Chapter 2

Issues and Findings

Contents

PageWhat ls Cogeneration? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Will Cogeneration Save Oil? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Under What Circumstances Are Available Cogeneration Technologies Attractive?.. . . . 28What Are Some Promising Future Cogeneration Technologies? . . . . . . . . . . . . . . . . . . . . 29Will Cogeneration Be Competitive With Conventional Thermal and

Electric Energy Systems?. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31What Are the lndustrial Cogeneration Opportunities?. . . . . . . . . . . . . . . . . . . . . . . . . . . . 32What Are the Opportunities for Cogeneration uncommercial Buildings? . . . . . . . . . . . . 34What Are the interconnection Requirements for Cogeneration? . . . . . . . . . . . . . . . . . . . 35Who Will Own Cogenerators? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38What Are the Potential Effects of the PURPA lncentives?. . . . . . . . . . . . . . . . . . . . . . . . . 39What Are the Potential Economic impacts of Cogeneration on Electric Utilities?. . . . . . 40What Are the Environmental impacts of Cogeneration? . . . . . . . . . . . . . . . . . . . . . . . . . . 43Chapter p references. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

TablesTable No. Page3. interconnection Costs for Three Typical Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 374. Considerations in Determining Avoided Costs Under PURPA . . . . . . . . . . . . . . . . . . . 415. Effect of Cogeneration Characteristics on Air Quality . . . . . . . . . . . . . . . . . . . . . . . . . . 43

FiguresFigure No. Page3. illustrations of Topping Cycle Cogeneration Systems . . . . . . . . . . . . . . . . . . . . . . . . . . 264. Schematic of a Bottoming Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275. Schematic of a Combined-Cycle Cogenerator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296. Fuel Cell Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307. Schematic of a Stirling Engine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Chapter 2Issues and Findings

WHAT IS COGENERATION?Cogeneration is the combined production of

two forms of energyelectric or mechanicalpower plus useful thermal energyin one tech-nological process. The electric power producedby a cogenerator can be used onsite or dis-tributed through the utility grid, or both. The ther-mal energy usually is used onsite for industrialprocess heat or steam, space conditioning, and/orhot water. But, if the cogeneration system pro-duces more useful thermal energy than is neededonsite, distribution of the excess to nearby facil-ities can substantially improve the cogeneratorseconomics and energy efficiency.

The total amount of fuel needed to produceboth electricity and thermal energy in a cogener-ator is less than the total fuel needed to producethe same amount of electric and thermal energyin separate technologies (e.g., an electric utilitygenerating plant and an industrial boiler). It isprimarily this greater fuel use efficiency that has

created a resurgence of interest in cogenerationsystems. However, cogeneration also can be at-tractive as a means of adding electric generatingcapacity rapidly at sites where thermal energyalready is produced.

Cogeneration technologies are termed top-ping cycles if the electric or mechanical poweris produced first, and the thermal energy ex-hausted from power production is then capturedand used (see fig. 3). Bottoming cycle cogener-ation systems produce high-temperature thermalenergy first (e.g., for steel reheating or aluminumremelting), and then recover the waste heat foruse in generating electric or mechanical powerplus additional, lower temperature thermal ener-gy (see fig. 4). Topping cycle cogenerators wouldbe used in residential, commercial, and most in-dustrial applications, while bottoming cycle appli-cations would most likely arise from high-temper-ature industrial processes.

WILL COGENERATION SAVE OIL?Cogeneration is widely acclaimed as a conser-

vation technology because it uses less fuel (meas-ured in Btu equivalents) to generate a givenamount of electricity and useful thermal energythan separate conventional energy systems (e.g.,a powerplant and an industrial boiler; see fig. 2).However, just because cogeneration is more fuelefficient does not mean that it will automaticallyreduce oil consumption.

Whether cogeneration will save oil (or naturalgas, or any other particular fuel) depends on thefuel burned by a cogenerator and the fuel usedin the separate electric and thermal energy pro-ducing systems the cogenerator displaces. ifboth of these separate systems would burn oil,and continue to burn oil for most of the op-erating life of an oil-fired cogenerator that re-placed them, then an oil burning cogeneratorwould reduce total oil consumption. This sav-

ings can range from a 15-percent reduction in oiluse when a steam turbine cogenerator is substi-tuted for a steam electric powerplant and aseparate low-pressure steam boiler, to a 34 per-cent savings if a diesel cogenerator that converts38 percent of the fuel energy to electricity (30 per-cent to useful thermal energy) replaces separateoil-fired powerplants and furnaces.

However, if a cogenerator that will burn oilduring most of its useful life replaces either apowerplant or a conventional furnace or boilerthat uses a different fuel (e.g., coal, wood), orthat plans to convert to a different fuel duringthe useful life of the cogenerator, then oil burn-ing cogeneration will actually increase total sys-tem oil use. Therefore, cogeneration will onlysave oil if it uses an alternate fuel itself (e.g., coal),or if it replaces separate electric and thermal ener-gy systems that use (and will continue to use) oil.

25

26 l Industrial and Commercial Cogeneration

Figure 3.illustrations of Topping Cycle Cogeneration Systems

Combustion turbine

Air and

ir

High-t

Diesel engine

Air and

Steam turbine

Diesel engine

f u e l - - - > ity

Jacket cooling

steam

Heat-recovery boiier

m

Steam generator (boiler)SOURCE: Resource Plannlng Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washlngton, D. C.: U.S. Department of Energy, DOE-FFU-1703,

1978).

Ch. 2issues and Findings . 27

(w

Figure 4.Schematic of a Bottoming Cycle Cogenerator

Exhaust

r

t out

Regenerator

SOURCE: Resource Planning Associates, Cogeneration: Technical Concepts, Trends, Prospects (Washington, D. C.: U.S. Department of Energy, DOE-FFU-1703, 1978).

This finding is especially important for threereasons. First, most commercially available co-generation technologies require clean premiumfuels such as oil or natural gas (see ch. 4). Steamturbine cogenerators can burn coal or other alter-nate fuels such as biomass or solid waste, but maybe prevented from doing so due to site or envi-ronmental considerations. Advanced cogenera-tors that can use alternate fuels may not be avail-able for several years. Second, although industrialprocesses and, to a lesser extent, electric utilities,are heavily dependent on oil and natural gas,both groups already plan to reduce their use ofthese fuels either through conservation or con-version to alternate fuels or both. Third, althoughthe Powerplant and Industrial Fuel Use Act of1978 (FUA) prohibits the use of oil and naturalgas in new powerplants and boilers, cogeneratorsare exempt from these prohibitions if less thanhalf of their annual electric output is sold or ex-changed for resale, or if they are relatively small(less than about 10 megawatts per unit (MW/unit)

or 25 MW/site, assuming a 10,000 Btu per kilo-watthour (Btu/kWh) heat rate), or if they candemonstrate a net savings of oil or gas.

When these three considerations are combinedwith economic conditions that favor cogenera-tion (e.g., high retail electricity rates), the com-bination could outweigh market considerationsand result in oil-fired cogeneration that wouldlock industrial or commercial cogenerators intopremium fuel use for 10 to 20 years or more. Onthe other hand, if oil cogeneration is used onlywhere premium fuel savings are sure to result(i.e., where both the electric and thermal systemsthe cogenerator replaces would continue to burnoil for most of the operating life of the cogener-ator), or where conversion to alternate fuels willbe possible in the near term (e.g., a dual-fuel sys-tem that can convert from oil to synthetic gaswhen gasification technology is improved), theneven oil-fired cogeneration can pose significantoil savings.

28 l Industrial and Commercial Cogeneration

UNDER WHAT CIRCUMSTANCES ARE AVAILABLE COGENERATIONTECHNOLOGIES ATTRACTIVE?

The commercially available cogeneration tech-nologies described in this report include steamturbines, open-cycle combustion turbines, com-bined-cycle systems, diesels, and steam Rankinebottoming cycles. All of these technologies willprovide energy savings because their fuel efficien-cy is greater than that of the separate electric andthermal energy systems they will replace, buttheir comparative technical, economic, and fueluse advantages vary (see table 1 and ch. 4; fora review of their relative environmental advan-tages, see, What Are the Environmental Impactsof Cogeneration?).

