Context for Cogeneration

Chapter 3

Context for Cogeneration

PageNational Energy Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Current Picture and Trends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49Future Prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50implications for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51Conclusion .. .. .. .. .. .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Electric Utilities Context . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54The Electric Power Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55Current Status of Electric Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Regulation and Financing of Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Federal and State Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Financing and Ownership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

Chapter 3 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

Tables

Table No. Page6. 1980 U.S. Energy Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 507. Ratio of Annual Energy Demand to GNP Growth Rates. . . . . . . . . . . . . . . . . . . . . . 508. Comparison of Energy Demand Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 509. Thermal Energy Demand. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

10. U.S. Electric Power System Statistics, 1980 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5511. installed Generating Capacity, by Type of Prime Mover 1978 . . . . . . . . . . . . . . . . . 6112. Differences in Financing by Form of Ownership. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6413. New Capacity Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6514. Capital Structure for Private Utilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6515. Sources of Long-Term Financing to REA Electric Borrowers . . . . . . . . . . . . . . . . . . . . 6616. Taxes Paid by investor-Owned Electric Utilities-Electric Department Only, 1980.. 6717. Energy Property Eligible for ITC Under the Energy Tax Act of 1978.... . . . . . . . . . 6818. State Regulation of Utiiity Service and Operations.. . . . . . . . . . . . . . . . . . . . . . . . . . 6919. Rates for Power Purchased From Quality Facilities by State-Regulated Utilities . . . . 8620. Capital Recovery Factors for Cogeneration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106

Figures

Figure No. Page8. North American Electric Reliability Council Regions.. . . . . . . . . . . . . . . . . . . . . . . . . 589. The General Patterns of an Electric Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

IO. Daily Load Shapes for Five Representative Weekdays . . . . . . . . . . . . . . . . . . . . . . . . 6011. Typical Electric Distribution System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6212. Allocation of Electricity Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6313. Statewide Utility Resource Plan Additions 1981-82: Renewable/Innovative

Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9114. CWE Average Avoided Cost Paths: Baseline Construction . . . . . . . . . . . . . . . . . . . . . 9515. Generic Paths for Average Avoided Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98

Chapter 3

Context for Cogeneration

Cogeneration has attracted widespread atten-tion in recent years because of its potential forincreased energy efficiency, and therefore, lowerenergy costs. A decision by an industrial concern,a commercial building owner, or a utility to in-vest in a cogeneration system will be based onan evaluation of the supply and price of fuel,regulatory considerations, the cost and availabilityof capital, tax incentives, and the technical, cost,and output characteristics of cogeneration rel-ative to conventional separate electric and ther-mal energy systems. This chapter will review theinstitutional, regulatory, and financial contextwithin which cogeneration must compete against

conventional energy supplies, including the na-tional energy context (supply of and demand forelectricity and fuels), the structure and operationsof the electric power industry (as they may af-fect a utility’s choice of investing in a conven-tional baseload or peakload powerplant or incogeneration), and the regulation and financingof cogeneration technologies. Subsequent chap-ters will describe cogeneration technologies andtheir cost and output characteristics, promisingcogeneration applications in the industrial andcommercial sectors and in rural areas, and thepotential environmental and economic impactsof cogeneration.

NATIONAL ENERGY CONTEXTCogeneration systems could affect both the

supply of and demand for fuels and electricity.The greater operating efficiency that can resultfrom cogeneration’s dual energy output couldreduce the amount of fuel needed to supply elec-tric and thermal energy for the industrial andcommercial sectors. In many cases, dependingon the fuel used by the cogenerator and by theutility capacity it would displace, the fuel savedwith cogeneration could be oil or natural gas.Moreover, the widespread use of cogenerationcould reduce the demand for electricity from cen-tral generating plants. In order to analyze thesepotential effects, it is first necessary to understandthe current supply and demand picture for fuelsand electric power—the national energy contextin which cogenerators would operate.

This section discusses cogeneration with refer-ence to the current and projected energy picturein the United States. First, the present energysituation and recent trends are reviewed briefly.Then, some projections of energy demand–par-ticularly of electric and thermal demand in theindustrial and commercial sectors—are discussed.In doing so, this section also briefly outlines someof the factors that could alter the energy picturein these sectors which, in turn, would affect themarket penetration of cogeneration.

Current Picture and Trends

Table 6 presents 1980 U.S. energy demand byfuel and sector. Electricity is shown both as a de-mand and as a “fuel, ” with losses distributed toeach final demand sector.

Total energy demand in 1980 was 76.3 quad-rillion Btu (Quads), a decline of 3.4 percent fromthe 1979 total of 79.0 Quads. The size of this de-cline—the largest annual drop in energy demandever experienced by this country—was due inpart to the very large increase in oil prices in 1979and in part to investments in energy efficiencymade as a result of the 1973-74 price rise. Thiscan readily be seen by the 7.8-percent (2.9Quads) decline in petroleum consumption from1979 to 1980, and by the substantial decrease inthe rate of growth in energy demand since the1973 Arab oil embargo. Since 1973, overall U.S.energy demand has grown by approximately 0.8percent annually, as compared with an averageyearly growth of about 3.5 percent between 1950and 1972. The most telling change in the overallU.S. energy growth picture, however, is thatwhile energy growth has slowed dramatically,gross national product (GNP) has continued togrow at near historical rates. Table 7 shows thegrowth rates for both energy demand and GNP

49

50 . Industrial and Commercial Cogeneration

Table 6.—1980 U.S. Energy Demand (Quads)

SectorElectric

Fuel Residential Commercial Industrial Transportation utilitiesPetroleum . . . . . . . . . . . . . . 2.05 2,34 8.88 17.99 3.00Natural gas . . . . . . . . . . . . . 5.91 1.92 8.41 0.60 3.79Coal . . . . . . . . . . . . . . . . . . . 0.10 0.10 3.35 — 12.12Nuclear ... , . . . . . . . . . . . . — — — 2.70Electricity . . . . . . . . . . . . . . 9.00 6,03 9.67 0.04Hydro . . . . . . . . . . . . . . . . . . —

—— — — 3.09

Total . . . . . . . . . . . . . . . . . 17.06 10.39 30.31 18.63 24.70SOURCE: U.S. Department of Energy.

Table 7.—Ratio of Annual Energy Demandto GNP Growth Rates

GNP rate Energy demand ratePeriod (percent) (percent) Ratio1950-60 . . . . . . . . 3.29 2.76 0.841960-70 . . . . . . . . 3.85 4.24 1.101970-80 . . . . . . . . 3.26 1.31 0.40SOURCE: Office of Technology Assessment.

over the last three decades, as well as the ratioof energy demand to GNP growth rates for eachof those decades. This latter measure indicatesthat a healthy economic growth rate can be sus-tained with a wide variety of energy growth rates,and demonstrates the conservation potential ofthe U.S. energy economy.

In addition to the cost effectiveness of conser-vation, other important national energy trendsthat have emerged during the past 8 years includethe steady decline of domestic oil and natural gasproduction, and the increasing financial problemsof electric utilities. The latter are, in large part,due to the large drop in electricity demandgrowth and the rapidly escalating costs of cen-tral station electricity generation. The unexpectedrapid decline in the growth of electric energy de-mand (from 7.9 percent per year for 1950-72 to3.5 percent annually for 1972-80) found mostutilities with far greater capacity under construc-tion than needed to meet the new growth. Whenit became evident that the lower growth rateswere here to stay—in fact they might even getsmaller—electric utilities deferred or canceled asmuch of their construction budget as they could.Many utilities were still left, however, withsubstantial excess capacity.

In addition, several factors combined to makenew capacity much more expensive. These in-cluded longer construction times, increased en-vironmental and regulatory review, higher in-terest rates, and high inflation. One major con-sequence of these considerations is that, in mostcases, the marginal cost of new central stationelectricity now exceeds the average cost. As aresult, electric utilities face severe financial prob-lems, and those utilities that are experiencing de-mand growth or that need to displace oil-firedcapacity may be unable to raise capital for anynew plant construction (see “Electric UtilitiesContext,” below).

Future Prospects

All energy demand projections show a con-tinuation of the trend toward increased energyefficiency, although there is still considerablevariation as to how much (see table 8). The rangeof the projections shown in table 8 is due prin-cipally to different assumptions about consumerresponses to changes in energy prices. In allcases, however, these projections recognize thatchanges in demand will be the dominant factorin the energy future of the United States for thenext few decades.

Table 8.—Comparison of Energy Demandprojections (Quads)

Forecaster 1980 1990 2000Energy Information Administration . . 76.3 87.0 102.5Exxon . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.3 81.0 91.0Edison Electric Institute . . . . . . . . . . . 76.3 — 117.2National Energy Policy Plan. . . . . . . . 76.3 80-90 90-110SOURCE: Office of Technology Assessment

Another trend mentioned above–the declinein domestic petroleum and natural gas produc-tion—also is very likely to continue. In a technicalmemorandum, World Petroleum Availability:79802000, OTA estimated U.S. oil productionat 4 million to 7 million barrels per day (MMB/D)by 2000 compared to today’s 10.2 MMB/D (52).Exxon also has projected a drop to about 7.5MMB/D in 2000 (26). The Energy Information Ad-ministration (EIA), on the other hand, projects aslight increase above today’s level to about 10.9MMB/D (23). Despite the rapid increase in drill-ing activity since 1979, OTA has not yet seen anyevidence to contradict findings of a net declineof between 3 to 6 MMB/D by the end of thecentury.

Natural gas production is even more uncertaindue to the existence of large quantities of un-conventional gas (Devonian shale, tight sands,coal seam methane, and geopressurized brine).For most types of unconventional gas, the uncer-tainty is not so much the size of the resourcebase, but the production rates that can be ob-tained and the production cost. The availableestimates currently center on total natural gas pro-duction of 15 trillion to 17 trillion cubic feet (TCF)per year in 2000 compared to 19.5 TCF for 1980.If the price of natural gas rises to that of worldoil, however, these same estimates show produc-tion in 2000 to be approximately the same as itis today. In any case, there is little probability thatthe Nation will see a significant increase indomestic gas production, and such an increaseis even less likely for oil.

Implications for Cogeneration

The Nation is confronted with a combinationof circumstances that favor continued emphasison different, less costly ways to generate electrici-ty, and on increased efficiency in electricity use.These circumstances have led to a resurgence ininterest in the cogeneration of electricity and ther-mal energy. The relatively small size of cogenera-tion units compared to central power stationsmay offer significant short-term advantages forfinancing new capacity. Cogenerators will takemuch less time to build than central station plantsand they represent smaller capacity increments

that would allow rapid adjustment to changes indemand. Moreover, because cogeneration unitsare installed at or close to the point of demand,most or all of the energy requirements of manyindustrial plants and commercial buildings couldbe provided onsite with the added possibility ofgenerating electricity for distribution through theutility grid. Finally, cogenerators’ ability to usefuel for two purposes (electricity and thermalenergy) greatly increases the overall utilizationefficiency of that fuel. Thus, where electric utilitiesproject continued reliance on oil and gas due tothe unavailability or infeasibility of other fuels,or where cogeneration systems can use alternatefuels, substantial oil or gas savings may result.

The technical advantages of cogeneration havealways been available. It is the advent of theeconomic and energy supply and demand con-ditions described above that adds potential fueleconomy, financial, and planning advantages forcogeneration compared to central station elec-tricity generation and conventional thermalenergy combustion systems. Whether these ad-vantages will prove sufficient to accelerate thegrowth of cogeneration will be determined large-ly by the amount and character of demand forelectricity and thermal energy in the commercialand industrial sector, and by the future financialhealth of the electric utility sector.

Electricity Supply and Demand

Perhaps the most critical factor in cogenerationeconomics is the demand for electric power. ThePublic Utility Regulatory Policies Act of 1978 of-fers economic and regulatory incentives to co-generators that enable utilities to defer or cancelnew powerplants and decrease oil and gas use.A zero or low growth in electricity demand, how-ever, could undermine these incentives by reduc-ing the need for cogenerated electricity and,therefore, reducing the economic attractivenessof cogeneration. Moreover, where the utility isprimarily dependent on coal, nuclear, or hydro-electric plants, or where it plans to convert ex-isting oil-fired capacity to alternate fuels,cogeneration will only be attractive if it also canuse alternate fuels and can offer substantial finan-cial advantages.

Currently there is considerable uncertaintyabout future electric power demand growth; theSolar Energy Research Institute (SERI) projecteda 0.4 percent per year increase under their leastcost approach (61 ), while the North AmericanElectric Reliability Council (NERC) estimates a 2.9percent annual growth rate (48). In terms ofcapacity requirements, the SERI projection couldbe met by 620 gigawatts (GW) of capacity oper-ating at the current capacity factor of 45 percent.Further, SERI shows that 577 GW could be avail-able in 1985 assuming completion of all plantsscheduled to be on-line in 1985, and the retire-ment of all plants built before 1961 and of all oiland natural gas plants built between 1961-70 (61).Therefore, under the SERI least cost approach,very little new capacity would be needed past1985, and any cogeneration added after thatwould be likely to substitute for electricity fromexisting coal, nuclear, or hydroelectric plants.Under the NERC case, however, capacity is pro-jected to reach about 900 GW by 2000, an in-crease of 300 GW over present capacity. Eventhen, NERC estimates that the capacity factorwould have to increase to 50 percent to meettheir projected energy demand. Accounting forretirements and conversion of oil and natural gas,about 50 percent more new capacity would haveto be added under NERC projections than nowexists (49). In this case, cogeneration could havea very large market potential.

The future demand for electricity will be deter-mined by the relative prices of electricity andcompeting fuels (including conservation meas-ures), by the development of technologies thatuse electricity more efficiently (e.g., processequipment, appliances), and by consumers’ per-ceptions about the stability of oil and natural gasresources. Currently, average electricity prices inthe commercial sector are about 2.5 times dis-tillate fuel oil prices and five times natural gasprices on a delivered Btu basis. * For industry,both of these price ratios are about 2 to 1. Theratios have decreased by 20 to 60 percent fromthose in 1970, however.

*As will be discussed below, differences in end use efficiencybetween equipment using electricity and that using natural gas orfuel oil make price comparison on a delivered Btu basis alone,incomplete.

Continuation of the low rate of growth in elec-tricity demand, coupled with the current excessof generating capacity, may keep the rate ofgrowth in electricity prices rather low over thenext several years. If prices do remain somewhatstable, then the difference between electricityprices and oil and gas prices would be likely tobecome even smaller. However, the current de-cline in the real price of oil could alter this trend.Furthermore, if the oil price decline continues forthe next few years, natural gas price increasesfollowing decontrol also are not likely to be sodramatic as originally thought. Therefore, theratio of electricity prices to oil and natural gasprices would not decline for some time. At thispoint, it is most likely that the ratio will decline,although more slowly that previously antici-pated. The price trajectories used in the analysisof commercial cogeneration in chapter 5 also pro-ject that the ratio will become smaller.

Such growth rates would continue the trendtoward price closure between electricity andnatural gas or distillate fuel oil. If these trends arecombined with the development of technologiesfor buildings and industry that use electricity moreefficiently than equivalent oil or natural gas burn-ing technologies that provide the same services(e.g., space heating, reheating of finished metals),the costs of providing these services with elec-tricity could become lower than with oil ornatural gas. For example, in many areas, efficientelectric heat pumps can provide space heatingmore economically than oil furnaces. There areeven a few regions where space heating withelectric heat pumps is cheaper than with naturalgas furnaces.

Natural gas and oil are the primary energysources for industrial processes, supplying bothdirect heat (such as catalyzing chemical reactionsand heat treating) and process steam. The majoruse of electricity in industry is to run motors.Whether technologies that use electricity couldeconomically replace direct heat or processsteam in industry is much less certain than in thecommercial sector. Some possibilities includemicrowave, infrared, or dielectric heating, veryefficient electric motors for replacing steammechanical drives, and pulsed current devicesfor surface reheating of metals.

Ch. 3—Context for Cogeneration ● 53

It is possible, then, that the growth of electricitydemand could increase sharply toward the endof the decade. * However, the extent of any in-crease in industrial or commercial demand willdepend on the size of the dollar savings achievedby switching to electricity relative to the requiredcapital investment. Conversion is much morelikely for new buildings and plants than for ex-isting facilities. Therefore, unless there is signifi-cant new development in energy intensive indus-tries for which more economical electric tech-nologies are available and accepted, the growthrate of industrial use of electricity is not likely tochange substantially for the remainder of thecentury.

It is this uncertainty of future demand that pro-vides a potentially important role for cogenera-tion. If electricity use in buildings and industrydid increase substantially, electric utilities couldbe strained financially if they tried to meet theincreased demand with new central station ca-pacity. Further, attempts to accommodate de-mand growth with central station capacity couldlead to a rapid increase in electricity prices. Thisis because the marginal cost of electricity—thecost of a new plant—is often considerably higherthan the average cost. Therefore, as new capacitybecomes a larger fraction of the total electric utili-ty plant, the average cost will grow closer to themarginal cost. Cogeneration could help alleviatethese pressures, particularly in the first years ofan increase in demand. The small size of cogen-eration systems would allow rapid and fairlyprecise matching of supply and demand, andwith much smaller increments of capital. Thiswould greatly reduce the risk of building excesscapacity or having to defer or cancel capacityunder construction should demand growth sud-denly slow or stop. Moreover, because cogenera-tion supplies thermal energy, it could at least par-tially offset increases in electricity demand dueto a rapid rise in the use of electric heating.Cogeneration’s competitiveness would then turnon the difference between the cost of purchas-ing electricity plus supplying heat, and the fuel

*The extent to which electricity can be substituted economical-ly for other energy sources in buildings and industry will be ex-

amined in detail in forthcoming OTA studies on oil disruption andon electric utilities.

and operating and maintenance costs of a cogen-eration system. Finally, the avoidance of exten-sive new additions to transmission and distribu-tion systems also might alleviate some of the elec-tric utilities’ capital problems.

However, if utilities are able to raise capitaleasily, or if demand does not increase in the faceof stable prices, central station powerplants fueledwith coal, uranium, or hydropower may be pre-ferred to oil- or gas-fired cogeneration systems.These alternate energy sources probably wouldbe cheaper than the oil or natural gas likely tobe used in most cogeneration systems in the nearterm. Therefore central station electricity—evenwith a substantially larger capital cost per kilo-watt than cogeneration capacity—is likely to becheaper than cogenerated electricity despite co-generation’s higher overall fuel efficiency.

Thermal Energy Demand

The second major influence on the growth ofcogeneration is future thermal energy demandin buildings (space and water heat) and industry

(direct heat and process steam ). We have alreadydiscussed how some of this future load may bemet by electricity rather than by direct combus-tion of fossil fuels. In addition, available conser-vation opportunities will slow thermal demandgrowth and could even reduce thermal energy

use (by 2000) from the 1980 levels. Conservationwill affect electricity use as well, and even ifsignificant conversion from other fuels to elec-tricity (as discussed above) does occur, electricity

demand growth in these sectors still could be keptlow. Table 9 shows two estimates of direct com-bustion heat requirements for commercial build-ings and industry for 2000 compared to 1978. Ascan be seen, current thermal demand in industryis more than twice that of commercial buildings.Moreover, under either the EIA or the SERI pro-jection, the difference would become even morepronounced.

Table 9.—Thermal Energy Demand (Quads)

Buildings IndustryYear Space/water heat Direct heat Steam1978 ......., . . . . 4.5 3.8 6.82000 (EIA) . . . . . . . 3.8 5.0 9.32000 (SERII . . . . . . 1.6 3.7 6.6SOURCE: Office of Technology Assessment

54 ● Industrial and Commercial Cogeneration

The SERI estimates in table 9 are based on aleast cost approach using conservation technol-ogies that cost the equivalent of up to the 1980average cost of oil and electricity ($7.50/MMBtuand $.057/kWh respectively) (60). The EIA pro-jections are derived from economic and engi-neering models and reflect judgments about ac-tual consumer response to changing energyprices (22). In either case, cost-effective conser-vation opportunities for commercial buildingscould reduce fuel requirements for space andwater heating from 15 to 65 percent. For industry,EIA estimates a 37-percent increase in steamgrowth while SERI projects a 3-percent decrease(see the section on “Industrial Cogeneration Op-portunities” in chapter 5 for an analysis of steamgrowth projections).

These analyses indicate that cogeneration willhave greater potential in the industrial sector thanin commercial buildings as far as supplying ther-mal energy is concerned. Both EIA and SERI anal-yses imply that in the commercial buildings sec-tor, cogeneration will have to compete with cen-tral station electricity and with fuel freed by con-servation in meeting future space and water heat-ing demand. When the low load factor inherentin buildings’ heat load is added, the economicpotential of cogeneration is decreased further (seech. 5). In essence, conservation can considerablyreduce the opportunity to take advantage of co-generation’s high fuel utilization efficiency.

The air-conditioning demand of buildings alsooffers a potential market for thermal energy fromcogeneration. In 1980, over 98 percent of allcommercial air-conditioning was electric. Forthese buildings, the use of cogenerated steam forcooling would require conversion to either ab-sorption units or steam-driven compressors.

Where it is economic to do so, such conversionwould increase the baseload steam demand andtherefore the building’s thermal load factor. By2000, SERI and EIA project cooling demands of2 and 4 Quads of primary energy, respectively.

Conclusion

The attractiveness of cogeneration will depend,to a large extent, on energy demand in the com-mercial and industrial sectors, on the balance be-tween thermal and electric loads, and on theoverall demand for electricity. These, in turn, de-pend heavily on the price of energy–particularlythe relative prices of electricity, distillate fuel oil,and natural gas. It is fairly certain that energy de-mand will grow much more slowly than in thepast. The range of possible growth rates, how-ever, is large. Lower growth rates, while notnecessarily changing the economics of cogenera-tion, will clearly reduce the potential market aswell as the net fuel savings. Further, a very lowgrowth rate for electricity is likely to dampenprice increases and reduce the price paid byutilities for cogenerated power, both of whichwould reduce the economic attractiveness of co-generation. However, the uncertainty of futureelectricity demand and the economic problemscaused by a severe mismatch between loadgrowth and capacity growth make small capaci-ty additions potentially very desirable in the shortterm. Therefore, while conservation through in-creased efficiency is likely to be the most eco-nomic route to choose for at least the next severalyears, there appears to be a potential role forcogeneration, particularly in the industrial sec-tor where thermal and electrical demands arelikely to remain large.

ELECTRIC UTILITIES CONTEXTFuture supply of and demand for energy and owned and operated by electric utilities, or they

electricity, as discussed above, will be a major may be installed by former utility customers whofactor in determining the role cogeneration will now provide some or all of their own electricplay in the Nation’s energy future. Equally im- power needs and who may even supply powerportant in defining that role will be the electric to the utility. In this context, cogeneration mustpower industry. Cogeneration systems may be compete, both technologically and economically,

with well established electric and thermal energyconversion and distribution systems as well aswith alternate energy forms and conservation.The elements of this competition—both on a site-specific and a national energy policy basis—willbe wide ranging, encompassing the technologi-cal, fuel use, and institutional characteristics ofthe electric power industry, as well as the financ-ing, regulation, and operations of technologiesthat supply energy for commercial and industrialapplications.

This section will review the general electric utili-ty context within which cogeneration systems willcompete. The following section of this chapterwill analyze the present institutional and regu-latory context specific to cogeneration.

The Electric Power Industry

Current operations of electric utility systems arediverse, encompassing a wide range of technicaland institutional configurations. These include thenumber, size, and type of generating plants; theamount of electricity consumed by customerclasses and their regional load profiles; and thedifferent types of institutions that supply power,coordinate specific utility functions, and regulatethe power industry. Support activities include theproduction and acquisition of fuel supply and ofthe necessary equipment for fuel handling andstorage, and for electricity generation, transmis-sion, distribution, and consumption.

A wide array of institutions has evolved to per-form the functions listed above. The U.S. elec-tric power supply system is composed of over3,400 separate entities, including private, public,and cooperative utilities, joint action agencies,

Federal power agencies, power pools, and elec-tric reliability councils. In 1980, these systems had619,050 megawatts (MW) of installed generatingcapacity to supply close to 93 million customerswith about 2.3 trillion kilowatthours (kWh) ofelectricity (see table 10) (55). The utilities in theelectric power system obtain financing from avariety of sources including banks, insurancecompanies, traditional stock and bond markets,and Federal programs; their financial and tech-nical operations are regulated at the Federal,State, and local level. Finally, both the produc-tion and consumption of electricity are supportedby innumerable institutions that manufacture, dis-tribute, install, and service equipment, tools, andappliances. All of these factors together make theelectric utility industry the largest in the UnitedStates in terms of capital assets and issuance ofstocks and bonds.

Utility Organizations

The organizations that supply electricity in theUnited States include private or investor-ownedutility companies; publicly owned utilities suchas State, county, or municipal systems, and Fed-eral power agencies; rural electric cooperatives;joint ownership organizations; and groups of util-ities that coordinate their operations to improveefficiency and reliability.

Private utiiities are owned by their investorsand generally are granted territorial franchises byState or local governments. Most investor-ownedutilities (IOUS) generate their own electricity, andsome are part of vertically integrated corporationsthat own their fuel supply (e.g., “captive” coalmines) or other support activities.

Table 1O.–U.S. Electric Power System Statistics, 1980

Electric operating Net electricInstalled capacity kWh generation Customers revenues plant investment

Type of system Millions Millions Millions(and number) Megawatts Percent of kWh Percent Number Percent of dollars Percent of dollars Percent

Local public systems (2,248) . . . . 67,568 10.9 204,880 9.0 12,467,700 13.5 $12,224 10.8 $34,100 11.9Privately owned systems (217) . . . 476,979 77.1 1,782,545 78.0 70,620,300 76.2 87,062 76.9 207,555 72.4Rural electric cooperatives

(924) . . . . . . . . . . . . . . . . . . . . . . . 15,425 2.5 63,557 2.8 9,523,600 10.3 9,707 8.6 23,892 8.3Federal power agencies (8). . . . . . 59,078 9.5 235,051 10.3 13,300 0.01 4,238 3.7 21,100 7.3

Total . . . . . . . . . . . . . . . . . . . . . . . 619,050 100.0 2 , 2 6 6 , 0 3 3 1 0 0 . 0 9 2 , 6 2 4 , 9 0 0 1 0 0 . 0 $113,231 100.0 $ 2 8 6 , 6 4 7 1 0 0 . 0

aDoes not Include nuclear fuel.

