (23).

In an informal update of his earlier work,Williams (34) begun with a much lower steamdemand–4.l Quads in six industries in 1977–but assumed that cogeneration would achieve ahigher degree of penetration of the steam basethan he had assumed earlier. Of these 4.1 Quads,Williams assumed 1.25 Quads would be unsuit-able for cogeneration (due to load fluctuations,low steam demand, low-pressure waste heatstreams, declining demand, etc.), resulting in asix industry market potential of 93 to 142 GWin 2000, depending on the technology mix.Williams estimated an additional potential of upto 32 to 49 GW in other industrial sectors, if theirsteam loads are proportional to those in the sixindustries, but less if their steam loads are smalleror more variable. Finally, Williams estimates thatnew industries (e.g., thermally enhanced oil re-covery) have a potential of 11 to 20 GW of in-stalled capacity. Together, these sources have an“economic potential” of 136 to 211 GW of co-generation capacity in 2000. Williams considersthis economic potential to be the amount avail-able for insuring against underdevelopment ofcentral station generating capacity. The actualamount to be designated as a “prudent planningbase” for such insurance could not be deter-mined without better disaggregated data on thesteam base, but Williams found 100 to 150 GWto be a “conservative estimate” (34).

Williams’ approach to cogeneration as insur-ance against the uncertainty in future electricitydemand growth was included in the 1981 SERI

report on solar/conservation. SERI did notestimate the total potential for industrial cogen-eration because the report’s emphasis on con-servation meant that projected electricity demandgrowth was so low (0.13 percent annually) thatno cogeneration electrical capacity would beneeded unless the conservation targets were notmet. The study concluded that 93 GW of cogen-eration in the six industries would be an adequateinsurance measure, but made no attempt to as-certain how much capacity would be econom-ically attractive (27).

A different methodology was adopted in a 1982analysis for DOE (12). Rather than using a grossestimate of steam demand as the primary meas-ure of potential, this study began by individuallyanalyzing the 10,000 largest U.S. industrial sitesfor their cogeneration potential based on buy-back rates, accelerated depreciation, heat match,and other considerations. This analysis identified3,131 plants in the 19 manufacturing sectors thatwould have a return on investment greater than7 percent and represent the maximum potentialof 42.8 GW of cogeneration capacity (produc-ing 3.3 Quads of steam). Ninety-two percent ofthe electric capacity and 95 percent of the steamgenerated are in the five top steam-using indus-tries. The “best” mix of technologies for thesesites was found to be 70 percent combustion tur-bines and 30 percent steam turbines, resultingin the offsite export of 49 percent of the electricitygenerated. If the return on investment increasedto 20 percent, the maximum potential decreasesto 20 GW. The study also estimated that an ad-ditional 48.5 GW of capacity could be installed

188 . Industrial and Commercial Cogenerafion

at new industrial sites based on U.S. Departmentof Commerce industrial growth figures andassuming that plant expansions and new plantswould have characteristics similar to those in ex-isting plants (12).

The studies reviewed above illustrate two mainpoints:

1.

2.

The technical potential for cogeneration isvery large; even the lowest of these estimatescorresponds to the equivalent of 20 newbaseload central generating plants, while thehighest estimate corresponds to a generatingcapacity capable of producing more thanone-sixth of the electrical power presentlyused in the country.Economic and institutional considerationsare paramount in determining how muchcogeneration will actually be installed, as il-lustrated by the wide sensitivity of these es-timates to variations in utility purchase rates,tax incentives, ownership, fuel prices, etc.The underlying consensus among these stud-ies on all matters except the likely steam loadis in fact remarkable.

While the market for cogeneration is potentiallylarge, the actual rate of cogeneration equipmentinstallation is much lower than expected a fewyears ago. This trend is occurring in spite of higherelectricity prices because of the weakened finan-cial posture of utilities, industries’ difficulty in rais-ing capital for expansion due to unprecedentedlyhigh interest rates, and the unexpectedly rapidrate of energy use reductions in industry. Long-term fuel supply uncertainties also may workagainst cogeneration, or against the more attrac-tive cogeneration options.

The effect of energy conservation in industryis one of the key influences on future cogenera-tion. Whereas substantial steam load growth wasassumed in most cases, the rate of energy use perunit of production has in fact dropped substan-tially in major industries. The industry that hastraditionally been most committed to cogenera-tion as an integral part of its business, the pulp

and paper industry, has reduced its energy con-sumption per ton of production by 26 percentbetween 1972 and 1980. The chemical industryhas reduced its energy use by 22 percent overthe same period, and the petroleum refining in-dustry, 15 percent. Steam production at thelargest operating industrial cogeneration sys-tem–the Gulf States 130-MW complex supply-ing steam to oil refineries and related industriesnear Baton Rouge, La.—has decreased by 30 to50 percent over the past several years, accordingto a spokesman for the utility.

The weakened financial position of some in-dustries is also likely to be a factor in cogenera-tion. Whereas the steel industry is a very heavyenergy user, it has been a declining industry overthe past decade and one unlikely to have the cap-ital for new cogeneration facilities. In most in-dustries, cogeneration faces competition forcapital with expansion of production capacity,and in such a face-off cogeneration investmentsare likely to have a low priority. However, thissituation would be averted under utility owner-ship, or under the leasing provisions of theEconomic Recovery Tax Act of 1981. Althoughutilities face more financial problems than at anytime in decades, smaller investments in cogenera-tion systems can be financed more easily than1,000-MW central powerplants.

If cogeneration is implemented, the amount ofelectrical capacity resulting from a system sizedto fit a given heat or steam load could vary byas much as a factor of 4 depending on the typeof cogeneration equipment that is used. For ex-ample, a large industrial installation that uses 0.5million lb/hr of steam would cogenerate 30 to 40MW of electricity with steam turbines, and 120to 150 MW with gas or oil burning combustionturbines. A major question for industrial usage,therefore, is the extent to which alternate fuelssuch as coal or biomass can be adapted to tur-bine technology, because the traditional fuels (oiland gas) are now the most expensive availableon the U.S. market.


COMMERCIAL COGENERATIONAlthough the opportunities for cogeneration in

industry are numerous and diverse, cogenerationin commercial buildings is likely to have a smallermarket potential. Commercial enterprises typical-ly use thermal energy only for space condition-ing and water heating, and have thermal load fac-tors that are usually much lower than those ofindustrial concerns. As a result, the economicsof cogeneration systems for commercial buildingstraditionally have been much less favorable thanthose of industrial systems. Recently, however,market incentives resulting from PURPA and/orfrom high electricity and fuel prices have changedthe economics of commercial cogeneration. Sev-eral technical and economic factors in particulardetermine the relative attractiveness of commer-cial building cogeneration and purchasing utility-generated electricity, such as the suitability ofelectrical and thermal load profiles, the poten-tial for fuel savings, and the change in relativefuel prices.

This section discusses the results of OTA anal-yses of cogeneration in commercial buildings v.centralized electric utility systems. The sectionbegins with a review of the literature on commer-cial cogeneration, followed by a general introduc-tion to OTA’s analytical methods, a discussionof the major assumptions used in the analyses,and a summary of the results.

Previous Studies ofCommercial Cogeneration

Several existing studies have examined thepotential for commercial cogeneration in par-ticular areas or under certain conditions. Theseinclude a FERC study that estimated the amountof cogeneration that would be stimulated byPURPA (28); a study by the American Gas Asso-ciation (AGA) that compared gas-fired cogenera-tion with two conventional heating systems in ahospital in different climate regions (l); andregional studies by Consolidated Edison (Con Ed)for their service area (1 3,25) and by the State ofCalifornia for State-owned buildings (s).

The FERC study calculates the national and re-gional penetration of cogeneration and small

power production induced by PURPA through1995, and concludes that only in the Mid-Atlanticregion (New York, New Jersey, and Pennsylvania)is commercial building cogeneration likely to beeconomically attractive. FERC projects that 2,500MW of commercial sector capacity could ormight be installed in this region by 1995, produc-ing 10,000 GWh/yr of electricity. In these calcula-tions FERC assumed: first, that the PURPA regula-tions would be the sole incentive for cogenera-tion; second, that cogeneration would only occurin large new buildings (e.g., new apartment build-ings with more than sO units, new hospitals hav-ing more than SO beds); third, that all commer-cial investment would earn a fixed rate of returnof 20 percent; and fourth, that all equipmentwould have a fixed capacity factor of 45 percentand a fixed size of 500 kw. Some of these as-sumptions may be both too kind and too cruelto commercial cogeneration. That is, FERC’S anal-ysis ignores incentives other than PURPA (e.g.,tax benefits, high electricity rates), the possibili-ty of retrofits or eventual use in smaller buildings,and the achievement of higher capacity factors,and thus may understate cogeneration’s poten-tial. At the same time, the analysis uses a veryfavorable rate of return and thus may overstatethe market potential for cogeneration under cur-rent high interest rates.

The AGA study is based on a prototype designfor a 300,000 square foot hospital located in fourdifferent climate regions. AGA assumed two dif-ferent rates for utility purchases of cogeneratedpower to compare the annualized capital, fuel,O&M, and net electricity costs for three differenttypes of heating and cooling systems for the hos-pital: 1) a conventional combination system,using a gas boiler to provide steam for spaceheating plus an electric air-conditioner for spacecooling, and relying on the grid for electricity;2) an all-electric system, using baseboard resist-ance heaters and air-conditioners run with utility-generated electricity; and 3) an all-gas system,using a gas-fired cogenerator to provide electricityand space heating and a waste heat recovery sys-tem to run an absorptive air-conditioner. AGAassumed the cogenerator was sized to match the


thermal load, with any excess electricity beingsold to the electric utility.

The AGA study concluded that the “economicattractiveness (of cogeneration) is heavily depend-ent on the buyback rate for cogenerated electrici-ty.” The study found that, for all four climateregions, the cogeneration system had a lower an-nual cost than the other options when the buy-back rates were set at 8cents/kWh. However, whenthe rate was lowered to 2cents/kWh, cogenerationwas found to be economical only in the Mid-Atlantic region. This is because the higherbuyback rates offset cogeneration’s high capitalcost compared to the capital costs of the com-bination and all-electric systems. But when thebuyback rates were lowered, cogeneration’s cap-ital cost became prohibitive in all but the Mid-Atlantic region, where high fuel costs and elec-tric utilities’ dependence on foreign oil give fuel-efficient cogenerators an economic advantage.

Although the AGA study analyzes the sensitivityof cogeneration economics to factors such as buy-back rate and climate, it is limited to hospitals,a type of commercial building with a relativelyconstant energy demand.

ConEd developed a model of the costs andbenefits of investment in cogeneration based onthe internal rate of return from such investment,and applied the model to load data for their 4,500largest customers, assuming that the investmentwould be made if the rate of return would be atleast 15 percent over 10 years. Depending oncustomers’ loads and other variables, ConEdfound an “expected” cogeneration penetrationof 395 customers with a combined peakload of1,086 MW, with a high range of up to 750 co-generators totaling 1,483 MW peakload. Theanalysis was then repeated using a slightly highercost cogenerator (and thus a lower rate of return),and the market potential dropped substantially—to 27 customers with a combined peakload of 130MW.