A steam turbine topping cycle cogenerator (seefig. 3) produces thermal energy at moderate tem-peratures and pressures that are suitable for manyindustrial applications that do not need high-tem-perature heat. Available steam turbines have arelatively high overall efficiency, but their ratioof electricity generated to thermal energy pro-duced (electricity-to-steam (E/S) ratio) is relativelylow. Therefore, steam turbine cogenerators are usu-ally not appropriate where large electricity require-ments are paramount, such as the need to pro-vide power to the grid to improve economic feasi-bility. In addition, steam turbines can have rel-atively high unit costs, longer startup times andinstallation Ieadtimes than other available cogen-erators, and more stringent personnel require-ments specified by boiler codes. On the otherhand, steam turbines are extremely reliable, andcan use a wider range of fuels more easily thanother cogeneration technologies, including coal,biomass, and solid wastes, as well as coal-derivedliquids and gases when they become available.

Open-cycle combustion turbine topping cycles(see fig. 3) have a higher E/S ratio and producehigher temperature steam than steam turbines.Therefore, combustion turbines can meet theelectric and thermal needs of more types of in-dustries and are more likely to produce excesselectricity that may be exported to the grid. Com-bustion turbines unit cost and construction timeare relatively low while their reliability is compar-able to that of steam turbines. Combustion tur-

bines are available in a wider range of unit sizesthan steam turbines, and the lower capacity units(i.e., below 7 MW) may be attractive for commer-cial facilities (such as shopping centers, apart-ments, hotels) because they are small in size andcan be operated remotely. Combustion turbinesalso are well suited to arid climates because theyrequire no cooling water. Finally, although open-cycle combustion turbines cannot now use solidfuels such as coal or wood directly, they will beable to use synthetic gas or liquid fuels derivedfrom coal or biomass, and units using pulverizedwood directly are under development.

Combined-cycle cogenerators (combinedsteam turbine and combustion turbine systems;see fig. 5) increase electric power output at theexpense of recoverable heat. They have a higherE/S ratio than either a steam or combustion tur-bine alone, and thus will be most attractive insituations where electricity requirements are rel-atively high, or where electric power can be dis-tributed to the grid economically. Their unit ca-pacity also tends to be greater than either of theseparate turbine systems. Currently availablecombined-cycle systems require too much spacefor most commercial applications, but they shouldbe well suited to larger industrial facilities. Theirunit cost and installation Ieadtime are higher thancombustion turbines, but comparable to medi-um- or large-size steam turbines. Furthermore,while combined cycles availability is lower thaneither system alone, their overall fuel efficiencyis higher. Finally, combined cycles can use thefull range of fuels and will be readily adaptableto fluidized bed combustion systems.

Diesel cogenerators (see fig. 3) have a higherE/S ratio than the technologies described above,and thus will be very attractive for facilities withhigh electricity demand but low thermal energyneeds (i.e., most commercial building applica-tions and many smaller industries), or where elec-tricity can be distributed to the grid economically.Diesels relatively high efficiency, low cost, shortinstallation Ieadtime, long service lifetime, andestablished service infrastructure all contributeto their attractiveness. However, diesels also can

Ch. ZIssues and Findings l 29

Figure 5.Schematic of a Combined-Cycle Cogenerator

Mechanic~inefficiency Generator inefficiency

SOURCE: Resource Planning Associates, Cogeneration: Technical Concepts, Trends, prospects (Washington, D. C.: U.S. Department of Energy, DOE-FFU-1703, 1978).

have high maintenance costs and may be lessacceptable environmentally due to their poten-tially high nitrogen oxide and particulate emis-sions. In addition, currently available diesel tech-nologies must burn oil or gas (some are dual-fueled), although they will be able to use synthet-ic fuels. Diesels capable of burning powderedcoal or coal slurries are under development, butit is unclear whether they will be economicallycompetitive with other types of cogenerators.

Rankine steam bottoming cycles (see fig. 4) areconceptually different from the technologies sum-marized above in that high-temperature processheat is produced first, then waste heat from the

thermal process is used to produce electric ormechanical power plus additional lower tempera-ture thermal energy. Because waste heat is usedto generate electricity, Rankine bottoming cyclescan present even greater fuel savings than top-ping cycle cogenerators. The cost, average an-nual availability, and construction Ieadtime ofRankine steam bottoming cycles are comparableto steam turbines, while their expected servicelife is approximately equal to combustion tur-bines, combined cycles, and diesels. Unit capac-ity, however, often is smaller than other cogener-ation systems. Rankine steam bottoming cyclestypically are considered for industrial applicationswith very high-temperature heat needs.

WHAT ARE SOME PROMISING FUTURECOGENERATION TECHNOLOGIES?

Current research and development efforts on cumstances Are Available Cogeneration Technol-cogeneration are directed toward both improve- ogies Attractive?) and the development of newments in existing systems (see, Under W/hat Cir- technologies. The primary concerns in these ef-

30 l INdustrial and Commercial Cogeneration

forts include the ability to burn fuels other thanoil and gas (e.g., coal, biomass, solid waste), im-proved fuel efficiency, increased electrical out-put, and lower capital and operating costs (seech. 4).

Advanced steam turbine cogenerators withhigher steam pressures and temperatures, andthus greater electric generating efficiency, shouldbe available between 1985 and 1990. Much ofthe research on steam turbines is aimed at im-proving the efficiency of smaller systems (less than7 MW), while reducing their cost. Similarly, re-search on open-cycle combustion turbines is di-rected toward increasing efficiency throughhigher inlet temperatures by improving turbineblade cooling or making materials changes inblade composition. Materials changes also wouldimprove the anticorrosive properties of turbineblades and thus would allow combustion turbinesto use solid fuels (municipal solid waste, pulver-ized coal, etc.). However, as with steam turbines,capital and operating costs for advanced com-bustion turbines are likely to be slightly higherthan present costs. Improvements in combined-cycle systems include the advances in combus-tion turbines, as well as the development ofsmaller combined cycles with a wider range ofpotential applications. Finally, advanced dieselcogenerators are being developed that use coal-derived fuels, and have a much greater poweroutput, as well as those for which all the recov-ered thermal energy could be high-quality steam.Each of these improvements in the diesel cogen-erator should be commercially available by 1990,but not all in the same system.

Advanced cogeneration technologies that arenot now available commercially include closed-cycle combustion turbines, organic Rankine bot-toming cycles, fuel cells, and Stirling engines (seetable 1 and ch. 4). (Solar cogenerators, such asthe therm ionic topping system, are not discussedin this report.)

Closed-cycle, externally fired combustion tur-bines are not available commercially in theUnited States but are well developed in Europeand Japan. These systems are potentially very at-tractive because they can use a wide variety offuels (including coal), have a relatively high effi-

ciency and E/S ratio, and should be priced com-petitively with other topping cycle cogenerators.They will be attractive primarily in larger industrialand utility applications.

Organic Rankine bottoming cycles evaporateorganic working fluids (e.g., toluene) to produceshaft power, and can operate efficiently at lowertemperatures and in smaller sizes (i.e., 2 kW to2 MW) than steam bottoming cycles. Becausethey use lower temperature heat, they can beadapted to a wide variety of heat sources, includ-ing solar, geothermal, and industrial waste heat,or engine exhausts. However, they currently re-quire more maintenance than most topping cy-cles, and further development and demonstra-tion are necessary before the organic Rankinebottoming cycle can be considered a maturetechnology.