SOURCE: Office of Technology Assessment from “Public Power Directory,” Publlc Power, January-February 1982.


IOU companies dominate power generation inthe United States today. The 217 IOUS representabout 6 percent of the total number of utilities,but those 217 own approximately 77 percent ofall installed generating capacity and generateabout 78 percent of the electricity produced (seetable 10). In 1977, approximately two-thirds ofthe IOUS had a peak demand in excess of 100MW, and about 12 percent had a peak demandgreater then 3,000 MW (21). Because of the cap-ital intensity of the electric utility industry, withtotal operating revenues of over $113 billion in1980 and net electric plant investment of over$286 billion, the domination of the industry bya relatively few IOUS means that they also deter-mine the role of utilities in financial and othermarkets.

publicly owned utilities include municipal,public utility districts, and State and county sys-tems. The authority to establish a public utilityderives from the State government, and a fewStates (e.g., New York, Nebraska) currently havetheir own systems. However, most States havedelegated this authority to county or municipalgovernments.

The relatively large number of publicly ownedutilities, in contrast to their small share of the elec-tricity market (see table 10), reflects their smallsize. Most of these systems only purchase whole-sale power and distribute it to their customers;those municipal that do generate have very smallloads (fewer than 100 publicly owned utilitieshave peak demands in excess of 100 MW) (21).Roughly 71 percent of the local public power sys-tems purchase all their electricity, while about6 percent own sufficient generating capacity tosupply all their needs. The remaining 23 percentof public utilities generate some portion of theirneeds and purchase the remainder (55).

Cooperative utilities represent a different typeof public ownership. The co-ops are nonprofiteconomic entities that are owned and managedby their customer members. Members’ shares inthe co-op may be plowed back into the opera-tion and/or expansion of the business as patron-age capital in order to keep the cost of co-op serv-ice as low as possible, or the patronage capitalmay be “rotated” —essentially paid out as divi-

dends–if the co-op’s equity ratio is 40 percentor higher.

Rural electric co-ops comprise a vast operatingnetwork of over 900 local and regional electricsystems in 46 States which own and maintainnearly 44 percent of the Nation’s electric distribu-tion lines, and whose service territories encom-pass 75 percent of the land area of the UnitedStates. The rural electric system is a two-tieredoperation, including 870 local distribution co-opsand 54 generation and transmission co-ops(G&Ts). The 870 local co-ops purchase electrici-ty and distribute it to their own rural customers,while G&Ts generate and/or transmit electricityprimarily for local distribution co-ops. Some G&Tsalso sell electricity wholesale to municipal andIOUS, while distribution co-ops may purchasepower from a combination of sources, includingG&Ts, Federal power agencies, and IOUS (16).

Still another form of public utility ownershipis represented by Federal power marketing agen-cies. The Federal role in electricity generationdates back to the Reclamation Act of 1906, whichempowered the Bureau of Reclamation to pro-duce electricity in conjunction with Federal ir-rigation projects, and to dispose of any surpluspower to municipal utilities (39). The secondFederal power marketing agency was the Ten-nessee Valley Authority (TVA), which was estab-lished in 1933 as a multipurpose river project withresponsibility for flood control, regional develop-ment, hydroelectric power generation, and otheractivities. Today, it is the single largest electricutility in the country, with a total system capaci-ty of over 31,000 MW. Approximately 65 percentof TVA’s sales are at wholesale to municipal utili-ties and rural electric co-ops. The remainder issold to private industries, other Federal agencies,and private power companies (55).

Other Federal power agencies include theBonneville Power Administration, which wasestablished in 1937 and which markets powerfrom hydroelectric projects constructed by theArmy Corps of Engineers and the Bureau of Recla-mation in the Columbia River Basin and operatesthe Nation’s largest network of long-distancehigh-voltage transmission lines; the SouthwesternPower Administration, which was set up in 1944


to market power from Corps of Engineers proj-ects in Arkansas, Missouri, Oklahoma, and Texas;the Southeastern Power Administration, createdin 1950 to market power from Corps projects in10 Southeastern States; the Alaska Power Ad-ministration, established in 1967 to operate andmarket power from Federal hydroelectric projectsin Alaska; and the Western Area Power Admin-istration, which was set up in 1977 and incor-porates Federal power marketing and transmis-sion functions formerly performed by the Bureauof Reclamation and markets power from a num-ber of Corps hydroelectric projects (55).

A hybrid form of public ownership is the jointaction agency, in which two or more publicpower systems pool their plans to purchasepower or to finance total or partial ownership ofgeneration and/or transmission systems. Wherethe local public utility system is no longer ade-quate or economical and low-cost Federal poweris not available, joint action agencies can placepublic power systems in a more advantageouscost and supply position, allowing even the small-est electric utilities to realize economies of scale(4). Joint action may also provide publicly ownedutilities with more flexibility in choosing fuels andtypes of generating capacity while avoiding therisks of a single-shot investment in one plant.IOUS may choose to participate in joint actionagencies to reduce plant construction costs or toobtain lower cost financing (32).

Joint action agencies are authorized by Statelegislation and membership arrangements vary.They may include statewide areas (e.g., Munici-pal Electric Authority of Georgia), correspond toIOU service areas (such as in North Carolina,which has three agencies, one for each of theState’s major IOUS), or be determined accordingto both geography and perceived mutual interests(e.g., the five Minnesota organizations). Somejoint action agencies, such as the Missouri BasinMunicipal Power Agency, have members fromseveral States. As such, they cannot finance proj-ects themselves but must rely on the members’funding abilities. In 1981, there were 49 public-ly owned joint action agencies in 31 States (55).

Since the 1920’s, all the types of utility systemsdescribed above have been interconnected and

their operations coordinated to some degree inorder to reduce costs by increasing the produc-tivity of the resources employed in the genera-tion and transmission of electricity, and to im-prove reliability by applying the combined re-sources of several systems to a contingency onany one. These intersystem agreements nowcomprise approximately 20 formal organizationsknown as power pools. The degree of coordina-tion among utilities in power pools can rangefrom very loose agreements for exchanges ofenergy; to some coordination of planning, con-struction, operation, and capacity reserves; tocomplete integration with joint planning on asingle system basis, centralized dispatch ofgenerating facilities, and strict contractual re-quirements for generating capacity and operatingreserves (29).

In general, the potential economic benefits ofpooling include reduced investment coststhrough economies of scale in building largergenerating units and through lower reserve mar-gins that result from reducing the ratio of gener-ating unit size to combined system peakload;greater operating economies through increasedload diversity, reduced operating costs per unitoutput for larger plants, and fuller use of thelowest cost capacity available on the system; andincreased savings through coordinated construc-tion programs that minimize the costs of tem-porary excess capacity that may result from theaddition of large generating plants. The poten-tial reliability benefits of power pools derive fromaccess to support from other systems, and maybe realized either through a reduction in reservesneeded to achieve a certain level of reliability orthrough an increase in the level of reliability ofthe coordinated systems (29).

Electric reliability councils represent a secondform of coordination among utilities. A FederalPower Commission (FPC) investigation of the1965 blackout in the Northeast stressed the needfor greater reliability and coordination amongelectric utility companies. In response to FPC find-ings, NERC and nine regional councils wereformed in the late 1960’s (see fig. 8), represent-ing about 95 percent of the Nation’s generatingcapacity. Each regional council consists of a rep-

98-946 (I - 83 - 5 : IQI, 3


Mid-AmericaInterpool Network

Mid-Continent AreaRellablllty CoordinationAgreement

Northeast PowerCoordlnatlng Council

Southeastern ElectricReliability Council

Southwest Power Pool

Western SystemsCoordinating Council

resentative from each of the major utilities in theregion and from groups of small utilities in someregions.

The regional councils develop voluntary stand-ards for those aspects of bulk power supply thataffect the regionwide reliability of service (e.g.,design criteria for transmission facilities). NERCaids in the coordination of policy issues amongthe regional councils, and provides industry in-formation, comment, and recommendationsabout the reliability and adequacy of bulk powersupply at the national level. In addition, NERCis responsible for the development and mainte-

Figure 9.—The Generai Patterns

Generating station

TransmittingGenerating station . . .

nance of nationwide standards for interconnectedoperation (18).

Technical Aspects of the Utility industry

A conventional power system can be describedas the coordinated operation of generating units,high-voltage transmission lines, and subtransmis-sion and distribution networks. Figure 9 showsa typical power system structure.

The primary consideration in an electric powersystem is to serve the electric loads, or power re-quirements, in a given area or region. The power

of an Eiectric Power System

a

Receiving substation’

Generating station

Distribution linesto electric users

Distribution linesto electric users

SOURCE: Economic Regulatory Administration, The National Power Gr/d Study, Volume //(Washington, D. C.: U.S. Departmentof Energy, DOE/ERA41056-2, September 1979).


requirements include all devices or equipmentthat convert electricity into light, heat, ormechanical energy, or otherwise consume elec-tricity (e.g., aluminum reduction), or the re-quirements of electronic and control devices. Thetotal load on any power system is seldom con-stant; rather it varies with hourly, daily, seasonal,and annual changes in the service area’s re-quirements (see fig. 10). The minimum systemload for a given period is termed the baseload,while maximum requirements (usually resultingfrom temporary conditions) are called peakloads.Because electric energy currently cannot be

stored in large quantities, generating plant opera-tions must be coordinated closely with fluctua-tions in the load, and large utility systems usual-ly have separate generating plants sized to meetbase, intermediate, and peakloads.

Table 11 shows the current U.S. generatingcapacity by type of prime mover. The choice ofcapacity type is a function of service needs, eco-nomic and financial considerations, resourceconstraints (e.g., fuel, land, water), potential en-vironmental impacts, future growth, politics, reg-ulatory requirements, and management prefer-

Figure 10.—Daily Load Shapes for Five Representative Weekdays(North Central Region, 1980)

1.0

0.9

0.8

0.6

0.5

0.4

0.3

SOURCE: Decision Focus, Inc., Evacuation of the Economic Benefits of Oecentra/lzed Electr(c Generathrg Equipment Con-nected to a Ut///ty Gr/d (contractor report to OTA, October 19S0).

Ch. 3—Context for Cogeneration . 61

Table 11.–lnstalled Generating Capacity, by Type of Prime Mover, 1978

Total Hydroelectric Conventional steam Nuclear steam Internal combustion

Thousandsof kilowatts

Investor-owned utilities . . . . . . . . . . . . . . . . 453,647Municipal utilities . . . . . . . . . . . . . . . . . . . . . 34,426State systems and publlc

utility dlstrlcts . . . . . . . . . . . . . . . . . . . . . . 25,322Rural electric cooperatives . . . . . . . . . . . . . 11,635Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54,282

ThousandsP e r c e n t o f k W

76 23,8476 4,694

4 11,97529 30,431

ThousandsP e r c e n t o f k W

4 383,024< 1 25,511

2 9,245<1 11,073

5 20,376

Thousands ThousandsPercent of kW Percent of k i lowatts Percent

66 44,984 8 1,792 < 14 963 < 1 3,258 < 1

2 4,059 < 1 43 < 12 < 1 430 < 14 3,456 < 1 17 < 1

Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 579,312 100 71,014 12 449,231 78 53,527 9 5,540 1

SOURCE: Edison Electric Institute, Statistical Yearbook of the Electric Utility Industry, 1980 (Washington, D. C.: Edison Electric Institute, November 1981).

ences. In general, fossil and nuclear fueled steamplants and many hydroelectric facilities are usedfor baseload and intermediate-load generationwhile some hydro equipment (usually pumpedstorage) and combustion turbines are used tosupply peaking power.

The trend in recent years has been to constructlarge baseload plants in order to capture econo-mies of scale. Nuclear plants usually exceed1,000 MW in nameplate capacity and most of theexisting fossil steam plants are larger than 5ooMW. However, as capital costs and constructiontimes increase and it becomes more difficult tofinance large powerplants, some utilities are turn-ing to smaller equipment that may use uncon-ventional fuels. Where the service needs are notexpected to grow rapidly, small units such ascogenerators may improve load factors whilealleviating utility financial problems in the shortterm, although their longer term financial andsystem planning advantages are uncertain (seech. 6).

In order to serve the electric loads of an areaadequately, a utility must plan not only forbaseloads and peakloads, but also for systemreliability during scheduled and unscheduledoutages (e.g., equipment maintenance, stormdamage) and for demand growth. To some de-gree, system reliability can be achieved throughinterconnections with other utilities (i.e., powerpooling), but utilities also must incorporate re-serve margins into their planning. Reserve mar-gins are the installed available capacity in excessof that needed to meet the system’s peak demandwhen due consideration is given to maintenancerequirements, random equipment failure, orother contingencies. The amount of reservecapacity required in a given situation depends on

the reliability criterion, the behavior of individualgenerators, the unit size mix, and the intercon-nection support available. The usual planningprocedure is to specify a reliability level or lossof load probability, such as an expected deficien-cy of 1 day in 10 years, and optimize capacityexpansion so that this criterion is always met (3 S).The accepted industry minimum value is about20 percent. In 1979, the average reserve marginfor IOUS was around 36 percent of peakload (20).Some utilities have reserve margins above so per-cent, while others are below 10 percent.

Once electricity has been generated, its voltageis stepped up with power transformers and it istransmitted to the load center. High-voltage trans-mission lines (69 kilovolts (kV) and above) areused to transfer bulk power from the generatingplant to a substation or bulk purchaser, and tointerconnect utility systems for greater efficien-cy and reliability. Such lines are built to accom-modate power flows in either direction in orderto facilitate interconnection among systems.

After the bulk power has been transmitted tothe demand center, it goes into the distributionsystem, which supplies electric energy to the in-dividual user or consumer. The distribution sys-tem includes the primary circuits and the distribu-tion substations that supply them; the distribu-tion transformers; the secondary circuits, in-cluding the services to the consumer; and ap-propriate protective and control devices (see fig.11). A transmission substation transforms powerto subtransmission voltage (below 69 kV). It isthen distributed to various distribution substa-tions, load substations, and distribution transform-ers, where the voltage is stepped down furtherto match residential, commercial, and industrialneeds. Once the electricity enters a local distribu-

Figure 11.—Typicai Eiectric Distribution System (three.phase)

From transmission

volt

Industrial Commercial Residentialor large load or rural

commercial loadload

SOURCE: McGraw-Hill Encyclopedla of Energy (New York: McGraw-Hill Book Co., 1976).

tion system, the power usually only flows oneway in order to protect electrical workers andequipment. Special equipment is thus needed foronsite generators that feed power back to the grid(see discussion of interconnection in ch. 4).

Economic and Regulatory Aspectsof Utility Systems

Electric utilities are among the most capital-intensive and highly regulated industries in theUnited States, and the two aspects of the industryare integrally related. The rates charged forservice-as determined by State or Federal reg-ulation—are the primary factor in utility eco-nomics. But the economics of electric powersupply and demand also may be affected by fi-nancing and its regulation as well as by regula-tion of utility services and operations. Theseaspects of utility regulation and their effects onthe production and consumption of electricity—and thus on the potential role of cogeneration—are discussed below.

UTILITY RATES

In exchange for the privilege of operating asa natural monopoly, utility practices are regulatedin the public interest. The primary form of suchregulation is the determination of the rates utilitiescan charge for their services. State public servicecommissions (PSCS) traditionally have controlledrates for intrastate sales of electricity, while theFederal Government has had jurisdiction oversales for resale in interstate commerce since 1935.

State Regulation .–Each of the States (exceptNebraska, where all electricity is supplied througha State-owned and operated utility system) hasa PSC established by law to regulate utilities. Thedegree of State regulation varies. Ail PSCS regulatethe rates of IOUS, while 19 commissions havesome authority over publicly owned utility rates,and 29 regulate cooperatives (30). Where the PSCdoes not have such authority, public utilities areself-regulating through the municipal or countygovernment.


Determining the rates a utility charges for itsservices is a two-step process. The PSC mustdecide first, how much money the utility needs(the revenue requirement) and second, howthose funds will be collected (the rate structureor rate schedule). A utility’s revenue requirementis the total number of dollars required to coverits operating expenses and to provide a fair prof-it. The revenue requirement is usually expressedin formula form as follows:

E + d + T + (V – D) R

revenue requirementoperating expensesannual depreciation expensetaxes, including income taxesgross valuation of the property servingthe publicaccrued depreciationrate of return (a percentage)rate base (net valuation)profit, expressed as earnings on therate base, plus interest on debt (53).

The rate schedule allocates the revenue re-quirement among a utility’s customers. The prob-lem of cost allocation arises because most elec-tricity is produced in jointly utilized equipmentand its cost must be assigned to the customerclasses involved (36). First, costs directly at-tributable to a particular class or customer (e.g.,the distribution line from a substation to a fac-

Figure 12.–Allocation

Total utility Costs are$ costs attributed

for a given to majoryear functions

tory) are identified and segregated. Second, theremaining costs are arranged so that they can beapportioned among the various groups of cus-tomers jointly responsible. Third, those costs aredistributed in accordance with some physicallymeasurable attribute of the customer class.

in accomplishing the last two steps, costs arearranged according to function (such as produc-tion, transmission, and distribution), and theneither assigned to demand, energy, or customercost categories, or simply classified as fixed orvariable (see fig. 12). Demand costs (the fixed ratebase and expense items related to peak or aver-age demand) are generally the most difficult toallocate and have become controversial in thesetting of rates for backup service to cogenerators(see discussion of rates in next section). Energycosts can be directly allocated to customer classesbased on the number of kilowatt-hours con-sumed by the group, and thus do not pose aproblem (36).

Federal Regulation.–Federal regulation ofelectricity prices began in 1920 with the authorityto set rates for interstate sales of power fromfederally licensed hydroelectric projects. Thefinancial abuses of the 1920’s and early 1930’s,however, revealed a need for a more extensivenational role, and the Federal Power Act of 1935expanded Federal jurisdiction to include all salesof electric energy at wholesale in interstate com-

of Electricity Costs

Costs are Costs aredivided into allocated to

three principal three classes ofcategories customers

SOURCE: Office of Technology Assessment.

merce. The States retained exclusive jurisdictionover intrastate and retail electricity sales untilpassage of the Public Utility Regulatory PoliciesAct of 1978 (PURPA), which required the FederalEnergy Regulatory Commission (FERC) to estab-lish standards for PSCS to consider in setting retailand certain wholesale rates (56).

The Federal Power Act of 1935 requires thatall rates and charges of any electric utility for thetransmission or sale of power subject to FERC(formerly FPC) jurisdiction be just and reasonableas well as nondiscriminatory. Each utility mustregularly file with FERC schedules that show suchrates and charges, and the classifications, prac-tices, and regulations that may affect them. FERCrate proceedings are similar to those of State com-missions: FERC first determines the utility’s rev-enue requirement and then approves a rateschedule designed to meet that requirement. Insuch proceedings, FERC traditionally has em-ployed the same cost-based formulae used byPSCs (3).

Although only about 10 percent of the reve-nues realized by IOUS are from wholesale trans-actions subject to Federal jurisdiction, FERC stillhas a broad opportunity to influence State rate-making. For example, States may be reluctant tointroduce innovative rate structures for fear ofplacing utilities within their jurisdiction at a com-petitive disadvantage. Innovation at the Federallevel can provide the experience necessary for

State adoption of innovative rate designs. More-over, FERC’S ability to examine cost trends andpricing practices on a regional or nationwide (asopposed to local) scale may reveal to States op-portunities for ensuring greater economy in elec-tric power supply.

FINANCING

The second major factor in utility economicsis financing of new generating capacity. Utilityfinancing options vary widely depending on theform of ownership, current economic conditions,the type of project being financed, and similarconsiderations. A summary of differences infinancing by form of ownership is shown in table12. The general considerations related to utilityfinancing of capacity additions are reviewed here;financing considerations specific to cogenerationwill be discussed in the following section.

Investor-Owned Utilities.– IOUS spend thelargest proportion of funds in the electric powerindustry (see table 10) and, based on announcedplans for capacity additions (table 13), their shareof funds is likely to remain large. IOUS have fourbasic options for securing those funds: long-termdebt, preferred stock, common stock, and re-tained earnings (see table 14).

The primary form of long-term debt financingfor IOUS is the mortgage bond, which is securedby a conditional lien on part or all of the com-

Table 12.—Differences in Financing by Form of Ownershipa

Average return toOwnership Capitalization Percent financing sources Tax treatment Financiability

Federal DebtRetained earningsFederal

Municipal DebtRetained earningsMunicipality

Cooperative:Distribution Dept

EquityG & T sb Debt

EquityInvestor owned Debt

PreferredCommonRetained earnings

27.89.1

63.17325.5

1.5

66 (1977)34 (1977)96 (1977)

2 (1977)50.312.524.912.3

7.25% (1977)

4.9

7.4 (1977)10.7 (1977)7.4 (1977)

10.7 (1977)11.859.76

11.3

Tax exempt FederalTaxed revenues

Interest on debt Electricexempt from taxes revenues or

municipality

Taxed Federal loansor guarantees,or members’shares

Taxed investors

a1979 data unless Indicated otherwlse.bGeneration and transmission.

SOURCE: Economlc Regulatory Adminlstration, The National Power Grid Study, Volume Il(Washlngton, D.C.: U.S. Department of Energy, DOE/ERA-0056-2, September 1979.

Ch 3—Context for Cogeneration ● 65

Table 13.–New Capacity Additions (in megawatts, net operating capacity)

Added Planned After Total1979 1980 1981 1982 1983 planned

Private . . . . . . . . . . . . . . . . 9,167 22,373 13,139 17,582 137,832 190,930Public . . . . . . . . . . . . . . . . . 2,945 17,444 26,448 1,488 20,793 26,563Cooperative . . . . . . . . . . . . 1,640 2,675 1,543 2,577 11,376 18,171Federal . . . . . . . . . . . . . . . . 3,323 3,315 3,322 1,891 19,376 27,904

Total . . . . . . . . . . . . . . . . 17,075 30,107 20,652 23,522 187,377 263,658SOURCE: Office of Technology Assessment from U.S. Department of Energy data.

Table 14.—Capital Structure for Private Utiiities (average percent of capitalization)

1966 1970 1974 1977 1978 1979 1960Long-term debt . . . . . . . . . . . . . 52.3 54.8 53.0 51.0 50.5 50.4 50.4Preferred stock . . . . . . . . . . . . . 9.5 9.8 12.2 12.5 12.4 12.5 12.3Common stock. . . . . . . . . . . . . . 26.1 23.2 23.5 24.2 24,8 25.0 25.4Retained earnings . . . . . . . . . . . 12.1 12.2 11.3 12.3 12.3 12.1 11.9SOURCE: Edison Eiectric institute, Stat/st/ca/ Yearbook of the Electric Ut///tY hxfustrx W&l(Waahin@on, D. C.: Edieon Eiec-. .

tric Institute, November”1981).

pany’s property. In 1980, approximately 50 per-cent of total average IOU capitalization was longterm debt. In the same year, IOUS issued around$8.3 billion in long term debt (or 58 percent oftheir 1980 long term financing), $7.85 billion ofwhich was new capital and the remainder refund-ing. For the last quarter of 1980, the average yieldon all IOU bonds was 14.11 percent, with a rangeof 13.18 percent for Aaa bonds to 15.20 percentfor Baa bonds. For newly issued bonds, the aver-age yield in 1980 was 13.46 percent (20).

Common stock equity represented about 25percent of electric utilities’ total outstandingcapitalization in 1980. iOUs issued approximately$4.1 billion of common stock in 1980, or around28 percent of the long term financing obtainedby IOUS during that year. The average yield oncommon stocks during 1980 was 12.01 percent.The actual return on average common equity was11.4 percent, while the authorized rate of returnaveraged around 14.2 percent (20).

Preferred stock was about 12 percent of totaloutstanding electric utility capitalization in 1980.In the same year, approximately $2.0 billion ofpreferred stock was issued by IOUS (or about 14percent of total 1980 long-term financing), withan average yield of 12.28 percent (20).

Finally, IOUS may use internally generatedcapital or retained earnings to finance capacity

additions. The amount of retained earnings avail-able for financing usually is reflected by the ratioof dividends to net income, or the payout ratio.IOUS have had to pay a major portion of theirnet profits in dividends in recent years (75.8 per-cent in 1980), reducing their ability to financeprojects internally. In 1980, retained earningswere the smallest source of capital available toutilities (about 12 percent of total capitalization)(20).

Publicly Owned Utilities.–Publicly ownedutilities’ advantages over IOUS in financing newcapacity include their smaller size and thus lowercapital needs, their self-regulating (in most cases)and tax-exempt status, and their absence of con-cern about protecting shareholders’ equity. Yet this does not mean that they are totally withoutfinancing problems.

As with lOUs, the predominant form of munici-pal utility financing is long-term debt (73 percentof total 1979 capitalization) —mostly electric rev-enue bonds or general obligation bonds. Munici-pal bonds are attractive to investors because oftheir tax-free interest, but their average yield islower as a result (4.9 percent in 1979). Equityfinancing for municipal utilities is a combinationof direct investment by the municipal governmentand the retained surplus from operating revenues.The retained surplus is extremely important for


municipal’ ability to build a base for expansion;it averages about 10 times the amount of directinvestment by the municipal government (18). In1979, retained earnings represented an averageof 25.5 percent of municipal’ total capitalization(25).