These market penetration estimates for cogen-eration depend heavily on how the cogeneratorswill operate. Con Ed assumed that cogeneratorswould only operate when there is sufficient elec-trical demand on the system. Thus, the assumedthermal efficiency is low (52 percent for commer-

cial building systems and 62 percent for residen-tial systems), and the cogenerators are unable toprovide either substantial fuel or cost savings.However, if cogenerators are undersized (relativeto the electrical demand) so that they operate as“baseload” heaters and only supply some of theelectrical needs, they may have lower total costs,and thus, higher penetration rates than the onescalculated by ConEd (3). Therefore, even in theMid-Atlantic region, cogeneration’s market pen-etration may be very sensitive to operating andcost assumptions.

In the fourth study of cogeneration in commer-

cial buildings three State agencies in Californiacalculated the cogeneration potential in State-owned buildings, including hospitals, universities,and State offices. The State identified 188 State-owned facilities that have significant potential forcogeneration, and initiated engineering studiesfor the cost effectiveness of cogeneration. “Theevaluation showed that 150 MW at 24 sites couldbe designed, under construction, or in operationin fiscal year 1981. An additional 97 MW at 31sites could be developed in fiscal year 1982, total-ing 247 MW at 55 sites. It should be clearly un-derstood that these are preliminary estimates ofcost-effective cogeneration capacity. Furtherengineering analyses may result in increased ordecreased capacity.” The study concludes thatthe total potential for cogeneration in State-owned buildings is over 400 MW. The distribu-tion of this capacity among State facilities isshown in figure 51.

Because the literature on commercial cogen-eration is sparse, OTA undertook its own analysisof cogeneration opportunities in the commercialsector. This analysis is concerned with illustratingthose parameters that significantly affect the useof cogeneration in commercial buildings. To dothis, in part, we make use of a computer-basedmodel—the Dispersed Electricity TechnologyAssessment (DELTA) model–that simulates deci-sionmaking by electric utilities in choosing newcapacity. The model can accommodate rangesof values for the technical, operating, and finan-cial characteristics of utilities and cogenerators.There are limitations to its use, however, due tothe number of assumptions that have to be madeand to the gaps in the available data. Consequent-

Ch. 5—industrial, Commercial, and Rural (generation Opportunities ● 191

100

90

80

70

60

50

40

30

20

10

0

Figure 51.— Cogeneration Potential at California State Facilities

Megawatts Total potential = 410 MW

Uc Csuc Hospital Prison Comm New Others

college buildings

Type of State facilitySOURCE: California Energy Commission, Commercial Status: Electrical Generation and Nongeneration Technologies

(Sacramento, Calif.: California Energy Commission, P102-8O4O4, April 1980).

Iy, the DELTA model cannot be used to accurate-ly project levels of cogeneration use in commer-cial buildings over the next several years. in par-ticular, we have not used the model to analyzethe case where natural gas and distillate oil pricesare significantly different from one another, northe case where retrofits of existing buildings areincluded in the demand for thermal energy. Aqualitative discussion of these cases is presented,however. The model does give us, though, in-sight into how cogeneration might compete withnew central station capacity to supply commer-cial electricity demand, and the effect of such fac-tors as thermal load profiles on that competition.Therefore, despite its limitations it is believed thatthe DELTA model–properly clarified–will sub-stantially assist in understanding the conditionsthat affect cogeneration’s future in the commer-cial sector.

Critical Assumptions and Limitsof the DELTA Model

The DELTA model uses a linear program (sim-ilar to those used by utility planners) thatminimizes the total cost of producing electricityand thermal power during the years 1981 to 2000(see app. A for model description). The modelsimulates the addition of grid-connected cogen-eration in three kinds of large new commercialbuildings, with different types of daily load cycles,to supply electricity, space heating, and spacecooling demands. Several scenarios were con-structed to explore the sensitivity of cogenera-tion in these buildings to regional utility andclimate characteristics, future fuel price changes,

and different technological specifications. Thestructure of the model, the assumptions aboutthermal and electricity supply and demand, and


the features of the scenarios constructed are de-scribed below.

Model StructureElectric and Thermal Cost Minimization.—The

DELTA model differs from many existing utilityplanning models in that its objective is the min-imization of total annualized fixed plus operatingcosts for both utilities and their commercialbuilding customers (e.g., for heating and cool-ing). Thus, DELTA goes beyond traditional utili-ty planning, which usually analyzes only thosecosts borne by the power system. The strategyselected through this hybrid cost minimizationmay not exactly match either the strategy chosenby the utility or by the customer acting alone, butwill tend to produce an “average” between bothparties.

Demand Assumptions

Grid-Connected Cogeneration.–The DELTAmodel only examines grid-connected cogenera-tion because the PURPA provisions on purchasesof cogenerated power are intended to benefitcogeneration systems that provide energy and/orcapacity as well as diversity to utilities. Therefore,OTA did not analyze the effects of stand-alonesystems on utility operations.

Three Types of Energy Demands.–The DELTAmodel specifies hourly demands for three typesof energy: space heating, space cooling, and elec-tricity. The analysis begins in 1980 with a specifiedthermal baseline of zero load and zero capaci-ty, and an electrical baseline of 1,000-MW loadand the existing generating capacity mix (nor-malized to the 1,000-MW load) in each sampleregion. The model then determines what capacityadditions will minimize utility and customer costsfor all three types of energy, assuming a rangeof growth rates for energy and peak demands ineach sample region (see table 40, below, for adescription of existing electrical capacity andgrowth rates). New capacity is added at the endof each decade—in 1989 and 1999—and then sys-tem costs are evaluated in 1990 and 2000.

The 1980 electric generating capacity in eachsample region was normalized to 1,000 MW tofacilitate comparisons of capacity additions and

future utility operations among the differentregions. However, in order to compare thermaldemands among the building types and regionsa different approach was necessary. A largeamount of data would be needed for a precisespecification of existing thermal capacity anddemands–unlike electrical demands, there is noaccurate and centralized source of informationon thermal demand and capacity. Thus, in orderto ensure consistent and accurate treatment ofthermal demands, OTA would have had to col-lect individual commercial customer profiles–atime-consuming and expensive process. There-fore, OTA chose another method for the DELTAmodel: to set existing thermal demands andcapacity equal to zero. In effect, this is equivalentto only allowing cogeneration in new buildings,and then comparing the cost of installing cogen-eration with the costs for new centralized capaci-ty and new steam boilers, but not considering thereplacement of any existing steam boilers withnew cogeneration equipment. As was stated,without inclusion of such boiler retrofits, themodel cannot be used to project the cogenera-tion potential in the entire commercial sector.Although we have not attempted to project theretrofit potential in any other way, the factors thatwill influence this potential will be discussed laterin this section.

Eight Typical Days. –OTA chose to specifyeach type of energy demand with a yearly pat-tern of eight different “typical days” in order toobserve more clearly the range and frequencyof utility operating characteristics (see table 37).

Table 37.—Typical Days Used in the DELTA Model

Day type Frequency Per YearWinter:

Peak a. . . . . . . . . . . . . . . . . . . . . . . . . . .Weekday . . . . . . . . . . . . . . . . . . . . . . . .Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Summer:Peak a.. . . . . . . . . . . . . . . . . . . . . . . . . .Weekday . . . . . . . . . . . . . . . . . . . . . . . .Weekend. . . . . . . . . . . . . . . . . . . . . . . .

Fall/spring:Weekday a . . . . . . . . . . . . . . . . . . . . . . .Weekend . . . ... , . . . . . . . . . . . . . . . . .

65926

10844

Total . . . . . . . . . . . . . . . . . . . . . . . . . 365aThe 1990 electrlc bad patterns for region 1 for these 3 days are shown in fig. 52.

SOURCE: Off Ice of Technology Assessment.

Ch. 5—lndustrial, Commercial, and Rural Cogeneration Opportunities 193

Each typical day has a specific load cycle patternfor each region and year. For example, the loadcycle patterns during 1990 for three differenttypical days and for one region (New England)are shown in figure 52. The differences amongthese cycles are caused by the different assump-tions for energy use and demand growth usedin each region.

Three Commercial subsectors.-ln addition tospecifying the annual load patterns for electrici-ty, OTA chose to disaggregate the commercialsector’s thermal heating and cooling demandsinto three parts: hospitals and hotels, multifami-ly buildings, and 9-to-5 office buildings. This wasdone to explore the effects of load diversity oncogeneration operation, and thus to providemore precise information on the opportunitiesfor commercial cogeneration. Other commercialsector building types (such as universities andretail stores) have energy demand profiles thatare combinations of these basic three categories.(The electric demands were not disaggregated inthe DELTA model because the load profiles for

the entire commercial sector were sufficient tocapture the interaction of the cogenerators withthe centralized utility system.)

The three subsectors were chosen for their dif-ferent thermal load patterns; examples of thesepatterns for two typical day types are given infigures 53 and 54 for 1990 New England heatingand cooling demands respectively. For heatingdemands, hospitals and hotels have the lowestenergy demands of all the subsectors, with smallpeaks at 8 a.m. and 9 p.m. Multifamily buildingsuse somewhat more energy and have similarlyoccurring peaks, while 9-to-5 offices use the mostenergy and have the most pronounced peak dur-ing the winter days at 6 a.m. The cooling de-mands of hospitals and hotels and multifamilybuildings are small when compared to officebuildings, the latter having a peak during sum-mer days at 2 p.m.

Supply Assumptions

The energy supply assumptions in the DELTAmodel specify different sets of fuel prices and of

Figure 52.—Comparison of Eiectric Demand for Three Types of Days(for region 1 during 1990)

Fall/spring Summer Winterweekday peak day peak day-. .-. . . . . . . . .

MW electrical demand1,100

1,000

900

800

700

600

500

40012 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of day

SOURCE: Office of Technology Assessment.


Figure 53.—1990 Heating Demands for Scenario 1s (for Region 1 during 1990)

Winter peak day

1 0 0

90


Time of day

Summer peak day7

Multifamily 9-to-5 office I

12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnightTime of dayaScale on two graphs Is different.


technological and operational characteristics in coal (and electricity) and 1.7 percent per year fororder to describe the three different sample utility fuel oil and natural gas for the low price trajec-regions. tory, and 4.7 percent annually for coal (and elec-

Fuel Prices.–OTA specified two different fueltricity) and 4.8 percent per year for fuel oil and

price trajectories, based on the 1980 averagenatural gas for the high price trajectory. * For this

prices in the commercial sector (31) and the rangeanalysis of commercial cogeneration, these as-

of real growth rates (not accounting for inflation)assumed in two previous OTA studies (1 7,20).

*These growth rates are explained in the OTA report, Applica-

These growth rates are: 1.0 percent annually fortion of Solar Technology to Today’s Energy Needs, vol. 11, September1978.