Fuel cells (electrochemical devices that con-vert the chemical energy of a fuel directly intoelectricity with no intermediate combustion cyclesee fig. 6) are potentially attractive cogeneratorsdue to their modular construction, good electri-cal-load-following capabilities, automatic opera-tion, ability to use coal-derived fuels, and lowpollutant emissions. In addition, fuel cells couldbe adapted to a wide range of sizes and applica-tions, from small (40 to 500 kW) residential andcommercial systems to larger industrial and utilityplants (5 to 25 MW). Although fuel cell demon-

Figure 6.Fuei CellHydrogen-rich gas and C02

from shift converter

1Porousanode

( - )Electrolyte

(phosphoricacid)

Porouscathode

(+)

OperationC02 and unreacted

hydrogen

Ch. 2Issues and Findings l 31

stration plants are under construction, commer-cial readiness is still at least 5 years away. Theprimary development concerns include some-what high capital costs and short service life.

Finally, Stirling engines (see fig. 7) could offeran attractive alternative to available topping cy-cles because of their ability to use coal and othersolid fuels, their high thermal and part-load effi-ciency, and their low emissions, noise, and vibra-tions. Stirling engines also could be used as com-ponents of solar energy systems or as adjunctsto fluidized bed combustors, nuclear reactors, orother conversion technologies. Current researchefforts are directed toward improved efficiencyand solid fuel combustion characteristics, as wellas lower capital costs, before Stirling engines canbe considered commercial. Because they pro-duce relatively low-temperature recoverableheat, Stirling engines will be most attractive forwater heating or in facilities with relatively smallprocess heat requirements.

In addition to the cogeneration technologiesreviewed above, two types of advanced combus-tion systems may be attractive for increasing co-generators fuel flexibility: gasifiers and fluidizedbed combustors. Gasifiers would convert coal,pet coke, or other solid fuels to medium-Btu gas(about 300 Btu/standard cubic foot) for distribu-tion to cogenerators (or other facilities) withinabout a 100-mile radius. Gasification could cen-tralize the use of solid fuels, and thus eliminatecogenerators need for coal storage and handlingfacilities. However, gasification is not yet a prov-en technology, although both small- and large-scale systems are being demonstrated. Whethersuch a scheme will be successful is heavily de-

Figure 7.Schematic of a Stirling Engine

duct

SOURCE: Application of Solar Technology to Todays Energy Needs (Waehlngton,D. C.: U.S. Congress, Office of Technology Assessment, OTA-E86, June1978).

pendent on the capital costs, which are still highlyuncertain. Fluidized bed combustors can accom-modate a wide range of solid fuels, and operateat a lower temperature and pose fewer environ-mental and operating problems than convention-al boilers. Fluidized beds can be adapted to fireseveral different types of cogeneration technol-ogies. Atmospheric fluidized bed systems couldbe used with steam or combustion turbines orcombined cycles, while pressurized systems coulddrive combustion turbines or combined cycles.Fluidized bed combustors are now being demon-strated and could become commercial within afew years.

WILL COGENERATION BE COMPETITIVE WITH CONVENTIONALTHERMAL AND ELECTRIC ENERGY SYSTEMS?

Cogeneration is most likely to be competitive oil-fired cogeneration will only save oil in awith conventional separate electric and thermal few circumstances (see, Will Cogeneration Saveenergy technologies when it can use relatively oil?). Moreover, the price gap between oil/gasinexpensive, plentiful fuels, and where there are and other fuels is likely to become wider overlarge thermal energy needs or it can meet on- time. Therefore, cogenerators will have to usesite energy needs while supplying significant relatively inexpensive and plentiful fuels (suchamounts of electricity to the utility grid. as coal, biomass, or solid wastes) in order to be

32 l Industrial and Commercial Cogeneration

economically competitive with utility generatingcapacity over the long run (10 to 20 years andbeyond). Alternatively, if the utilitys avoided costis determined by the price of oil, or if the utilityis primarily dependent on oil-fired capacity, thennatural gas may remain economically attractiveas a cogeneration fuel for several years. In theshort term, it is possible that cogenerators maybe able to rely on natural gas as a transition meas-ure until synthetic gas from coal or biomass be-comes widely available at a competitive price.However, if gasifier technology or planned ad-vances in the fuel flexibility of cogeneration tech-nologies are not available as soon as expected,or synthetic gas is not competitive in price withnatural gas, this strategy could lock cogeneratorsinto premium fuel use for many years.

For cogeneration to be economically attrac-tive, there usually must also be substantial ther-mal loads. Sites with low loads (e.g., less than50,000 lb/hr of steam) due to conservation meas-ures or limited process needs, or with fluctuatingloads, generally would not be economically com-petitive with conventional steam boilers and util-ity-supplied electricity. Thus, commercial build-ings are likely to have a low potential forcogeneration because of their very low thermalload factors. In some cases, however, cogenera-tors can be undersized and operated at a highcapacity factor to meet the base thermal load,with conventional boilers or furnaces used whennecessary to meet the remaining thermal demand(see, What Are the Opportunities for Cogenera-tion in Commercial Buildings?).

Finally, cogenerations ability to meet onsitethermal and electrical needs, or to meet the

thermal needs and supply significant amountsof power to the utility grid, will be a major deter-minant of its economic competitiveness. In theregions where electric utilities have substantialamounts of generating capacity fueled by oil ornatural gas, or where demand growth is signifi-cant (primarily the Northeastern States and Cali-fornia, and to a lesser extent the South Atlanticand West South-Central States), cogeneration willbe more attractive when it can supply significantamounts of electricity to the grid (see, What Arethe Potential Effects of the PURPA Incentives?).Alternatively, if the utility has substantial excesscapacity or primarily uses coal or other non-premium fuels, and avoided costs are low or retailelectricity rates are high, a cogenerators eco-nomic competitiveness will depend primarily onits ability to reduce onsite energy costs.

These determinants of cogenerations econom-ic competitiveness will affect the choice of cogen-eration technologies. Of the technologies thatare commercially available, only the steam tur-bine topping and Rankine cycle bottoming sys-tems can use fuels other than oil/gas. However,bottoming cycles usually are limited to special-ized applications that require high-temperatureheat, while steam turbines have low E/S ratios(see, Under What Circumstances Are AvailableCogeneration Technologies Attractive?). Systemswith higher E/S ratios that will be able to use alter-nate fuels are under development or demonstra-tion, as are advanced combustion technologiessuch as fluidized beds and gasifiers, and shouldbe available commercially by the mid to late1980s (see, What Are Some Promising FutureCogeneration Technologies?).

WHAT ARE THE INDUSTRIAL COGENERATION OPPORTUNITIES?Cogeneration of electricity and thermal energy at which the thermal load is sufficient to justify

for industrial processes is a proven concept, an investment in a cogeneration system) is highwith approximately 9,000 to 15,000 MW of co- perhaps as much as 200 gigawatts (GW), or aboutgeneration capacity in operation at industrial 32 percent of current U.S. generating capacity.sites throughout the United States (see table However, the market potential (the amount for2), and at least 3,300 MW in the planning stage which an investment is likely to be made) is muchor under construction. The technical potential lower due to economic and institutional consid-for industrial cogeneration (the number of sites erations.

ll

l

l

versions of existing process technologiesnow under development will have greaterfuel flexibility, higher fuel efficiency, andhigher electricity output.Whether cogeneration retrofits are feasibleor new plants will be built: For instance,petroleum refineries are well suited to cogen-eration, and some existing refineries couldbe upgraded, resulting in the production oflow-Btu gas suitable for onsite cogeneration.But, few new refineries are likely to be builtexcept in areas such as California, which hasspecial requirements related to enhanced oilrecovery.Whether a plants operating pattern makescogeneration economic: Many food process-ing plants operate only during harvest sea-son, and the resulting low capacity factormay make cogeneration economically infea-sible. However, the food processing seasonoften overlaps the hottest months when irri-gation and air-conditioning loads contributeto peak demands on electric systems in ruralareas, the seasonal price for utility generatedpower is often very high and/or its reliabilityis low. As a result, this industrys seasonaloperating pattern can be outweighed by itspotential for lower energy costs.The availability of capital for investmentsin cogeneration: Industrial firms typically re-quire shorter payback periods for their in-vestments than cogeneration may be able toprovide, although current accelerated depre-ciation measures and investment and energytax credits can improve the payback signifi-cantly. Cogeneration also must compete foravailable capital with process equipment orother investments that improve an industryscompetitive position (as well as with conser-vation measures, as mentioned above).Third-party or utility ownership can improvecapital availability (see, Who Will Own Co-generators?), as can low interest loans andother financing measures that alleviate theeffects of high interest rates and capitalshortages.Whether there is a match between a plantsneeds and the cogenerators output: An in-dustry may need more or less thermal or