The primary sources of long-term financing forcooperatives are insured loans and loanguarantees from the Rural Electrification Ad-ministration (REA). REA makes insured loans tothe local distribution co-ops at interest rates of2 to 5 percent, based on a revolving fund thathas a borrowing “floor” and “ceiling” specifiedannually by Congress. Loans from the revolvingfund are repaid from borrowers’ operating reve-nues and from collections on outstanding REAloans (16). Since 1973, REA also has been author-ized to make 100-percent loan guarantees topower supply borrowers–mostly G&Ts–for theconstruction and operation of powerplants andrelated transmission facilities. These guaranteesare made almost entirely by the Federal Financ-ing Bank, which borrows money from the U.S.Treasury. In fiscal year 1981, 34 REA loanguarantee commitments were made to powersupply borrowers; they accounted for about 85percent of REA’s total fiscal year 1981 electricfinancing programs. Interest rates on REA loanguarantees averaged about 15 percent (45).

REA insured loans are supplemented by moneyraised by the National Rural Utilities CooperativeFinance Corp. (CFC) in the public bond market.Co-ops that receive REA insured loans are re-quired to obtain from 10 to 30 percent sup-plemental financing from non-REA sources suchas CFC (which is a giant nonprofit co-op ownedby about 85 percent of the rural electric co-ops).CFC bonds accounted for approximately 4 per-cent of all rural electric co-op financing in fiscalyear 1981 (see table 15).

Regulatory Considerations.–Almost all aspectsof utility finance are regulated at either the Stateor Federal level or both. As in rate regulation, theStates have primary jurisdiction over intrastateutility financial transactions while the FederalGovernment regulates interstate financing ar-rangements as well as those with antitrust impli-cations.

In general, State regulation focuses on priorapproval of IOU’S issuance of mortgage and de-benture bonds and other long-term debts (e.g.,notes over 1 year), and of common and preferredstock. Some PSCS also regulate declarations ofdividends and budgets for capital expenditures.For public utilities, the authority to issue bondsderives from the State constitution or statutoryauthority. In many cases, a municipality must alsoobtain voter approval before issuing new bonds.

Table 15.—Sources of Long-Term Financing to REA Electric Borrowers (percent byfiscal year)

REAguarantee Other

Year REA 20/0 REA 5°A commitments CFC financing Total1969 . . . . . . . . 100.0% — — — — 100.0 ’%01970 . . . . . . . . 100.0 — — — 100.01971 . . . . . . . . 96.6 — — 3.4% — 100.01972 . . . . . . . . 72.2 — — 15.3 12.5% 100.01973 . . . . . . . . 32.4 52.80/o — 13.6 100.01974. . . . . . . . 3.1 26.0 45.80/o 4.9 20.2% 100.01975. . . . . . . . 5.1 28.7 58.2 7.7 0.3 100.01976 . . . . . . . . 10.3 24.5 57.6 5.1 2.5 100.0TQ . . . . . . . . . 7.6 22.5 64.8 3.3 1.8 100.01977. . . . . . . . 5.3 11.4 77.9 2.9 2.5 100,01978. . . . . . . . 5.1 20.8 66.2 6.0 100.01979. . . . . . . . 3.3 11.5 80.5 3.7 0.9 100.01980. . . . . . . . 2.0 11.3 81.4 4,3 0.9 100.01981 . . . . . . . . 2.8 10.6 78.7 4.0 3.9 100.0SOURCE: U.S. Congress, Senate hearfngs before the Commlttee on Appropiations, “Agriculture, Rural Development, and Related

Agencies Appropriations,” fiscal year IWO, 9t3th Cong., 1s1 aaas., part l—juntlflcations; National Rural ElectrlcComparative Association, peraonat communication to the OffIce of Technology Asaaaament.


Federal jurisdiction over electric utility owner-ship and financial operations includes regulationof debt and equity financing of holding com-panies and their acquisition of other entities, salesand purchases of utility property, and the is-suance of securities by both the Securities andExchange Commission (SEC) and FERC. In gen-eral, SEC regulates holding companies* under thePublic Utility Holding Company Act of 1935(PUI-ICA) in order to simplify their structures andto prevent abuses similar to those that occurredduring the 1920’s. SEC also regulates IOUS underthe Securities and Exchange Commission Act of1935 to protect investors and the public by pro-viding accurate information about a wide rangeof factors that may affect a utility’s financial posi-tion, and thus the relative risks associated withinvestment in its securities. Finally, under the pro-visions of the Federal Power Act, no utility mayissue securities, or assume any financial obliga-tion or liability (e.g., as guarantor, endorser, sure-ty, etc.) with respect to securities, without author-ization from FERC. FERC also must approve anyutility sale, lease, or other disposition of proper-ty worth more than $50,000, as well as mergersor consolidations of such property, if it finds theyare reasonably necessary or appropriate for theutility’s corporate purposes, are in the public in-terest, and will not impair the utility’s ability toprovide service. Utilities may file the same reportson securities with both FERC and SEC in orderto eliminate unnecessary paperwork.

Taxation.–Like financing, utility tax liabilitydepends to a large extent on ownership. IOUSare fully liable for all taxes—income, excise, prop-erty, and sales as imposed by various levels ofgovernment–whereas Federal and municipalutilities usually are exempt from all tax liability.However, Federal and municipal utilities oftenmake payments to local governments in lieu ofproperty taxes (about 25 to 50 percent of theotherwise exempted taxes). Cooperatives general-ly are exempt from income and excise taxes butliable for property and sales taxes. In addition,

*Holding companies are defined in PUHCA as those that direct-ly or indirectly control 10 percent or more of the outstanding votingsecurities of a utility (or other holding company) or that, in the judg-ment of SEC, could exercise a controlling interest over the manage-ment or policies of a utility or holding company sufficient to makeregulation necessary in the public interest.

cooperatives that derive more than 15 percentof their total revenues from nonmember servicesare liable for income taxes. In 1980, tax paymentsby IOUS averaged 12.7 percent of electric depart-ment operating revenues (20). The tax break-down for 1980 is shown in table 16.

Taxation is primarily an issue in electric utilityfinance and regulation to the extent it allowsspecial treatment that will reduce the cost ofcapital investments. The primary forms of specialtax treatment are the investment tax credit andaccelerated cost recovery coupled with specialfederally mandated accounting rules.

The investment tax credit (ITC) encourages in-vestment in new, used, or leased business prop-erty that is placed in service after 1980 and thathas a useful life of at least 3 years. The propertymust be depreciable (i.e., either tangible personalproperty or an improvement to real property usedin qualifying manufacturing or service busi-nesses). Buildings and real property are specifical-ly excluded from eligibility. Since 1975, treatmentof utilities under ITC provisions has been roughlyequal to that of other businesses.

The amount of ITC depends on the acceleratedcost recovery (ACRS) for the property. Propertyin the 3-year ACRS class (cars, light trucks, andresearch and development equipment) is eligi-ble for a 6-percent credit, and all other propertyreceives a 10-percent credit. There is a $125,000limit for qualifying investments in used propertyfrom 1981 through 1984, and a $150,000 limitafter 1984. If the available investment tax credit

Table 16.—Taxes Paid by Investor-Owned ElectricUtilities–Electric Department Only, 1980

Amount Percent o f(millIons of operating

dollars) revenue

Federal taxes:Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,242 1.5 ”/0Deferred taxes on Income . . . . . . . . . . . 1,347 1.7Other charges In lieu of taxesa . . . . . . . 1,392 1.7Miscellaneous . . . . . . . . . . . . . . . . . . . . . . 1,492 1.9

Total Federal taxes charged to income . . 5,473 6.8State and Iooal taxes. . . . . . . . . . . . . . . . . . 4,795 5.9

Total taxes charged to income . . . . . . . $10,268 12.7%alncludes Investment tax cradlts reported as charges to income for the current

year.

SOURCE: Edison Electric Inatltute, Stat/st/ca/ Yearbook of the E/ac@/c Ut///ty /rr-dustry, 1980, (VWshlngton, D. C.: Edlaon Electric Inatltute, November19s1).


exceeds a taxpayer’s liability in any year, the ex-cess credit may be carried forward for 15 yearsor backward for 3 years.

In addition to the standard ITC, an extra 10-percent credit may be available for investmentsin certain qualifying energy property (see table17) through December 1982. This energy taxcredit is not available on that portion of an in-vestment which is financed by tax-exempt orother subsidized financing (e.g., industrial devel-opment bonds). Moreover, public utility property(with the exception of hydroelectric equipment)does not qualify for the energy tax credit. Otherthan the exceptions outlined above, the rules per-taining to the energy credit generally parallelthose for the ITC.

The ITC and energy credit represent a directreduction in tax liability (for those businesses withsufficient tax liability to benefit from it) that, in

Table 17.—Energy Property Eligible for ITC Underthe Energy Tax Act of 1978

recuperators,heat wheels,heat exchangers,waste heat boilers,heat pipes,automatic energy control systems,turbulators,preheater,combustible gas recovery systems,economizers, orother similar property defined in regulations,

4.

5.6.

the principal purpose of which is to reduce the amount ofenergy used in any existing industrial or commercial proc-ess and which is installed in an existing industrial or com-mercial facility.Equipment used to sort and prepare for recycling or to re-cycle solid waste.Equipment for extracting oil from shale.Equipment for producing natural gas from geopressurizedbrine.

SOURCE: OffIce of Technology Assessment.

effect, reduces the cost of equipment purchases.Thus, these credits decrease the amount of in-vestment capital needed without reducing thebasis for cost recovery purposes. At present,many electric utilities have accumulated largebacklogs of excess credits due to the percentageoffset limitations and the accompanying carry-back and carryforward provisions (see table 16).If State regulators allow utilities to retain thebenefits of the ITC, they usually are used to helpdefray the costs of construction of new generatingcapacity rather than passed on to customers im-mediately.

The second form of tax treatment that canreduce the cost of capital investments is ac-celerated cost recovery. The Internal RevenueCode allows a deduction for “the exhaustion,wear and tear (including a reasonable allowancefor obsolescence)” of business or investmentproperty. Accelerated cost recovery allows prop-erty to be written off before its useful life hasended, either by shortening the useful life or byconcentrating larger deductions in the early yearsof the asset’s useful life. Under the Economic Re-covery Tax Act of 1981 (ERTA), cogeneratorsplaced in service after December 31, 1980, wouldbe in a 5-year cost recovery class, while publicutility property would be in a 5-, 10- or 15-yearclass, depending on its depreciation class underthe previous tax laws.

In a competitive industry, much of the reducedcapital cost that results from accelerated costrecovery would be passed on to customers in theform of lower prices. With regulated utilities,however, the State commissions have had todecide whether the taxes incorporated into therevenue requirement should be only those ac-tually paid (i.e., the benefits of accelerated costrecovery are “flowed through” to customers inyears of tax savings) or whether the taxes shouldbe “normalized” over the life of the investment(i.e., the taxes included in the revenue require-ment will be higher than actual taxes in the earlyyears and lower in later years and the benefitsare retained by the utility). Under ERTA, a publicutility that wants to take advantage of ACRS andITC must use normalization accounting to com-pute the tax expense for ratemaking purposes.If the utility uses flow-through accounting it must

Ch. 3—Context for Cogenerafion ● 69

use the same cost recovery method for both taxand ratemaking purposes.

In 1976, accelerated cost recovery is estimatedto have reduced customer rates by about $1.3billion (2.2 percent) and utility tax payments byabout $2 billion (51 percent). The ITC reducedrates to a much smaller extent (perhaps $200million), but decreased utility taxes by $1.3billion. The combined effect was a 2.6-percentreduction in customer billings, an 84-percentdecrease in Federal tax payments by utilities, anda 20-percent ($2 billion) increase in the cash flowsof normalizing utilities. In 1979, it is estimatedthat tax incentives provided IOUS with $3 billionper year additional construction funds (equivalentto 15 percent of annual construction expendi-tures). In some cases, these tax incentives mayrepresent the only source of internal funds forutilities (1 5).

Other provisions of Federal tax law that pro-vide investment incentives for utilities include adeduction for interest paid to bondholders thatreduces the cost of debt financing; a deductionfor IOUS of about 30 percent of the dividendspaid on preferred stock; and, a deduction for thecosts of repairs or improvements to depreciableproperty based on a specified annual percentageof the property’s cost.

REGULATION OF SERVICE AND OPERATIONS

The third major area of electric utility regula-tion is State and Federal jurisdiction over utilityservice and operations. The primary concerns ofsuch regulation are to ensure adequate service,to protect the public health and welfare, and tofurther national policy goals related to fuel use.

Service Regulation.– State PSCS have broadauthority over utility services, including grantingthe right to serve, defining service territories, andapproving major capacity additions. The primarymechanism by which a PSC exerts control overthese activities is the certificate of public con-venience and necessity, which essentially is a per-mit to operate a utility. In addition, many PSCSalso have jurisdiction over the operating charac-teristics of private (and some public) utilities, in-cluding authorizing or requiring interconnections,requiring utilities to operate as common carriers,ordering the joint use of facilities among two ormore utilities, and requiring line extensions withina utility’s service territory (see table 18).

The Federal Government’s primary role in reg-ulating utility service is through its authority overinterconnection and coordination among utilities.Under section 202(a) of the Federal Power Actof 1935, FERC (formerly FPC) was directed to

Table 18.—State Regulation of Utiiity Service and Operations

Number of PSCS according to -

type of utility regulatedAuthority Investor-owned Public Co-opCertificate of convenience and necessity

required for:Generating capacity additions . . . . . . . . . . . . . . . . 25 9 15Transmission line additions. . . . . . . . . . . . . . . . . . 28 14 20Distribution system additions . . . . . . . . . . . . . . . . 20 11 13Other plant additions . . . . . . . . . . . . . . . . . . . . . . . 16 8 11Initiating service . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 13 20Abandoning facilities or service . . . . . . . . . . . . . . 34 17 21

Regulate State exports . . . . . . . . . . . . . . . . . . . . . . . . 6 2 3Allocate unincorporated territory among utilities . 33 14 22Establish standards for:

Voltage levels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 17 24Safetv. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 21 26

alncludes w State commissions plus District of Columbia, Puerto Rico, and Vir9in Islands.

SOURCE: Alan E. Finder, The States and Electric Utility Regulation (Lexington, Ky.: The Council of State Governments, 1977).

70 ● lndustrial and Commercial Cogeneration

“divide the country into regional districts for thevoluntary interconnection and coordination offacilities for the generation, transmission, and saleof electric energy” in order to ensure an abun-dant supply of electricity throughout the UnitedStates “with the greatest possible economy andwith regard to the proper utilization and conser-vation of natural resources.” Once these districtswere established, the Federal Government’s rolewas limited to promoting and encouraging volun-tary interconnection and coordination of facilitieswithin and among them.

PURPA expanded FERC’S authority in regardto interconnection and coordination in a numberof ways. Section 205(a) of PURPA authorizesFERC (either on its own motion or upon receiptof an application) to exempt a utility from Statelaws, rules, or regulations that prohibit or pre-vent voluntary coordination, including agree-ments for central dispatch, if the coordination isdesigned to obtain the economic utilization offacilities and resources in any area. Section 205(b)directs FERC to study the opportunities for energyconservation, increased reliability, and greater ef-ficiency in the use of facilities and resourcesthrough pooling arrangements. Where such op-portunities exist, FERC may recommend to utili-ties that they voluntarily enter into negotiationsfor pooling. Finally, PURPA expanded FERC’S au-thority to order interconnections to include thosewith qualifying cogeneration and small powerproduction facilities, and to include wheelingorders. These provisions are discussed in detailin the next section.

Public Health and Welfare.–Regulation ofutility operations in the interests of protecting thepublic health and welfare focuses on safety stand-ards and on environmental protection. At theState level, the primary responsibilities includethe implementation of federally mandated pro-grams as well as the establishment and enforce-ment of minimum standards for voltage, meter-ing accuracy, customer and employee safety, andemergency situations and curtailments.

Such Federal legislation affects powerplantsiting and operation substantially through re-quirements for environmental impact assessmentsand pollution monitoring and control, as well as

through provisions that limit the available sitesfor large generating facilities. The most importantFederal programs in this area include:

The National Environmental Policy Act of7969 (NEPA), which requires all Federalagencies to include a detailed environmen-tal impact statement on every major Federalaction significantly affecting the quality of thehuman environment.The C/can Air Act sets National Ambient AirQuality Standards that are implementedthrough standards of performance for newstationary sources and guidelines for Statecontrol strategies for existing sources, andthrough guidelines for regulatory programsdesigned to improve air quality in non-attain-ment areas and to prevent degradation of airquality in clean air areas.The Clean Water Act imposes effluent limita-tions on quantities, rates, and concentrationsof chemical, physical, biological, and otherconstituents discharged into navigablewaters, and are implemented through am-bient water quality standards, effluent stand-ards for new and existing sources, standardsfor thermal discharges, and permit programs.The Resource Conservation and RecoveryAct of 1976 seeks to control the land disposalof solid wastes (e.g., fly and bottom ash,scrubber sludge) through a system of Stateplans and permits for solid waste disposal.The Atomic Energy Act, which includes com-prehensive licensing and permitting pro-cedures for both the construction and opera-tion of nuclear powerplants.The Occupational Safety and Health Act(OSHAJ which establishes standards for theprotection of workers, requires recordkeep-ing, and sets up a process for periodic in-spections and the filing of complaints.The Endangered Species Act of 1973, whichrequires that all Federal departments andagencies consult with the Secretary of the in-terior to ensure that actions authorized,funded, or carried out by them do not jeop-ardize the continued existence of thesespecies or result in the destruction or adversemodification of their habitat.The National Historic Preservation Act of1970 which requires all Federal agencies to


●

●

●

determine whether a proposed action willaffect a site or structure listed or eligible forlisting in the National Register and, if so, toobtain comments from the Advisory Coun-cil on Historic Preservation.The Fish and Wildlife Coordination Act of1970, under which Federal agencies mustconsult with the Department of the Interior’sFish and Wildlife Service and with the Stateagency having jurisdiction over fish andwildlife prior to taking any action potential-ly affecting surface waters.Army Corps of Engineers requirements thatall projects affecting navigable waters obtaina permit from the Corps.The Coastal Zone Management Act, whichrequires Federal agencies to obtain certifica-tion that proposed actions are consistentwith approved State programs.

Although this list of Federal programs is not all-inclusive, it offers a general idea of the scope oflaws and regulations that affect the siting, con-struction, and operation of central station gen-erating plants. These regulations can lengthen theIeadtime for siting and building a powerplant, re-quire technological and other environmental con-trols in plant design and operation, and imposesignificant monitoring and recordkeeping re-quirements during plant construction and opera-tion, all of which increase the direct costs of elec-tricity generation.

Regulation of Fuel Use.–Prior to 1973, thechoice of fuel for utility and industrial plants wasprimarily a matter of resource availability, eco-nomics, and convenience, as influenced by in-direct regulation through tax and environmen-tal laws, and price controls. Then, natural gasshortages and the 1973 oil embargo drasticallychanged the economic and supply considerationsof fuel use and introduced direct Federal regula-tion. The primary Federal regulations on fuel usethat affect utilities derive from the Fuel Use Act(FUA) and the Natural Gas Policy Act (NGPA),both part of the National Energy Act of 1978.

The primary purpose of FUA is to encouragegreater use of coal and other alternate fuels asthe primary energy source in utility, industrial,and commercial generation of electricity or ther-

mal energy, and thus to conserve oil and gas forother uses. To achieve these purposes, FUA pro-hibits the use of natural gas or petroleum as aprimary energy source in new electric pow-erplants and new major fuel-burning installa-tions* and provides that no new electricpowerplants may be constructed without thecapability to use coal or any other alternate fuelas a primary energy source. FUA also prohibitsexisting powerplants from using natural gas astheir primary energy source after 1990 and, inthe meantime, from switching from any other fuelto natural gas or from increasing the proportionof natural gas used as the primary energy source.Moreover, the Secretary of Energy can issue pro-hibition orders for the involuntary conversion ofexisting powerplants to coal or another alternatefuel if the owner or operator of the powerplantcommences the proceeding by filing an affirma-tive certification that the plant has the technicalcapability to use coal or another alternate fuel,or could have that capability without substantialphysical modification or reduction in rated ca-pacity, and it is financially feasible for the facili-ty to use coal or other non-premium fuels.

Through December 1980, FUA prohibition or-ders had been issued for 53 oil burning units–mostly powerplants—and another 13 units wereundergoing voluntary conversion to coal. In ad-dition, 33 powerplants and 15 major fuel-burninginstallations (MFBIs) are subject to outstandingconversion orders under an earlier law (theEnergy Supply and Environmental CoordinationAct of 1974). Together, these 114 units have thepotential to displace around 400,000 barrels (bbl)of oil per day (19).

FUA prohibitions are subject to a wide rangeof temporary and permanent exemptions. Thetemporary exemptions are granted for a periodof 5 years; some of these can be extended to atotal of 10 years but in no case beyond December31, 1994. The most widely used of these exemp-tions is a special public interest exemption for thetemporary use of natural gas in existing power-

*The provisions of FUA apply to powerplants and other ~tationavunits that have the design capability to consume any fuel at a heatinput rate of at least 100 MMBtu/hr or to a unit at a site that hasan aggregate heat input rate of at least 250 MMBtu/hr.


plants that would otherwise burn middle distil-lates or residual fuel oils. The 1,058 petitions forthis exemption that have been granted or are inprocess have the potential to displace 83,523bbl/day middle distillate, 323,825 bbl/day residualfuel oil with a sulfur content of 0.5 percent or less,and 236,950 bbl/day residual with greater than0.5 percent sulfur (or a total of 644,298 bbl/day)(19).

The actual effect of FUA on fuel use in existingand new powerplants and MFBIs is difficult todetermine without a case-by-case analysis. Theconsiderations imposed by the act must beviewed in the context of economic, technical,and managerial concerns. Absent a FUA prohibi-tion order or exemption request, it is not alwayspossible to identify the determining factor in elec-tric utilities’ fuel choice. Many energy analystsargue that it became cheaper to convert existingoil-fired plants to coal or to replace them withnew coal or nuclear plants when the price ofresidual fuel oil reached $30 to $40/bbl (2,46).However, the economics of displacing existingoil-fired capacity may be outweighed by utilities’financial problems and the costs of using alter-nate fuels. Thus, fully two-thirds of the capacitythat is economically feasible to convert has yetto be converted. Moreover, of the 66 units beingconverted under FUA, only 13 are doing so vol-untarily (i.e., without a prohibition order), andthose 13 represent only about 4 percent of thetotal potential oil displacement in the 66 units(19).

NGPA was designed to increase energy sup-plies while reducing domestic consumption. Ingeneral, the act distinguishes among a numberof different classes and categories of natural gasaccording to the date the gas is committed to in-terstate commerce, whether the well is onshoreor offshore, and the depth and location of thereservoir. Varying price schedules that wouldeventually lead to decontrol are established forthe different classes and categories. Theseschedules are supplemented with rules for alloca-tion and pricing of gas to final consumers. Resi-dential customers generally have first priority forsupplies under contract to interstate pipelines,with any remaining supplies spread through vari-ous lower priority commercial and industrial cus-

tomers. There are complicated resale price sched-ules for all customer classes, with the highestpriority generally being given the lowest of alloutstanding prices.

NGPA assigns the lowest priority industrial gasusers an incremental price equal to the new gaswellhead price plus regulated pipeline transpor-tation margins. This higher incremental price ismitigated through a ceiling determined by the al-ternative fuel oil price. In some areas, the ceil-ing is based on number two distillate fuel and inothers on residual fuel. Several users that other-wise would be subject to the higher incremen-tal prices are specifically exempted, includingsmall industrial boilers (using less than an averageof 300 MCF/day); agricultural uses for which alter-native fuels are not economic or available;schools, hospitals, and other institutions; electricutilities; and qualifying cogeneration facilitiesunder section 201 of PURPA.

Current Status of Electric Utilities

Economic, energy, and utility analysts agreeunanimously that the electric power industry—particularly the investor-owned portion-is introuble due to its deteriorating financial condi-tion (34,64). The symptoms are abundant, in-cluding declining real returns on equity and in-terest coverage, increased capital spending anddebt/equity financing combined with high divi-dends per share, high payout ratios, and lowmarket-to-book values. This situation representsa somewhat abrupt turnaround in the industry’sfinancial health. During the two decades from1945 to 1965, utilities accommodated rapid de-mand growth while continually lowering pricesby taking advantage of economies of scale ingeneration as well as greater efficiency intransmission and distribution. Capital expendi-tures remained relatively constant on a per-customer basis and utility costs actually declinedin some years although prices within the econ-omy in general were rising. Return on equity rosesteadily, most utilities had high bond ratings, andthe market-to-book ratio more than doubled.Moreover, during those two decades energy con-sumption in general moved in line with othereconomic activity as electricity demand grew at

Ch 3—Context for Cogeneration . 73

roughly twice the rate of the economy and farfaster than energy usage as a whole. The priceof electricity declined on an absolute basis as wellas relative to prices as a whole and to the priceof competing fuels (34).

However, 1965 is considered the watershedyear for the electric utility industry. In that year,stock prices, rate reductions, and interest cover-age ratios peaked, while a number of eventsreshaped utility capital investment such thatmoney spent would not necessarily lead to re-duced costs. For example, the Northeast blackoutrequired expenditures to improve reliability ofservice, but those expenditures would neitherreduce costs nor automatically be associated withincreased revenues. Similarly, the environmen-tal movement required capital expenditures thatdid not make plants more efficient or increasecapacity. The military buildup in Vietnam sig-naled the onset of high inflation rates and broughtconstruction delays and labor productivity prob-lems. Emerging natural gas shortages caused utili-ties to shift to more capital-intensive types of pow-erplants, including coal and nuclear fueled plants,that took longer to build, cost more, and operatedless efficiently (34).