Ch. 5—Industrial, Commercial, and Rural Cogeneration Opportunities ● 195

Figure 54.-1990 Cooling Demandsa (for Region 1 during 1990)

Winter peak day

70

Summer peak day

4 r

(12 midnight 4 a.m. 8 a.m. 12 noon 4 p.m. 8 p.m. 12 midnight

Time of daya Scale on two graphs Is different.


sumptions were modified slightly by setting the Therefore, only the lower price path results wereprice of natural gas equal to fuel oil after 1985. reported. These prices are shown in table 38.

Using two different fuel price trajectories al- our assumption about natural gas prices re-Iowed us to test the sensitivity of our results. quires elaboration. Currently, most natural gasHowever, the results varied by less than 2 per- is used for purposes that require a higher qualitycent between the two different price paths. fuel than coal or residual fuel oil. About 25 to

—.


Table 38.-Fuel Prices(all prices In 1980 dollars per MMBtu)

1980 1990 2000

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.34 1.95 2.38Residual . . . . . . . . . . . . . . . . . . . . ., . . . 4.05 5.86 7.13Distillate . . . . . . . . . . . . . . . . . . . . . . . . 5.67 8.20 9.98Natural gas . . . . . . . . . . . . . . . . . . . . . . 2.09 8.20 9.98SOURCE: Office of Technology Assessment.

30 percent of current natural gas use is for rais-ing steam, while the remainder goes for spaceheating in buildings, industrial process heat,peakload electricity generation (primarily com-bustion turbines), and chemical feedstocks (7).The future price of natural gas will be determinedby the relative strengths of these demands com-bined with the availability and cost of new do-mestic natural gas.

The conversion of all natural gas-fired boilersto coal would free about 4 trillion to 5 trillioncubic feet (TCF) of natural gas per year at cur-rent consumption rates. If there were no otherchange in natural gas supply and demand, thisnew “supply” would be more than enough toreplace all current distillate fuel oil used for sta-tionary purposes (1.9 MMB/D) (8). If price in-creases resulting from decontrol bring aboutmore conservation, additional natural gas wouldbe freed, which, when combined with the dis-placed boiler fuel, would result in a substantialsurplus of natural gas. The most logical use forthis surplus gas would be to displace residual fueloil used to fire boilers. (Of course, in reality, thegas would only leave the boiler market until itjust displaced all stationary fuel oil). This competi-tion with residual fuel oil would keep the margin-al cost of natural gas about the same as that ofresidual oil.

This scenario, however, assumes that domesticnatural gas supplies do not decline significantlyover the same period, and that the marginal costof the new supplies that offset the decline in pro-duction from existing reserves will be below theprice of distillate fuel oil. It is quite possible–indeed both Exxon and the Energy InformationAdministration have projected as much–thatthere will be a net decline in domestic naturalgas supplies by as much as 3 TCF by 1990 (10).On the other hand, AGA estimates that supplies

could increase substantially over this same period(2). In all cases, however, a significant fractionof new domestic supplies in these projections ismade up of high cost supplemental supplies—unconventional gas, Alaskan gas, and syntheticgas from coal. In fact, the three organizations pro-ject about the same amount of conventional do-mestic natural gas production—about 14 TCF in1990 and 12 TCF in 2000. This is close to thequantity now being consumed by the so-calledhigh priority uses for which only distillate fuel oilor electricity are feasible substitutes (19). There-fore, if the cost of new marginal natural gas sup-plies were equivalent to distillate fuel oil, the priceof all natural gas would approach that of distillateor electricity (whichever is cheaper) as decontroltakes effect and the quantity of old, flowing nat-ural gas under contract vanishes. It is partly thesomewhat optimistic supply assumptions aboutnew, “lower cost” gas that has caused most re-cent price projections to show natural gas pricesbelow those for distillate fuel oil for the remainderof the century (8).

Our price scenarios rest on the assumption that“lower cost” gas supplies will decline as fast orfaster than the rate at which coal displaces naturalgas in boilers. Even in this case, however, naturalgas prices could be lower than distillate oil if elec-tricity prices stay below distillate (on an energy-service basis)—as they currently are in many re-gions of the country. in this case, natural gasprices will likely approach those of electricity(again on an energy service basis). Similar specu-lation has been offered by others (26). BecauseOTA did not run the model with natural gasprices below distillate, the model results pre-sented are confined to what would happen underthe plausible situation that the prices of the twofuels are the same. To partially expand the analy-sis, some calculations of target gas prices are pre-sented for the condition that cogeneration pro-duces power at the cost of electricity determinedby the model. There is evidence, as will be seen,that some cogenerators are proceeding based onthe assumption that natural gas prices will remainbelow distillate prices for the economic life oftheir projects.

Technology Characteristics.–The majortechnologies used in the DELTA model include


three types of central electricity generating plants,several space heating and cooling technologies,and the cogenerators. Table 39 summarizes thecharacteristics for each type.

OTA specified three different types of genericutility generating plants to serve base, intermedi-ate, and peak loads. The baseload type is repre-sented by coal-fired steam powerplants, the inter-mediate-load type by either residual oil-fired ordistillate or gas-fired steam turbines, and the peak-ing technologies by distillate or gas-fired combus-tion turbines.

Space heating and cooling technologies in themodel include ordinary steam boilers used forheating, electric air-conditioners, absorptive air-conditioners using distillate or gas fuel, and ther-mal storage equipment with a capacity of up to24 hours storage. Because of the linear program-ing formulation, the model cannot change thetype of fuel used in either electric generating orthermal equipment from their original specifica-tion in table 39.

Two sets of capital costs for cogeneration ca-pacity were included in the analysis. The highercost cogenerator has a capital cost of $750/kW,while the lower cost system has a capital cost of$575/kW (both in 1980 dollars). These capitalcosts are typical of the range of cogenerationcosts described in chapter 4 (see table 23). We

did not include, explicitly, cogeneration technol-ogies that could use coal by means of syntheticfuel production or advanced combustion tech-nologies (e.g., fluidized beds). If the capital costsof these technologies are similar to those usedin the model, the results would remain un-changed. The only exception would be a re-ported increase in coal use if these technologiesare employed, because the model allowed co-generation technologies to use only oil or naturalgas.

Operational Assumptions.–OTA made threeoperational assumptions that would allow theDELTA model to follow more closely the way ac-tual grid-connected cogeneration systems wouldoperate. First, OTA specified the utility plannedreserve margin to be 20 percent of annual peakdemand. This includes scheduled maintenancefor 10 percent of the year for the base and in-termediate types of plants, and is typical ofreserve margins used in power systems planning,although actual reserve margins may be muchhigher than 20 percent. For the sample utilityregions used in this analysis (see below), all 1980reserve margins were above 20 percent. In ad-dition, the actual 1981 national average reservecapacity was around 33 percent (16).

Second, the model assumes that all cogenera-tion equipment has an E/S ratio of 227 kWh/

Table 39.—Technology Characteristics (all costs are for 1980 In 1980 dollars)

Cap cost Fixed O&M Variable O&M Availabilitya Heat rateb

Technology type ($/kW) ($/kW-yr) ($/kWh) (percent) (Btu/kWh)Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,014 14.0 0,001 68 10,300Intermediate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0,0015 88 10,500Peak . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 0.3 0.003 93 14,000Cogeneration—high . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 750 0.0 0.008 95 9,751Cogeneration—low . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 575 0.0 0.008 95 9,751Thermal boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 0.0 0.0 95 4,266Thermal storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2’ 0.0 0.0 — —Electric air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 700 0.0 0.0 95 1,138Absorption air-conditioners . . . . . . . . . . . . . . . . . . . . . . . . . . . 110 0.0 0.0 95 5,251aAvailability is the maximum percent of time that capacity can serve demand—thus 88 percent means the baseload equipment is out of service a total of 12 Percent

of the year.bThe cogeneration heat rate shown is the heat rata for electrical service only: the net heat rate (Including the energy In Steam produced by the cogenerator) is 5,333

Btu/kWh. Both of the heat rates shown for air-conditioners are calculated in Btu/kWh of heat removed from commercial buildings.cCapital cost of thermal storage is expressed in dollars/kWh.

SOURCES: Electric Power Research Institute, The Technical Assessment Guide, Special Report PS 1201 SR, July 1979, specifies capital cost, variable and fixed O&Mcosts, heat rates, and availabilities for coal steam plants with flue-gas desulfurization, for distillate oil-fired steam plants, and for oil- and gas-fired combus-tion turbine plants. OTA multiplied the costs for these plants by the Consumer Price index inflator to bring 1978 costs to 1980 costs, and used the GrossNational Product inflator to bring 1978 dollars to 1980 dollars. Characteristics for the thermal technologies were obtained by averaging the data collectedin ch. 4 for cogeneration equipment, thermal boilers, and storage (see table 23 for these figures). Zero fixed and variable O&M costs are assumed for theconventional space heating and cooling technologies, because these costs are very small when compared to the 8 mills/kWh variable O&M costs of thecogenerators.


MMBtu, with 35 percent of the output used forelectricity, 45 percent to satisfy the thermal load, *and 20 percent exhausted to the outside environ-ment—an overall efficiency of 80 percent. Third,thermal storage is assumed to have an efficien-cy of 90 percent (i.e., 1.0 MWh (thermal) intostorage can supply 0.9 MWh (thermal) out ofstorage). No electrical storage is considered.These values are within the range of actual valuesdescribed in chapter 4 for E/S ratios and efficien-cies for gas turbine or combined-cycle cogenera-tion systems, which are or will be applicable inthe commercial sector (see table 23).

Sample Regions. –OTA chose three sampleutility regions based on the technological andoperational assumptions mentioned above andon data from the regional electric reliability coun-cils. Region 1 is typical of areas with utilities thathave a large percentage of oil-fired steam genera-tion, high reserve margins (over 40 percent), anda relatively moderate annual growth in electric-ity demand of 1 percent (such as the NortheastPower Coordinating Council). The summer andwinter peaks for Region 1 are about equal. Region2 is typical of summer-peaking regions with most-ly nuclear or coal baseload capacity, a higher an-nual load growth than in Region 1 (2 percent),but lower reserve margins (26 percent) (e.g., theMid-America Interpool Network). Region 3 istypical of areas with large reserve margins (over40 percent), relatively high load growth (3 per-cent), and large amounts of gas-fired steam gen-eration (such as the Electric Reliability Councilof Texas). Region 3 is also summer-peaking. (Seefig. 8 for the location of each of these regions ofthe North American Electric Reliability Council.)

● Measured in megawatts, i.e., 1 MW (thermal) = 3.412MMBtu/hr.

Table 40 summarizes the electrical demand andsupply characteristics of each region, normalizedto 1,000 MW.