34 . Industrial and Commercial Cogeneration

l

electric energy than a cogenerator provides.usually the technology will be chosen to op-timize the match between load and output,but this will not always be possible. The PubIic Utility Regulatory Policies Act (PURPA) re-quirements that electric utilities offer to buypower from and sell power to cogeneratorscan mitigate an electricity supply and de-mand mismatch, but the economics may notalways be favorable to the cogenerator (see,What Are the Potential Effects of the PURPAIncentives?). In some cases, industrial parkswith central cogenerators and shared energyproducts through dedicated distribution sys-tems may be an attractive solution to ther-mal and electric supply/demand mis-matches.Regulatory uncertainty and perceived risks:Doubt about the continued availability of theeconomic and regulatory incentives offeredby PURPA, the fuel use and pricing provi-sions of FUA and the Natural Gas Policy Act,and the various tax incentives for investmentin cogeneration (e.g., investment and energytax credits, accelerated cost recovery, safe

harbor leasing) can be a significant deterrentto investment in cogenerators. Similarly, un-certainty about interest costs and capitalavailability, fuel costs, investment paybackperiods, the use of solid fuels, and environ-mental regulation can be disincentives to theimplementation of cogeneration projects.

All of the above factors could lead industrialmanagers to adopt a wait-and-see attitude to-ward cogeneration. As a result, widespread de-ployment of industrial cogeneration capacitycould be delayed a decade or more. But the res-olution of legal and regulatory uncertainties, therapid development and demonstration of ad-vanced technologies that can burn solid fuelscleanly, and lower interest rates or innovativefinancing and ownership arrangements couldsubstantially improve industrial cogenerationsmarket potential. In addition, if natural gas pricesare seen to be lower than distillate for an ex-tended periodlo to 20 yearsan industry mightdecide it is worth the investment risk if their pur-chase power rates are based on oil.

WHAT ARE THE OPPORTUNITIES FOR COGENERATIONIN COMMERCIAL BUILDINGS?

Although the opportunities for cogeneration incommercial buildings depend on the same gen-eral factors as industrial cogenerationthermalenergy demand, availability of capital, competi-tion with conservation, capability of using non-premium fuels, etc. there are characteristicsabout buildings that constrain cogeneration morethan in industry.

In the near termthe next 10 to 15 yearscom-mercial cogeneration will be fueled predom-inantly by natural gas. Coal-fired units can beused but these will be limited because of the dif-ficulties of handling and storing coal in andaround commercial buildings. Therefore, theprincipal determinants for commercial cogener-ation for the near term will be the price andavailability of natural gas, and either the priceof electricity from central station units or theprice that utilities will pay for electricity from

cogenerators as set by their public utility commis-sions. For those regions where the latter is set ator near the price of oil-fired electricity and theutilities have oil or natural gas fueled capacity,commercial cogeneration fueled by natural gashas a promising market even if natural gas pricesshould approach those of distillate fuel oil. Theprimary advantage of commercial cogenerationin these cases is that it allows rapid developmentof new capacity to meet new demand and/or toreplace the utilitys oil-fired capacity.

Under least cost conditions, cogenerated elec-tricity will be produced and sold when it is lessexpensive than central station electricity (see,Will Cogeneration Be Competitive With Con-ventional Thermal and Electric Energy Systems?).Net fuel savings by cogeneration compared toseparate production of electricity and heat, how-ever, may be less than that indicated by the

Ch. 2Issues and Findings l 35

amount of electricity sold because of the very lowthermal load factors of commercial buildings. Themost promising arrangement for commercialbuildings probably would be to undersize thecogenerator and operate it at a high capacityfactor to meet the base thermal load, and useconventional thermal energy systems when nec-essary to meet the remaining load. This allowsa high degree of heat recovery and efficient cap-ital utilization. Alternatively, the diversity addedby using several buildings for heating loads couldgreatly increase net fuel savings. This also meansthat buildings located in regions with high ther-mal loads (about 6,000 degree days or higher peryear) will be the most attractive candidates forcogeneration.

However, in both the near and long term,commercial cogeneration will compete withconservation-especially in new buildings. Con-servation will very likely be more economic thancogeneration for most of the Nations buildings.Further, the more efficient a building is, the lowerits thermal demands and the less attractive cogen-eration becomes. This is particularly significantwhen capital is scarce. Utility ownership may beone way of reducing the severity of the latter con-cern (see, Who Will Own Cogenerators?).

For the longer term, beyond 10 years, com-mercial cogeneration ultimately must competewith new coal-fired or, possibly, nuclear capac-ity. It is unlikely that natural gas-fired cogenera-tion will be able to compete economically withnew coal-fired central station capacityeven withbyproduct credit for displacing natural gas forspace heatingunless natural gas prices stay wellbelow distillate oil. This is not likely to be the case

toward the end of the century as supplies of con-ventional natural gas diminish. Where electricitygrowth rates are high (greater than 2 percent peryear) and thermal demands are high (6,000 de-gree days or higher per year), however, naturalgas-fired commercial cogeneration, even at highgas prices, could be competitive for new interme-diate and peaking electric loads or for cases inwhich coal use is limited.

Cogeneration directly fired by coal with newtechnologies, such as fluidized bed combustion,or indirectly through low-Btu gasification andcombined-cycle systems, could compete withnew central station coal capacity (see, What AreSome Promising Future Cogeneration Technol-ogies?). Some current analyses indicate that thiswill be so, but the OTA analysis of synthetic fuelsfor transportation shows that there is considerableuncertainty with respect to cost of synfuels pro-duction (6). Other promising possibilities arecombined-cycle systems fired by biomass or solidwaste gasifiers. These new technologies do noteliminate the coal or biomass handling problem,however, which will still act to inhibit cogener-ation.

Finally, environmental considerations are like-ly to be more important for commercial build-ings than for other cogeneration applications.This is due in part to the potential for increasedemissions with the technologies that are mostsuited to commercial building applications, andin part to the inherent characteristics of the urbanenvironment (e.g., proximity of buildings to eachother, urban meteorology; see, What Are theEnvironmental Impacts of Cogeneration?).

WHAT ARE THE INTERCONNECTION REQUIREMENTSFOR COGENERATION?

In the past, electric utilities and the agencies into the grid. These two-way power flows havethat regulate them have only been concerned raised concerns about the technical and safetywith power flows from the central grid to cus- aspects of interconnection and integration withtomers, or from one utility to another. However, the grid, about liability for any damage that maythe economic and other incentives offered to co- result from improper interconnection, and aboutgeneration under Federal (and some States) law the costs of the equipment needed for proper in-assume that cogenerators may feed power back terconnection and integration. OTA found that

36 l Industrial and Commercial Cogeneration

most of the technical aspects of interconnectionand integration with the grid are relatively wellunderstood, although some electric utilities stillhave reservations. Rather, the primary issues reIated to interconnection are the costs of theequipment and the utilities legal obligation tointerconnect.

The technical aspects of interconnection aboutwhich utilities are concerned include maintain-ing power quality, metering cogenerators powerproduction and consumption, and controllingutility system operations. Power supplied by co-generators to the grid must be within certain tol-erances so that the overall utility system powerquality remains satisfactory and utilities and cus-tomers equipment will function properly and notbe damaged. In order to maintain power quality,grid-connected cogenerators may need capaci-tors to keep voltage and current in phase, over/under relays to disconnect the generator if itsvoltage goes outside a certain range, and a dedi-cated distribution transformer to isolate voltageflicker problems. However, the power quality ef-fects of interconnected cogenerators often aretechnology- and site-specific, and not all systemswill need all of this equipment. in particular,smaller systems (under 20 kW) may have few orno adverse effects on power quality and may re-quire only limited interconnection equipment.Larger systems probably will already have dedi-cated transformers, and would only need capaci-tors to correct power factor if they use induction(as opposed to synchronous) generators.