As a result, capital spending accelerated, ratebase increased more rapidly than sales, and alarger percentage of financing requirements hadto be met through new capital (i.e., sales ofsecurities). The combination of rising interestrates, an increasing amount of debt, and relativelyslow growth in income resulted in decreasing in-terest coverage ratios and a decline in the quali-ty of utility debt, and thus even higher interestrates. The combination of higher interest ratesand lower return on equity pushed stock pricesdown until they fell well below book values. Theaverage market-to-book ratio went from an all-time high of 2.35 in 1965 to a low of 0.67 in 1974,and back up to 0.80 in 1978. Thus, during aperiod when securities were claiming an everlarger share of total capitalization, each new issuefurther diluted the interests of shareholders. Atthe same time, utilities began to capitalize anallowance for funds used during construction(AFUDC) in their income statements, which in-creased the non-cash portion of their reportedearnings. Therefore the overall decline in return

on equity was greater than was apparent fromthe reported figures. The only available solutionto the problem was to increase rates (34).

in 1970, the average price of residential elec-tricity increased for the first time in 25 years, andhas continued to rise ever since from its low of$.0209/kWh in 1969 to its high in 1980 of $.0493/kWh ($.0536/kWh for IOUS). * The averageprice of all electricity also has risen–from a lowof $.0154/kWh in 1969 to a high of $.0437/kWhin 1980 (4.72 WkWh for IOUS) (20). However,the rate relief obtained in the last 10 years hasbeen inadequate to raise interest coverage andreturn on equity to their previous levels and bondratings have fallen, increasing interest charges stillfurther. Moreover, although the price of electrici-ty did not increase as rapidly as those of com-peting fuels, it did go up more than prices as awhole throughout the economy.

The electric power industry’s problems up untilthe early 1970’s were compounded by other fac-tors during the last decade. First, the 1973-74 oilembargo drastically changed both fuel suppliesand prices, and utility customers cut back onelectricity consumption. In 1974, electric usageper customer decreased for the first time since1946, and the previously steady pattern of rapidgrowth (about 8 percent per year from 1947 to1972) changed dramatically.** But the industryhad geared its capital spending and its expensebudget to the previous sales gains. Capacity ad-ditions begun before 1974 became excess capaci-ty as these gains failed to materialize. Moreover,much of the new capacity installed or announcedin the years immediately preceding the embargowas oil-fired in response to environmental objec-tions to coal and to uncertainties in natural gassupplies. This decline in demand growth caughtutilities in a squeeze between high fixed costs anddeclining base rate revenue due to falling sales(34).

A second factor that dramatically affected utilityfortunes during the 1970’s was one utility’s omis-sion of a common stock dividend—a first for theutility industry-in April 1974. In that month, the

*Prices expressed in current dollars.* *while ele~rici~ demand growth has slowed noticeably, since

1973 it still has been about twice that of energy as a whole.


utility stock average fell 18 percent, and by Sep-tember had fallen 36 percent, the largest dropin any calendar year since 1937. Also, 1974 wasthe year that market-to-book ratios hit their lowof 0.67. The increased risk in utility stocks car-ried over to the market in lower quality bonds,and for the first time, investors had to considerthe possibility of a financial risk in utility securities,and utilities had to face the prospects of evenhigher costs for new capital (34).

A third major event affecting the electric powerindustry during the 1970’s was the accident atthe Three Mile Island (TMl) nuclear powerplantin 1979. Even before TMI, some investors hadbeen leery of nuclear-oriented utilities becauseof the huge sums involved in one project thatcould be delayed or halted by a determined op-position. The TMI accident added another risk–ifan operating nuclear plant went out of service,the power company might have to purchase farmore expensive electricity from other utilities. Ifthe regulators did not allow the purchased powercosts to be passed on to consumers, the utilitycould suffer serious financial losses. GeneralPublic Utilities, whose subsidiaries owned TMI,was forced to omit its dividend and was unableto place securities in the public market after theaccident. In conjunction with a weakened finan-cial state and excess generating capacity in manyareas, the accident accelerated the cancellationor deferral of nuclear projects by many electricutilities (34).

Based on some indicators, the general econom-ic and financial deterioration of the electric powerindustry that began in the late 1960’s and con-tinued through the 197o’s seems to have begunto turn around. Electric utility earnings began torise sharply in late 1980 and continued to increasethrough 1981. The gain in earnings lifted the aver-age return on equity (for a sample of 85 electricutilities representing 95 percent of IOU revenue)to 12.3 percent by September 1981 —the highestreturn earned since the late 1960’s. The propor-tion of capital spending financed with internallygenerated funds (including common equity) rosewith the return on equity, reaching 43 percentlate in 1981, entirely offsetting the decline thatoccurred during 1979 and early 1980 (63).

However, other indicators are not so favorable.Even though the earned rate of return has in-creased steadily in the last 2 years, it still lagsbehind the authorized return–estimated to beabout 14.2 percent in 1980. In addition, althoughoperating revenues have risen (by 18.3 percentin 1980) due to a combination of increases inrates, fuel adjustment clauses, and sales toultimate customers, the gains in revenues weremore than offset by increased operating expenses(up 19 percent in 1980), primarily due to higherfuel costs (20). Similarly, the increased percent-age of equity financing has not been sufficientto offset the record high interest rates. Utility in-terest expenses have continued to rise at morethan 20 percent annually while interest coverageratios (the ratio of net income and income taxesto interest expense) have remained relativelystatic for the last 2 years. In late 1981, the averageinterest coverage ratio was 2.47 with AFUDC, and2.01 without AFUDC. Common stock dividendpayout ratios have risen steadily, to a record 75.8percent in 1980 (compared to a traditional IOUpayout ratio of 65 to 68 percent). Finally, salesof stock have continued to dilute the book valueat a rate that more than offsets the contributionof retained earnings (63).

As long as interest rates remain high and earnedreturns on equity remain lower than authorized,utilities will continue to have trouble regainingtheir financial health. Without additional ag-gressive rate relief, growth in earnings is likely tocontinue to lag behind that of revenues. The highinterest rates would continue to favor equity fi-nancing over long-term debt, and thus continueto erode book value and increase payout ratiosto the detriment of stockholders’ interests. As aresult, IOUS are likely to continue having troublefinancing their construction budget.

Possibie Future Paths forthe Electric Power industry

A wide range of options are available to utilityplanners today, perhaps wider than at any timein the past. The menu of generating and othertechnologies from which to choose, the array ofinstitutional arrangements for financing andmanagement, the possibilities for investment on

the customer’s side of the meter—all have ex-panded greatly in recent years. All of these op-tions must be considered in the context of theirpotential to reduce utility dependence on oil andreduce capital expenditures and operating costs,while enabling utilities to continue to providereliable service and protect investors.

Given the numerous unpredictable events thathave plagued the electric power industry over thelast 15 years, utilities will have to develop planswith sufficient flexibility to handle a wide arrayof contingencies in demand growth, technologyavailability, and economic conditions. In manycases, these plans will be substantially differentin character from traditional planning, either dueto their approach to the size and mix of generat-ing technologies, or through planned controls onthe rate or type of demand growth.

One possible way to achieve such flexibility isfor a utility to diversify its energy mix. Thus, ratherthan being heavily dependent on any one fuel(e.g., coal, nuclear), the utility’s capacity wouldbe spread among the available options, reduc-ing the risk of a capacity shortfall in the event ofunexpected fuel shortages (e.g., a coal strike, anuclear accident). Second, utilities will have toplan for financing flexibility. Conventional largebaseload plants are extremely capital intensive.Because of their size, they often lead to short-term excess capacity until sales have a chanceto grow sufficiently to match the increasedcapacity. In addition, their long construction lead-times often mean high interest charges. As wasseen in the previous section, unless these largebaseload plants substantially increase system ef-ficiency and reduce utility costs, they can con-tribute significantly to financial deterioration.Smaller capacity increments, on the other hand,are easier to phase in as demand develops, andallow greater short-term financing flexibility. Inthis sense, the smaller additions substitute finan-cial optimization in planning for the engineeringoptimization achieved in large conventionalplants.

A third option for utility planners is to investin energy and fuel efficiency at the point of use.

As was seen in the discussion of the current statusof electric utilities above, one of the factors thatcontributed to current utility financial problemswas utilities’ need to make capital investments(e.g., for environmental protection, increasedsystem reliability) that neither reduced costs norserved new customers. Thus, overall system pro-ductivity declined as costs increased. In order toreverse this trend, some utilities are planning toinvest heavily in technologies that contribute tosystem efficiency (e.g., conservation, load man-agement) in lieu of new capacity.

Beyond these three major options, there areseveral other steps a utility can take to improveits financial position with regard to meeting futureservice needs. For example, joint action agencies(see discussion of utility organizations, above)allow a utility to benefit from economies of scalewhile also receiving the advantages of investmentin small capacity increments, including financialand planning flexibility. In some areas, conver-sion to public ownership may be an option forimproving utilities’ financial status, since public-ly owned utilities have access to lower cost capitaland do not need to be concerned with protect-ing stockholders’ interests.

However, utilities’ system and financial plan-ning is only one aspect of the future of the elec-tric power industry. Without appropriate regula-tion, many of the options discussed above willnot be feasible and even well-managed utilitiescould face financial and service dilemmas.

Utility regulators at all levels of government alsohave a wider range of options than has existedin the past. The problems faced by electric utilitieshave led to a better understanding of utility eco-nomics and its regulatory implications. The resulthas been a wide range of regulatory innovationsthat could complement utility planning for flex-ibility. But if regulators fail to take advantage ofsuch options, or to ensure that utilities are com-pensated adequately for the increased risks theywill be facing, even the most innovative utilityplanning will be to no avail.


REGULATION AND FINANCING OF COGENERATION

Historically, cogenerators faced three major in-stitutional obstacles when seeking interconnectedoperation with an electric utility. First, utilitiesoften were reluctant to purchase cogeneratedelectricity at a rate that made interconnectedcogeneration economically feasible. Second,some utilities charged very high rates for pro-viding backup service to cogenerators. Third, acogenerator that sold electricity risked beingclassified as—and therefore being regulated underState and Federal law as–an electric utility. Asa result of these and other disincentives, cogen-eration was not able to compete, except in largestand-alone industrial applications, with electrici-ty generated in central station powerplants plusthermal energy from conventional combustionsystems.

In recent years, however, cogeneration has at-tracted a lot of attention as a means of increas-ing energy efficiency, easing utilities’ financialstress, and reducing the amount of oil neededto supply electric and thermal power to buildingsand industries. Where these benefits are available(see chs. 5 and 6), recent changes in Federal andState regulation and in financing practices mayimprove cogeneration’s ability to compete withconventional energy conversion systems. Thissection describes the regulatory and financingconsiderations that may affect utility, industrial,or commercial firms’ decisions to install cogen-eration capacity.

Federal and State Regulation

A number of recent legislative initiatives are in-tended to clarify the role of cogeneration withinnational energy and environmental policy, andto encourage its use under those circumstanceswhere it would save fuel or allow increased effi-ciency in electric utilities’ use of facilities andresources. The most significant of these initiativesinclude PURPA which provides guidelines for re-lations among cogenerators, utilities, and regu-lators; other parts of the National Energy Act thataddress the use and cost of premium fuels; andprovisions of various environmental regulationsthat have been adapted to cogeneration’s specialproblems and opportunities.

The Public Utility Regulatory Policies Act

Title Ii of PURPA was designed to remove thethree obstacles to interconnected cogenerationlisted above. Under section 210 of PURPA, util-ities are required to purchase electricity from, andprovide backup service to, cogenerators (andsmall power producers) at rates that are just andreasonable, that are in the public interest, andthat do not discriminate against cogenerators.Section 210 also allows FERC to exempt cogen-erators from state regulation of utility rates andfinancial organization, and from Federal regula-tion under the Federal Power Act and PUHCA.Electric utilities also are required to interconnectwith qualifying facilities and must offer to operatein parallel with them. In order to qualify for theseand other benefits available under PURPA, co-generators must meet the requirements of sec-tion 201 for operating characteristics, fuel use,and ownership.

At this time, the fate of the PURPA provisionsis unclear. In January 1982, the U.S. Court of Ap-peals for the District of Columbia Circuit ruledthat portions of the FERC regulations imple-menting PURPA were invalid. Specifically, the ap-peals court vacated the FERC rules on rates forutility purchases of cogenerated power, and oninterconnections between utilities and cogen-erators, but upheld the FERC regulations on fueluse and on simultaneous purchase and sale (1).The Supreme Court has agreed to review the ap-peals court decision.

As a result of this pending case, it is not possi-ble to say definitively what is the Federal policyon cogeneration. Therefore this section will out-line the statutory provisions of PURPA and theFERC rules implementing those provisions, andwill review the relevant court rulings and theireffect on PURPA’S implementation.

REQUIREMENTS FOR QUALIFICATION

The benefits of PURPA are afforded only to“qualifying facilities.” Section 201 defines a quali-fying cogeneration facility as one that produceselectricity and steam or other forms of useful ther-mal energy for industrial, commercial, heating,

Ch 3—Context fo r Cogeneration-” 77

or cooling purposes; that meets the operating re-quirements prescribed by FERC (such as require-ments respecting minimum size, fuel use, and fuelefficiency); and that is owned by a person notprimarily engaged in the generation or sale ofelectric power (other than cogenerated power).

Ownership Criteria. –The conference reporton PURPA makes it clear that Congress did notintend to preclude electric utilities altogether fromparticipation in qualifying facilities (14). Thus,either directly or through a subsidiary company,an electric utility can participate in the owner-ship of a qualifying cogenerator. Rather, the thrustof the ownership requirement is to limit the ad-vantages of qualifying status to cogenerators thatare not owned primarily by electric utilities ortheir subsidiaries. Under the FERC rules imple-menting section 201, the legal test is whethermore than 50 percent of the entity that owns thefacility is comprised of electric utilities or publicutility holding companies (70). This ownershiplimitation does not apply to gas or other utilities.

Efficiency and Operating Standards.–TheFERC regulations require topping cycle cogenera-tion facilities to meet both operating and efficien-cy standards. Because “token” topping cycle fa-cilities could produce “trivial amounts of eitheruseful heat or power,” an operating standardwas established to distinguish bona fide cogen-erators from essentially single purpose facilities.This standard specifies that at least 5 percent ofa topping cycle cogenerator’s total energy out-put (on an annual basis) must be useful thermalenergy (69). There is no operating standard forbottoming cycle plants because they produceelectricity from otherwise wasted heat, and thusdo not have the same potential for “token” pro-duction.

The topping cycle efficiency standard is de-signed to ensure that an oil- or natural gas-firedcogenerator will use these fuels more efficientlythan any combination of separately generatedelectric and thermal energy using efficient state-of-the-art technology (e.g., a 8,500-Btu/kWh com-bined-cycle generating station and a 90-percentefficient process steam boiler). The efficiencystandard established by FERC specifies that, fortopping cycle cogenerators: 1) for which any of

the energy input is oil or natural gas; and 2) forwhich installation began on or after March 13,1980, the useful electric power output plus one-half the useful thermal energy produced must be,during any calendar year, no less than 42.5 per-cent of the energy input of oil and natural gas.However, if the useful thermal energy output isless than 15 percent of the total energy produc-tion, the useful electricity output plus one-halfthe useful thermal energy production must be noless than 45 percent of the total oil or gas input.Topping cycle cogenerators that were installedprior to March 13, 1980, and those that use fuelsother than oil and gas do not have to meet anyefficiency standards in order to qualify underPURPA (69).

The 2-to-1 weighting in favor of electricity pro-duction in these topping cycle efficiency stand-ards reflects FERC’S view that “systems with highelectricity to heat ratios have the highest second-Iaw’ energy efficiencies,” and their developmentand use should be encouraged (see discussionof the thermodynamic efficiency of cogeneratorsin ch. 4) (76). This weighting will be moreequitable to the various cogeneration technolo-gies than a standard that simply summed elec-tric and thermal output on an equal basis, be-cause the latter would have made it relativelyeasy for steam turbines that produce little elec-tricity to qualify, but would have penalized higherE/S ratio systems through difficult heat recoveryrequirements.

Because bottoming cycle facilities produceelectricity from normally wasted heat, the effi-ciency standard only applies to those with sup-plementary firing heat inputs from oil and naturalgas. In such facilities, the useful output of the bot-toming cycle must, during any calendar year, beno less than 45 percent of the energy input ofnatural gas or oil for supplementary firing (i.e.,the fuels used in the thermal process “upstream”from the facility’s power production system arenot considered in the efficiency test) (69).

Environmental Criteria.– FERC’S original re-quirements for qualification under PURPA deniedqualifying status to diesel and dual fuelcogenerators built after March 13, 1980, pendingenvironmental review. FERC’S final environmen-


tal impact statement (FEIS), released in April 1981,acknowledged that “an increase in the numberof diesel and dual-fuel cogeneration facilities inan air regime may cause significant environmen-tal effects in the near term.” But the FEIS con-cluded that existing State and local air qualitymonitoring and permit programs would be ade-quate to prevent such effects, and “unregulatedproliferation of diesel and dual-fuel cogeneratorsis not a realistic scenario.” Based on these con-clusions, FERC has declared diesel and dual-fuelcogenerators eligible for PURPA benefits (28).

Fuel Use Limitations.—Section 201 of PURPAspecifies that a qualifying cogeneration facilitymust meet “such requirements (including re-quirements respecting minimum size, fuel use,and fuel efficiency) as the Commission may, byrule, prescribe.” In implementing this section,FERC interpreted the statutory language as discre-tionary and chose not to impose fuel use limita-tions on qualifying cogenerators. FERC offeredfour arguments to support their position that thisdecision was consistent with congressional intentand national energy policy. First, FERC reasonedthat if Congress had intended to deny qualifyingstatus to oil- and gas-fueled cogenerators, PURPAwould have contained explicit restrictions on fueluse similar to those that apply to small power pro-ducers. Second, Congress did include fuel userestrictions on oil- and gas-fired cogenerators inFUA, which was enacted at the same time asPURPA. Therefore, FERC determined it would beboth unnecessary and inappropriate to imposean additional set of fuel use regulations underPURPA. Third, FERC argued that Congress rec-ognized that qualifying cogenerators would burnnatural gas by expressly exempting such facilitiesfrom the incremental pricing program underNGPA (enacted at the same time as PURPA).Fourth, FERC noted that the findings in section2 of PURPA require “a program providing for . . .increased efficiency in the use of facilities andresources.” Thus, the commission argued that oiland gas burning cogenerators should be grantedqualifying status to the extent that they providefor more efficient use of these resources, and theefficiency standards discussed above would besufficient to ensure such use (76).

FERC’S decision was upheld by the U.S. Courtof Appeals, which agreed with these four argu-ments and held that the statutory language isdiscretionary and that the regulations promul-gated by FERC were a reasoned and adequateresponse to the congressional mandate.

UTILITY OBLIGATIONS TOQUALIFYING FACILITIES

Under section 210 of PURPA and the FERC reg-ulations implementing that section, electricutilities have a number of obligations to qualify-ing cogenerators. These include the requirementthat utilities offer to purchase power from andsell power to cogenerators at equitable rates (in-cluding simultaneous purchase and sale), thatthey offer to operate in parallel with cogenerators,and that they interconnect with cogenerators.

Obligation to Purchase.–Section 210 ofPURPA requires FERC to establish “such rules asit determines necessary to encourage cogenera-tion,” including rules that require electric utilitiesto offer to purchase electric power from cogen-erators. FERC interprets this provision as impos-ing on electric utilities an obligation to purchaseall electric energy and capacity made availablefrom qualifying facilities (QFs) with which theelectric utility is directly or indirectly intercon-nected, except during system emergencies orduring “light loading periods” (see below) (75).

PURPA specifies that purchase power ratesmust be just and reasonable to the electricutilities’ consumers and in the public interest, andmust not exceed the incremental cost to the utilityof alternative electric energy. The FERC regula-tions use the term “avoided costs” to representthese incremental costs, and define them as:

The incremental costs to an electric utility ofelectric energy or capacity or both which, butfor the purchase from the qualifying facility, suchutility would generate itself or purchase fromanother source (68).

The energy costs referred to in this definitionare the variable costs associated with the produc-tion of electricity, and include the cost of fuel andsome operating and maintenance expenses (see

discussion of rate structures in the previous sec-tion). Capacity costs are the costs associated withproviding the capability to deliver energy; theyconsist primarily of the capital costs of generatingand other facilities (75). Thus, if by purchasingelectricity from a qualifying facility, a utility canreduce its energy costs or can avoid purchasingenergy from another utility, the rate for the pur-chase from the QF must be based on those ener-gy costs that the utility can thereby avoid. Similar-ly, if a QF offers energy of sufficient reliability andwith sufficient legally enforceable guarantees ofdeliverability to permit the purchasing utility tobuild a smaller less expensive plant, avoid theneed to construct a generating unit, or reducefirm power purchases from the grid, then the pur-chase rates must be based on both the avoidedcapacity and energy costs (75). In each case, itis the incremental costs, and not the average orembedded system costs, that are used to deter-mine avoided costs.

One way of figuring the avoided cost is to cal-culate the difference between: 1 ) the total capaci-ty and energy costs that would be incurred bya utility to meet a specified demand, and 2) thecost the utility would incur if it purchased energyor capacity or both from a QF to meet part ofits demand and supplied its remaining needs fromits own facilities. In this case, the avoided costsare the excess of the total capacity and energycost of the system developed in accordance withthe utility’s optimal capacity expansion plan ex-cluding the QF, over the same total capacity andenergy cost of the system including the QF (75).The FERC rules require utilities to furnish dataconcerning present and anticipated future systemcosts of energy and capacity to enable potentialcogenerators to estimate avoided costs.

The FERC rules outlined three primary consid-erations in determining avoided costs. The firstis the availability of capacity or energy from aQF during system daily and seasonal peakloads.If a QF can provide electricity during peak periodswhen the utility is running its most expensive gen-erating units, the electricity from the QF will havea higher value to the utility than power suppliedduring off-peak periods when only lower costunits are running. The relevant factors in deter-mining the QF’s availability include:

The utility’s ability to dispatch the cogener-ator will enhance its ability to respond tochanges in demand and thereby enhancethe value of the cogenerated power (see dis-cussion of interconnection in ch. 4).The expected or demonstrated reliability ofthe cogenerator (i.e., whether it may go outof service during the period when the utili-ty needs its power to meet system demand)will determine whether the utility can avoidthe construction or purchase of alternativecapacity.The terms of any contractor other legally en-forceable obligation (including its duration,termination notice requirements, and sanc-tions for noncompliance) also will providea measure of the QF’s reliability.If maintenance of the QF can be scheduledduring the periods of low demand on theutility system or during periods when theutility’s own capacity will be adequate tohandle existing demand, it will enable theutility to avoid the expenses associated withproviding an equivalent amount of capaci-ty on peak.If the QF can provide capacity and energyduring system emergencies, and canseparate its load from its generation duringsuch an emergency, it may increase overallsystem reliability and thereby enhance thevalue of the cogenerated power.The aggregate or collective value of capaci-ty from a number of small QFs may be suffi-cient to enable a purchasing utility to deferor avoid scheduled capacity additions whennone of the QFs alone would provide theequivalent of firm power to the utility.The Ieadtimes associated with capacity ad-ditions from QFs maybe less than the lead-time required for a utility powerplant, andthus the QF might provide savings in the utili-ty’s total power production costs by permit-ting utilities to avoid the excess capacityassociated with adding large generating unitsor by providing greater flexibility in accom-modating changes in demand (see ch. 6)(72).

The second consideration in a State regulatorycommission’s determination of avoided costsunder the FERC rules is the relationship of energy


or capacity from a QF to the purchasing utili-ty’s need for such energy or capacity. If an elec-tric utility has sufficient capacity to meet its de-mand, and is not planning to add new capacity,then the availability of capacity from a cogen-erator will not immediately enable the utility toavoid any capacity costs. However, a utility withexcess capacity may plan to build new plants inorder to increase system efficiency or reduce oiland gas use. If purchases from a QF allow theutility to defer or avoid these capacity additions,the rate for such purchases should reflect theseavoided capacity costs as adjusted for the lowerenergy costs the utility would have incurred if ithad added the new capacity (75), That is, if defer-ring new construction may actually increasepower costs, the qualifying facility may be cred-ited only with the net of the deferred and in-creased costs.

Third, the utilities and State commissions musttake into account any costs or savings fromtransmission line losses. Power produced by aQF maybe nearer to or farther from the servicearea than the utility-generated power it supplants.Because all power is subject to transmission lossesas a function of distance, the rate for energy pro-vided by the QF is to be net of line losses or gains.

In general, avoided costs are determined ona case-by-case basis. However, for small QFs, in-dividualized rates may have very high transac-tion costs. Therefore, the FERC rules requireutilities to implement standardized tariffs forfacilities of 100-kW electrical capacity or less, andpermit the use of such tariffs for larger units. Thesetariffs must be based on the purchasing utility’savoided cost, as described above, but may dif-ferentiate among QFs on the basis of the supplycharacteristics of the particular technology (72).

The net avoided cost concept leads to the pos-sibility that, despite their inherent efficiencies,QFs may at times produce power that is moreexpensive than power produced by the utility(e.g., when the utility is under a low load situa-tion and operating only baseload plants). Thus,if the utility has to reduce its baseload plant out-put in order to accommodate power purchasesfrom a QF, it may also have to utilize higher costpeaking units when load increases or supplies

from qualifying facilities drop, due to the longerstartup times of baseload plants. A strict applica-tion of the avoided cost rules under such cir-cumstances would mean a negative avoided costthat would have to be reimbursed by the QF. Toavoid the anomalous result of forcing a cogen-erator to pay a utility for purchasing cogeneratedpower, the FERC rules provide that an electricutility is not required to purchase power from aQF when such a purchase would result in net in-creased operating costs to the utility. A utility thatwants to cease purchasing from a QF due to theseoperational circumstances must notify each af-fected QF in time for the QF to stop deliveringenergy or capacity. If the utility fails to provideadequate notice of a light loading period, it mustreimburse the QF for energy and/or capacity asif the light loading had not occurred. The ex-istence of a light loading period is subject toverification by the PSC (75).

The FERC rules for purchase power rates do notpreclude negotiated agreements between cogen-erators and electric utilities on terms that differfrom the PURPA provisions. However, a QF thatneeds a long-term contract to provide certaintyin return on investment can still obtain a purchaserate based on the utility’s avoided costs, eitherby establishing a fixed contract price for energyand capacity at the avoided costs at the time ofthe contract or arranging to receive the avoidedcosts determined at the time of power delivery(75).