Scenario DescriptionBased on the above demand and supply as-

sumptions, OTA used nine “standard scenarios”to investigate the effects of cogeneration on thesample utility regions for different cogenerationcosts (see table 41). These standard scenarioswere grouped into three sets to represent thethree utility regions. Each set has three differentscenarios: a base case in which no cogenerationis allowed and only utility powerplants are used,and two cogeneration cases using higher andlower capital costs of the cogenerators. As men-tioned previously, the scenarios also originally in-cluded two sets of fuel prices. However, the re-sults of the analysis varied by less than 2 percentbetween the higher and lower prices, and onlythe results for the lower prices are reported here.

In addition, five special scenarios were for-mulated to investigate the effects of limiting theaddition of baseload capacity and of using a zerocapital cost cogenerator. Not all possible combi-nations of regions and cogeneration capital costswere made for these five special scenarios be-cause OTA was primarily interested in observingthe sensitivity of the standard set of scenario as-sumptions to particular situations, rather thanmaking complete inter-regional comparisons.Table 41 identifies these special scenarios andtheir distinguishing assumptions.

Commercial Cogeneration Opportunities

The DELTA model described above choosesamong the varying technological, financial, andother assumptions to find the minimum total cost

Table 40.-Sample Utility Configurations

Annual 19601960 capacity installed (MW) Electrical peak reserve

Region Base Intermediate Peak Total demand growtha in margin740 150 1,390 1% Summer, winter 39%

2500

1,020 o 237 1,257 2 % Summer 26°A3 265 1,107 5 0 1 , 4 4 2 3%0 Summer 4 4 %

aAnnual growth in both electrical peak demand and total energy demand.



Table 41.—Description of Scenarios Used

Standard scenarios:l-NO COGEN1-HIGH COST COGENl-LOW COST COG EN2-NO COGEN2-HIGH COST COGEN2-LOW COST COG EN3-NO COGEN3-HIGH COST COGEN3-LOW COST COG EN

Special scenariosl-NO COGEN/COAL-LIMITEDl-LOW COST COGEN/COAL-LIMITED2-ZERO COST COGEN3-NO COGENI/OAL-LIMITED3-LOW COST COGEN/COAL-LIMITED

Region 1, base case/no cogeneratlon allowedRegion 1, high capital cost cogenerationRegion 1, low capital cost cogenerationRegion 2, base case/no cogeneration allowedRegion 2, high capital cost cogenerationRegion 2, low capital cost cogenerationRegion 3, base case/no cogeneration allowedRegion 3, high capital cost cogenerationRegion 3, low capital cost cogeneration

Region 1, coal-fired baseload capacity limit, no cogenerationRegion 1, coal-fired baseload capacity limit, low capital cost cogenerationRegion 2, zero capital cost cogenerationRegion 3, coal-fired baseload capacity limit, no cogenerationRegion 3, coal-fired baseload capacity limit, low capital cost cogeneration


of providing electric and thermal energy in eachscenario. The model results are not predictionsabout future utility behavior—rather, they repre-sent what might happen under the conditions andassumptions used to specify the scenario. Byanswering these “what-if” types of questions, themodel can provide valuable insights about theinteraction of cogeneration with the existing cen-tralized utility systems.

Capacity Additions andOperating Characteristics

In order to analyze the addition of cogenera-tion capacity and its effects on utility systemoperations, OTA determined, first, whether aminimum-cost capacity expansion plan would in-clude significant amounts of cogeneration, andsecond, how the cogeneration equipment thatis added is used to supply electric and thermalenergy.

COGENERATION CAPACITY

To see if cogeneration capacity would be eco-nomically attractive compared to central stationgeneration for our set of assumptions, OTA com-pared the electric generating capacity additionsfor the base-case scenarios–in which no cogen-eration is allowed—with the scenarios in whichcogeneration can be added. Figure 55 summa-rizes these capacity addition comparisons for thenine standard scenarios.

The results show that the greatest opportunityfor cogeneration occurs when the match be-tween thermal space heating and electricaldemands is the closest. Thus, the largest propor-tion of cogeneration capacity is added in Region2, which has the highest thermal demand of thethree regions. Region 3, on the other hand, addsmore total capacity (cogeneration and central sta-tion) because it has the largest growth in elec-tricity demand, and because it has a large pro-portion of existing gas-fired capacity that can bereplaced by less expensive coal-fired units. Withour assumptions, therefore, commercial cogen-eration in new buildings is competitive with cen-tral station technologies only when there is asignificant need for space heating and at least amoderate growth in electricity demand. Coal-fired capacity is cheaper than new cogenerationcapacity when electricity is needed but very lit-tle or no heating is required. Coal is cheaper be-cause of the difference in fuel prices, and thatdifference dominates any other cost of installingor operating the technology under our assump-tions.

One way to test this result is to vary the capitalcost of the cogenerator. By going to the extremecase of zero capital cost, the limit of cogenera-tion penetration can be shown under our fuelcost assumptions. * We ran this case for Region

*This analysis also provides a rough approximation of what mighthappen by keeping the capital cost unchanged but lowering naturalgas fuel prices.


Figure 55.–Elactrical Capacity Additions 1990-200@Baseload Peak Cogeneration

I Low

aFor 1990, scenario l–LOW-COST COGEN/COAL-LIMITED.


2 (abbreviated as 2-ZERO COST COGEN), andfound that the cogeneration technology wasmore competitive with the coal baseload capacityand more cogeneration was installed than in theother cogeneration scenarios for Region 2. How-ever, the amount of electricity produced from thecogeneration did not increase significantly (seethe discussion on costs below).

In another set of special cases, the amount ofcoal that could be used for central station capaci-ty was restricted. This constraint had two pur-poses. First, it simulated conditions where coalburning may be prohibited or severely restrictedfor environmental, availability, or other reasons.(This assumption also simulates the case wherenuclear would serve as the baseload and it, too,would be restricted.) The second purpose wasto examine the effect of much higher coal pricesrelative to natural gas and oil. This method(restricting coal use) is not as satisfactory as car-rying out model runs with different fuel price tra-

jectories and ratios, but will serve qualitativelyto show how higher coal prices would benefit oil-or natural gas-fired cogeneration.

In Region 1, no baseload plants were allowedto be added through 2000, while in Region 3,baseload capacity additions through 1990 werelimited to a small percentage of the total existingbaseload capacity, while no limits were placedon additions from 1990 to 2000. Two scenarioswere run for each region: a new base-case inwhich only central station equipment was added(abbreviated l-NO COGEN/COAL-LIMITED and3-NO COGEN/COAL-LIMITED, for Regions 1 and3 respectively) and a cogeneration case (ab-breviated l-LOW COST COGEN/COAL-LIMITEDand 3-LOW COST COGEN/COAL-LIMITED).Table 42 summarizes the capacity additions forthese four scenarios.

Table 42 shows that the limits on baseloadcapacity additions increase the economic attrac-tiveness of cogeneration in both regions. For ex-

Ch. 5—lndustrial, Commercial, and Rural Cogeneration Opportunities ● 201

Table 42.—New Capacity Installed for Coal-Limited Scenarios

Total electrical Proportion of new electricalcapacity installed capacity installed (o/o)

Scenario (MW) Base Peak Cogeneration

l-NO COGEN/COAL-LIMITED 15 — 100 —l-LOW COST COGEN/COAL-LIMITED 62 — o 1003-NO COGEN/COAL-LIMITED 1,192 100 03-LOW COST COGEN/COAL-LIMITED 1,363 63 0 17NOTE: “-” means assumed zero input for this scenario.


ample, 3-LOW COST COGEN/COAL-LIMITED in-stalls 77 percent of its total capacity as cogenera-tion while the standard Region 3 scenarios(3-HIGH COST COGEN, and 3-LOW COSTCOGEN) install at most 4 percent.

These results demonstrate the competition be-tween cogeneration and central station coal-firedcapacity to meet new electricity demand. Bothcapital and operating costs of the system and thethermal demand determine this choice. If newcoal-fired capacity is sufficiently inexpensive,even in the face of the efficiency advantage ofcogeneration, coal will provide electricity andconventional oil- or gas-fired space heaters willprovide thermal energy for these new buildings.Further, if excess electric generating capacity ex-ists, the ability of cogeneration to penetrate thecommercial market may also be limited, even ifcogeneration is less costly than new, coal-firedcentral station generation. Electricity from the ex-isting capacity, because of its sunk capital cost,is usually cheaper than that produced by new,more efficient cogeneration if the latter is con-fined to premium fuels. In some cases, however,economics may still favor cogeneration, particu-larly if the existing central station capacity is oilfired and near retirement. In some markets whereretirement would be desirable in the next fewyears, cogeneration from natural gas-fired unitscould be the only means of replacement capacity,whether coal-fired generation is permitted or not.We will discuss this further below.

COGENERATION OPERATION

The above results on cogeneration capacity areexplained by the details of how the electrical andthermal loads are met. OTA calculated the elec-trical capacity factor (the ratio of time a generator

actually supplies power to the time the plant isavailable for service) for both the cogenerationand the baseload capacity in each of the sce-narios. Table 43 shows the electrical capacity fac-tors calculated by the model for both the stand-ard and coal-limited scenarios. Most of the base-Ioad capacity operates 66 to 70 percent of thetime, while the cogenerators operate less than30 percent of the time. * The low load factor forcogeneration results from its inability to generateelectricity that is competitive with central stationelectricity even though cogeneration is moreenergy efficient. This is a result of our assumedfuel prices. As we shall see, the DELTA modelonly operates cogenerators when the electricityis needed to meet intermediate or peaking de-mands that otherwise would be supplied by oil-fired utility units. The higher fuel prices of theseutility units, combined with the high overall effi-ciency of the cogenerator, allows the latter tocompete economically in the market for in-termediate and peaking power. When coal is pro-hibited, the thermal and electrical capacity fac-tor of the cogenerators increases from 30 percentor less to over 50 percent. In this case, the cogen-erators are also supplying a small amount of base-Ioad electricity. This is because the cogeneratorscan supply power less expensively than othertypes of central station generation when coal-firedadditions are limited.

However, these capacity factors only indicatethe most general performance of each type ofequipment. in order to provide a more completedescription, we need to observe, for each sce-nario, the hour-by-hour dispatching schedule (for

*For the cogenerator, this is also the thermal capacity factor sincethe unit is producing both electricity and thermal energy while itoperates.


Table 43.-Capacity Factors for Baseload and Cogeneration Plants

Baseload plants Cogeneration plants1990 2000 1 9 9 0 2 0 0 0

Standard scenariosl-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 681-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 69 68

—— 27

1-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 31 292-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 67 —2-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . .

—70 10

2-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 66 68 7 133-NO COGEN . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 683-HIGH COST COGEN . . . . . . . . . . . . . . . . . . . . 70 68 21 203-LOW COST COGEN . . . . . . . . . . . . . . . . . . . . 70 69 21 21Baseload-limlted-scenarlosl-NO COGEN/COAL LIMITED . . . . . . . . . . . . . . 80 80 —l-LOW COST COGEN/COAL-LIMITED . . . . . . . 80 80 58 533-NO COGEN/COAL-LlMlTED. . . . . . . . . . . . . . 80 673-L0W C0ST COGEN/COAL-LlMlTED . . . . . . . 80 69 95 7Note:”—” means no cogeneratlon was Installed by the model, elther due to economics of the model or because of input

es zero for the base-case scenarlos. Capacity factors are calculated for each plant type as follows:

MWh Supplied x 100(MW installed + existing MW) x 8,760 hours


both cogenerators and central station generators)for each of the eight different types of “typical”days used in the analysis. Figures 56 and 57 pre-sent the space heating and electric demands, re-spectively, and show how each technology isdispatched to meet these demands for 1 day(winter peak which occurs six times a year) in1990 for scenario 1-LOW COST COG EN/COAL-LIMITED.

Figure 56 shows that, during the 1990 peakwinter day, the cogenerators provide about 37MW of heat to meet thermal demands that varybetween 30 and 78 MW. During this peak day,the cogenerators operate 95 percent of the time.Thus, seen from the perspective of a commer-cial building owner, cogenerators operate as a“baseload” heating system during winter peakdays.

Figure 57 shows the electrical demands for thesame 1990 winter peak day. Note that the co-generators only contribute to the peak and inter-mediate load. The small numerical value of thesecontributions is partly due to our assumptions ofzero thermal demand and 1,000 MW of electricaldemand for 1980. If a larger thermal demand hadbeen assumed and retrofits considered, the elec-tricity contribution of the cogenerators would

have increased substantially, although it wouldstill be confined to the peak and intermediateload. What is important here, however, is not theabsolute value of the electrical contribution bycogeneration, but rather what portion of the elec-trical demand it can supply economically com-pared with other options.

RETROFIT OPPORTUNITIES

As discussed above, existing buildings (henceexisting thermal demands) were not included inthis analysis. This rules out cogeneration retrofitsand thus the analysis understates cogeneration’scontribution to the total electric load. It is there-fore important to discuss the factors that willinfluence the choice of whether to install a cogen-eration system in an existing building. In addi-tion to the considerations about economic com-petition with new central station electric generat-ing capacity, the major constraints to retrofittingare excess central station capacity, the uncertain-ty about natural gas prices and availability, andthe difficult financial conditions brought aboutby high interest rates and short loan terms.

The first constraint, excess capacity, has the ef-fect of keeping the price of electricity well belowits marginal cost in most regions of the country


Figure 56.—Thermal Supply and Demand for Winter Peak Daya


Time of day

aFor 1990, scenario 1- LOW-COST COGEN/COAL-LIMITED.


Figure 57.–Electricity Supply for Winter Peak Day


Time of day

aFor 1990, scenario 1 - LOW-COST COGEN/COAL-LIMITED.



and thus to force payments for cogeneratedpower under PURPA to be determined by fuelsavings alone (i.e., no capacity credit). Both actas an incentive for building owners to continuepurchasing all their electricity from the utility.New buildings have a similar incentive–as themodel results have demonstrated. In the case ofexisting buildings the incentive is even greater,however, because of the sunk costs of existingheating equipment and interconnection with theutility. Where current prices exceed marginalcost, as would likely be the case if oil is the domi-nant fuel used to generate electricity and the fu-ture capacity would be coal-fired, shortrunPURPA payments based solely on fuel savingscould be high, stimulating cogeneration invest-ment. More will be discussed on this below.

The second constraint, uncertainty about fuelprices and availability, is important because nat-ural gas is the most likely fuel for commercialcogeneration retrofits for the next several years.As discussed earlier, the price of natural gas willincrease, but it could still be low enough to makecogenerated electricity and thermal energy (usinga combustion turbine, diesel, or combined-cyclesystem) cost less than a combination of electricityproduced from central station generators and anindividual heating plant. Gas prices also couldbe much higher, perhaps as high as distillate fueloil, which would make potential retrofits too cost-ly in most cases. In the latter case, the resultswould be similar to those obtained for new con-struction as given by the model. The price atwhich natural gas-fired cogeneration is competi-tive with electricity depends primarily on the sizeof the facility, the credit obtained for displacingnatural gas or oil used for space heating, the fi-nancial conditions available to the prospectiveowner, and the thermal load factor of the build-ing. Capital and O&M costs per unit output in-crease as the facility size decreases, lowering thenatural gas prices required for breakeven withelectricity. The displacement credit depends onthe amount of fuel saved from the displacedspace heating unit, and the cost of hooking upthe cogeneration unit. The thermal load factorwill determine the amount of electricity that canbe produced assuming the cogeneration unit op-erates to supply baseload thermal demand. The

Photo credit: OTA staff

Some older commercial buildings could be retrofitted forcogeneration, but the economics of such retrofit will dependon the price of electricity and the price and availability of

cogeneration fuels—primarily natural gas

analysis of this point is similar to that describedabove for the new buildings.

As an example of these considerations, we ex-amine a combined-cycle cogeneration unit ofabout 10 MW (a size typical for a very largebuilding), operating to supply 50 percent of abuilding’s heat load. Further, if this unit canoperate at a high electric load factor of 85 per-cent or more, this unit could produce electricitythat would compete with central station electric-ity priced at 5cents/kWh if natural gas cost $4.50/MMBtu or less (all in 1980 dollars) (34). * The na-

*This calculation assumed a value for the capacity factor in orderto determine a breakeven natural gas price. In actual operation itis the other way around. Under the conditions that the buildingowner’s goal is minimum cost and that the cogeneration unit is sized


tional average price of natural gas in the commer-cial sector commercial sector for the third-quarterof 1981 was about $3.50/MMBtu. Therefore thecombined-cycle system described above appearsto have a definite economic advantage for regionswhere electricity is selling for 5cents/kWh or greater.

There is another set of conditions that wouldallow natural gas-fired cogeneration to be eco-nomically competitive even if the price relation-ships just calculated do not hold. If the price thatutilities must pay to cogenerators for power is sethigh enough by the State public utility commis-sion, then cogeneration would be installed evenif its electricity production costs were greater thanthe retail price for electricity. Further, dependingon the purchase power price under PURPA, co-generated electricity from a natural gas unit couldcost more than new, central station coal-firedgeneration and still be economically preferableto the latter. In California, for example, the pur-chase price is based on the cost of oil-fired gen-eration. Many industrial and commercial estab-lishments see this as a very attractive opportunitybecause their natural gas prices are below the fueloil prices paid by the utility. Therefore, thesecogenerators are willing to enter into agreementswith utilities in California to sell them electricityfor the next 5 to 10 years.

Even though natural gas prices will increase andprobably surpass those of residual oil during thatperiod, the cogenerators will still receive a highreturn because of their higher overall efficiencies.Further, the utilities will be able to replace cur-rent oil-fired capacity more quickly than by moreconventional means—i.e., coal or nuclear cen-tral station. For the period beyond 1990, how-ever, coal-fired, central station capacity is plannedand probably will be cheaper than natural gas-

to supply baseload thermal energy, cogeneration would be operatedwhenever it can produce electricity at a cost less than or equal tothe combined cost of central station electricity and separate ther-mal energy production (e.g., a conventional building heating sys-tem). The former cost depends on the price of the fuel for cogenera-tion (natural gas in this case), various financial parameters (interest,taxes, debt/equity ratio, etc.), and O&M costs. The cogenerationunit must be sized to provide baseload thermal energy becausethe cost of electricity alone from the cogenerator will nearly alwaysbe greater than the cost of electricity from a central station plantdue to economic and efficiency reasons. It is therefore necessaryfor the cogenerator to be able to displace building heating fuel andobtain a cost credit in order to meet the minimum cost criteria.

fired cogenerated electricity as the ultimate re-placement for the existing oil-fired capacity. How-ever, successful coal gasification with combined-cycle generation could alter the economics backto favoring cogeneration. More is discussed aboutthis last point below.

The California case is not typical of fuel oil de-pendent utilities, primarily because such utilitieslocated in other States usually can purchase pow-er from neighboring utilities with an excess of coalor nuclear power. In California, power purchasesgenerally are not an option because of limitedtransmission interties with other systems. TheCalifornia case does, however, point out the po-tential for natural gas-fired cogeneration in thenext 10 years. We have also not calculated thatpotential for new buildings since that analysisdetermines longrun generation needs only (hencelongrun avoided costs).

The final point about cogeneration’s potentialin existing buildings concerns the financing con-ditions currently available to prospective cogen-eration owners. Financial factors will help deter-mine the cost of electricity and thermal energyfrom a cogenerator. The current high interestrates and short loan terms available to non utilityinvestors for investments in building energy sys-tems are acting to severely limit cost effective in-vestments of any type—conservation or cogen-eration.

In a study released by OTA, Energy Efficiencyof Buildings in Cities (18), these current financialconditions are partially responsible for keepingabout 60 percent of the otherwise cost-effectiveconservation retrofits identified in that study frombeing installed. Although OTA did not examinecogeneration in this same way, it is likely thatcogeneration retrofits will be affected similarly,perhaps even more so because of the much high-er initial investment levels per building neededfor cogeneration than conservation. This is oneplace where utility or third-party ownershipwould be potentially very helpful. In the formercase, utilities would be able to secure longer termloans at lower interest rates than commercial in-vestors. In addition, utilities possess the engineer-ing skills needed to install and hook up the units.Utilities currently are prohibited from owning

206. Industrial and Commercial Cogeneration

more than so percent of a cogeneration unit andstill qualifying for PURPA benefits.

Aside from this legal barrier, however, a poten-tially more important one exists as a result of thelow thermal load factors in individual buildings.Because of this, cogeneration that supplies base-Ioad thermal demand to these buildings may notproduce excess electricity for sale to the grid.Unless such electricity is produced, utilities can-not be expected to invest in commercial cogen-eration. Raising the load factor, for example, bysupplying clusters of buildings (each with differentload patterns), would be one way to eliminatethis problem. Finally, third-party ownership withlease arrangements may also be promising be-cause of the provisions of the new tax laws.

Although we have not attempted to project theretrofit potential for cogeneration, it is probablethat movement in that direction will be tentativefor the next few years, primarily due to unfav-orable financial conditions. Even should interestrates and loan terms ease in the near future, how-ever, there still will be competition with conser-vation investments, which will reduce the techni-cal potential for cogeneration in a given building.Further the uncertainty over natural gas is likelyto remain until resolution of pricing policy andelimination of end-use restrictions (the Fuel UseAct, see ch. 3). Once these conditions arecleared, however, and if natural gas prices arelow enough, or purchase power rates are highenough, there could be considerable interest andactivity in cogeneration retrofits in the last halfof the 1980’s. If new technologies that can usesolid fuels—through gasification-are successfullydeveloped by then, further stimulus would exist.

Fuel Use

In addition to investigating the changes in utilitycapacity additions and operating characteristicsthat might result from cogeneration, OTA alsoanalyzed the change in proportion of fuels usedin the sample utility regions to determine ifcogeneration would displace any oil or gas. Asmentioned earlier, the analysis assumes that allcogeneration equipment uses distillate fuels inRegions 1 and 2 and natural gas in Region 3. Theresults of the calculations of fuel consumption in1990 and 2000 for the “no-cogeneration” stand-ard scenarios are shown in table 44.