Cogenerators power production and con-sumption must be metered accurately in orderto collect data for better understanding their con-tribution to electric system loads, and thus for de-termining how to price buyback and backuppower. Two standard watthour meters can beused, with one operating normally to measureelectricity consumption and the other runningbackwards to indicate production. Alternatively,more advanced meters are available that indicatenot only kilowatthours used/produced, but alsopower factor correction and time-of-use. Al-though an advanced meter provides more usefuldata, it also costs about five times more than twostandard watthour meters. Whether cogener-ators are given a choice between standard and

advanced meters and, if not, whether the utilityor the cogenerator pays for the advanced meter,varies among utilities.

Utilities also are concerned about cogeneratorseffects on their ability to control utility systemsoperations, including the possibility that largenumbers of cogenerators (or small power produc-ers) would overload system dispatch capabilities,and would contribute to unstable power systems.Although very large cogenerators might be dis-patched by a central utility control center (andthus require connection via expensive telemetryequipment), most utilities will treat cogeneratorsas negative loads by subtracting the power pro-duced by the dispersed generators from total sys-tem demand, and then dispatching the utilityscapacity to meet the reduced demand. Studiesof such negative load treatment indicate that itshould work well where the total capacity of thecogenerators is limited compared to the overallsystem capacity. However, additional researchis needed on the effects of large numbers ofcogenerators on system stability. The primaryconcern with a significant system penetration ofcogenerators is their ability to remain synchro-nized with the system following a disturbance.

Without proper interconnection measures,large numbers of cogenerators also might posehazards to worker safety during repairs to trans-mission and distribution lines. First, dispersedgenerators will need to locate their disconnectswitches in specified areas in order to simplify lineworkers disconnect procedures. Second, induc-tion (and, very occasionally, synchronous) gen-erators must guard against self-excitation eitherby using voltage and frequency relays and auto-matic disconnect circuit breakers, or by locatingtheir power-factor correcting capacitors wherethey will be disconnected with the cogeneratoror where they can be isolated easily by lineworkers. Therefore, while proper interconnec-tion must be ensured in order to protect utilityworkers safety, none of the necessary precau-tions is difficult to implement.

The cogenerator usually is liable for accidentsor damage to equipment resulting from improperinterconnection or operation. The utility may in-clude the cost of insurance against such mishaps

Ch. 2Issues and Findings . 37

in the cogenerators regular billing, or liability(and adequate insurance to cover it) may be acondition of the contract between the utility andcogenerator. However, in some cases, require-ments for both insurance and protective equip-ment may be redundant and place an excessivecost burden on the cogenerator.

The cost of interconnection varies widely de-pending on the size and type of cogenerator,the equipment already in place, and the utilitysor State regulatory commissions requirements.Few guidelines have been published (althoughseveral are being prepared) and some utilities orcommissions may require more equipment thandescribed above in order to provide extra pro-tection for their system and their other customers.In addition, the quality of equipment required (in-dustrial or utility grade) can affect the cost sub-stantially. Most utility engineers agree that the lessexpensive industrial grade should be adequatefor smaller cogenerators, but specifications of thecutoff range from 200 to 1,000 kW. Finally, costswill depend on the amount of equipment that isalready in place (e.g., dedicated transformers)and on the adequacy of existing distribution lines.

Based on published studies, OTA estimated twosets of interconnection costs for three sizes ofcogeneration systems: a base case that assumes

that much of the equipment is already in placeor not required (e.g., capacitors, dedicated trans-formers, protective relays), and a worst casethat assumes this equipment must be purchased(see table 3). Most of the cost difference betweenthe two cases results from the addition of a dedi-cated transformer, and from the use of more ex-pensive relays and other protective devices.Moreover, these estimates indicate that there aresignificant economies of scale in interconnectioncosts.

The Federal Energy Regulatory Commissions(FERC) rules implementing section 210 of PURPAoriginally specified that any electric utility shallmake such interconnections as may be necessaryto accomplish purchases or sales of cogeneratedpower. However, this rule recently was over-turned by the U.S. Court of Appeals on thegrounds that it is inconsistent with other parts ofPURPA that provide for individual FERC ordersrequiring interconnection after the opportunityfor a full evidentiary hearing in accordance withthe Federal Power Act. Thus, if cogenerators can-not get a utility to agree to interconnect withthem, they will have to meet the multiple strin-gent legislative tests of the Federal Power Act,which will be very difficult, expensive, and time-consuming for the cogenerator.

Table 3.interconnection Costs for Three Typical Systems

50 kW 500 kW 5MWEquipment Best Worst Best Worst AveraaeCapacitors for power factor . . . . . . . . . . . .Voltage/frequency relays . . . . . . . . . . . . . . .Dedicated transformer. . . . . . . . . . . . . . . . .Meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Ground fault overvoltage relay . . . . . . . . . .Manual disconnect switch . . . . . . . . . . . . .Circuit breakers . . . . . . . . . . . . . . . . . . . . . .Automatic synchronizers. . . . . . . . . . . . . . .Equipment transformers . . . . . . . . . . . . . . .Other protective relays . . . . . . . . . . . . . . . .

Total costs ($) . . . . . . . . . . . . . . . . . . . . . .Total costs ($/kW). . . . . . . . . . . . . . . . . . .

$1,000 ------- $5,000$1,000 1,000 , 1,000 3,900 12,50080 1,000 80 1,000

600 600 600 600300 300 1,400 1,400620 620 4,200 4,200 2,600 2,600600 1,100 600 1,100 3,500 3,500

$2,600 $13,020 $11,080 $32,90052 260 22 66

$1,:0040,000

1,000600

3,0005,0002,6001,1003,500

$57,80012

NOTE: - means an optional piece of interconnection equipment that was not included in the requirements and costcalculations.

SOURCE: Office of Technology Assessment calculations based on data derived from Howard S. Geller, The /interconnectionof Cogenerators and Small Power Producers to a Utility System (Washington, D. C.: Office of the Peoples Counsel,February 1982).

38 . Industrial and Commercial Cogeneration

WHO WILL OWN COGENERATORS?Cogenerators might be owned by industrial,

commercial, or other users, by utilities, by thirdparties, or by some combination of these (jointventures). Each of these forms of ownership hasrelative advantages and disadvantages for financ-ing, taxation, operating characteristics, and regu-latory considerations.

The energy and investment tax credits, coupledwith the economic and regulatory incentives insti-tuted by PURPA, encourage private firms (e.g.,industrial facility and commercial building own-ers) to cogenerate. The PURPA requirement thatutilities purchase electricity from, and sell it to,cogenerators, and the provision that exempts co-generators from regulation as electric utilities, re-moved the primary institutional and economicobstacles to private ownership of cogenerationcapacity. PURPA also encourages the develop-ment of contractual relationships between privateowners and electric utilitiesoften a prerequisitefor obtaining attractive financing. Long-term con-tracts can establish a purchase rate based on theutilitys avoided costs either at the time of thecontract or at the time power is delivered to theutility, or the cogenerator and utility can negotiatea price independent of avoided cost considera-tions. PURPA incentives are augmented by pri-vate owners ability to earn up to 20 percent taxcredits for investment in cogenerators throughthe end of 1982, and 10 percent thereafter, whichoffers a boost to cash flow early in a projects life.Finally, user ownership generally would providethe greatest control over the cogenerators energyoutput. However, industrial and commercialfirms willingness to invest in cogeneration willbe influenced heavily by the cost of capital (oftenhigher than the cost to utilities or many third-partyinvestors), the need to invest in process equip-ment or other items that will contribute to a firmscompetitive position, and the availability of lesscostly conservation measures.