Finally, the FERC rules do not preclude Statesenacting laws or regulations that provide for pur-chase power rates that are higher than those thatwould obtain under PURPA. However, the Statescannot require rates at less than full avoided costsbecause such lower rates would fail to providethe requisite encouragement to cogeneration andsmall power production (75).

As mentioned previously, the FERC rules forpurchase power rates were challenged by theAmerican Electric Power Service Corp. (AEP) andseveral other electric utilities, who argued thatFERC’S requirement that purchase power ratesequal the utility’s full avoided costs forecloses thesharing of any of the benefits of the purchase withthe utility’s other customers, and thus contra-

venes the PURPA section 210 requirement thatsuch rates be “just and reasonable to the elec-tric consumers of the electric utility and in thepublic interest.” The U.S. Court of Appeals forthe District of Columbia Circuit held that Con-gress, in the statute, had clearly distinguished be-tween a “just and reasonable” rate and onebased on the full avoided cost, and that, although“the two may coincide,” FERC had not adequate-ly justified its adoption of a uniform full avoidedcost standard (1).

In the preamble to its final rule on purchasepower rates, FERC states that:

The Commission interprets its mandate undersection 21 O(a) to prescribe “such rules as it deter-mines necessary to encourage cogeneration andsmall power production . . . “ to mean that thetotal costs to the utility and the rates to its othercustomers should not be greater than they wouldhave been had the utility not made the purchasefrom the qualifying facility (75).

FERC considered several alternative standardsthat would have set the purchase rate at less thanfull avoided cost, including rate standards basedon a fixed percentage of avoided costs and ona “split-the-savings” approach. The commissionnoted that these pricing mechanisms would trans-fer to the utility’s ratepayers a portion of the sav-ings represented by the difference between theQF’s costs and those of the utility, and thus wouldprovide an incentive for the utility to purchasecogenerated power (75). The same argument wasmade by California utilities in opposing purchasepower payments based on full avoided costs, butrejected by the Public Utilities Commission (seediscussion of PURPA implementation, below)(lo).

However, FERC argued that, in most instances,the resulting rate reductions would be insignifi-cant for individual ratepayers, while if the full sav-ings were allocated to the QF they would pro-vide a significant incentive to cogenerate. Further-more, FERC felt that a “split-the-savings” ap-proach would require a determination of thecosts of power production in a QF—exactly thesort of cost-of-service regulation from which QFsare exempt under PURPA. FERC also argued thata fixed percentage standard would lead QFs to

stop producing additional units of energy whentheir costs exceeded the price to be paid by theutility, and thus could force the utility to operateless efficient generating units or consume morepremium fuels (l).

Based on these considerations, FERC deter-mined that only a rate for purchases that equalsthe utility’s full avoided costs for energy andcapacity would simultaneously satisfy the stat-utory requirements that the rate be just andreasonable to ratepayers, in the public interest,and not discriminate against QFs, and fulfill thestatutory mandate to encourage cogeneration.

The Court of Appeals ruled that FERC had ap-propriately rejected the split-the-savings approachbecause that would “veer toward the public utili-ties-style rate setting that Congress wanted toavoid” (1). However, the court recognized thatother alternatives to the full avoided cost stand-ard might allocate benefits between cogeneratorsand utilities more evenly without requiring an in-quiry into the QF’s production costs, and thatFERC should take a harder look at these alter-native approaches. In particular, the court statedthat FERC should reconsider the percentage ofavoided cost approach to determine whether itwould disproportionately discourage cogenera-tion. The court argued that the “bare unquan-tified possibility that a rule permitting rates at lessthan full cost might be insufficient to encouragethe last kilowatthour of cogeneration” is incon-sistent with the clear intent of PURPA, whichseeks to strike a balance among the interests ofcogenerators, electricity consumers, and thepublic (l).

The court also outlined several additional waysthat the avoided cost standard could disadvan-tage utility ratepayers, and specified that FERCshould address these in its subsequent rulemak-ing. First, the commission should take into ac-count, if possible, elements of utilities’ avoidedcosts that cogenerators would not also have topay (e.g., where the utility is subject to higherpollution control standards than a cogenerator,when a utility pays taxes at a higher rate thancogenerators). Second, FERC should consider autility’s capacity situation. If a utility has excess


capacity, cogeneration stimulated by full avoided cost payments may result in higher rates for the utility’s remaining customers (without increasing the utility’s total costs) due to the fixed cost -declining demand situation, in which the cogenerator reduces the number of customer-purchased kilowatt-hours over which the utility can spread a share of the fixed costs of the extra capacity (see ch. 6). Third, the full avoided coststandard precludes consideration of competitivemarket forces, that might encourage utilities topurchase a substantial amount of cogeneratedpower at a price lower than the statutory ceiling ( l ) .

As a result of all of the above considerations, the court held that FERC had not adequately justified its decision to prohibit any purchase power rates below full avoided costs, and vacated the FERC rate regulations and remanded the matter to the commission. However, the court emphasized that its holding:

. . . should not be read as requiring FERC to es-tablish different standards for a variety of cogen-eration cases and methods. A general rule is ac-ceptable, but the Commission must justify andexplain it fully, particularly in its balancing of theinterests of cogenerators, the public interest, and“electric consumers” (l).

As noted above, the U.S. Supreme Court has agreed to review the appeals court decision.

The purchasing utility normally will be the one with which a cogenerator is directly interconnected (i.e., the “local” electric utility). In some instances, however, either the cogenerator or its local utility may prefer that a second, more distant electric utility purchase the cogenerator’s energy and/or capacity. For example, if the local utility has no generating capacity, its avoided cost will be the price of bulk purchased power, which ordinarily is based on the average embedded capacity cost and the average energy cost on the supplying utility’s system. But if the QF’s output were purchased by the supplying utility directly, that output usually would replace the highest cost energy on the supplying utility’s system at the time of the purchase, and the QF’s capacity may enable the supplying utility to avoid adding new generating plants. Thus, the avoided costs

of the supplying utility may be higher than thoseof the local nongenerating utility.

Similarly, if the local utility has excess gener-ating capacity and/or relatively inexpensive coalor other alternate-fueled baseload generation, itsavoided energy costs could be quite low and itmay not have any avoided capacity costs. Aneighboring utility, however, may have excessload or expensive oil-fired baseload plants, andthus relatively high avoided costs.

For circumstances such as these, the FERC rulesprovide that a utility that receives energy orcapacity from a QF may, with the consent of theQF, transmit that energy or capacity to a secondutility. However, if the QF does not consent totransmission to another utility, the local utility re-tains the purchase obligation. Similarly, if thelocal utility does not agree to transmit the QF’senergy or capacity, it retains the purchase obliga-tion. Because the transmission can only occurwith the consent of the utility to which the energyor capacity is first delivered, this rule does notconstitute forced wheeling of power (75).

The FERC rule on transmission of cogeneratedpower to other utilities specifies that any electricutility to which such energy or capacity is deliv-ered must purchase that energy or capacity underthe same obligations and at the same rates as ifthe purchase were made directly from the QF.As discussed above, these rates should take intoaccount any transmission losses or gains. If theelectricity from the QF actually travels across thetransmitting utility’s system, the amount of energydelivered will be less than that transmitted, dueto line losses, and the purchase rate should reflectthese losses. Alternatively, the transmission canbe fictionalized (as in simultaneous purchases andsales—see below). For instance, energy and/orcapacity from a cogenerator may displace bulkpower that would have been purchased by a non-generating utility, as in the example cited above.In this case, the energy from the QF may replacea greater amount of energy than would havebeen purchased from the supplying utility (sincethe power from the latter is subject to greater linelosses than the power from the QF), and the pur-chase rate should reflect the net transmission gain(72).


obligation to SeIl.–Section 210(a) of PURPAalso requires that each electric utility offer to sellelectric energy to QFs. The FERC regulations in-terpret this obligation as requiring utilities to pro-vide four classes of service to QFs: supplemen-tary power, which is energy or capacity used bya QF in addition to that which it generates itself;interruptible power, which is energy or capaci-ty that is subject to interruption by the utilityunder specified conditions, and is normally pro-vided at a lower rate than non interruptible serv-ice if it enables the utility to reduce peakloads;maintenance power, which is energy or capaci-ty supplied during scheduled outages of the QF–presumably during periods when the utility’sother load is low; and backup power, forunsceduled outages (e.g., during equipment fail-ure). A utility may avoid providing any of thesefour classes of service only if it convinces the PSCthat compliance would impair its ability to renderadequate service or would place an undue bur-den on the electric utility (73).

PURPA requires that rates for sales of thesefour classes of service be “just and reasonableand in the public interest, ” and that they notdiscriminate against QFs. The FERC regulationsimplementing this requirement contemplate theformulation of rates based on traditional cost-of-service concepts (see discussion of rate regula-tion in the previous section), and specify that ratesfor sales to QFs shall be deemed nondiscrimina-tory to the extent that they apply to a utility’s non-cogenerating customers with similar load or othercost-related characteristics (73).

Thus, the FERC rules provide that rates for salesof power to QFs must reflect the probability thatthe facility will (or will not) contribute to the needfor and use of utility capacity. If the utility mustreserve capacity to provide service to a cogener-ator, the costs associated with that capacity maybe recovered from the cogenerator if the utilitynormally would assess these costs to noncogen-erating customers. If the utility can demonstrate,based on accurate data and consistent system-wide costing principles, that the rate that wouldbe charged to a comparable non-cogeneratingcustomer is not appropriate, the utility mayestablish separate rates for QFs according to thesedata and costing principles. However, any such

separate rates must still be nondiscriminatory, sothat the cogenerator is not “singled out to loseany interclass or intraclass subsidies to which itmight have been entitled had it not generatedpart of its electric energy needs itself” (73).

The FERC regulations also specify that rates forsales of backup and maintenance power may notbe based, without adequate supporting data, onthe assumption that all QFs will experience forcedoutages or other reductions in output eithersimultaneously or during the system peak. Thus,QFs are to be credited for either interclass or in-traclass diversity to the same extent as non-cogenerating customers, because such diversitywill mean that utilities supplying backup ormaintenance power to QFs probably will notneed to reserve capacity on a one-to-one basis.In addition, rates for backup and maintenancepower must take into account the extent to whicha QF can usefully coordinate maintenance withthe utility (74).

Simultaneous Purchase and Sale.–The FERCregulations specify that a utility must offer to pur-chase all of a cogenerator’s electric power out-put at avoided cost rates regardless of whetherthat utility simultaneously sells power to the QFat standard retail rates (72). In effect, this ruleseparates the electricity production and con-sumption aspects of QFs, and thus equalizes thetreatment of facilities which consume all thepower they generate with that of cogeneratorswhich sell some or all of their power (75).

AEP, et al., challenged this rule on the groundsthat it misconstrued the statutory terms “pur-chase” and “sale,” because it requires utilitiesto treat cogenerators as if they have engaged ina purchase and sale when in fact none might haveoccurred. The Court of Appeals disagreed, hold-ing that FERC’S rule is consistent with PURPA. Thecourt noted that the narrower construction of thestatute urged by AEP would result—anomalous-Iy–in discriminatorily different treatment forcogenerators that use some or all of their poweronsite and those that sell all their electric output.With such a narrow construction, cogenerationcould be uneconomical because utility retail ratesusually are lower than the utility’s incrementalenergy and capacity costs and the cost of cogen-erating.


AEP also argued that FERC did not adequatelyconsider and explain its decision to require utili-ties to engage in the simultaneous transaction fic-tion. The court found that FERC had consideredthe impact of this rule on all interested partiesand thus that the rule had been adequately jus-tified (l).

Obligation to Operate in Parallel.–The FERCrules also require each electric utility to offer tooperate in parallel with a QF, provided that theQF meets the State standards for protection ofsystem reliability (71). By operating in parallel,a QF can automatically export any electric powerthat is not consumed by its own load. Thus, thesame customer circuits can be served simultane-ously by customer- and utility-generated elec-tricity.

Obligation to Interconnect. -In their regula-tions implementing section 210 of PURPA, FERCargued that electric utilities’ obligation to inter-connect with QFs is subsumed within the pur-chase and sale obligations of section 210(a).Moreover, FERC noted that it has ample authorityto require utilities to interconnect with QFs underthe general mandate of section 210 that the com-mission prescribe “such rules as it determinesnecessary to encourage cogeneration and smallpower production” (75). Consequently, the FERCrules specified that “any electric utility shall makesuch interconnections with any qualifying facili-ty as may be necessary to accomplish purchasesor sales” (71).

AEP, et al., challenged this rule on the groundsthat it was inconsistent with sections 202 and 204of PURPA (which became sec. 210 and 212 ofthe Federal Power Act), as well as with PURPAsection 210 itself. Section 202(a)(l) provides:

Upon application of any electric utility, Federalpower marketing agency, qualifying cogenerator,or qualifying small power producer, the Commis-sion may issue an order requiring—

(A) the physical connection of any cogen-eration facility, any small power produc-tion facility, or the transmission facilitiesof any electric utility, with the facilitiesof such applicant.

In issuing an order under section 202(a)(l), theCommission must issue notice to each affected

party and afford an opportunity for a full eviden-tiary hearing under the Administrative ProcedureAct.

Section 202(c) states that FERC may not issuean order under 202(a)(l) unless FERC determinesthat the order:

(1) is in the public interest,(2) would–

(A) encourage overall conservation of energyor capital,

(B) optimize the efficiency of use of facilitiesand resources, or

(C) improve the reliability of any electric utili-ty system or Federal power marketingagency to which the order applies, and

(3) meets the requirements of section [204].

The requirements of section 204 are that FERCdetermine that an order issued under section202(a)(l):

(1) is not likely to result in a reasonably ascer-tainable uncompensated economic loss forany electric utility, qualifying cogenerator, orqualifying small power producer . . . affectedby the order;

(2) will not place an undue burden on an electricutility, qualifying cogenerator, or qualifyingsmall power producer . . . affected by theorder;

(3) will not unreasonably impair the reliability ofany electric utility affected by the order; and

(4) will not impair the ability of any electric utili-ty affected by the order to render adequateservice to its customers.

Finally, while section 21 O(e) of PURPA authorizesFERC to exempt QFs from provisions of the Fed-eral Power Act, it specifically excludes sections202 and 204 from such exemption.

In the AEP case, FERC argued that compliancewith sections 202 and 204 of PURPA would im-pose an undue burden on cogenerators and thuswould be contrary to the entire thrust of sections201 and 210. in particular, FERC noted that inenacting sections 201 and 210, Congress hadalready determined that QFs serve the purposeof the act to optimize the efficiency of use offacilities and resources by electric utilities, andthus it would be both redundant and unduly bur-densome to require QFs to meet all the re-quirements of sections 202 and 204 in order tosell power to the grid.


However, the U.S. Court of Appeals agreedwith AEP, holding that FERC’S rule requiring in-terconnection was inconsistent with PURPA. Thecourt noted that FERC, in promulgating an inter-connection rule that is consistent:

need not impose substantial administrativeburdens on those facilities, but rather can adoptstreamlined procedures. If the Commission be-lieves that even streamlined procedures are tooburdensome, the necessary amendment mustcome from Congress (1).

In its petition for rehearing of the AEP decision,FERC emphasized the basic intent of PURPA toencourage cogeneration, and argued that, with-out the interconnection requirement, the obliga-tion to purchase and sell is meaningless. FERCalso contended that PURPA section 210 is inde-pendent of, and does not amend, the FederalPower Act, and thus the interconnection require-ment must be read into PURPA and the section202 and 204 provisions interpreted as an alter-native means of obtaining interconnection.

If the AEP decision is upheld by the SupremeCourt, then QFs who cannot get a utility to agreeto interconnect will have to apply for a FERCorder under the procedures outlined in section202(a)(l), and thus meet the evidentiary re-quirements of sections 202 and 204. However,the requirements of sections 202(c) and 204would be very difficult and expensive for a QFto meet. Even in well-understood situations, theexpenses and delays associated with evidentiaryhearings under the Administrative Procedure Actwill deter all but those who have a pressing needfor an administrative order. But the multiplestringent legislative tests of sections 202(c) and204 are couched in new, broad language that willhave to be construed, first, by FERC and then,in all likelihood, by the courts. Thus, these pro-visions pose a substantial deterrent to cogener-ators that cannot get an electric utility to volun-tarily interconnect with them–exactly the prob-lem PURPA was intended to remedy. Options forresolving this issue are discussed in chapter 7.

Under the FERC regulations implementingPURPA, a QF must reimburse any electric utilitythat purchases energy or capacity from the facility

for interconnection costs. These costs are definedin the regulations as:

. . . the reasonable costs of connection, switch-ing, metering, transmission, distribution, safetyprovisions, and administrative costs incurred bythe electric utility and directly related to the in-stallation and maintenance of the physical facil-ities necessary to permit interconnected opera-tions with a qualifying facility, to the extent thatsuch costs are in excess of the correspondingcosts which the electric utility would have in-curred if it had not engaged in interconnectedoperations, but instead generated an equivalentamount of electric energy itself or purchased anequivalent amount of electric energy or capaci-ty from other sources (68).

Interconnection costs must be assessed on a non-discriminatory basis with respect to noncogen-erating customers with similar load characteris-tics, and may not duplicate any costs includedin the avoided costs (74). Standard or classcharges for interconnection may be included inpurchase power tariffs for QFs with a designcapacity of 100 kW or less, and PSCS may alsodetermine interconnection costs for larger facil-ities on either a class or individual basis.

State regulatory commissions have the authori-ty to ensure that utility requirements for systemsafety equipment and other interconnection re-quirements and their associated costs are reason-able. In practice, utility interconnection re-quirements vary widely (see ch. 4) and few PSCShave addressed the interconnection questiondirectly.

OTHER PURPA BENEFITS

Qualifying cogenerators are exempt from reg-ulation as a public utility or a utility holding com-pany under the Federal Power Act and PUHCA,and from State laws regulating the rates, struc-ture, and financing of utilities. However, if a reg-ulated electric utility owns more than a 50-per-cent equity interest in a qualifying cogenerator,the cogenerator will be subject to the traditionaljurisdiction of ratemaking authorities to the ex-tent of utility ownership. In addition, qualifyingcogenerators may be eligible for an exemptionfrom the FUA prohibitions on oil and gas use andfrom the incremental pricing provisions of NGPA.

IMPLEMENTATION OF SECTION 210

The FERC regulations on section 210 of PURPArequired State public utility commissions (PUCS)to begin implementation of the regulations byMarch 1981. Since that time, a wide range of draft

Table 19.—Rates for Power Purchased

and final rules have been issued by the States,and utilities have published a variety of tariffs forcogenerated power (see table 19). The State PUCShave taken full advantage of the procedural lati-tude allowed by the FERC rules, using rulemak-ing, adjudication, and dispute resolution to es-

From QFs by State-Regulated Utilities

Capacity paymentsUtility Energy payments (cents/kWh) ($/kW-yr) Comments

AlabamaAlabama Power Co.

ArkansasArkansas Power & Light Co.

CaliforniaPacific Gas & Electric Co.

Southern California Edison

San Diego Gas & Electric Co.

ConnecticutConnecticut Light & Power Co. and

Hartford Electric Light Co.

IdahoUtah Power & Light Co.

Washington Water Power Co.

Idaho Power Co.

Illinois

Illinois Power

Commonwealth Edison

Central Illinois Light Co.

2.59 on-peak, June-October2.17 off-peak, June-October2.14 on-peak, November-May2.05 off-peak, November-May

Reverse metering currently used

6.58 on-peak6.219 mid-peak5.553 off-peak6.030 non-TOD6.6 on-peak6.0 mid-peak5.8 off-peak6.0 non-TOD8.333 on-peak7.069 mid-peak6.225 off-peak6.850 non-TOD

Firm power6.7 on-peak (114.5% of fossil fuels cost)5.4 off-peak (90.5% of fossil fuels coat)Nonflrm power6.6 on-peak (110% of fossil fuels cost)5.2 off-peak (86.5% of fossil fuels cost)

Firm power 1,2Non.firm power 2.6

Firm power 1.6

Nonfirm power 2.4Firm power 1.639

Nonflrm power1.41-3.86 (varies each month,2.4 average)

2.42 on-peak summer1.55 off-peak summer2.65 on-peak winter1.88 off-peak winterNon-TOO:1.89 summer2.18 winter5.31 on-peak summer2.90 off-peak summer5.17 on-peak winter3.37 off-peak winter34 kV or greater2.3 on-peak2.1 off-paak12 kV to 34 kV:2.4 on-peak2.2 off-peakLess than 12 kV:2.5 on-peak2.3 off-peak

$0.75-$1.50/kW-month

25% of full value

$0.70-$2.00/kW-month

88-268 Increasing withcontract length4-35 years.

96-280 Increaslng withcontract length4-35 years.

0.3cents/kWh116-318 Increasing withcontract length4-35 years.

Nuclear 24%, coal 58%, oil 1%, gas 3%, hydro 14%.Off peak purchase rates are offered for utilities withouttime-of-day metering. Rates are for facllities Iess than100 kW.

Nuclear 17%, coal 9%, oil 44%, gas 10%, hydro 20°AComments on proposed rates were due byJune 1, 1981.

Nuclear 4%, oil 67%’., gas 1%, hydro 25%, other 3%.Rates are for February-April 1981.

Rates are for February-April 1961.

Rates are for February-April 1981.

Nuclear 38%, oil 80°/0, hydro 2%.

Purchase rates are temporarily In effect pending ap-proval of utlllty proposals. Percentage is tied tomonthly fuel adjustment. Firm power rates are forfacilities greater than 100 kW. Off-peak purchaserates are offered for facilities without tlme-of-daymetering. No size restrictions apply to non-flrmfacilities.

Oil 1%, gas 3%, hydro 96%The Idaho PUC has ordered UP&L to add some capac-

ity credit to the non-flrm energy payment.

Rates are for facilities less than 100 kW.

The Idaho PUC has ordered IPC to add some capacitycredit to the non-flrm energy payment.

Nuclear 19%, coal 57%, oil 23°/0, < 1% gas,<1 % hydro, 1 % other.

1,000 kW or less.

Ch. 3—Context tor Cogeneration ● 87

Table 19.—Rates for Power Purchased From QFs by State-Regulated Utilities-Continued

Capaclty paymentsutility Energy payments (Cents/kWh) ($/kW-yr) Commenta

Interstate Power Co.

Central Illinois Public Service

South Beloit Water, Gas &Electric Co.

Union Electric

Indiana

Indiana & Michigan Eiectric Co.

Indianapolis Power & Light

Northern Indiana PublicService Co.

Public Service Co. of IndianaSouthern Indiana Gee & Electric

Richmond Power & LightKansasKansas Power & LightMassachusetts

Boston Edison

Commonwealth Electrlc

Eastern Edison

Massachusetts Electric

Cambridge Electric

Nantucket ElectrlcManchester ElectricFitchburg Gas & Eiectrtc

Western Massachusetts Electric

Michigan

Statewide purchase rate includes:Consumers Power Co. andDetroit Edison

Mlnnesota

2.45 on-peak, June-September2.05 off-peak, June-September2.19 on-peak, October-May2.05 off-peak, October-May1.978 on-peak summer (3 months)1.620 off-peak summer1.884 on-peak winter (3 months)1.861 off-peak winter1.805 on-peak (rest of year)1.565 off-peak2.30 on-peak1.70 off-peakNon. TOD:1.77 summer1.53 winterTOO:2.41 on-peak summer1.36 off-peak summer1.50 summer, weekends and holidays1.86 on-peak winter1.35 off-peak winter1.35 winter, weekends end holidays

TOO:1.36 on-peak0.81 off-peakNon.TOD: 0.811.14 general rateSeaaonal:1.19 on-peak summer1.07 off-peak summer1.28 on-peak winter1.08 off-peak winter2.62 on-peak summer2.29 off-peak summer2.61 on-peak winter2.29 off-peak winterNorr. TOD seasonal:1.86 summer1.83 winter1.331.49 on-peak summer1.02 off-peak summer1.15 on-peak winter1.00 off-peak winter0.914

1.60

6.971 on-peak4.047 off-peak5.543 flat7.16 on-peak6.15 off-peak6.51 flat8.792 on-peak5.161 off-peak5.995 fiat5.51 on-peak4.79 off-peak5.08 fiat7.22 on-peak5.91 off-peak6.34 fiat7.444.7486.081 on-peak3.313 off-peak4,940 flat5.813 on-peak4.238 off-peak4.979 flat

2.5

Nuclear O%, coal 89%, oil 8%, gas < 1%, hydro 1%,other 2%.

Coal 35%, Oil 11%, gas 55%.Rate is for a cogenerator on-line since the 1920’s.Nuclear 9%, coal O%, oil 72%, gas <1%, hydro 18°/0,other 1%.

Interim rates. Energy rates wIII be reset every 3 monthswhen fuel adjustment is figured. QFs of 30 kW or lesscan use reverse metering.

Nuclear 14°/0, coal 47%., oii 230/o, gee 4%, hydro 11 O/.,other 1‘/0.

This rate was established prior to PURPA compliance.New purchase rates implemented in March orApril of 1982.

Nuclear 21%, coal 55°/0, oil 19%, gas 1%, hydro 2%,other 2%.


Table 19.—Rates for Power Purchased From QFs by State”Regulated Utillties—Continued

Capacity paymentautility Energy payments (cents./kWh) ($/kW-yr) Comments

Northern States Power Co,

Montana

Montana Power

Montana-Dakota

Pacific Power & LightNebraska

Omaha Public Power District

NevadaIdaho Power

Sierra PacificNevada Power Co.