Not all scenarios are shown in table 44 becausethe total fuel used and the proportion used byeach fuel type are similar between the base-case(“NO COG EN”) and the cogeneration scenariosfor each region. Cogeneration accounts for lessthan 1 percent of the total fuel used in all cogen-eration scenarios, and the total fuel and propor-tionate fuel use change less than 1 percent be-tween the two types of scenarios. As expectedfor our fuel price and use assumptions, becausecogeneration cannot compete with baseloadcoal-fired electricity, cogenerators operate onlya small fraction of the time (when they can supplyintermediate and peak demand electricity) andtherefore use only a small fraction of the total fuel.A further caveat is the exclusion of existingbuildings’ thermal demand, as explained earlier.

Because the model was restricted to the casewhere natural gas and distillate prices were equal,no results were obtained for the case when nat-ural gas prices fall low enough so that cogener-ated power could compete with central stationelectricity. OTA calculated this gas price, given

Table 44.-Base-Case Standard Scenario Fuel Use, By Generation Type and Year

Percentage of total fuel used Total annual fuelScenario Base Intermediate Peak Cogeneration Steam boiler use (10’2 Btu)1990l-NO COGEN 98 1 0 64.22-NO COGEN 97 0 0 2 62.53-NO COGEN 95 2 0 o 3 74.0

l-NO COGEN 97 0 0 2 69.32-NO COGEN 95 0 o 4 74.43-NO COGEN 94 1 0 o 5 95.1SOURCE: Office of Technology Assessment.


the set of costs and technical assumptions as wellas the average price of electricity determinedin our analysis (ranging from 3.3cents/kWh to 7.0cents/kwh). Using our assumptions of $575/kW capitalcost for the cogenerator, 0.8cents/kWh O&M cost,and an overall heat rate of 9,750 Btu/kWh withan 80-percent combined heat and electric powerefficiency, we can calculate the breakeven pricerange of natural gas. For a cogenerator capacityfactor of 0.85 this price ranges between $2.55/MMBtu to $8.40/MMBtu, which brackets the cur-rent commercial natural gas price of $3.50/MMBtu (in 1980 dollars). Again, the capacity fac-tor will be determined by the cost of electricityproduced by the cogenerator and, therefore, thecost of natural gas. This is a complex interactionbecause lower capacity factors reduce the fueldisplacement credit, thus increasing the net costof cogenerated electricity.

Similar arguments can be applied for the newtechnologies not considered in the model. Theability of these newer technologies to enter themarket depends ultimately on the cost of steamand power they produce. Currently a few systemsare being developed that will allow these coststo be estimated. One such system is the Cool-water combined-cycle, coal gasification systemrecently announced (1 1). Although that systemis being designed to supply electric power to theSouthern California Edison system, successfuldemonstration of the technology could lead theway to cogeneration applications. An unpub-lished analysis of the economics of the Coolwaterfacility as a cogeneration plant estimates an elec-tricity cost of about 3.6cents/kWh, including a creditfor heat recovery (fuel displaced by byproductsteam from the cogenerator) of about 4.6cents/kWh(34). This price for electricity is lower than themarginal cost of electricity from a new central sta-tion coal plant, although higher than the averagecost calculated in some of the cases of our analy-sis. The calculation, however, assumes a returnon equity that may be less than will be requiredof new plants such as the Coolwater facility. * In

● In the particular example cited, the return on equity assumedwas 10 percent along with a 50/50 debt-equity ratio and a real in-terest rate on debt of 3 percent. If we repeat the calculation witha 15 percent return on equity and a 5 percent real interest rate ondebt, values which we have found to be operative in favor of syn-fuels projects (21), the cost of electricity increases to 5.9cents/kWh.

addition, using such facilities for commercialbuildings entails the development of coal hand-ing, delivery, and storage facilities plus the needfor air quality control equipment. All will add ex-penses to these systems (which were not includedin the calculation cited above), and the questionof the economic attractiveness of these advancedcogeneration systems is still open. Biomass andurban solid waste have been proposed as fuelsfor gasification-cogeneration systems, and, insome cases, are under development. The eco-nomic analysis of these systems is similar to thatgiven for the Coolwater facility. One exceptionis that for proposed solid waste units, a credit isavailable in the form of the tipping fees usuallycharged to dispose of these wastes.

A recent development concerning biomasscogeneration is a combined-cycle system usinga direct-fired combustion turbine fueled by pul-verized wood. Using hot gas cleanup technologydeveloped in the British pressurized fluidized bedcombustion program, turbine blade damage isreduced to an acceptable level. A 3-MW test unitis currently being designed and built by the Aero-space Research Corp. of Roanoke, Va. Economicanalysis of this technology in a cogeneration sys-tem looks very promising and may be competitivewith coal-fired central station electric power (35).As with other systems described in this chapter,the economics are highly dependent on the elec-tric load factor. Consequently, they are more pro-mising for industrial sites then for buildings.

COAL-LIMITED SCENARIOS

While few changes in fuel use are observed in1990 and 2000 between the cogeneration andthe base-case standard scenarios, some changesdo occur in the special scenarios that limit coal-fired capacity additions (thus allowing other typesto operate more frequently than they would with-out these limitations). As mentioned earlier, fourspecial scenarios that limit baseload additionswere constructed: two allowing cogeneration andtwo restricting cogeneration. Figure 58 shows thatthe addition of cogeneration to the sample sys-

Utility financing, however, would allow a lower return even fora first-of-a-kind plant, perhaps close to that assumed in the originalcalculation. This argues in favor of utility ownership of suchcogeneration facilities.


Figure 58.— Fuel Used in 1990 and 2000

Baseload Intermediate

I

or Coal= Limited Scenarios

Thermalboilers Cogeneration

70

60

50

40

30

20

10

0NoCogen Cogen NoCogen Cogen NoCogen Cogen NoCogen Cogen

- - - 1 9 9 0 - - - - - - 2 0 0 0 - - - - - 1 9 9 0 - — — - 2000 — -

- - - - - R e g i o n 1 - - — - - - - - - - R e g i o n 2 — - — — —SOURCE: Off Ice of Technology Assessment.

terns decreases total fuel use when the cogenera-tion scenarios (I-LOW COST COGEN/COAL-LIMITED and 3-LOW COST COGEN/COAL-LIMITED) are compared to their respective base-case scenarios (l-NO COGEN/COAL-LIMITEDand 3-NO COGEN/COAL-LIMITED). This is a re-sult of two factors. First, there is considerablymore cogeneration that operates at higher capac-ity factors, as shown above. Second, this greaterpenetration allows the higher overall fuel efficien-cy of cogeneration to significantly affect total fueluse.

Most of the decrease in overall fuel use in thecoal-limited scenarios (when 1- and 3-LOW COSTCOGEN/COAL-LIMITED are compared to 1- and3-NO COG EN/COAL-LIMITED, respectively) re-sults from the decrease in fuels used by the in-termediate electric generating capacity. While thebaseload coal consumption remains identical be-tween the base-case and the cogeneration sce-

narios, the efficiency of the cogenerators, com-bined with the reduction of intermediate capacitygeneration, reduces overall fuel used for the twospecial coal-limited cogeneration scenarios. Table45 compares the use of oil and gas for the fourcoal-limited scenarios.

In summary, cogeneration has only a small ef-fect on utility fuel use as long as electricity canbe produced more cheaply with other types oftechnologies. However, in the special coal-lim-ited scenarios, cogeneration may cause less totaloil to be used and may displace fuel used by theintermediate capacity.

Sensitivities to Changes in AssumptionsIn addition to analyzing fuel use and operating

characteristics with and without cogeneration, wemust also determine the sensitivity of this analysisto changes in some of the assumptions used in


Table 45.-Comparison of Fuel Use for Coal-Limited Scenarios

Region 1 coal-limited Region 3 coal-limitedscenarios (net change scenarios (net change

in percenta) in Percenta)

1990 2000 1990 2000

Total fuel . . . . . . . . . . . . . . . . . . . . . . . – 1 – 2 –7 –1Total residual . . . . . . . . . . . . . . . . . . . – 6 – l o —Total distillate/natural gas . . . . . . . . +155 + 121 –13 +3Total oil . . . . . . . . . . . . . . . . . . . . . . . . – 3 – 5 –13 +3aA negative change means that the coal-limited cogeneratlon scenarios use less fuel than the no Cogeneration coal-limited

scenarios; a positive change means that the cogeneratlon scenarios use more fuel. All fuel is measured In Btu-equivalents.


the scenarios. One important assumption is thecost for installing and operating cogenerators. Asmentioned above in the discussion of capacityadditions, OTA formulated a scenario, 2-ZEROCOST COG EN, that uses zero capital cost cogen-erators for Region 2.

The sensitivity of our results to the costs ofcogeneration is determined by comparing thetypes of capacity that are installed and how theutility system uses cogeneration for two scenarios:the 2-ZERO COST COGEN scenario with the2-LOW COST COG EN scenario. While the ZEROCOST scenario installs 81 percent of its capacityas cogeneration, the LOW COST scenario installs20 percent. Despite the difference in cogenera-tion capacity between the two scenarios, the fuelsconsumed by cogeneration are only 2 percentof the total fuels used in each scenario. In otherwords, for our fuel price assumptions, baseloadelectricity from coal is still cheaper so it is usedto meet the baseload demand. In the zero capitalcost case, however, cogenerators can supplythermal energy much more cheaply than boilers,so cogeneration is being used primarily to meetspace heating demands plus as much intermedi-ate and peak electricity demand as possible. Zero-capital cost cogeneration therefore is used as aninexpensive heater, without displacing any coal-fired generation. Thus, the cogeneration in thisscenario displaces some of the peakload equip-ment, and does not use its steam during peaksummer days.

Summary

By using the DELTA model and our set of tech-nical and economic assumptions, OTA was ableto determine the interaction of cogeneration with

several sample centralized utility systems. Undermost circumstances, cogeneration additions innew buildings were very limited because theycould not compete economically with central sta-tion coal-fired generation. As a result, fuel usagedid not change greatly from an all-centralized sys-tem. When coal-fired expansion was limited,however, cogenerators penetrated the utility sys-tem significantly and provided much of the heat-ing demands and peak and intermediate electric-ity for the system.

Three specific conclusions can be made fromthis analysis. First, given the assumptions, cogen-erated electricity cannot compete with centralstation, coal-fired capacity. Therefore, in com-mercial buildings, cogeneration will only contribute to peak and intermediate demands and willonly operate when it can supply such electricity.This holds for even a zero capital-cost cogenera-tor. Lower natural gas prices, however, couldgreatly increase the opportunity for cogeneration.in fact, natural gas prices somewhat above cur-rent gas prices would allow cogeneration to com-pete with new, baseload, coal-fired central sta-tion capacity. Alternatively, successful develop-ment of gasification technologies that can pro-duce moderately priced (about $5/MMBtu) medi-um-Btu gas from coal, biomass, or solid wastecould expand the competitive position of cogen-eration. Finally, cost relationships could be deter-mined by high utility purchase rates for cogener-ated power that would also make natural or syn-thetic gas-fired cogeneration preferable regardlessof the actual Iongrun marginal costs of new COA

fired capacity.