Investor-owned electric utilities and their sub-sidiaries are logical potential owners of cogenera-tion capacity because electricity generation istheir primary business. Ownership of cogenera-tors would enable the electric utility industry toprovide a wide range of energy supply options

and not just to facilitate their development byother parties. Moreover, utility ownership wouldreduce the potential for revenue losses from thedevelopment of generating capacity by nonutil-ities, while providing an additional revenuestream from thermal energy sales. Direct utilityownership (i.e., not utility subsidiaries) also couldresult in lower generation costs to be passed onto consumers because the avoided cost wouldbecome the lower of the cost of cogenerating orof providing electricity from alternate sources(see, What Are the Potential Effects of thePURPA Incentives?). In addition, utilities aremore likely to choose technologies that have highE/S ratios and that can accommodate coal orother alternate fuels (e.g., with gasifies). As aresult of all these considerations, cogenerationsmarket potential in general, and its ability tosupply large amounts of electricity to the gridin particular, are likely to be enhanced substan-tially under utility ownership.

However, current Federal policy toward cogen-eration discourages full utility ownership. First,PURPA incentives are not available to cogenera-tors in which utilities own more than a 50-percentinterest. Allowing 100-percent ownership wouldmean that utilities could earn a higher rate ofreturn on unregulated cogeneration capacity thanon their regulated central station capacity, andwould compensate utilities more fully for accept-ing the business risks of investment in generatingequipment over which they have little control(e.g., strikes, plant closings, or fuel interruptionsat the cogeneration facility). Second, utility prop-erty is not eligible for the energy tax credit, andthus utilities would not gain the same cash flowadvantages as private investors. Removing thesedisincentives would allow electric utilities to com-pete on at least an equal basis with other poten-tial owners, and may give utilities a competitiveadvantage, and thus could substantially increasecogenerations market potential.

However, full utility ownership raises concernsabout competition and potential economic distor-tions. Utilities could favor their own (or their sub-sidiaries) projects through the duration or otherterms of the purchase power contract, the inter-

Ch. 2issues and Findings . 39

connection requirements, or the priority for con-tracting. There is also a potential for utilities tocross-subsidize cogenerators through their otheroperations, making it difficult for private ownersto compete, or for utilities to favor particular mod-els and thus stifle competition among vendors.Each of these concerns can be dealt with eitherthrough carefully drafted legislation and regula-tions, or through careful review of utility owner-ship schemes by State regulatory commissions.

Publicly owned utilities also are logical candi-dates for investment in cogeneration capacity.Most publicly owned electric utilities purchaseall or some of their power from the grid. invest-ment in cogeneration capacity would enablethem to add a new source of municipal revenuewhile increasing the reliability of their power sup-ply. Moreover, many existing small municipalpowerplants are sitting idle due to their high oper-

ating costs relative to the cost of grid-suppliedpower. These small plants could be retrofitted forcogeneration and the thermal energy used tomeet local needs for such processes as grain dry-ing or ethanol production. Municipal utilities alsohave advantages in financing because they aretax-exempt and so is the interest paid on theirobligations.

Finally, joint ventures among any of the typesof owners listed above or with third-party inves-tors will be attractive, primarily due to the tax ad-vantages. If the primary investor cannot take ad-vantage of tax benefits such as credits or acceler-ated depreciation (e.g., because the investor istax-exempt or has a low tax liability), the cogen-eration equipment can be sold to another partyfor tax purposes only and leased back to the co-generator or other owner.

WHAT ARE THE POTENTIAL EFFECTS OFTHE PURPA INCENTIVES?

PURPA extends several important incentives toqualifying cogenerators (and small power produc-ers). These include exemptions from electric util-ity or utility holding company regulation underFederal and State law and from some Federal fueluse and pricing regulations; incentive rates forsales of cogenerated electricity to the grid, andnondiscriminatory rates for purchases of backupor supplementary power from the grid; and spe-cial provisions on interconnection, and on wheel-ing of cogenerated power. All of these incentivesare important because they could remove long-standing regulatory and economic barriers to on-site electricity generation. However, the rate pro-visions of PURPA are likely to have the most im-portant impacts.

PURPA requires electric utilities to purchasepower from cogenerators at a rate that does notexceed the incremental cost to the electric utilityof alternative electric energy. This is termed theutilitys avoided cost, and is measured by the sav-ings to the utility in not generating the power itselfor purchasing it from the grid. Avoided cost ratesare based on a cogenerators contribution to

power supply or peak load during daily or season-al peak demands (including the reliability of thatcontribution from the utilitys perspective); acredit for capacity and/or energy if the cogenera-tor enables the utility to defer new constructionand decrease oil/gas use; and any costs or sav-ings to the utility in transmission and distribution.

The level at which avoided cost rates will beset is uncertain at this time. The original FERCrules implementing PURPA provided for pur-chases of cogenerated power at 100 percent ofthe utilitys avoided cost. This provision was chal-lenged successfully on the grounds that PURPAestablished the full incremental cost as a rate ceil-ing, and that FERC had not adequately justifiedtheir choice of the highest permissible rate whena lower rate would share the economic benefitsof cogeneration with the utilitys ratepayers. FERCis appealing this ruling, but it may be monthsbefore a final decision is available and the regula-tions are rewritten, if necessary.

Regardless of whether the rates for purchasesof cogenerated power are set at 100 percent of

40 . Industrial and Commercial Cogeneration

avoided costs or less than 100 percent, theserates will vary widely regionally. In most cases,only those utilities that are heavily dependent onoil or gas, have a declining reserve margin, or areanticipating relatively high peak demand growth(e.g., 3 percent per year or greater) will have suf-ficiently high avoided costs to make grid-con-nected cogeneration an attractive investment (seetable 4). Therefore, PURPA rate provisions aremost likely to be an incentive to cogeneration inthe New England States (especially Massachu-setts, Rhode Island, New Hampshire, and Con-necticut); the Mid-Atlantic States (particularlyNew York, New Jersey, and Delaware); theSouthern and South-Central States of Florida,Mississippi, Arkansas, Louisiana, and Texas; andthe State of California and the Pacific Northwest.

However, in each area, PURPA avoided costincentives may be reduced by such factors asutility plans to convert to less costly generatingcapacity, or by conservation measures that re-duce the rate of peak demand growth. Thus, ifpeak demand growth rates are not so high asthose presented in table 4, then reserve marginswould be higher than shown and avoided costswould be lower. Where avoided costs are low,a cogenerator may deliver its electricity to a moredistant utility that would have higher avoidedcosts, if the local utility agrees to transmit thepower.

PURPA economic incentives also can have im-portant impacts on electric utilities and their cus-tomersespecially if cogenerated power is pricedat 100 percent of the utilitys avoided cost. Be-

cause the avoided cost rate is based on the costto the utility of alternative electric power, theprice of electricity for non-cogenerating custom-ers should not be any higher than it would beif the utility did not make avoided cost paymentsto cogenerators (unless the State has establishedrates higher than the full avoided cost). However,neither will the price to those customers be anylower under 100-percent avoided cost rates (ex-cept in those cases where utilities negotiate a con-tract price for cogenerated power that is less thanthe full avoided cost).

Moreover, even though utilities should treat co-generated power as part of their overall capacity,they will not earn a rate of return on cogenera-tion equipment unless they own it. Under PURPA,cogenerators that are more than 50 percent util-ity-owned are not eligible for PURPA economicand regulatory incentives. If utilities could owncogeneration capacity outright and still benefitfrom those incentives, the avoided cost couldbecome equivalent to the cost of cogeneratedelectricity or the cost of alternative powerwhichever is lower. If the cost of cogeneratedpower were lower, utilities could pass this sav-ings on to their non-cogenerating customers,while still earning a higher rate of return on un-regulated cogenerators than the regulated returnon their conventional capacity. Therefore, remov-ing the ownership limits in PURPA could act asan incentive to utility investment in cogeneration,and thus increase the technologys market poten-tial. However, utility ownership also raises con-cerns about possible anti-competitive effects (see,Who Will Own Cogenerators?).

WHAT ARE THE POTENTIAL ECONOMIC IMPACTSOF COGENERATION ON ELECTRIC UTILITIES?