New HampshireStatewide rate

New Jersey

Firm power2.08-3.07 increasing with contract length

5-25 years.TOD metering service:2.15 on-peak1.39 off-peakNonfirm power : 1.35Occasional power 1.66

2.7842

Nonfirm power2.21 on-peak1.57 off-peakNon firm, non-TOD: 1.91Firm power:1.97-3.08 (depending on contract length)

1.34-1.88

TOD metering:1.60 on-peak summer1.00 off-peak all year1.20 on-peak winterStandard rate: 1.10

1.71 (February)-4.16 (August)4.093.802 on-peak, October 1961

1.943 off-peak, October 1981

3.528 on-peak, November 1981

2.331 off-peak, November 1981

4.311 on-peak, December 1981

2,630 off-peak, December 1981

Firm power 8.2Nonfirm power 7.7

Jersey Central Power and Light Co. Approximate only:6.0-7.5 on-peak2.0-5.0 off-peak

Atlantic City Electric Co. Temporary rate: 2.5

New York

77.24 (25-yesr contractonly)

3.75-7.37 per kW-month

116.00-263.00 (1981)

6.1cents/kWh8.55 on-peak

October 19810.07 off-peakOctober 1961

0.14 on-peakNovember 1981

0.00 off-peakNovember 1981

0.14 on-peakDecember 1981

0.00 off-peakDecember 1981

Statewide minimum rate includes: 6.00 minimumLong island Lighting Co.,Niagara Mohawk Power Co.,New York State Electric &Gas CO.,

Consolidated Edison,Orange & Rockland Utilities, Inc.,Central Hudson Gas & Electric

Corp. and othersNorth Carolina(Note: North Caroiina capacity payments are given as cents/kWh not $/kW-yr as shown above.)Carolina Light & Power Co. 2.60-5.55 on-peak 1.49-2.39 summer

month2.074.04 off-peak 1.29-2.08 non-summer

monthsDuke Power Co. 2.38-5.20 on-peak 1.11-1.88 on-peak

months1.78-3.91 off-peak 0.68=1.00 off-peak

monthsVirginia Electric & Power CO. 4.23-9.30 on-peak summer 1.61-2.50 summer

3.59-4.30 peak non-summer 1.42-2.25 non-summer2.82-5.77 all others

Nanthahala Power & Light Co. 2.05 2.50North Dakota(Note: proposed rates–not yet finished.)Northern States Power Co. 2.15 on-peak 2.06-3.07 (cents/kWh)

1.39 off-peak

Temporary rate schedule in effect until further studiesare completed. These rates are intended to complywith PURPA requirements and are restricted to facili-ties less than 100 kW. Capacity credits are includedin firm power purchase rates. Non-firm power ratestake effect in the event that a firm producer does notprovide dependable generation. Occasional power islimited to 500 kWh/month.

Nuclear 0%, coal 32%, oil 5%, gas 1%, hydro 61 O/.,other 1%.

Non-firm rates for QFs of 100 kW or less.

Nuclear 26°/0, coal 48°/0, oil 130A, gas 9%., hydro 30A,other 3%.

Rates apply to facilities of 100 kW or less.

Nuclear OO/., coal 540/’, oil 5%, gee 23%, hydro 18%.Energy payments vary monthly. Capacity payments varyby length of contract.

Energy payments and capacity payments vary monthly.

coal 30%, oil 47 %, hydro 23%.Granite State Electric Utility is not required to pay the

firm power rate due to excess capacity.Nuclear 14%, coal 13%, oil 690/’, gas 1%, hydro 3%.Actual rates are determined by averaging marginalenergy rates for previous 3-month on-peak and off-peak hours. The rate appiies to facilities between10 and 1,000 kW.

This October 1980 rate was greater than averageenergy costs. The utility has proposed that buybackrates may be set at time of interconnection.

Nuclear 13%, coal 8%, oil 83%, hydro 15%°, gas andother 1%.

Nuclear 110/0, coal 71%, oil 6%, hydro 12%.

Rates increase with contract length.



NP&L purchases power from TVA.Coal 82%, oil 4%, hydro 14%.

Rates apply to facilities less than 100 kW. Capacitypayments increase with length of contract 5-25 years.Facilities larger than 100 kW treated case-by-case.

Ch 3—Context for Cogeneration . 89

Table 19.—Rates for Power Purchased From QFs by State-Regulated Utilities—Continued

Capacity paymentsUtlllty Energy payments (cents/kWh) ($/kW-yr) Comments

Nuclear O%, coal 20%, oil 3%, gee 65°/0, hydro 80A,other 40/o.

Formulae have been established to treat purchase ratesfor various types of small power producers. Bothenergy and capacity components are considered.

Nuclear 12%, coal 00/’, oil 70A, gas 1%, hydro 78°/0,other 2%.

Nuclear O%, coal O%, oil 99%, gas O%, hydro 1 %.

Okiahoma

0.66-3.05 depending on firmness ofcapacity

Statewide rate schedule includes:Oklahoma Gas & Electrlc Co.Public Service Co.

Oregon Reverse metering currently used

Rhode IslandNew England Power Co. 5.5247 on-peak

4.5339 off-peak4.9643 averagePrimary:6.412 on-peak4.642 off-peak5.511 averageSecondary:6.726 on-peak4.965 off-peak5.723 average4.473 on-peak4.093 off-peak4.317 average

Blackstone Valley Electric Co.

Newport Electric Co.

Nuclear 29%, coal 300/., oil 210/0, hydro 19°/0, gas andother 1%.

Rates are for facilities less than 5 MW.

South Carolina

Carolina Power & Light Co.

Duke Power Co.

46.68 summer40.20 non-summer60.00 (Based on

integrated capacityduring peak monthsJune-September,December-March).

2.60 on-peak2.07 off-peak1.96 on-peak1.49 off-peak

Coal 86%, oil 2%, gas 2%, hydro 1O%.Purchase rates are for facilities less than 1,000 kW(100 kW for hydro). Larger facilities are consideredcase-by-case (up to 3.5cents/kWh).

UtahUtah Power & Light Co. 2.2 (temporary rate) 2.6cents/kWh

C.P. NationalVermontStatewide rate schedule

2.2 (temporary rate) 2.66cents/kWhNuclear 57%, coal 3%, oil 16°/0, hydro 24%.Avoided costs are higher than would be expected from

Vermont’s capacity mix due to dispatch and account-ing practices of NEPOOL.

7.8 standard rateTOD rates:9.0 on-peak6.6 off-peak

Nuclear 17%, coal 59%, oil 170/., gas 20/., hydro 5°/0.Purchase rates are for facilities less than 200 kW.

Larger facilities are treated case-by-case.Purchase rates are for facilities less than 200 kW.

Larger facilities are treated case-by-case.

WisconsinWisconsin Power & Light Co.

Madison Gas & Electric Co.

1.60 on-peak1.75 off-peak (includes capacity)2.75 on-peak summer1.50 off-peak summer2.22 on-peak winter1.50 off-peak winterFirm power:3.65 on-peak summer1.45 off-peak summer3.45 on-peak winter1.45 off-peak winterNon firm power:2.90 on-peak1.45 off-peakFor 20 kW or less:1.81 on-peak1.14 off-peakFor 21-500 kW after 1986:1.60 on-peak1.14 off-peak1.90

Wisconsin Electrlc Co.

Northern States Power Co. $4/kW/month Prior to 1966 the rates for 20 kW and less apply to21-500 kW. No capacity credits will be paid until after1966. Facilities greater than 500 kW are treatedcase-by-case.

S4/kW-month

Lake Superior District Power Co. S6.02/kW-month Purchase rates are for facilities between 6 and 200 kW.Smaller facilities receive no payments. Larger facili-ties are considered case-by-case.

Wisconsin Public Service Corp. 1.65 on-peak1.32 off-peak

To be determinedaccording to character-istics of each facillty.

Coal 93%, hydro 6%, oil and gas 10/..

Purchase rates are for facilities less than 100 kW.

Wyoming(Note: All of the Wyoming purchaseUtah Power & Light Co.

rates are “experimental.”)Non-firm power: 2.2Firm power 2.60.53Cheyenne Light, Fuel and

Power Co.

Tri-County Electric Association

Available on demonstra-tion of demandreduction.

1.07

0.405

This is a non-generating utility which has based itsavoided costs on wholesale supply rates.

Montana-Dakota Utilities Co. Available on demonstra-tion of capacity dis-placement or demandreduction potential.

SOURCE: Reiner H. J. H. Lock and Jack C. Van Kuiken, “Cogeneratlon and Small Power Production: State Implementation of Section 210 of PURPA,” 3 Solar L Rep.659 (November-December 1961).

98-946 0 - B 3 - 7 : Q L 3

tablish rates and operating criteria. These pro-cedures have resulted in a wide diversity in Stateapproaches to PURPA as well as in the rates es-tablished thereunder. A comprehensive surveyof State implementation actions and cogenera-tion potential is beyond the scope of this assess-ment. Moreover, the status of these actions isuncertain due to the Court of Appeals case dis-cussed above. Therefore, this section will presentcase studies based on the implementation of titleII in three areas: California, where cogenerationhas a potentially large market and the State gov-ernment is actively promoting its use; Illinois,where cogeneration’s technical potential couldbe significant but the market will be limited bythe electric utilities’ large construction budget;and New England, where existing excess capaci-ty, extensive pooling agreements, and plannedconservation measures will influence cogenera-tion’s market potential. It should be emphasizedthat these case studies do not typify the range ofState and utility actions on PURPA. Rather, theyrepresent examples of three kinds of planningsituations that will affect PURPA’S implementa-tion. The same case study areas are used in theanalysis of cogeneration’s potential impacts onutility planning and regulation in chapter 6.

California.—The dominant factor in Californiautilities’ capacity planning is not demand growth,but the need to reduce their dependence on oil.Planning and construction of new coal and nu-clear baseload facilities was limited during the1970’s as demand growth declined, and cancella-tions and postponements of coal and nuclear ca-pacity left the State’s utilities heavily dependenton oil and natural gas. The California EnergyCommission’s (CEC) 1981 final report on electrici-ty projects an annual energy growth rate (meas-ured in GWh) of less than 1.5 percent through1992, but a capacity growth rate of approximately2.5 percent per year (5). The capacity growth rateis higher because it includes a projected 30-per-cent reserve margin (in case the energy growthrate is higher than 1.5 percent), the replacementof retired powerplants and expired purchasepower contracts, and the reduction of utility oiland gas consumption Statewide to one-half the1979 level by 1992.

The CEC report identifies three priorities thatshould be sufficient (according to the report) toprovide the needed energy and capacity for the1980-92 period: 1) additional conservation andpower pooling; 2) geothermal and renewable re-sources (biomass, wind, solar, small hydro, andexisting reservoirs); and 3) cogeneration and in-terstate electricity transfers. CEC estimates thatcogeneration could provide up to 3,000 MW ofgenerating capacity by 1992. Their estimate isbracketed by the California utilities’ long-rangeresource plans, which project 1,900 MW of co-generation capacity by 1992, and the NaturalResources Defense Council estimate of 4,300MW by 1995 (5).

State regulators in California had taken a num-ber of regulatory actions favoring cogenerationeven before the FERC rules implementing PURPAsection 210 became final. The California PublicUtilities Commission (CPUC) investigated the roleof cogeneration in utility resource planning (seefig. 13) and, in 1979, ordered Pacific Gas& Elec-tric (PG&E), in particular, and all of the State’selectric utilities in general, to adopt a specifictimetable for bringing cogeneration capacity intothe electrical system. Under the CPUC order,PG&E was expected to bring 2000 MW of cogen-eration into the resource base by 1985, principal-ly through contracts tied to the avoided cost ofoil-fired utility capacity that is displaced (8). Ina companion decision (this time in a PG&E gen-eral rate case), CPUC imposed a rate-of-returnpenalty on the company’s electric division for fail-ure to implement cogeneration projects aggres-sively. The penalty, which represented over $7million in annual revenues, or 0.2 percent inreturn on equity, was to be restored if PG&Ebrought 600 MW of cogeneration capacity undercontract by 1982 (7). Although PG&E was not ableto meet this goal, the CPUC staff recommended,late in 1981, that the penalty be discontinuedbecause the utility’s performance in encourag-ing cogeneration has been adequate (41).

PG&E planners argue that the CPUC goals of2,000 MW by 1985 are unrealistic. In a majorplanning study, PG&E estimated the cogenera-tion market potential in their service area to bebetween 204 and 903 MW of capacity additions


Flgure 13.–Statewide Utility Resource Plan Additions 1981=82:Renewable/lnnovative Technologies

4,500

I Biomass

3,600

1,800

900

0

Fuel cells

Fuel cells160/0

Wind 2Biomass 3

%

%

Fossilco-

gener-ation

Utility fi l ing - Utility filing Utility filing

with CPUC with CEC with CEC

1972 1974 1976 1978 1980 1980

July December

SOURCE: California Energy Commission, Electricity Tomorrow: 1981 Final Report (Sacramento, CalIf.: Ca/item/a EnergyCommission, 19S1).

by 1990 (beyond the 472 MW already operating),and their long range resource plan projects 190MW additional cogeneration capacity by 1985,and 600 MW by 1992. PG&E’s anaiysis suggeststhat industry would have to commit approximate-ly 12.5 percent of their total annual capital ex-penditures to cogeneration in order to meet theCEC goal of 2,000 MW under contract by 1985(41).

The California regulatory climate is unique. Inno other State has the public utility commissionparticipated so actively in capacity and resourceplanning. Encouraging cogeneration is an explicitpolicy expressed in price signals to the utility andfrom the utility to the potential cogenerator. De-spite these attitudes that favor cogeneration de-velopment, however, there remain significantquestions and uncertainties about the amount ofcogeneration capacity that can be counted on,and thus about the other types of capacity addi-tions that may be needed.

one major difficulty in assessing the extent offuture cogeneration development in Californialies in the special nature of the market, namely,the potential for large enhanced oil recoverycogeneration projects. The heavy oilfields in KernCounty, Calif., require steam injection or otheradvanced techniques for economic production.Converting existing steam boilers in these fieldsto cogeneration would involve projects with 200to 300 MW of generating capacity. CEC has stud-ied at least six of these projects, and one con-tract has been signed for 66 MW. Aggregate co-generation potential in the California oilfields hasbeen estimated by various sources to be between700 and 10,000 MW or more, depending on theprice of oil and the cogeneration technologyemployed (5,6,31 ,59).

In January 1982, CPUC issued their final deci-sion on rates and other standards for cogenera-tion and small power production pursuant to theFERC rules implementing sections 201 and 210

of PURPA. In general, this decision, known asOIR-2, requires utilities to file standard offers ap-plicable to QFs larger than 100 kw and tariffs forsmaller facilities. Both the standard offers and thetariffs are complete packages that include pricesfor power purchases and sales, requirements forinterconnection, and other relevant factors. Oncea utility’s tariff and standard offer terms are ap-proved by CPUC, purchases can be made underthem without further administrative review, andthe utility can recover its expenses for such pur-chases through an energy cost adjustment clausein the same manner as it recoups other purchasepower expenses (10).

Under OIR-2, utilities must file an array ofstandard offers based on different terms and con-ditions in order to provide QFs larger than 100kw with a sufficiently wide choice of options tomeet their particular needs, and thus to minimizethe use of nonstandard contracts that would haveto be reviewed individually by CPUC. In general,these include standard offers for energy andcapacity delivered by a QF both “as-available”and under a firm contract, and for energy andcapacity prices based on both the utility’s short-run and Iongrun marginal cost.

Standard offers for “as-available” energy andcapacity are based on the utility’s avoided costat the time of delivery, which is the cost the utilitywould have to incur to produce an equivalentamount of power at that time, or the utility’sshortrun marginal cost. The energy componentof this standard offer is defined as the highestvariable operating cost per unit of electricity pro-duced at a given time, and equals the productof: 1 ) the purchase price of oil used as the mar-ginal fuel over the last 3 months, and 2) theforecast incremental heat rates* of the plants ac-tually used by the utility to follow load. The as-available energy price also includes an aggregateadjustment for transmission and distribution costsand line losses or savings. In OIR-2, CPUC de-cided that it was not reasonable to treat thesecosts on an individual basis except for facilitieslarger than 1 MW at remote sites.

*Heat rate is a measure of thermal efficiency expressed in Btuinput per net kilowatthour output (see ch. 4). The marginal, or in-cremental, heat rate is calculated as the additional (or saved) Btuto produce (or not produce) the next kilowatthour.

The as-available capacity payment equals amarginal shortage cost that reflects the effects ofthe added increment of production on reservemargins and reliability, and is determined basedon the 1982 estimated cost of peaking capacity(represented by a combustion turbine). Thiscapacity payment is in cents/kWh varying by timeof delivery, and is available only for energydelivered through a meter to the utility. Thus,simultaneous purchase and sale QFs will receivethe capacity value for all the electricity theygenerate because their entire output is meteredat the generator before any goes to the QF’s loador the utility. Other QFs will only receive thecapacity value of the electricity actually deliveredto the utility (10).

Standard offers for energy and capacitydelivered under long-term contracts can bebased on either the utility’s shortrun or Iongrunmarginal cost. For shortrun marginal costs, energyprices can be contracted for up to 5 years basedon a forecast of the utility’s variable operating cost(described above). The QF must commit to de-liver all the electricity it produces to the utilityover the contract period. These contractual ener-gy payments can be combined with either as-available capacity payments or with firm capacitypayments based on shortrun marginal costs (1 O).

Firm capacity is equivalent to an increase insupply with corresponding standards, terminationprovisions, and sanctions regarding dispatch-ability, reliability, availability, and other factorsspecified in the FERC rules. The value of each ofthese factors is calculated based on the same per-formance standards utilities impose on their owngenerating plants. If a QF exceeds utility stand-ards, its capacity value should be increased cor-respondingly. The sum of each of these factorsdetermines the overall capacity value, which isto be offered on both a $/kW/yr and a cents/kWhbasis (10).

Alternatively, QFs can choose a contractperiod of up to 25 years with a firm pricing struc-ture for energy and capacity based on the utili-ty’s Iongrun marginal costs. This standard offeroption was included due to concerns that short-run marginal costs would be too volatile to pro-vide financial certainty and would not adequatelyreflect a QF’s value in the utility’s long-range

resource plans. The longrun marginal costs areestimated based on the fixed costs associated withthe utility’s resource plan and the correspondingsystem projected marginal operating costs (10).

Standard tariffs for QFs smaller than 100 kWprovide for purchase power payments incents/kWh calculated in the same manner as theas-available rates for larger facilities (describedabove). These tariffs may be time-differentiated,but if a small QF chooses not to buy a time-of-use meter, the utility may offer capacity paymentsthat aggregate over 1 year to 50 percent of thecapacity provided by facilities with such meters(lo).

Both standard offers and tariffs also provide forsales of supplementary, backup, maintenance,and interruptible power to QFs. The first threenormally are provided under the regular rateschedules applicable to all customers of the sameclass. However, the demand charges associatedwith such rates are substantially lower for QFsthan for other customers, and may be waived ifthe facility maintains an 85-percent on-peakcapacity factor. Interruptible rates apply to QFsto the extent their generation is used to serve theirown load (10).

Finally, CPUC allows nonstandard offers (thosethat vary from the terms described above) whenthey are necessary to shift some of a project’s riskfrom the QF to the ratepayers (e.g., in the caseof debt guarantees, Ievelized payments, or pay-ment floors). in return for accepting such risks,ratepayers are afforded some reduction onavoided cost payments. In general, the reason-ableness of nonstandard offers will be determinedduring the annual review of energy cost adjust-ment clauses or other normal rate proceedings.However, during the first 2 years of OIR-2’S im-plementation CPUC will provide advance reviewof those nonstandard offers about which a utili-ty has significant questions (10).

It is not clear how the California Public UtilitiesCommission would revise OIR-2 in the event thatthe FERC regulations implementing PURPA arerevised to require payments for QF power at lessthan the utility’s full avoided cost. The utilitieshave argued that full avoided cost paymentsbased on their highest variable operating cost,

as determined by the price of oil used on themargin, does not reflect the utilities’ actual fuelmix, and thus does not allow ratepayers to sharethe benefits of QF generation at a cost potential-ly below the utility’s marginal cost, nor does itcompensate utilities or their shareholders for thepotentially higher risks of reliance on QF energyand capacity. In issuing OIR-2, CPUC consideredarguments by the patties that full avoided costpayments disadvantage ratepayers (the same ar-gument accepted by the U.S. Court of Appealsagainst the FERC rules, as discussed previously).However, CPUC found that only full avoided costpayments would parallel the prices that wouldbe established in a competitive market, and thusgive consumers an efficient price signal and “en-courage the fullest possible efficient developmentof QF resources that can effectively and econom-ically compete with utility resources” (1 O).

On the other hand, CPUC did explicitly rec-ognize that payments at less than the full avoidedcost are appropriate when some of the risk of in-vesting in QFs is transferred to the ratepayers.CPUC also requested comments from interestedparties on whether utilities should receive apercentage of the avoided cost (e.g., one-half of1 percent) as a brokerage fee for serving as in-termediaries between QFs and electricity con-sumers. However, in such a scheme, the fullavoided cost would still be passed on to rate-payers through the energy cost adjustment clause(lo).

It is instructive to contrast the Californiacogeneration planning situation with roughlyanalogous efforts in New York by the Consoli-dated Edison Co. (ConEd). The potential cogen-eration market in ConEd’s service territory maybe large, but the principal ConEd customers likelyto cogenerate are large commercial buildings.Their primary economic motive would be toavoid high electricity bills, and they are less like-ly to sell excess power to the utility than Califor-nia projects. Given the large number and homo-geneity of ConEd’s potential cogenerators, it ispossible to analyze the market systematically.

Con Ed constructed a model of the cogenera-tion investment decision that calculates the costsand benefits of investing in cogeneration and

measures the internal rate of return from such in-vestments. Where this return, on an aftertax basis,would be 15 percent or better over a 10-yearhorizon, Con Ed assumed the investment wouldbe made. In order to estimate market size, thismodel was applied to the load data describingConEd’s 4500 largest customers. Depending oninput assumptions, Con Ed found a high range ofup to 750 potential cogenerators with a combinedpeakload of 1,483 MW, and an expected out-come or base case of 395 cogenerators with acombined peakload of 1,086 MW. ConEd hasused this model to characterize the sensitivity ofmarket size to the policies that would reduce their“loss exposure” to cogeneration (48).

ConEd’s loss exposure stems from a fixed-cost/declining demand problem. Because de-mand is not expected to grow, cogenerators leav-ing the system will shift a burden of fixed costsonto the other remaining customers. This wouldnot be a problem if there were enough new kWhsales or customers to replace the cogeneratorsleaving the system, but ConEd does not anticipatesuch growth. Situations such as the fixed-cost/declining demand problem, in which cogenera-tion has a potential to operate to the financialdetriment of utilities, are discussed in more detailin chapter 6.

If State regulators are asked to protect utilitysales from loss exposure, the utilities mustdemonstrate that the problem is real and substan-tial in magnitude. ConEd’s cogeneration modelpurports to make such a demonstration. How-ever, the New York Public Service Commission(NYPSC) argued that the model results were ex-tremely sensitive to input assumptions, and askedCon Ed to run the model using slightly higher costsfor cogenerators but holding utility rates constant.The result was an extremely small market poten-tial, with only 27 customers (130 MW of peak-Ioad) leaving the system (48). At this level of loss,there is no substantial economic threat to Con Ed.The NYPSC staff argued further that the actualmarket may be either smaller or larger than thisestimate, and until market penetration is morecertain, no policy changes are needed to protectConEd’s sales from loss exposure.

This loss exposure problem has not arisen inCalifornia. Thus, while CPUC is creating a climate

favorable to large-scale cogeneration develop-ment, it also is encouraging or ordering utilitiesto aggressively pursue conservation plans, in-cluding developing investment/finance plans forresidential weatherization and solar water heatingretrofit (9).

Illinois.–Electric utilities in Illinois currently areengaged in a massive construction program thatbegan before the 1973 escalation in oil prices.The largest companies, Commonwealth Edison(CWE) and Illinois Power (1P) are most heavily in-volved in new construction. CWE has six nuclearunits at various stages of completion, while 1P,a company roughly one-fifth the size of CWE, hasone.

The financial burden of this construction hasbecome increasingly onerous as utility kwh salesgrowth has lagged behind expectations. In thecase of CWE, the strain has appeared in the rapiddecline of their bond rating. In June 1980, Stand-ard and Poor’s lowered the rating on CWE deben-tures and pollution control bonds to BBB, thelowest rating acceptable to institutional investors.The rapid downgrading threatens to limit themarket for CWE debt securities, because investorsmay not want to risk the possibility of furtherrating cuts (35).

Moreover, in order to finance their $1 billionper year construction program, CWE needs morecash income. In 1979, CWE reported $297 mil-lion in net income to stockholders, but $222million of this was for AFUDC. Thus, 75 percentof net income did not represent cash (comparedto an industrywide 1979 average of 38 percent)(13). To improve CWE’S cash flow (as well as thatof 1P), the Illinois Commerce Commission (ICC)has allowed some portion of construction workin progress (CWIP) to be included in the ratebase. At the end of 1980, CWE had a balance of$4.14 billion in their CWIP account, while IP had$920 million (24).

Planning under these conditions leaves relative-ly few options for the utility and the Stateregulators. ICC has initiated investigations intoelectric load forecasting and reserve margin/reliability issues, but the only feasible option isdelaying part of the CWE construction program.With this option, the tradeoff is between extra

fuel savings and avoided escalation of costs fromcompleting construction, versus delayed fixedcharges by postponing it. The relative value ofthese factors depends on the projected growthrate in kWh sales. Lower sales growth meanssmaller fuel savings and a decreased value ofcompleting construction. In its study of delayingtwo of CWE’S nuclear units, the ICC staff foundthat even with zero growth in kWh sales, it wasbetter to complete construction without delay(65).

In contrast to the California regulatory system,ICC has not developed an independent forecast-ing capability. Instead it has channeled its ad-ministrative resources into financial analysis andproduction cost modeling to allow independentregulatory assessment of the costs and benefitsof construction delays (albeit with many engineer-ing assumptions determined by utility data). Theproduction cost modeling will provide a basis forestablishing purchased power rates as requiredby PURPA section 210. By contrast, the Califor-nia agencies have devoted relatively few re-sources to financial and production cost model-ing, but instead have concentrated on demandforecasting (35).

Given the lack of flexibility in any of the con-struction commitments of CWE and 1P, ICC haschosen to avoid conflict over future demandgrowth expectations. The sensitivity of ICC to thefinancial strains of the utilities makes it unlikelythat any effort will be directed toward demandreduction policies (35). The more relevant ques-tion in this jurisdiction is the extent to which ICCcan shelter the utilities from the damaging finan-cial impacts of competition either from conser-vation measures or from cogeneration and smallpower production.