Second, existing electric generating plantsusually can provide power more cheaply than


new cogenerators. Even if oil is used for these fired central stations that are near retirement.plants, the cogenerator capital costs dominate Third, if oil- and natural gas-fired equipment isany gains from more efficient fuel use; and this used, the best opportunity for cogenerators is indomination results in little significant penetration regions with high heating loads (about 6,000 heat-of cogeneration. However, lower cost natural gas ing degree-days) and moderate electrical growthcould change these economics. In some regions (at least 2 percent annual growth in peak and totalthis is the case now where natural gas-fired co- energy).generation is the preferable choice to existing oil-

RURAL COGENERATIONAlthough industrial and commercial sector co-

generation opportunities are recognized widely,little attention has been paid to cogeneration ap-plications in rural areas, particularly in agriculture.The rural cogeneration potential is not so largeas in the industrial sectors, but could present fueland cost savings on farms or in rural communi-ties. The principal rural cogeneration opportuni-ties arise where there are existing small power-plants or where agricultural wastes can be usedas fuel. Promising cogeneration applications forrural communities include producing ethanol,drying crops or wood, and heating livestock shel-ters.

Small, rural municipal powerplants can gain sig-nificant economic and fuel conservation advan-tages with cogeneration if a market for the ther-mal energy is available. Many of these power-plants use reciprocating internal combustionengines or combustion turbines as their primemovers. Dual fuel engines predominate (generallyburning natural gas, with small amounts of fueloil to facilitate ignition), but diesel engines andnatural gas fueled spark ignition engines also arecommon. Generally, these small rural power-plants have a peak electric power rating of 10MW or less, and they operate at around 33 per-cent efficiency in producing electricity (i.e., 33percent of the fuel input energy is converted toelectricity and 67 percent is exhausted as wasteheat). If only half of the waste heat from theseplants were used, the energy output would dou-ble (IS).

Table 46 shows the distribution and maximumtemperature of waste heat sources in a super-charged diesel engine. As shown in this table,

Table 4&—Distribution of Waste Heat From aSupercharged Diesel Engine

Percent of Maximumtotal waste temperature

Heat source heat (Fo). ,

Engine cooling jacket . . . . . . . . 20 165-171Aftercoolers a. . . . . . . . . . . . . . . . 15 104-111Lubrication system . . . . . . . . . . 10 140-150Exhaust gasb. . . . . . . . . . . . . . . . 55 797-696aAftercoolers generally are used In temperate cllmates, with maximum

use occurring In the summer.bIn engines that are not supercharged, exhaust gas temperatures maybe cooler,

approximately 572° to 662° F.

SOURCE: Randall Noon and Thomas Hochstetler, “Rural Cegeneratlon: An Un-tapped Energy Source,” Public Power January-February 1981.

most of the waste heat is in the exhaust gases.The engine cooling jacket and lubrication systemtogether produce almost as much waste heat asthe exhaust gases, but at a much lower tempera-ture (15).

The hot exhaust gas from an existing power-plant fueled with natural gas can be used direct-ly in a waste heat boiler. Alternatively, water canbe preheated via heat exchange with the after-coolers, lubrication system, and cooling jacket,then flashed into dry steam through heat ex-change with the exhaust gas. Steam temperaturesas high as 850° F can be obtained in this man-ner (15).

For on-farm systems, a small powerplant (withdirect heat recovery or steam production, as de-scribed above) could be connected with an an-aerobic digester (using animal wastes as the feed-stock) producing biogas, or with a small gasifierthat converts biomass (e.g., crop residues) to low-or medium-Btu gas. However, as described inchapter 4, further development of combustionturbine or internal combustion engine technol-


ogy may be necessary if these systems are to oper-ate efficiently for long periods of time with low-or medium-Btu gas derived from lower qualityfeedstocks.

Potential Applications

Ethanol production is one promising applica-tion for rural cogeneration. Ethanol has beenshown to be a useful fuel for spark ignition en-gines, and it can be produced readily from renew-able biomass feedstocks (e.g., grains and sugarcrops). If ethanol is used as an octane-boostingadditive in gasoline, and if the ethanol is distilledwithout the use of premium fuels, then each gal-lon of ethanol can displace up to about 0.9 gallonof gasoline. However, if ethanol distilleries arefueled with oil, then ethanol production for gaso-hol could actually mean a net increase in oil use. *Moreover, the premium fuels usually consideredfor ethanol distilleries–diesel fuel and naturalgas–already are used widely in the agriculturalsector but often are in short supply. Using thesefuels in distilleries could aggravate any shortages.

One way to improve ethanol production’s pre-mium fuels balance is to cogenerate with existingsmall rural powerplants. The waste heat wouldbe flashed into dry steam (as described above),and the steam distributed into the distillation col-umns of the ethanol recovery system. To facilitatecooking (the process stage where starch grainsare ruptured for effective enzymatic action),steam above atmospheric pressure and at about300° F can be bled from the exhaust gas heat ex-changer. In addition, warm water can be bledfrom the aftercooler heat exhanger to soak themilled corn and speed up water absorption. Final-ly, heat for drying wet stillage into distillers driedgrain (which can be used as a livestock feed sup-plement) can be obtained either directly from theexhaust gas in a natural gas-fired plant, or by plac-ing an air-to-exhaust gas heat exchanger down-stream from the steam-producing heat exchanger(15). Figure 59 shows a schematic of ethanol co-generation with diesel engine heat recovery.

The waste heat from a 1 -MW powerplant oper-ating at full load (33o full-time operating days) is

*See Energy From Biological Processes (OTA-E-124; July 1980)for an in-depth analysis of ethanol production.

sufficient to produce around 600,000 gallons ofanhydrous ethanol per year with wet byproduct,or 300,000 to 400,000 gallons annually with drieddistillers grain byproduct (15).

Cogeneration also can be used for grain dry-ing, which requires relatively low-temperatureheat. Seed drying requires a temperature of ap-proximately 110° F, while milling drying requires130° to 1400 F depending on the crop, and ani-mal feed drying needs around 180° F. Thesetemperatures are well below those of exhaustgases, and thus, for grain drying, the exhaust gasof natural gas-fired powerplants can be mixedwith flush air and used directly (i.e., without heatexchangers). For plants that use fuels other thannatural gas, a heat exchanger may be requiredin order to recover the energy without contami-nating the grain with the exhaust gas. Due to thelow temperatures needed, waste heat from thecooling water or lubrication oil also can be recov-ered and used to dry grain (15).

The waste heat from a 1-MW powerplant coulddry grain at a rate of approximately 370 bushelsper hour. In the case of field-shelled corn, thiswould reduce the moisture content from around25 to about 15 percent—a safe level for storage.That grain-drying rate is comparable to that ofmany commercial dryers, and is sufficient for thegrain-drying needs of small communities (1 5).However, grain drying is a seasonal activity andother uses for the waste heat would have to be

Photo credit: Department of Agrlculture

Small existing powerplants can be retrofitted forcogeneration with the thermal output used for applications

such as drying grain


Figure 59.—Ethanol Cogeneration With Diesei Engine Waste Heat Recovery

Water

\ 1

Lubrication

Engine cooling jacket

!t

found in the off-seasons in order to optimize the

efficiency of the system.

In most cases, applying cogeneration to graindrying using existing powerplants will cost onlyslightly more than a conventional grain dryingfacility. A relatively small additional investmentwould be required for the engineering designneeded to interface the exhaust stacks (or heatexchanger) with the drier. The grain drying wouldneed flexible scheduling in order to coordinatewith the powerplant’s operation, especially whenexpected electricity demands do not materialize,but this is a relatively minor inconvenience. A

more important concern is that rural grain eleva-tors usually have low priority or interruptible serv-ice from natural gas suppliers (unless they usepropane). Any resulting shutdowns can be a seri-ous problem during a harvest season that is wetand cold, because the grain could spoil beforeit can be dried.

Drying crops with cogeneration can have signif-icant dollar and fuel savings advantages. If thecost of waste heat is set at so percent of the costper Btu for natural gas, then a facility drying 500bushels of grain per hour would save $11.25 perhour compared to the cost of using a separate

Ch. 5–industrial, Commercial, and Rural Cogeneration Opportunities ● 213

natural gas-fired dryer using $2.50/MCF gas forcontinuous operation, and the fuel cost savingswould amount to $7,000 per month (1 5).

Wood drying is similar in many respects tograin drying. Both commodities are dried priorto shipping to minimize moisture weight. Histor-ically, both drying processes have relied on rela-tively cheap and plentiful natural gas supplies,but can do so no longer. Furthermore, mostwood drying kilns, like grain drying facilities, re-quire relatively low-temperature heat–104° to117° F–although a few kilns may need tempera-tures above 212° F (1 5).

Because most modern wood drying kilns usenatural gas combustion units, the exhaust gasfrom a small powerplant can be substituted easilyfor the natural gas burner. A 1-MW powerplantwill produce approximately 8,000 MWh of usabledrying heat annually (based on 24 hours per day,330 days per year operation). This is sufficient todry as much as 11 million board feet of air driedhardwood or 6.5 million board feet of green soft-wood per year.

As with grain drying, substantial savings can begained through cogeneration/wood drying. Be-cause the basic design would not change in acogeneration retrofit, the capital and installationcosts of a cogenerating unit would not be sub-stantially more than those of a new conventionalgas-fired kiln. It is estimated that 2 to 5 MCF ofnatural gas would be saved for each 1,000 boardfeet of lumber that is dried with cogeneration.For the 1-MW powerplant drying 11 millionboard feet, this would mean a savings of 22000MCF/yr. If the cogenerated heat were sold at 50percent of the value of $2.50/MCF natural gas,$27,000 per year could be saved in fuel costs (1 5).Additional savings would accrue from the elec-tricity generation.

Fuel Savings

The three rural cogeneration applications de-scribed above—producing ethanol and dryinggrain or wood–rely on existing small power-plants fueled with oil or natural gas. In each case,fuel savings is assumed to result when the plant’swaste heat is recovered and substituted for a sec-

ond oil- or gas-fired facility. However, as dis-cussed earlier in this chapter, the fuel saved maynot always be oil. For example, recovering thewaste heat from a diesel oil fueled engine andsubstituting it for heat previously provided by anatural gas combustion unit will save gas but in-crease oil consumption. Similarly, if the wasteheat from a spark-ignition engine burning oil issubstituted for a boiler using coal or biomass, nooil would be saved.