Cogeneration could have either beneficial oradverse economic impacts on electric utilitiesand their customers, depending on the choiceof cogeneration technologies, their fuel use, andthe type of utility capacity they might displace;on who owns the cogenerators; on the systemsoperating characteristics; and on the price paidby utilities for cogenerated power. These poten-tial impacts include decreased (or increased) costs

of constructing and operating electric generatingcapacity, increased (or decreased) employmentassociated with electricity supply, and a de-creased (or unchanged) rate of growth in electric-ity rates.

In order to gauge the potential magnitude ofthese economic impacts if cogeneration achieveda very large market penetration, OTA developed

Ch. 2issues and Findings l 41

Table 4.Considerations in Determining Avoided Costs Under PURPAFuel used (percent)b Reserve margin (percent) Peak demand growth (percent)

Regiona Oil Gas 1981 1990 2000 1981-1990 1991-2000Northeast . . . . . . . . . . . . . . . . .

Maine . . . . . . . . . . . . . . . . . . .New Hampshire . . . . . . . . . .Vermont. . . . . . . . . . . . . . . . .Massachusetts . . . . . . . . . . .Rhode Island . . . . . . . . . . . .Connecticut . . . . . . . . . . . . .New York. . . . . . . . . . . . . . . .

Mid-Atlantic . . . . . . . . . . . . . . .Pennsylvania. . . . . . . . . . . . .New Jersey . . . . . . . . . . . . . .Delaware . . . . . . . . . . . . . . . .

Southeast . . . . . . . . . . . . . . . . .Virginia . . . . . . . . . . . . . . . . .North Carolina . . . . . . . . . . .South Carolina. . . . . . . . . . .Georgia . . . . . . . . . . . . . . . . .Florida . . . . . . . . . . . . . . . . . .Tennessee. . . . . . . . . . . . . . .Alabama . . . . . . . . . . . . . . . .Mississippi . . . . . . . . . . . . . .

East-Central . . . . . . . . . . . . . . .Maryland . . . . . . . . . . . . . . . .District of Columbia . . . . . .West Virginia . . . . . . . . . . . .Ohio . . . . . . . . . . . . . . . . . . . .Kentucky . . . . . . . . . . . . . . . .Indiana . . . . . . . . . . . . . . . . . .Michigan . . . . . . . . . . . . . . . .

Midwest . . . . . . . . . . . . . . . . . . .Wisconsin . . . . . . . . . . . . . . .Illinois . . . . . . . . . . . . . . . . . .Missouri . . . . . . . . . . . . . . . .

North-Central . . . . . . . . . . . . . .Minnesota . . . . . . . . . . . . . . .North Dakota . . . . . . . . . . . .South Dakota . . . . . . . . . . . .Nebraska . . . . . . . . . . . . . . . .Iowa . . . . . . . . . . . . . . . . . . . .

South-Central . . . . . . . . . . . . . .Kansas .,...... . . . . . . . . . .Oklahoma . . . . . . . . . . . . . . .Arkansas . . . . . . . . . . . . . . . .Louisiana . . . . . . . . . . . . . . . .Texas . . . . . . . . . . . . . . . . . . .

Western . . . . . . . . . . . . . . . . . . .Montana . . . . . . . . . . . . . . . .Colorado . . . . . . . . . . . . . . . .Wyoming . . . . . . . . . . . . . . . .New Mexico . . . . . . . . . . . . .Arizona . . . . . . . . . . . . . . . . .Utah . . . . . . . . . . . . . . . . . . . .Idaho . . . . . . . . . . . . . . . . . . .Oregon . . . . . . . . . . . . . . . . . .Washington . . . . . . . . . . . . . .California . . . . . . . . . . . . . . . .Nevada . . . . . . . . . . . . . . . . . .

45.416.038,3

80.075.444.838.017.4

44.559.415.539.5

47.9

37.74.9

23.8100.0

10.74.8

1.6

5.3

27.017.7

15.7

40.6

52.9

24.1

2.1

10.5

4.9

16.0

30.6

2.9

2.4

70.441.182.915.582.373.214.4

12.5

26.3}13.5}

28.8}26.0}

43.8

31.6

33.5

38.8

19.4

41.4

25.4

30.1

32.8

21.2

43.7

29.1

28.5

33.5

18.4

20.4

19.7

34.3

40.2

18.0

24.2 1.9 2.1

25.6

18.6

29.0

2,4

3.7

3.5

2.9

3.8

4.0

3.5

4.7

1.9

3.0

2.9

14.7

14.8

17.6

25.6

16.5

11.4 2.6 2.2

3.2

3.3

3.6

2.8

3.6

aRegions correspond roughly to North American Electric Reliability Council regions.bElectric utility fuel use of less than about IO percent is not included for individual States.SOURCE: Office of Technology Assessment, from Edison Electric institute, Statlsflcal Yearbook off the Electric Utility Industry: 1980(Washington, D.C; Edison Electric

lnstltute,1981~ and North Amerlcan Electrlc Rellabillty council, Electrlc Power Supply and Demand, 1981-1990 (Princeton, N.J; North American ElectricReliablllty Council, July 198l)

42 . Industrial and Commercial Cogeneration

six scenarios of cogeneration use that postulatepenetrations of 50,000, 100,000, and 150,000MW of cogeneration capacity by 2000 with twodifferent technology mixes. We then comparedthe capital requirements, operation and mainte-nance (O&M) costs, and construction and O&Mlabor needs for these scenarios to those for install-ing an equivalent amount of central station base-Ioad and peaking capacity (using two mixes forbaseload capacityloo percent coal and SO/SOcoal and nuclear). In this comparison, OTA foundthat:

l

l

l

l

capital requirements for cogeneration variedfrom around 95 percent less to about 25 per-cent more than the capital requirements foran equivalent amount of central station ca-pacity;O&M costs for cogeneration ranged from ap-proximately 75 percent less to about 95 per-cent more than the O&M costs for centralstation generation;construction labor requirements for cogen-eration varied from around 45 percent lessto approximately 70 percent more than thosefor constructing an equivalent amount of util-ity capacity; andO&M labor requirements, measured inwork-hours per megawatthour, varied muchmore widely (e.g., 10 to several hundredtimes greater labor needs for cogenerationthan for central station capacity).

In generaI, the wide variations in these resultscan be attributed to the economies of scale inthe costs and labor needs for constructing andoperating cogeneration capacity. Thus, total esti-mated cogeneration capital requirements are, onthe average, lower than those for central stationcapacity, but may be slightly higher if all the co-generators were very small systems with a highinitial cost per kilowatt (e.g., 500-kW steam tur-bines, 75-kW diesels, 100-kW combustion tur-bines). Similarly, average estimated constructionlabor requirements for cogeneration range from

about the same as those for installing convention-al utility capacity to around so percent higher,and could be even greater when the smallest co-generators (that require more work-hours perkilowatt of capacity) are installed. On the otherhand, construction labor requirements for cogen-eration may be lower than those for central sta-tion utility capacity if the largest cogenerators areused (e.g., 100-MW steam or combustion tur-bines, 30-MW diesels). For O&M costs, cogenera-tion tends to be more expensive for small systemsand those with a higher capacity factor, and lessexpensive for large systems or those with a lowercapacity factor. Finally, the O&M labor require-ments for cogeneration are the most uncertain,primarily due to the lack of data in this area andbecause the economies of scale are even morepronounced.

Because the mean cost of cogenerated electric-ity tends to be lower than the marginal cost ofelectricity from new central station capacity, co-generation may have the potential to reduce therate of growth in retail electricity rates. That is,if utilities installed cogeneration capacity, lowercosts would be passed on to their customers thanif they installed conventional capacity. However,if utilities purchase cogenerated power at a ratebased on their marginal, or full avoided costs,then the cost passed onto other customers wouldbe equivalent to the cost of alternative electricity(i.e., either central station capacity or power sup-plied by the grid), and cogeneration would notreduce retail electricity rates, (see, What Are thePotential Effects of the PURPA Incentives?). Fur-thermore, where State regulatory actions providefor purchases of cogenerated power at rates thatare even higher than full avoided costs (e.g.,either because the State commission sets pur-chase power rates equivalent to the cost of oiland the utility uses a mix of fuels, or when thecommission establishes an explicit subsidy rate),non-cogenerating ratepayers will be subsidizingcogeneration.