ICC established purchase power rates for QFsbased on a time-of-day rate structure that reflectsavoided costs both on-peak and off-peak as wellas seasonal adjustments. These rates vary depend-ing on the utility’s fuel mix. Thus CWE—whichis roughly 40 percent coal, 30 percent oil, and30 percent nuclear—offers energy payments on-peak that are only slightly lower than those of-fered by PG&E (see table 19). However, the othermajor Illinois utilities, which have 85 to 98 per-

cent coal-fired capacity, have much loweravoided costs. None of the Illinois utilities is of-fering capacity payments to QFs, due to the cur-rent excess capacity situation in that State (39).

The future avoided cost path for CWE dependscritically on the growth rate of kwh sales. Highgrowth will require continued reliance on oil andgas for a significant fraction of annual energy re-quirements, but at an average annual rate of 2percent or less the primary avoidable fuel will becoal. Average avoided fuel cost estimates for CWEduring 1981-88 are shown in figure 14 for growthrates of zero and 2 percent. Figure 14 illustratesa situation of declining avoided costs; other CWEcalculations indicate a more conventional out-come, with increasing avoided costs over time(35). While the declining cost outcome is by nomeans certain to occur, it represents a risk to the

Figure 14.—CWE Average Avoided Cost Paths:Baseiine Construction~

1981 1983 1985 1988

aCalculations based on data supplied to the ICC by CWE.

SOURCE: Edward Kahn and Michael Merritt, Dk?persed E/ectr/c/ty Ganerat/omP/arm/rig and Regu/at/orr (contractor report to OTA, February 1981).

potential investor in cogeneration if economicfeasibility depends on sales of excess power tothe utility.

New England .–Electric power planning inNew England is dominated by the influence ofthe New England Power Pool (NEPOOL), a re-gional pool that fully integrates both operationsand planning, and by the fragmented nature ofthe regional utility industry. Most New Englandutilities are small by national standards, and eventhe larger New England systems are associationsof small companies. Under these conditions itwould be impossible for any individual companyto achieve the economies of scale offered by largebaseload units without undue risk and extra cost.By cooperating in joint venture projects, how-ever, the New England utilities are able to over-come the regional fragmentation and to captureeconomies of scale. From a regional perspectivethis has been a significant political achievement(35).

The New England utilities also can purchasecapacity from NEPOOL for minimal cost due tothe substantial excess capacity on the system (theNEPOOL reserve margin in 1979 was 38.6 per-cent or 5890 MW above the 15,278 MW winterpeakload) (17). A NEPOOL member can meet hiscapacity responsibility by paying a “deficiencycharge” of $22/kW annually to the pool. If thedeficiency is above 2 percent, then an additional$14/kW is required for this capacity (57). Evenallowing for some escalation in these charges, thisis a much lower opportunity cost of capacity thanthat estimated for potentially capacity shortregions such as California. PG&E, for example,is currently offering over $60/kW/yr for short-termcapacity contracts in the early 1980’s (54).

The principal problem facing NEPOOL and theNew England utilities is reducing oil dependencein face of the deteriorating financial condition of,and increasing opposition to, the region’splanned nuclear power projects. With the sub-stantial generation reserves in NEPOOL, approvalof new projects is more difficult politically. Theextreme regulatory risk is that completed projectswill not be entered into the rate base on thegrounds that they are unnecessary. Such a rul-ing has recently been made in Missouri (43).

Given the relatively large number of jurisdictionsin New England, the requirements for politicalconsensus on large-scale projects is severe. Bar-ring such consensus, the economy of scale capac-ity expansion strategy will fail (35).

Within this planning context, the New EnglandStates have adopted a variety of means of im-plementing PURPA, including two statewide ap-proaches (New Hampshire and Vermont), andone based on the cost differences between agenerating utility and its nongenerating sub-sidiaries (Massachusetts). Although most Stateregulatory commissions have adopted standardpurchase power rates based on each individualutility’s capacity mix and operating characteris-tics, nothing in PURPA precludes statewide oreven regional rates if they are appropriate andthey further PURPA’S goals of encouraging co-generation and small power production and pro-moting the efficient use of utility facilities andresources. Statewide or regional rates may beperceived as advantageous when, as in NewEngland, the operations of utilities are closely in-tegrated so that they effectively form a singlepower system. In this case, a rate that reflects theavoided costs of the system rather than of in-dividual utilities may provide a better signal ofthe value of QF power throughout the State orregion (38,75).

The New Hampshire PUC established a state-wide rate for utility purchases of QF power thatuses, as a substitute for individual utility’s avoidedcosts, the operating and maintenance costs of“the most recently constructed and most efficientoil generating station” (Newington) of the State’slargest utility (Public Service of New Hampshire)(38). Newington’s running costs were deemed tobe a “reasonable proxy” for statewide fullavoided costs because the other utilities in NewHampshire also rely primarily on oil for electricitygeneration from units with operating costs at leastas high as Newington’s.

The New Hampshire purchase rate can beraised to reflect the avoided costs of less efficientunits when the load exceeds Newington’s capaci-ty or when Newington is not operating. However,the rate cannot be lower. That is, the PUC es-tablished a lifetime guaranteed minimum (or


“floor”) rate for all QFs that begin operation priorto the completion of Seabrook I (a large nuclearunit). The guaranteed minimum encourages oil-displacing QFs to come on-line as soon as possi-ble rather than waiting to see how avoided costswill be affected by the completion of Seabrook,and provides assurance that QFs will have asteady income stream despite the volatility in oilprices. If avoided costs do drop after SeabrookI is completed, QFs that come on-line before thenwill be subsidized through the guaranteed min-imum, but such subsidies are authorized underthe New Hampshire Limited Electrical EnergyProducers Act, the State’s “mini -PURPA.” Thus,the primary question surrounding the guaranteedminimum rate is whether future PUCS will bebound by the decision of the present PUC or willdiscontinue the guarantee (38).

The Vermont Public Service Board based theirstatewide purchase rate on the estimated avoidedcosts of NEPOOL, as determined by the averageof the actual operating costs of three of theregion’s most efficient oil-fired baseload plants.The result was similar to that achieved in NewHampshire (see table 19). The Vermont rates willensure that QFs are not paid more than the costof oil-fired units in operation at any time, and willenable the State’s utilities to readily market QFpower either through NEPOOL or elsewhere. Therates are subject to annual revision, but cannotbe decreased by more than 10 percent in anyyear without a strong factual showing that agreater reduction is justified (38). This proceduredoes not provide as much protection againstchanges in avoided costs as the New Hampshireguaranteed minimum, but it does limit the rateof decrease if NEPOOL’S avoided costs drop sud-denly (e.g., if a new, more efficient baseload plantcomes on-line) and it conforms to the traditionalratemaking practice of not subjecting consumersto sudden, drastic changes in rates. As in NewHampshire, the Vermont rate guarantee couldresult in some subsidization of QFs, but probablywill average out over time and thus be within thelimits on such subsidies anticipated in the FERCreguIations.

A third approach was necessary in Massachu-setts to accommodate “all-requirements” con-tracts among the corporate members of the New

England Electric System, a public utility holdingcompany whose subsidiaries include a wholesalegeneration and transmission company (NewEngland Power) and two retail distribution com-panies that have “all-requirements” contractswith New England Power (a third distribution subsidiary purchases at least 75 percent of its elec-tricity needs from New England Power). Underthe FERC rules implementing PURPA, avoidedcost calculations are supposed to be based onthe supplying utility’s costs if the power is actuallywheeled, and otherwise on the nongeneratingutility’s cost of purchased power. The Massachu-setts Department of Public Utilities (DPU) peti-tioned FERC for avoided cost rates based on thesupplying utility’s costs, when the two utilities arecorporate affiliates, regardless of whether thepower actually is wheeled. DPU argued that suchrates would reflect “the true avoided costs of pro-ducing that power by the appropriate utility sys-tem,” rather than an intracorporate transfer pricethat might be kept artificially low (38). AlthoughFERC has not issued a decision on the DPU peti-tion, this approach does not seem to be pre-cluded by the FERC rules so long as it encouragesQF generation. However, if this approach re-quired DPU to look at the reasonableness of thewholesale rates between two corporate affiliates,it could infringe on Federal jurisdiction over suchrates under the Federal Power Act (38).

The basis for setting purchase power rates inNew England is likely to be tied to oil costs forat least the next 10 years. There is, however, morethan one way to reflect oil dependence in PURPArates. The New Hampshire decision, for exam-ple, is based on projected rather than actual oilcosts. Presumably such a procedure is intendedto correct the accounting lags that occur whenactual costs are used and prices are rising rapid-ly. The California rates discussed above achievea similar result by indexing rates to the averageoil cost in the previous quarter (8,1 O). The Califor-nia approach will match rates more closely withavoided costs and eliminate the uncertainty ofprojecting oil prices, but also will result in lowerpayments.

Given the current excess capacity in NewEngland, any capacity payments made to cogen-erators will be limited by NEPOOL deficiency


charges. For example, the New Hampshire andConnecticut capacity payments of 5 mills/kWh(the difference between the payments for firmand nonfirm power) correspond roughly to theNEPOOL deficiency charge of $22/kW, wherethis capacity would be required 4,400 hr/yr($22/kW / 4,400 hrs = 0.5 cents/kWh) (34).

The introduction of QF power into NEPOOLinterchanges raises the question of whetherNEPOOL billing procedures might reimburse theVermont utilities on a basis other than fullavoided cost. NEPOOL has a complex “split-the-savings” formula that allocates 50 percent of thesaving to cover NEPOOL overhead and appor-tions the remaining 50 percent among utilitiesbased on their volume of business with NEPOOLover a certain period. Due to the relatively lowvolume of business Vermont utilities do withNEPOOL and the large difference between theutilities’ incremental cost and NEPOOL’S decre-mental cost, in most cases Vermont utilities willnot receive the full NEPOOL avoided cost for QFpower they supply to the pool. If the utilities mustpay QFs the full NEPOOL avoided cost, but re-cover less than that from the pool, the utilitiesmust either absorb the difference as a loss or passit on to their ratepayers. The most obvious solu-tion is for NEPOOL to recognize QFs as “sourcesof power” to utilities under the pool agreement.This is the approach adopted by New EnglandPower in several recent contractual arrangementswhich identify dispatchability as the main oper-ative distinction: a purchased power resource thatcan be dispatched by the utility or NEPOOL isa generation resource. Anything else is a negativeload (38).

Alternatively, NEPOOL could change its bill-ing practices to accommodate full avoided costrates by treating QF power as its marginal powerrather than mixing it in with other power fur-nished by a utility. In this case, NEPOOL would,in effect, directly purchase QF power at its fullavoided cost and the utility would merely serveas a conduit. Thus, this approach is similar to theFERC provisions for wheeling power through alocal utility to a more distant utility.

FUTURE AVOIDED COST PATHS

Given the wide regional variation in the eco-nomic and regulatory environment of electricutilities, uniform implementation of PURPA sec-tion 210 pricing incentives is unlikely. The pat-tern of avoided costs over time will depend onexisting regional fuel mix and reserve margin, aswell as on regulatory policy toward rates andcapacity expansion. Figure 15 illustrates severalgeneric paths for average utility avoided costs.A given company will start off on the left-handside of this figure with its fuel base dominatedby oil, coal, or nuclear steam generation. As cur-rent construction is completed and fuel costs con-tinue to increase, the fuel base and its value willchange. The basis of PURPA payments, avoidedcosts, also depends on future demand growth.To the extent that supply and demand are outof equilibrium, there will be cost implications forcogenerators and small power producers. Onepossibility of this kind is the potential for perma-

Figure 15.–Generic Paths for Average AvoidedCosts (mills/kWh)

180

120

80

SOURCE: Edward Kahn and Michael Merritt, L)/spamed E/ectr/c/ty Generation:P/ann/ng and Ffegu/at/on (contractor report to OTA, February 1981).


nent excess capacity; e.g., if State regulatorsauthorize construction of central station plantsto displace oil. Resulting reserve margins maybeso great as to preclude PURPA payments for ca-pacity. To examine the potential variety of out-comes, it is-helpful to trace out various pathwaysthrough figure 15.

Starting at the upper left with the shortrunmarginal cost (SRMC) of oil, several develop-ments are possible. At some point, this shortrunmarginal cost curve will intersect the Iongrunmarginal cost (LRMC) curve. If the utility mustcontinue to displace large amounts of oil at thispoint, the avoided cost will continue to increaseat the oil price escalation rate. Two other alter-natives are possible. The utility fuel mix may bein equilibrium when SRMC (oil) = LRMC. In thiscase avoided cost becomes Iongrun marginalcost, which is likely to rise much more slowlythan oil prices. The third alternative is permanentexcess capacity. This could occur in any numberof ways; all that is required is for constructioncommitments to exceed long-term demand. Inthis scenario avoided costs level out over timeand converge ultimately to the shortrun marginalcost of coal or nuclear plants (35).

Starting out from a fuel base of excess coal ornuclear capacity, a utility’s average avoided costsalso will eventually reach equilibrium with long-run marginal cost. This may not occur verysmoothly, as figure 15 indicates. At some timeexcess capacity will be exhausted and new facil-ities will be necessary. At this point the avoidedcost will take a major step upward. Addition ofnew facilities in such circumstances would posethe practical problem of allocating the Iongrunmarginal cost to capacity and energy for the pur-pose of designing rate schedules for purchasedpower (35).

Regulation of Fuel Use

Cogenerators’ fuel choice may be influencedby the FUA prohibitions on oil and gas use andby the allocation and pricing rules of NGPA, aswell as by environmental requirements and taxincentives (see following sections).

The Fuel Use Act.-A cogenerator may be sub-ject to the FUA prohibitions if it has a fuel heat

input rate of 100 million Btu per hour (MMBtu/hr)or greater (or if the combination of units at anyone site exceeds 250 MMBtu/hr), and if it comeswithin the statutory definition of either a power-plant or a major fuel-burning installation. UnderFUA, a powerplant includes “any stationary elec-tric generating unit, consisting of a boiler, a gasturbine, or a combined-cycle unit that produceselectric power for purposes of sale or exchange,”but does not include cogeneration facilities if lessthan half of the annual electric output is sold orexchanged for resale. A major fuel-burning in-stallation is defined as “a stationary unit consistingof a boiler, gas turbine unit, combined-cycle unitor internal combustion engine.” However, theprohibition against the use of oil and gas in newmajor fuel-burning installations applies only toboilers.

Cogenerators can seek any of four different ex-emptions from FUA. The one most likely to beused is the cogeneration exemption. If this doesnot apply, the permanent exemption for the useof a fuel mixture or the temporary exemptionsfor the future use of synthetic fuels or for publicinterest considerations may be available.

FUA allows a permanent exemption for cogen-erators if the “economic and other benefits ofcogeneration are unobtainable unless petroleumor natural gas, or both, are used in such facilities.”The Department of Energy (DOE) interprets thephrase “economic and other benefits” to meanthat the oil or gas to be consumed by the cogen-erator will be less than that which would other-wise be consumed by conventional separate elec-tric and thermal energy systems. Alternatively, ifthe cogenerator can show that the exemptionwould be in the public interest (e.g., a technicallyinnovative facility, or one that would help tomaintain employment in an urban area), DOE willnot require a demonstration of oil/gas savings(72). The regulations to implement the cogenera-tion exemption are in the process of being revisedin order to simplify the procedures for calculatingoil and gas savings. Therefore, it is uncertain howdifficult it will be to meet the exemption re-quirements, and thus how FUA will affect themarket penetration of cogeneration (67).

Although the permanent exemption for cogen-eration is likely to be the preferred route for

100 ● Industrial and Commercial Generation

potential cogenerators subject to the FUA pro-hibitions, several other exemptions may be ap-plicable in certain circumstances. First, a perma-nent exemption is available to petitioners whopropose to use a mixture of natural gas orpetroleum and an alternate fuel. Under this mix-tures exemption, the amount of oil or gas to beused cannot exceed the minimum percentage ofthe total annual Btu heat input of the primaryenergy source needed to maintain operationalreliability of the unit consistent with maintaininga reasonable level of fuel efficiency. Second, atemporary exemption is available to petitionerswho plan to use a synthetic fuel (derived fromcoal or another fuel) by the end of the exemp-tion period. Third, a temporary public interestexemption may be obtained when the petitioneris unable to comply with FUA immediately (butwill be able to comply by the end of the exemp-tion). One of the cases where this public interestexemption may be granted is for the use of oilor gas in an existing facility during the ongoingconstruction of an alternate fuel-fired unit (77).

NGPA grants an exemption from its incremen-tal pricing provisions to qualifying cogenerationfacilities under section 201 of PURPA. However,a similar exemption also is available to small in-dustrial boilers and to utilities. Thus, the poten-tially lower gas prices should not affect the rel-ative competitiveness of gas-fired cogenerationsignificantly. Moreover, plants burning intrastategas may not realize any savings because the fuelprice is often at the same level as the incremen-tal price. In addition, deregulation could largelyremove incremental pricing. These uncertaintiesmean that NGPA probably will not be a majorfactor in cogeneration investment decisions (58).

Environmental Regulation

Federal, State, and local requirements for en-vironmental and safety regulation will affectcogeneration, although not to the same degreeas they do central station powerplants. The prin-cipal effects will result from permitting re-quirements and from the multiple jurisdictionalresponsibility for such permitting, which couldincrease the cost and Ieadtimes for deploymentof cogenerators and impose additional burdenson State agencies.

THE CLEAN AIR ACT

As discussed in chapter 6, cogeneration canhave significant impacts on air quality, especial-ly in urban areas. Depending on a cogenerator’ssize and location, it may be subject to one ormore of the Clean Air Act provisions, includingnew source performance standards (NSPS) andprograms for meeting and maintaining the Na-tional Ambient Air Quality Standards (NAAQS)in nonattainment and prevention of significantdeterioration (PSD) areas.

At present, NSPS exist for two types of sourcesthat might be used for cogeneration, and havebeen proposed for a third. NSPS have been im-plemented for electric utility steam units ofgreater than 250-MMBtu/hr heat input. However,cogeneration facilities in this category are exemptfrom NSPS if they sell annually less than either25 MW or one-third of their potential capacity.The other promulgated NSPS is for gas turbinesof greater than 10 MMBtu/hr heat input at peak-Ioads, but units in the 10-to 100-MMBtu/hr rangeare exempt until October 1982 and, in addition,have higher allowable nitrogen oxide (NOX)emission limits than units above 100 MM Btu/hr.NSPS have been proposed for NOX emissionsfrom both gasoline and diesel stationary engines.As proposed, they would apply to all dieselengines with greater than 560 cubic inch dis-placement per cylinder. Finally, the Environmen-tal Protection Agency is considering an NSPS forsmall fossil fuel boilers. The agency is reported-ly considering lower limits in the range of 50 to100 MMBtu/hr heat input. However, regulationshave not yet been proposed. Thus, only the NSPSfor gas turbines and the proposed standards forstationary internal combustion engines seem like-ly to affect cogeneration systems, and then onlyif they are larger than the prescribed limits.

PSD regulations would apply to fossil fuelboilers of greater than 250-MMBtu/hr heat inputthat emit more than 100 tons per year (tpy) ofany pollutant, and also to any stationary sourcethat emits more than 250 tpy of any pollutant(assuming that controls are in place). A PSD per-mit is only issued following a review of projectplans, and an assessment of project impacts onair quality based on modeling data and up to 1

Ch 3—Context for Cogeneration • 101

year of monitoring. These modeling and monitor-ing requirements can be expensive. For instance,one estimate suggests that the requisite model-ing and other PSD requirements add from$35,000 to $80,000 to the installation costs of a3-MW diesel cogenerator in New York City (1 2).

The application of the nonattainment area re-quirements to cogenerators also depends on sys-tem size; here the trigger is the capability of emit-ting 100 tpy of a pollutant. Sources with higheremissions must meet the lowest achievable emis-sion rate (LAER), secure emissions offsets, anddemonstrate companywide compliance with theClean Air Act. Smaller sources must use reason-ably available control technology and are sub-ject to the general requirement for “reasonablefurther progress” toward the NAAQS in nonat-tainment regions.

OTHER FEDERAL REQUIREMENTS

In addition to the potentially extensive permit-ting requirements for cogenerators under theClean Air Act, facilities with any cooling waterdischarges may also need National Pollutant Dis-charge Elimination System (NPDES) permitsunder the Clean Water Act. The NPDES permitgenerally specifies the applicable technologicalcontrols or effluent limitations required to achievethe water quality standards for the receivingwaters. These permits are only likely to be re-quired for large industrial cogenerators.

Because the only major Federal permit or au-thorization requirements for cogenerators arethose under the Clean Air and Water Acts, theyare not likely to be subject to the NEPA processor to the other environmental requirements ap-plicable to central station powerplants. However,operating cogeneration facilities can come underthe purview of OSHA, especially with regard tonoise standards and the general OSHA record-keeping requirements. Any restrictions imposedshould not be sufficiently burdensome to dis-courage the deployment of cogenerators.

STATE REGULATION*

State governments are required to implementthe Federal permit processes under the Clean Air

*Except where noted otherwise, the discussion in this section isdrawn from Energy and Resource Consultants, Inc. (22).

and Water Acts. States may or may not have otherenvironmental or safety regulations beyond thosemandated by Federal law, and State implemen-tation of the Federal requirements may vary wide-ly, depending on their orientation toward regula-tion as well as on the regional environmentalquality. A survey of all State requirements for en-vironmental and safety regulation of cogeneratorsis beyond the scope of this report. However,some general trends are noted below with a spe-cific comparison of a State with more rigorousrequirements (California) and one that has fewrequirements beyond those mandated by Federallaw (Colorado).

Colorado.–The permitting process in Coloradoclosely tracks the requirements of Federal laws(described in the previous section). One Coloradoenvironmental law deserving some explicit atten-tion is the Colorado Air Quality Control Act(CAQCA), which deviates from the Federal re-quirements in three ways. First, CAQCA requiresessentially all new or modified sources to file anAir Pollution Emission Notice (APEN). Second, allnew or modified sources must apply for an emis-sion permit which is required for both nonattain-ment and PSD areas, and which applies to vir-tually all fossil fuel facilities except small stationaryinternal combustion engines and gas burners withless than 750,000-Btu/hr heat input. Third,CAQCA’S significance levels for nonattainmentareas are considerably lower than those specifiedunder the Federal program (e.g., 10 tpy of par-ticulate or sulfur dioxide (S02) rather than the40 tpy under Federal regulations). Otherwise, thepermitting procedures under the Colorado Actare essentially the same as those under the Fed-eral requirements.

The length and complexity of the permittingprocess for cogeneration in Colorado will dependon the choice of site. Important site-specific fac-tors may include whether Federal or State landsare involved, impacts on surface waters, and am-bient air quality levels. Permitting agencies shouldbe contacted simultaneously in order to reducethe time required for licensing and decrease theamount of paperwork.

For this assessment, the Colorado permittingprocess was applied to two hypothetical cogen-eration facilities: a large cogeneration unit con-sisting of a new coal-fired boiler of 200-MMBtu/hr


heat input, with steam turbine topping capabili-ty, located in an urban area and not selling anyexcess electricity to the grid; and a small cogen-eration unit, represented by a commercial firm’sretrofitting a 15-MMBtu/hr diesel engine to supplya maximum of 2-MW electrical output with ex-cess power available to the grid during times ofpeak demand.

Large Cogeneration Project-Air Permits: Muchof the front range area in Colorado is nonattain-ment for particulate; however, with only min-imal control, the 200-MMBtu/hr boiler will notemit over 100 tpy of particulate and thus wouldnot be subject to the strict nonattainment arearequirements. Because the entire State is in at-tainment for S02 the plant would require a PSDpermit only if it emits more than 250 tpy. Assum-ing a 70 percent load factor and the use of coalwith a 1 percent sulfur content, the uncontrolledS02 emissions could approach 1,000 tpy, whichwould not meet the S02 emission rate of less than1.2 lb/MMBtu for an emission permit under thenew fuel burning equipment regulations. Thus,the sponsors for this hypothetical project mustchoose between achieving a 75-percent reduc-tion in S02 emissions or going through the PSDpermit process. Note that under the bubble con-cept for PSD, the source may have some emis-sion credits from the existing boiler.

Large Cogeneration Project– Water Permits: Ifthe boiler’s cooling system were to result indischarge to surface waters, a waste dischargepermit would be required, as part of the State im-plementation of the NPDES program. Althoughexisting sources can negotiate a complianceschedule for achieving discharge limits, newsources must meet those limits from the start.

Small Cogeneration Facility: The smallcogenerator will have to file an APEN and applyfor an emission permit. A 15-MMBtu/hr diesel unitdoes not qualify as a major source under eitherthe PSD or new source review programs for par-ticulate or S02, and at present no NOX standardhas been promulgated for diesels. However, itwill be subject to the (as yet undefined) minorsource requirements for particulate because itis located in a nonattainment area.

There is little experience with which to judgethe impacts of the Colorado permitting processon cogeneration facilities. There are only threecogeneration units in the State, and none is in-terconnected with the utility grid. Colorado hasno special laws, procedures, or exemptions thatmight suggest a State “policy” toward dispersedgenerating technologies. Rather the existing reg-ulations derive principally from Federal man-dates, which (except for PURPA and the cogen-eration exemption under FUA) make no specialrecognition of dispersed facilities. Thus, theregulatory obstacles to dispersed facilities in Col-orado are not severe. Most of the required per-mits and approvals can be secured in less than6 months and at modest expense, and, further-more, have cost and time requirements commen-surate with the project size. The only regulatoryobstacles would likely be the nonattainment areaand PSD requirements for large cogenerationunits, and the time the developers will have tospend determining what permits will be necessaryfor their facilities. At present, there is no centralclearinghouse dispensing information on the per-mitting process.