As a result of these fuel use considerations, ruralcogeneration opportunities that use fuels otherthan oil (i.e., that do not rely on waste from anexisting powerplant) merit a good deal of atten-tion. These opportunities are based on the directfiring of cogenerators with fuels derived fromplentiful rural resources.

Wood wastes have long been the traditionalfuel in the forest products industry, which histor-ically has been the largest industrial—and rural—cogenerator. The cogeneration potential in theforest products industry was discussed earlier inthis chapter. At this point it will be sufficient tomention that, in the wood drying example citedabove, a steam turbine and boiler can be substi-tuted for the powerplant and natural gas-firedkiln. Although the capital costs of the boilersystem would be higher (about one boiler horse-power is needed to dry 1,000 board feet of hard-wood), and it would not produce as much elec-tricity, this system can burn wood wastes or coaland thus save oil or natural gas. Similarly, fuelsavings in ethanol distilleries will be greater if coalor biomass is used as the primary fuel for thecogenerator. Savings also can be achieved ingrain drying but the potential for contaminatingthe grain would be greater unless heat exchangerswere used.

Alternatively, internal combustion engines orgas turbines can be adapted to alternate fuels.These technologies, if successful, would requirea smaller investment for equipment than steamturbines, an important consideration for small dis-persed cogenerators. In some cases, fuel flexibilitycan be achieved through advanced engine de-sign, advanced combustion systems such as fluid-ized beds, or fuel conversion (synthetic gas or oil).The technical and economic aspects of using fuels

214 Industrial and Commercial Cogeneratlon

other than oil or natural gas in conjunction withcombustion turbines or internal combustion en-gines are discussed in detail in chapter 4. Twoapplications that are especially promising for ruralareas include gasification of crop residues andanaerobic digestion of animal wastes. However,small powerplants also can be modified to ac-commodate alternate liquid fuels such as ethanoland methanol, which can be made from relativelyplentiful rural biomass resources; these liquid fueloptions are discussed in more detail in OTA’sreport on Energy From Biological Processes.

Gasification of crop residues has been sug-gested as a means of providing relatively cheapnonpremium fuels for rural cogenerators. Onedemonstration project being developed in lowauses downdraft gasifiers to produce low-Btu gasfrom corn stover for use in retrofitted diesel en-gines. Some of the probable end uses for the ther-mal energy include grain drying, green houses,,dairies, food processing, space heating, or dry-ing the corn cob feedstock (22).

Downdraft gasifiers were selected for this proj-ect because they can generate producer gas thathas relatively low amounts of tars and other hy-drocarbons and is suitable for use in steam gen-erators, directly fired dry kilns, or internal com-bustion engines. Field tests with downdraft gasi-fiers in California have produced diesel qualityproducer gas successfully from corn cobs, walnutshells, and other crop residues (32).

The demonstration project focuses on station-ary diesel engines for several reasons. First, thewide number of domestic diesel models in placeallows a range of retrofit considerations to beevaluated. Second, a number of tests are under-way around the country using dual-fuel dieselsfired with 80 percent producer gas and 20 per-cent diesel oil. European firms have offered effi-cient commercial producer gas/diesel packagescapable of continuous operation on 90 percentgas/10 percent diesel oil since World War 1.Third, a large number of functional diesel power-plants are standing idle because of high oil prices.A recent survey showed that more than 70 lowacommunities have diesel generators with a totalcapacity of over 300 MW that operate at an aver-age capacity factor of less than 2 percent (22).

Finally, the projects will use corn cobs as thefeedstock because this is a relatively plentiful,clean fuel with a low ash and sulphur content.Moreover, they require no special handling (e.g.,baling, chopping) and they are easy to gather andstore. * Other possible biomass gasification com-binations for cogeneration include other types oforganic wastes (e.g., crop residues, wood waste)and wood from excess commercial forest produc-tion or intensively managed tree farms.

Cost estimates for this project are shown intable 47. Two rural test sites designed to demon-

*For an in-depth analysis of the technical, economic, and en-vironmental considerations related to the use of crop residues asa fuel or feedstock, see Energy From Biological Processes(OTA-E-124, July 1980).

Table 47.—Model Community Gasification/DieseiEiectric Generation Energy Cost Estimate

Operating data from the fuel rate calculations:Energy output: Maximum, 1,000 kW; average, 750 kWGas input for electrical powec 10.18 MMBtulhrSolid fuel input for electrical power: 1,810 Ib/hrFuel oil input for electrical power: 0.825 MMBtulhr at 7.5

percent of total energy input (5.9 gal/hr)

Costs-gasiWr plant:Equipment:

Gasifier system . . . . . . . . . . . . . . . . . . $259,610Installation . . . . . . . . . . . . . . . . . . . . . . 64,800Capital cost total . . . . . . . . . . . . . . . . . 324,410

Annualized at 5°/0 for 20 years . . . $33,670Diesel retrofit @ $150/kW . . . . . . . . . 150,000

Annualized at 8.25% for 20 yrs. . . 15,564Insurance at 2.5°/0 of plant cost . . . . 6,490

Total fixed costly r. . . . . . . . . . . . $55,724@ 6,570,000 kWh/yr, fixed cost = $0.0085/kWh

Operational cost6,570 hr/yr, operating at 75°/0 capacity:Fuel handler, 1 person, 40 hr/wk, w/fringes . . . . . 31,200Maintenance charge @ 5°/0 of plant cost . . . . . . . 16,200

Fuel costs:Diesel oil @ $1.15/gal x 38,716 gal . . . . . . . . 44,523Corn cobs at 18.80/T x 5,979 T/yr . . . . . . . . . 112,400

Total operational costs . . . . . . . . . . . . . . . . . . . . $204,3236.57 MMkWh/yr, operational costs/kWh = $0.0311

Total cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .$O.0396/kWh

Cost of hot producer gas from gasifierOperating at 90°/0 capacity; with gas conversion efficiency

of 850/o1,810 lb cobs/hr x 8,760 hr x 0.90 = 7,135 T/yr @

$18.80~ = (fuel) . . . . . . . . . . . . . . . . . . . . . . . . $134,138Labor, maintenance, amortization, Insurance. . 87,560Total cost. .$221,698(7,135 T cobs x 15 MMBtu x 0.85

efficiency) = $2.441 MMBtuSOURCE: J. J. O’Toole, et al., “Corn Cob Gasification and Diesel Electric Genera-

tion,” in Energy Technology VIII: New Fuels Era Richard F. Hill (cd.)(Rockville, Md.: Government Institutes, Inc., 1981).


strate the technical and economic feasibility ofdowndraft gasifiers using corn cobs to producelow-Btu gas for diesels have been identified. Thesites (in Iowa) have different diesel models andusage patterns as well as different biomass re-source concentrations (one town has a localsource of excess corn cobs, one must set up acollection and transportation system on neighbor-ing farms). Thus, the sites will allow a sensitivityanalysis on a wide range of variables, includingenergy prices, Btu value, moisture content, farm-er participation rate, and cob processing costs.Economic modeling for the project will yield dataon agricultural production for the site, the quan-tity of cobs used, the system kWh costs, emis-sions, and energy balance. If these and other testsyield positive results, then gasification of cropresidues could become an important source ofenergy for diesel cogeneration in rural communi-ties—one that enables those communities to useexisting local resources and equipment at a costcompetitive with energy from central stationpowerplants.

A second rural cogeneration option is the an-aerobic digestion of animal wastes to producebiogas (a mixture of 40 percent carbon dioxideand 60 percent methane). The national energypotential of wastes from confined animal opera-tions is relatively low—about 0.2 to 0.3 Quad/yr–but other important benefits are that anaerobicdigestion also serves as a waste treatment proc-ess and the digester effluent can be used as a soilconditioner, or dried and used as animal bedding,or possibly treated and used as livestock feed.Digesters for use in cattle, hog, dairy, and poultryoperations are now available commercially andare being demonstrated at several sites in theUnited States. * Wastes from rural-based indus-tries (e.g., whey from cheese plants) also are be-ing used as a feedstock for farm-based digesters.

In a typical digester system (see fig. 60), a set-tling pond is used to store the manure prior todigestion. The digester consists of a long tank intowhich the manure is fed from one end. After sev-eral weeks, the digested manure is released atthe other end and stored in an effluent lagoon.

*For a detailed analysis of anaerobic digestion of animal waste,see Energy From Biologica/ Processes (OTA-E-1 24, July 1980).

Figure 60.-Anaerobic Digester System


Gas exits from the top of the digester tank, thesmall hydrogen sulfide content is removed if nec-essary, and the biogas is used to fuel an internalcombustion engine that drives an electric gener-ator. The system supplies electricity for onsite use(or for export Off-Sit@. The heat from the enginecan be used onsite for a variety of purposes, in-cluding heating the animal shelter or a green-house (that could also use the soil conditioningeffluent), or for crop drying, or even residentialspace heating.

Finally, it should be noted that the above appli-cations can be combined in farm energy com-plexes that integrate methane and alcohol sys-tems so that waste heat and byproducts are uti-lized more fully. For example, the waste heatfrom generating electricity with biogas can beused in alcohol production, while spent beerfrom the distilling process can be used as a di-gester feedstock. Moreover, the waste heat froma generator often is used to help maintain anoptimum digester temperature.

Summary

Significant energy and economic savings canbe achieved with cogeneration in rural areas.Communities can improve the economics of op-erating small powerplants by recovering wasteheat for use in distilling ethanol, drying grain or

wood; heating homes, greenhouses, or animalshelters, and other applications; or by retrofittingexisting powerplants to accommodate alternate

216 Industrial and Commercial Cogeneratlon

fuels. In addition, significant oil savings can be economy rather than being recirculated to pro-achieved if the cogenerator uses alternate fuels duce a second round of local income. Develop-or replaces two separate oil-fired systems. ing cogeneration opportunities could double the

Although the rural cogeneration potential is notproductive energy output of rural powerplants,creating significant local economic expansion in

so large as that in industry and urban applications, both public revenues (from electric and thermalthe cost and fuel savings can be very importantfor farms and rural communities. in rural econo-

energy sales) and private income (from new jobs)

mies, much of the gross income escapes the localwithout increasing the base demand of energy.

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

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13.

14,

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18

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21

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23.

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24. Resource Planning Associates, Inc., The Potentialfor Cogeneration Development in Six Major Indus-tries by 7985 (Cambridge, Mass.: Resource Plan-ning Associates, Inc., December 1977).

25. Rosenthal, Arnold, Consolidated Edison Co. ofNew York, private communication to OTA.

26. Schlesinger, Ben, American Gas Association, pri-vate communication to OTA.

27. Solar Energy Research Institute, A New Prosper-ity (Andover, Mass.: Brick House Publishing Co.,Inc., 1981).

28. SRI International, et al., Draft Environment/ Im-pact Statement, Small Power Production and Co-generation Facilities–Qualifying Status/Rates andExemptions (Washington, D. C.: U.S. GovernmentPrinting Office, FERC/EIS-0019/D, June 1980).

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Chapter 5 Industrial, Commercial, and Rural Cogeneration Opportunities