Ch. 2Issues and Findings . 43

WHAT ARE THE ENVIRONMENTAL IMPACTS OF COGENERATION?The primary environmental concern about co-

generation is the air quality impacts. In general,cogeneration does not appear to offer automaticair quality improvement or degradation com-pared to the separate production of electricityand thermal energy (see table s). Rather, eachcogeneration application must be evaluated sep-arately. Thus, cogenerations greater fuel efficien-cywhen considered by itselfappears to offera decrease in the total emissions associated withelectric and thermal energy production, but,when evaluated in combination with the otherchanges associated with substituting cogenera-tion for conventional energy systems (includingchanges in the type of combustion equipment,its scale, and the type of fuel), may actually leadto an increase in total emissions.

Similarly, the location and technological char-acteristics of a cogenerator will affect ambientpollution concentrations and pollution disper-sion. Cogeneration usually involves shifting emis-sions away from a few central powerplants withtall stacks to many dispersed facilities with lowerstacks. In many situations, this shift will lead tolocal increases in annual average pollutant con-centrations near the cogenerators. For urban co-generators, total population exposure may in-

.

crease because the emissions sources have beenmoved closer to densely populated areas. Also,air quality under certain meteorological condi-tions (such as low-level inversions) may be worsewith cogeneration than with conventional sepa-rate electricity and thermal energy production.On the other hand, in some situations the worstcase short-term pollutant concentrations causedby cogenerators will not be so high as the worstcase concentrations associated with the facilitiesthey displace. Moreover, if a cogenerator replacesseveral small furnaces or boilers then its air qualityimpacts can be positive.

Industrial and large-scale commercial cogen-eration systems using steam or combustion tur-bines do not appear to present significant airquality problems in most situations. However,if the substitution of these cogeneration technol-ogies for separate electric and thermal energyproduction also involves a switch from cleanto dirty fuels (e.g., from distillate oil to highsulfur coal) then emissions could increase. Simi-larly, where a new steam or gas turbine cogener-ator that primarily produces electricity is substi-tuted for a new boiler or furnace, then the cogen-erator could add significantly to local emissions.

Table 5.Effect of Cogeneration Characteristics on Air QuaiityEffect on air quality

Technological characteristic Direct physical effect (positive or negative)Increased efficiency Reduction in fuel burned PositiveChange in scale (usually smaller for Change in pollution control Negative for electrica

electric generation, at times requirements (stringency Positive for heatlarger for heat/steam production) increases with scale)

Change in stack height and plume Negative for electricrise (increases with scale) Positive for heat

Changes in design, combustion Mixedcontrol

Changes in fuel combustion Changes in emissions production, Mixedtechnology required controls, types of

pollutants, physical exhaustparameters

Change of fuels Change in emissions production, Mixedtype of pollutants

Change of location (most often for Change in emissions density and Mixedelectric generation) distributionelectric power more

distributed, heat/steam maybecome more centralized

~he air quallty effect of replacing the electric power component of the conventional system with the electrlc component of the cogeneration system is negative.SOURCE: Office of Technology Assessment from material in ch. 6.

44 . Industrial and Commercial Cogeneration

The use of diesel cogenerators (and gas-firedspark-ignition engines), however, generally willlead to increased levels of nitrogen oxide (NOX)emissions at the cogenerator site, even after ac-counting for the displaced emissions from theseparate electric and thermal energy sources.Available controls can reduce diesel NOX emis-sions by nearly one-half, which mitigates but doesnot eliminate this problem. Diesels also emit po-tentially toxic particulate, but conclusive medi-cal evidence of harm is lacking at this time, andthe evidence that is available suggests that thishazard may not be critical.

Cogenerators greater fuel efficiency can leadto an important environmental benefit throughreduced exploration, extraction, refining/process-ing, and transportation of the fuel saved. How-ever, this benefit is difficult to quantify and com-pare to the various air quality effects noted above.Furthermore, this benefit usually will occur onlywhen the cogenerator uses the same fuel as theconventional energy systems it displaces. That is,if a fuel that is difficult to extract, process, andtransport (e.g., coal) is substituted for a cleanerfuel (such as natural gas) the overall impacts maybe adverse rather than beneficial.

The air quality concerns reviewed above meanthat cogenerators especially those in urbanareasmust be designed and sited carefully.Most urban cogenerators are likely to be dieselsor gas-fired spark-ignition engines, both of whichhave higher NOX emissions than the systems theywould replace. In urban areas with high NOXconcentrations, deployment of large numbersof cogenerators without pollution controls andcareful siting could lead to violations of ambientair quality standards and increased risks of ad-verse health effects. There is considerable poten-tial to mitigate these problems through propersite selection and engine design, and the use ofavailable NOX controls. For example, uncon-

trolled diesel NOX emissions may vary by asmuch as a factor of 8 depending on the enginemodel and manufacturer, so appropriate enginechoice alone might improve environmental ac-ceptability significantly. However, there are noFederal emission standards for stationary dieselengines and the degree of risk from their deploy-ment will depend on the effectiveness of Stateand local air quality permitting and management.

Proper siting and design also are importantin avoiding the problems of urban meteorol-ogy, or the effect of tall buildings on air cur-rents and, thus, on pollutant dispersion. Urbanmeteorology can cause plumes to downwash orto be trapped and recirculated in the artificial can-yons created by urban buildings, and can there-fore result in very high local pollution levels dur-ing certain wind conditions. Proper design andsitingespecially ensuring that exhaust stacksare taller than surrounding buildingscan avoidair quality problems caused by urban meteorol-ogy. But the solutions may be costly in certaincircumstances (e.g., when adjacent structures aremuch taller than the cogenerators building), andmay be ignored by developers unless there is astrong State or local permit review process.

Although potential air quality impacts are theprimary environmental concern for cogeneration,water quality, solid waste, noise, and cooling tow-er drift also may be important. Water pollutioncan result from blowdown from boilers and wetcooling systems, and runoff from coal piles andfrom scrubber sludge and ash disposal. In urbanareas, these effluents may have to be pretreatedbefore discharge into the municipal treatmentsystem. in addition, sludge and ash disposal maybe a problem in urban areas due to the lack ofsecure disposal sites. Noise is also primarily anurban problem, but control measures are read-ily available. Finally, cooling tower drift can bea nuisance for those in the immediate area.

Ch. 2issues and Findings l 45

1.

2.

3.

4.

CHAPTER 2Khalsa, P. S., and Stamets, L., Cornrnercial Status:Electrical Generation and Non-generation Technol-ogies (Sacramento, Calif.: California Energy Com-mission, April 1980).Edison Electric Institute, Statistical Yearbook of theElectric Utility Industry: 1980 (Washington, D. C.:Edison Electric Institute, 1981).Geller, Howard S., The Interconnection of Cogen-erators and Small Power Producers to a Utility Sys-tem (Washington, D. C.: Office of the PeoplesCounsel, February 1982).North American Electric Reliability Council, Elec-tric Power Supply and Demand, 1981-1990 (Prince-ton, N.J.: North American Electric Reliability Coun-cil, July 1981).

5.

6.

7.

Office of Technology Assessment, U.S. Congress,Application of Solar Technology to Todays EnergyNeeds (Washington D. C.: U.S. Government Print-ing Office, OTA-E-66, June 1978).Office of Technology Assessment, U.S. Congress,Synthetic Fuels for Transportation (Washington,D. C.: U.S. Government Printing Ofllce, OTA-E-185,September 1982).Resource Planning Associates, Cogeneration: Tech-nical Concepts, Trends, Prospects (Washington,D. C.: U.S. Department of Energy, DOE-FFU-1 703,1978).