California.– Regulation of cogeneration inCalifornia is complex, but highly organized. Theincreased complexity arises in two ways: first, dueto the large number of agencies and commissionswith regulatory responsibility in California; andsecond, due to the regionalism of major regula-tory programs, notably air, water, and coastalzones. For example, the California Air ResourcesBoard (CARB) administers the Clean Air Act inCalifornia. Yet 46 local and regional air pollutioncontrol districts (APCDS) are responsible for con-trolling pollution from stationary sources throughpermitting, enforcement, and the adoption ofcontrol standards (often more stringent than thoserequired by CARB). Similarly, although the StateWater Resources Control Board administers theClean Water Act in California, most decisionsregarding permits and enforcement are made bynine regional boards and their staffs.

The high degree of organization of the permit-ting process in California stems from the roleplayed by the Office of Permit Assistance (located

Ch. 3—Context for Cogeneratlon . 103

in the Governor’s Office of Planning and Re-search), which helps project sponsors identify andmeet regulatory requirements. The office screenspermit applications and acts as an intermediarybetween projects and agencies. Another unit withthe Office of Planning and Research, the StateClearing House, attempts to coordinate the prep-aration of, and comments upon, environmentalstatements—either environmental impact reportsunder the California Environmental Quality Act(CEQA), or joint statements under CEQA andNEPA.

The permitting process in California centersaround the requirement for an environmental im-pact report (EIR) under CEQA. If the lead agen-cy decides that an EIR is required, one is preparedby that agency in consultation with all other per-mitting agencies, who must propose definitemeasures to mitigate any significant impacts iden-tified in the EIR. The entire process is subject toa schedule, defined by statute, such that all deci-sions on a project must be complete within 18months of the date the initial application was ac-cepted by the lead agency.

The permitting process in California was ana-lyzed for the same hypothetical large and smallcogeneration facilities as discussed for Colorado,above.

Large Cogeneration Project–Air Permits: Everysource of air pollution in California requires atwo-stage permit. The first stage is an authorityto construct based on a review of project plans,and the second stage, following construction, isa permit to operate based on a performance test.The authority to construct and permit to operaterequire compliance with the emission limitationsset by the local APCD. New source review rulesalso will apply if the source triggers any nonat-tainment area requirements. Although the basicnonattainment area rules (such as LAER, emissionoffsets, and companywide compliance) applyacross all APCDS, each APCD determines the trig-ger levels, in terms of pounds of emissions perday, for nonattainment areas. Although concep-tually straightforward, the regulations generatedby 46 APCDS for several classes of sources andhalf a dozen individual pollutants are volumi-nous.

Most APCD trigger levels for new source reviewin nonattainment areas are more stringent thanthe Federal requirements. Much of California isin attainment for S02, but the industrial areas aregenerally nonattainment for TSP and NOX. As-suming that the 200-MMBtu/hr coal boiler hasNOX emissions of 0.7 lb/MMBtu, it would emit140 lb/hr of NOX, thus triggering the LAER re-quirement. In addition, an EIR under CEQA maybe required. In any event, a final decision by theAPCD whether to issue an authority to constructmust be made within 1 year.

Large Cogeneration Project–Water Permits:California’s waste discharge requirement programpredates the Clean Water Act but encompassesthe same sources as the NPDES and section 401programs. For a point source discharge to sur-face waters, the State waste discharge require-ment serves as an NPDES permit. Similarly, re-quests for a section 401 Water Quality Certificatewill result in either a waste discharge requirementif the proposed project would affect water quality,or a letter to the effect that no certificate is re-quired because no impacts are anticipated. Allpermitting is done by the regional boards in ac-cordance with general standards and criteriadeveloped in their water pollution control plansand, in the case of sources subject to NPDES,using the various Federal technological standards.The waste discharge requirement applies to allpoint source discharges and additionally to anydischarges onto land or to a private pond, andwould thus be required for most large cogenera-tion projects.

Srnall Cogeneration Facility: in addition to anauthority to construct, the small cogenerator mayneed to meet nonattainment area requirementsfor NOX. A 15-MMBtu/hr heat input cogeneratorwith emissions of 3.5 lb/MMBtu would result inover so lb/hr of NOX emitted. These would beoffset (under the bubble concept) by the emis-sion level of the diesel engine before the retrofit(if any); so the net increase mayor may not ex-ceed the applicable trigger level.

The differences between environmental regula-tion in California and Colorado primarily resultfrom the environmental review process man-dated by CEQA, and California’s aggressive but

104 ● Industrial and Commerc ia l Cogenerat ion

helpful approach to regulating energy develop-ment. The guidelines under CEQA and NEPA forconducting environmental review are quite sim-ilar; in fact, many projects will prepare statementsacceptable under both guidelines even if CEQAalone is thought to apply. However, the impactof CEQA in California, as compared to NEPA inColorado, is greater because the environmentalreview process can be triggered by State, coun-ty, and municipal actions, whereas NEPA is trig-gered only by Federal action. Thus, many moreprojects may need to prepare environmental re-views in California than in Colorado. This putsmore projects into the public arena, but shouldnot result in delays so long as the statutory sched-ules for permitting are followed.

On the other hand, there are several initiativesin California that encourage cogeneration andmay help shorten part of the permitting process.First, new State legislation makes it easier for 50MW or smaller cogenerators to obtain air quali-ty permits. Under this legislation, cogeneratorswill receive an emissions credit equal to the emis-sions that would have come from a powerplantgenerating the same amount of electricity. In ad-dition, the statute requires CARB and the APCDSto develop a procedure to determine the avail-ability and magnitude of the offsets which resultwhen cogeneration facilities displace power-plants. Thus, in effect, the statute shifts the burdenof acquiring nonattainment area offsets from thepotential cogenerator to the APCD (1 1).

As a further aid to cogeneration, two specialadministrative offices have been established toassist prospective cogenerators with regulatoryrequirements: the Cogeneration Desk of the Of-fice of Permit Assistance, and the Project Evalua-tion Branch of the Stationary Source Control Divi-sion in CARB. Both of these offices are designedto provide assistance in obtaining permits andmeeting air quality requirements. Moreover, theGovernor’s Task Force on Cogeneration (whichincludes directors from CARB, the Office of Plan-ning and Research, the California Energy Com-mission, and the public Utilities Commission) isactively seeking ways to encourage cogenerationin the State. Each of these agencies has specialpersonnel available to assist potential cogener-ators with all aspects of their project, including

legal and technological problems. The ex-periences of recent California cogeneration proj-ects suggest that environmental and other regu-latory requirements are not a major obstacle,especially for smaller facilities. However, poten-tial cogenerators may perceive the permittingprocess to be onerous, and the principal task forState agencies is likely to be convincing poten-tial cogenerators that the regulatory requirementsare not insurmountable.

Financing and Ownership

The basic aspects of financing electric utilitycapacity additions (reviewed in the previous sec-tion) are applicable to cogenerators. A numberof other elements special to cogeneration arediscussed below, including the tax and financ-ing aspects of cogeneration and considerationsrelated to the different ownership categories:private investors, IOUS, tax-exempt entities, andrural electric cooperatives. *

General Considerations

General considerations related to financing andownership of cogeneration technologies includethe ownership and purchase and sale terms ofPURPA (discussed above), the utility financingprovisions of the National Energy ConservationPolicy Act (NECPA) of 1978 (as amended by theEnergy Security Act of 1980), tax incentives of theNational Energy Act, the Windfall Profits Tax Act,and the Economic Recovery Tax Act, aspects ofproject financing and lease relationships, andcapital recovery factors.

The most important sections of the EnergySecurity Act for the purposes of this assessmentare contained in title IV—Renewable Energy ini-tiatives, and title V—Solar Energy and Energy Con-servation. Title IV establishes incentives for theuse of renewable energy resources includingwind, solar, ocean, organic wastes, and hydro-power; only those provisions related to the useof organic wastes as fuel are applicable to cogen-erators. Funding of $10 million in fiscal year 1981was established to promote renewable energy re-

*Except where noted otherwise, the analysis in this section is fromL. W. Bergman & Co. (37).

Ch. 3—Context for Cogeneration • 105

sources under a 3-year pilot energy efficiencyprogram.

Title V set up a Solar Energy and Energy Con-servation Bank in the Department of Housing andUrban Development to make payments to finan-cial institutions in order to reduce either the prin-cipal or interest obligations of owners’ or tenants’loans for energy conserving improvements to res-idential, multifamily, agricultural, and commer-cial buildings. For commercial buildings, the eligi-ble improvements specifically include cogenera-tion equipment. Direct grants to owners andtenants of residential or multifamily buildings alsowere authorized but were limited to lower in-come people. No investment tax credits (onlyenergy credits) were allowed for any projects in-stalled under loans from the Solar Bank, and ex-penditures were to have been made after January1, 1980. The bank was intended to continue op-erations through September 30, 1987, but thefiscal year 1981 budget eliminated all funding forthe Bank and its future is, at best, highlyuncertain.

The Energy Security Act also amended NECPAto permit utilities to supply, install, and financeconservation improvements or alternate energysystems (including cogenerators) as long as inde-pendent contractors and local financial institu-tions are used and no unfair competitive prac-tices are undertaken by the utility. Utilities areeligible to qualify as lenders and receive subsidiesto pass on to customers. Local governments andcertain nonprofit organizations are eligible bor-rowers.

In addition to the regular investment tax creditof 10 percent on most capital investments, severalenergy incentives have been passed in recentyears. Under section 48(1) of the Internal Rev-enue Code a number of “energy properties” aredefined and set aside for special treatment underthe investment tax credit (see section on “Taxa-tion, ” above). Property is not eligible for thesespecial incentives to the extent that it uses sub-sidized energy financing (including industrialdevelopment bonds), or is used by a tax-exemptorganization or governmental unit other than acooperative. public utility property (that for whichthe rate of return is fixed by regulation) is ex-

cluded from these energy incentives even if itutilizes solar, wind, biomass, or other alternativesources of energy such as synthetic liquid orgaseous fuels derived from coal.

The methods of project finance are particularlyappropriate to the financing of distributed elec-tricity generation. project financing looks to thecash flow associated with the project as a sourceof funds with which to repay the loan, and to theassets of the project as collateral. For successfulproject financing, a project should be structuredwith as little recourse as possible to the sponsor,yet with sufficient credit support (through guar-antees or undertakings of the sponsor or third par-ty) to satisfy lenders. In addition, a market for theenergy output (electrical or thermal) must be as-sured (preferably through contractual agree-ments), the property financed must be valuableas collateral, the project must be insured, and allGovernment approvals must be available (47).With the adoption of PURPA, a source of reve-nues (rates for power purchases) has becomeavailable for small-scale energy project finance.

However, the uncertainty surrounding futurerates for power purchases (due to the 1982 Courtof Appeals decision discussed previously and thepending Supreme Court review of that decision)has chilled the interest of potential financialbackers of cogeneration and small power proj-ects. The revenue stream from utility purchasesof cogenerated power is used to secure the proj-ect financing. Because the future level of thatrevenue stream is in doubt, bankers and otherinvestors are reluctant to commit funds until theissue is resolved.

Leasing is a form of project finance becausefixed payments are used to amortize capitalequipment. Two types of lessors may be involvedin project financing: sponsors of a project wholease to the project company, and third-pattyleasing companies that are in the finance busi-ness. The third-party lessors may have more at-tractive rates because they utilize the tax benefitsof owning the equipment.

The Economic Recovery Tax Act of 1981substantially changed the tax treatment of leas-ing to make it very attractive for projects like

98-946 0 - 83 - 8: QL 3

106 ● Industrial and Commmercial Cogeneration

cogeneration. If a cogenerator is unable to takeadvantage of tax credits (e.g., already has a lowtax liability), the tax advantages can be transferredto another party under the safe harbor leasingprovisions of ERTA. In essence, these provisionsallow the property to be sold for tax purposesonly to a corporation in a higher tax bracket. Thecorporation would give the cogenerator a cashpayment (e.g., 25 percent of the property’s value)and a note for the remainder of the purchaseprice, and then lease the equipment back to thecogenerator. Payments due under the note wouldbe matched exactly by the lease payments. Thus,no money actually changes hands after the in-itial cash payment, and with the exception of thetax difference between lease payments (which areexpensed in full) and income from the note(which reflects only its interest component), thetransaction is extremely advantageous to bothparties (33).

The capital recovery factor, as used in this sec-tion, is the cost per kilowatthour which the ownerof a cogenerator must receive to recover itscapital in a given period of time. Table 20 com-pares capital recovery factors for four classes ofownership that reflect different income tax struc-tures: a nonutility investor with a 50-percentmarginal tax rate; a utility with a 50-percentmarginal tax rate; a utility with a 10-percentmarginal tax rate that is unable to take advantageof investment tax credits because it already hasan excess of such credits; and a nontax-payingentity. In all cases the capital recovery factors aregreatest for utilities in the high tax brackets andlowest for nontaxable entities.

One way for an investor to get around highcapital recovery factors is to use long-term bondfinancing. With high leverage, the equity investor

is able to recover his investment in a shorterperiod of time because the bond holder is will-ing to wait to recover his capital. However, highleverage increases the risk to the equity investorand therefore also increases the required returnon equity. Thus, depending on the terms of debtand equity markets, debt financing can makethese investments more attractive. It is also im-portant to note that utilities are more comfortablewith longer capital payback periods than nonutili-ty equity investors, and that nonprofit entitieshave a different set of criteria for evaluatinginvestments.

Industrial, Commercial, and Privateinvestor Ownership

Industrial, commercial, vendor, and privateownership share (for the most part) a commontax status and will be discussed together. As notedpreviously, energy tax credits, coupled withregular investment tax incentives and the PURPAbenefits, encourage private firms to enter smallpower production. The ability to obtain up to25-percent investment tax credits offers an enor-mous boost to cash flow early in the project’s life.These tax credits can be further magnified, in rela-tion to invested equity, by debt leverage by a fac-tor of 4. PURPA provides a guaranteed marketfor the power output and it encourages the de-velopment of contractual relationships betweencogenerators and utilities. In project finance, suchcontracts are preferable to operating under a tariffstructure because contractual relationships areless subject to arbitrary cancellation or alterationof the terms of delivery.

While the incremental investment tax credit forcogeneration is limited (particularly if the cogen-erator uses oil or gas), industrial companies have

Table 20.—Capltal Recovery Factors for Cogenerationa

(cents per year per kllowatthour, In 1980 cents)

Nonutility High tax rate Low tax rate Nontax payinginvestor utility utility utility

5 year . . . . . . . . . . . . . . . . . . . 3.6cents 4.2cents 3.Ocents 2.8cents10 year . . . . . . . . . . . . . . . . . . . 1.6 1.9 1.515 year . . . . . . . . . . . . . . . . . . . 1.1 1.2 0.99 0.9320 year . . . . . . . . . . . . . . . . . . . 0.77 0.91 0.74 0.70a1980 capital cost $700/kw; usage 5,000 hrs/yr; depreciation Iifetime 20 years.

SOURCE: L. W. Bergman &Co., Financing and Ownership of Dispersed E/ectriclty Generating Technologies (contractor reportto the Office of Technology Assessment, February 19S1).


some experience with cogeneration and nowhave the added advantage of PURPA’S purchaseand sale requirements. Continued Federal andState Government support of simultaneous pur-chase and sale at full avoided costs is viewed bysome as the single most important factor in over-coming industry indecision to cogenerate (27).

Existing and potential industrial cogenerationparticipants include industrial parks, integratedpulp and papermills, other process industries(e.g., chemicals, petroleum refining, steel, foodprocessing, textiles), and heavy oil recovery proj-ects (see analysis of industrial cogeneration in ch.6).

Financing options for industrial cogenerationmay be quite varied depending on the size andfinancial strength of the industrial firm. These op-tions include:

●

●

●

●

●

●

●

retained earnings;debt issues (including bonds, bank loans, andprivate placements with insurance compa-nies, pension funds, and similar institutions);equity issues;joint ventures with other industrial firms (seecase 1 ) or with utilities;joint partnership with equity investors suchas insurance companies (who may be bothlenders and equity investors) and tax sheltersyndicates (see case 2);leasing arrangements with third parties andvendors, including leveraged leases and safeharbor leases (under ERTA); andjoint ventures and operating relationshipswith tax-exempt entities such as municipali-ties and public power companies. Tax-exempt parties can raise lower cost debtwhile transferring tax ownership and taxbenefits to the private parties.

The incentive to commercial firms to invest incogeneration will rest heavily on a comparisonbetween the cost of cogenerated electricity (es-pecially the fuel cost) and the price the commer-cial cogenerator pays for its electricity and heat(comparative basis). Because of their smaller size,commercial firms often do not have financialresources equivalent to those of industrial firmsand will be less interested in large scale projectsunless they can be cooperatively owned (50).


Sources of financing for commercial cogenera-tion would be similar to those for industrialcogeneration with the following qualifications:

● banks will be a more important source offunds than for industrial firms;

. there will be a greater dependence on out-side developers and financial packages;

● joint venture funding will be very useful forregional malls, large buildings, and commer-cial parks; and

. vendors and third-party lessors will be quiteimportant, particularly for diesel cogenera-tion (see case 3).

Private investors may be interested in cogen-eration because of the unusual tax incentivesavailable and the possibility of an above invest-ment return in unusually promising situations.Joint venture relationships will be most advan-tageous to private investors, including tax sheltersyndicates that provide the equity portion of aleveraged lease and shift tax ownership amongthe partners. Vendors might provide financingand traditional lease arrangements, particularlyin the case of diesel cogenerators, or third par-

ties could take advantage of ERTA’s-safe harborleasing provisions.

Where the owner (industrial, commercial, pri-vate investor) is a single entity and no outsidejoint ventures are involved, project financing viaequity, secured or unsecured bank loans, debt,or lease arrangements is straightforvvard. Certainassurances or guarantees will be needed, how-ever, in structuring the financing. These mightinclude:

contractual arrangements with a utility forelectricity purchases under a take-or-pay con-tract;contractual arrangements with the thermalenergy purchaser; ortrustee relationships between the lender andrevenue source with excess revenues overfixed charges remitted to the project owner.

Finally, some IOUS may also have financial as-sistance programs for industrial, commercial, andother private investors in cogeneration. For ex-ample, Southern California Gas Co. offers, fund-ing assistance of up to $100,000 or 20 percentof the capital cost (excluding installation labor)for their cogenerating customers. Southern Cali-fornia Gas will co-fund upto$10,000 for the fea-sibility study (or 10 percent of the study’s cost,whichever is less). If the feasibility study ispositive, then the company will co-fund up to$40,000 (or 50 percent) of the cost of the designphase of the project, leaving $50,000 for installa-tion and startup (62).

lnvestor-Owned Utility Ownership

Because almost all electric IOUS are in the busi-ness of generating electricity, they are logicalpotential owners of dispersed generation facilities.The small size, shorter Ieadtimes, and lower cap-ital requirements of cogeneration systems mayprovide short-term advantages to utilities in plan-ning for uncertain demand growth. However, thePURPA limitations on utility ownership discour-age utility investment in cogeneration. Moreover,most large utilities do not see dispersed generat-ing facilities—including cogeneration—as havingthe ability to replace future central generating sta-tions, and the low-earned utility rates of returnin recent years may not be high enough to en-


courage utility investment in technologies withuncertain electricity output.

Full (100 percent) utility ownership may bevery advantageous if a utility faces revenue lossesdue to industrial or commercial cogeneration (seech. 6). For instance, Arkansas Power & Light(AP&L) estimates that if their 35 industrial custom-ers who are prime cogeneration candidates hadcogenerated in 1981, AP&L’s estimated revenueloss for that year would have been almost $40million. However, if AP&L developed and ownedthe cogeneration systems for those 35 industrialcustomers, not only would they retain that indus-trial market for electricity, but they would havean additional revenue stream from steam sales—potentially $500 million in the mid-1980’s (44).Moreover, if potential industrial or commercialcogenerators are unable to burn coal (e.g., dueto space or environmental limitations), or are un-willing to assume the risk of advanced technol-ogies (e.g., gasification), utility ownership withelectricity and steam distribution can centralizethe burden of using alternate fuels. However, thefull incremental ITC is not available for utility-owned cogenerators nor are PURPA benefitsavailable if an IOU owns more than 50 percentof the cogeneration facility. (The potential advan-tages and disadvantages of full utility ownershipare discussed in detail in ch. 7.)

Alternatively, a utility may decide to participatein a joint venture for a cogeneration facility (seecases 4 and 5) in order to structure the owner-ship in such a way that the investment tax creditand other tax benefits are diverted to the nonutili-ty participants. in addition, financing can bestructured so that any debt related to the facility(with the exception of relatively small amountsfor working capital) will not appear on the utili-ty’s balance sheet. This structuring would be ap-propriate for utility-financed industrial cogenera-tion or biomass projects.

Tax= Exempt Entities

The key advantage enjoyed by municipalitiesin issuing debt is the tax-free status of the interestpaid on their obligations, which results in a lowerinterest rate than that paid on taxable securities.The current spread in yields between new AAA

long-term IOU bonds and AAA municipal generalobligation bonds is around 375 basis points (100basis points equals 1 percentage point); betweenthe same utility bonds and revenue bonds thespread is around 330 basis points.

Section 103 of the Internal Revenue Code setsout the provisions for a security to receive tax-exempt interest treatment. Section 103(a) ex-empts the interest on an obligation of a State orpolitical subdivision (which would include gen-eral obligation bonds). Section 103(b), however,

110 . Industrial and Commercial Cogeneratlon

denies tax-free status for industrial developmentbonds (IDBs) except for specific exemptions. Inorder for IDBs to qualify for tax-exemption, morethan 25 percent of the proceeds of an obligationmust be used by a nonexempt person for businesspurposes; a major portion of the principal or in-terest must be secured by business property; and,in the case of a take-or-pay contract with an elec-tric facility, the contract must be with a nonex-empt person and in exchange for payments total-ing more than 25 percent of the total output debtservice. Moreover, the facilities financed by tax-exempt IDBs must be for general public use andfor specified activities including:

solid waste disposal facilities for the local fur-nishing of electric energy;air or water pollution control facilities; andacquisition or development of land for in-dustrial parks, including development forwater, sewer, power, or transportation pur-poses.

Under the Windfall Profits Tax, solid waste-to-energy facilities are eligible for tax-exempt financ-ing with IDBs if over half of the fuel is derivedfrom solid waste, and the facility is owned by agovernmental authority, although year-to-yearmanagement contracts with business corpora-tions are allowed.

Perhaps the most important exemption for tax-free financing is the small issue exemption, underwhich up to $1 million in IDBs (or $10 millionprovided total capital expenditures do not exceed$10 million) can be issued for any trade or busi-ness for the acquisition of land or property sub-ject to depreciation. However, if all of the pro-ceeds of a bond issue are used to finance a proj-ect for which an Urban Development ActionGrant (UDAG) has been made, then the capitalexpenditure can be $20 million, of which $10million must come from sources other than tax-exempt obligations. Renewable energy proper-ty is eligible for a special exemption if the bondsused to finance it are general obligations.

Cogeneration is not eligible for special energytax incentives if over 25-percent fueled from oilor gas. As the technology becomes available,coal-fired cogeneration plants will qualify forspecial tax incentives and be economically attrac-

tive. In the meantime, the best financing strategyfor municipalities to foster cogeneration develop-ment using available technologies may be to max-imize the use of tax-exempt financing (see case 6).

Industrial parks also are an excellent applica-tion in which municipalities can foster the devel-opment of cogeneration. Tax-exempt IDBs canbe issued without limit under a specific exemp-tion for the acquisition of land for industrial parksand its upgrading including water, sewage, drain-age, communication, and power facilities priorto use. Cogeneration facilities (including steamdistribution lines) presumably would fall into thisspecific exemption. The requirements encouragejoint ventures between the exempt entity andbusinesses, but the funds must be used by thenonexempt entity in a trade or business andpayments secured by an interest in property usedin a trade or business. Moreover, some State lawsprohibit municipalities from entering into cor-porate relationships with the private sector, butindependent public bonding authorities usuallycan be established to get around such prohibi-tions.

Any number of lessor-lessee relationships alsoare possible between a municipality and a cor-poration. An important aim of the financing struc-ture would be to allow the corporation to pickup the lo-percent investment tax credit (see case7).


Finally, an innovative financing option formunicipal utilities and other local governmentagencies that has attracted a lot of attention inCalifornia is the municipal solar utility (MSU). Asoriginally conceived, an MSU would reduce thecapital and maintenance costs of solar hot watersystems (or other alternative energy or conser-vation measures) by: 1) only charging customersfor their installation; 2) spreading that charge over

the lifetime of the system in the monthly electricbills; and 3) providing continued maintenance(28). More recently, the MSU concept has beenexpanded to include programs such as brokerageof different financial and service packages,dedicated deposits of city funds in local banksfor low interest alternative energy loans, ortechnical assistance and other community out-reach programs (60).

Rural Electric Cooperative Ownership

Rural electric cooperatives are finding it moredifficult to purchase additional electricity fromtheir traditional sources (IOUS and Federal powerauthorities) and consequently are being forcedto build or participate in new generating capaci-ty. Within this context, dispersed facilities (in-cluding cogeneration) may be advantageous dueto the shorter construction times, greater plan-ning flexibility, and lower capital costs. In addi-tion, alternate energy projects are more readilyfinanced at favorable terms. Such financing in-cludes 35-year loans for feasibility studies underthe REA insured loan program, and is designedto help overcome the lack of engineering exper-tise and other resource constraints faced by smalldistribution co-ops that wish to add generatingcapacity. As with other electric utilities, co-opswill prefer projects that provide most of their ad-ditional capacity during peak demand periodsand whose electricity output is not intermittent(e.g., biomass, hydroelectric, and industrialcogeneration projects).

For a project with IOO-percent co-op owner-ship, all the benefits accrue to the cooperative’smembers (e.g., no taxes are paid and no profitsare distributed to investors). Capital is raisedthrough an REA guaranteed loan, which meansthat the cost of capital will be lower than for aprivate investor because the U.S. Governmenthas guaranteed the loan. Other financing optionsfor cooperatives include joint ventures with localgovernments or with industrial concerns (see case8).


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4.

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