The economics of geothermal power

159

En&eerin,g Costs and Production Economics, I (1983) 159 - 170

Elsevier Scientific Publishing Company, Amsterdam - Printed in The Netherlands

THE ECONOIWCS OF GEOTHERMAL POWWER Laxmidas V. Popat Stone & Webster Engineering Corporation, Cenver Operations Center, Greenwood Plaza, Box 5406. Denver, CO 80217 (U.S.A.)

ABSTRACT Geothermal resource is a technically proven and economically feasible source of energy for producing electricity. It is already here and, in some circumstances, is competitive with other sources of energy. It can make a zignifican t contribution to generationresource additions in the western United States. Geothermal power projects have been subject to rapidly escalating costs, like other

power plant projects, but still remain competitive with new fossil-fueled and nuclear projects. The purpose of this paper is to examine briefly various aspects of geothermal energy development, related to its economics. The total generating costs of geothermal power plants are presented and compared with new coal-fired power plants. Factors contributing to the increased costs are briefly discussed.

SUMMARY AND CQNCLUSION

-

operating and maintenance cost, taxes and insurance, - reclamation, - salvage. Although there are different forms of utilization of geothermal energy, this paper has been confined to only the production of electricity from geothermal resources. Four general types of geothermal resources found i4r the United States are steam-dominated, liquid-dominated, hot dry rock and geopressured resources. Costs for employing geothermally driven power generation can be confidently estimated with respect to steamdominated and liquid-dommated systems. Therefore only these two types have been considered in this paper. Geothermal resources occur in limited quantities at only a limited number of sites. -

It is common practice to make economic comparisons of alternate sources of energy on the basis of total generating cost of the project. For geothermal power projects this might include, but not be limited to, the following costs: - geothermal lands (chiefly government and private leasing), - exploration, - field development, - fluid gathering and reinjection system, - power plant construction, Reprinted by special permission from 1982 Transactions of the American Assocbtion of Cost Engineers, copyright 1982 by the Amekan Association of Cost Engineers (AACE Monongahela Building, Morgantown, Incorp.1, 308 WV 26505. U.S.A.

140 Steam or hot water energy produced fmm economically cannot be sites these transported over long distances except in the form of electricity. Therefore9 to be comtitive, geothermal generating units must near load cknters or high-voltage n lines. and liquidsteam-dominated Roth dominated geothermal resources are technically proven and economically feasible urces of energy for producing electricity. l’he uniqre features of geothermal projects b~ve necessitated an intimate partnership of both public and private sectors of industry. Geothermal projects have been subject to rapidly escalating costs like other forms of flower generation but generally remain competitive with new fossil-fueled projects. They have significant potential as an altemative source of energy for the western United States.

Smaller unit sizes of geothermal power plants offer special advantages for smaller utility systems to own and operate such plants independently; and to larger utiilities they provide an ahemative with a smaller amount of money at risk for a shorter period of time. 1. WiCKGROUND

Since geothermal units can be efficient in sizes smaller than those economically feasible for coal or nuclear units, ownership of these smaller units by smaller utility systems (frequently controlled by govemmental units such as municipal utility systems an peratives) promises special benefits to em. They often require snail additional capacity and seek to control it independently. The drilling conditions in geothermal rce areas are difficult and expensive, most small public utility systems or utilities do not have the risk (venture) al structure required for wild-catting the needed for resource development.

Environmental and institutional restraints coupled with the depth of drilling required for successful well3 cau3e drilling costs to continue to rise. Thus the economic risks involved are very high. In general, re3ource developers seeking to maximize their return on investment to cover the high risk of drilling geothermal wells are pricing their product in line with it3 competition. In California, where the majority of these well3 are drilled, the competition is oil. The majority of re3ource developer3 are oil companies, with a few exceptions, such a3 Magma Power. Utilities are reluctant to embark upon a courSe of geothermal power generation without some fuel cost benefits, and so they seek a lower purchase price not tied to oil prices. bodies (e.g. Government regulatory California Public Utility Commission - CPUC) concerned about the energy cost paid by the consumers, expect utilities to find option3 that would keep the cost to rate payer3 at a level “no higher than for fossil-fuel generated electricity, and if feasible, lower” [ 41. These unique situation3 have influenced both the petroleum and utility industries. Robert W. Rex ha3 classically summarized this situation in hi3 statement, “The next twenty year3 of geothermal development will be an intimate partnership of the public and private sectors, and it is in the nations’ best interest to proceed rapidly and intelligently with the development of this U.S. energy resource that aids us in replacing imported petroleum” [ 51. 2. LIFE-CYCLE COSTING The fundamental basis for economic choice should be the “present worth” of all future revenue requirements. (“Present worth” is the discounted value of a series of future values.) The annual revenue requirement of a project i3 the annual revenue necessary to meet

161 all annual costs of that project, including and maintenance costs, fuel, operation taxes, recovery of capital insurance costs, for the depreciation account, and the minimum return that suppliers of bond and equity capital will accept. The calculation of “revenue requirements” is not dependent upon rate base considerations. It has to be assumed in economic comparisons that future rates will provide the revenue requirement. Admittedly, predictions of the future are subject to error, but the “present worth” technique de-emphasizes their impact on the answer. Although “life-cycle costing” is a sophisticated way of comparing one scheme with another, it is common to make comparisons on the basis of total generating cost at some point in time, using a “levelized” fixed charge rate and a “levelized” capacity factor (explained below). This method gives a good idea of the relative economic merits. The true relative costs of two or more generating systems over their lifetimes for decisionmaking is better illustrated by the present worth of revenue requirements for the total generating complex. This is particularly true if the capacity factors differ between the plants under consideration. The generating cost actually varies from year to year with changing capacity factors and annual fixed charge rates (see next section). However, costs are usually expressed and compared in cents per kilowatthour, using a “levelized” annual fixed charge rate and a “levelized” annual capacity factor. Levelizing is a technique by which a series of unequal numbers occurring at annual intervals is expressed as a series of equal numbers occurring at annual intervals which would have the same total “present worth”, using standard interest tables (even though the numbers may not represent dollars) [ 71. In cents per kilowatthour: Annual Annual Annual fixed charges + fuel ccist + operating cost Generating cost = Annual output in kilowatt hours

Generating cost may be expressed in mills per kilowatthour (ten mills = one cent). Important parameters used in the revenue requirement method and typical values of the above items are presented in Table 1 for three plants B, C, and D as follows: Plant B: A typical 55 MW modem geothermal plant in The Geysers area with a two-flow, 58 cm (23 in) last blade size machine using dry steam. Plant C: Same as B but with a more efficient four-flow, 63.5 cm (25-26 in) last blade size machine. Note the difference in machine outputs with almost the same quantity of steam being used by both. Plant D: A 540 MW gross (500 net) coalfired power plant. Comparison with a 540 MW coal-fired power plant has been selected to represent the condition (unit si.ze) typically used in the western United States where the geothermal resources are available. If compared with much smaller fossil units, the geothermal power plant would be even more competitive. There are too few small hydro power sites available to compare with the geothermal power plants. The data presented in Table 1 demonstrate that geothermal power plants using dry steam are cost competitive with the coal-fired power plants. In the example of Table 1 both plants B and C (geothermal) are less. expensive than plant D (coal). 2.1 Fixed charges Annual charges on capital include return on capital (interest on bonds, dividends on shares), corporate income tax paid before dividends, recovery of capital (or depreciation), and ad vaZorem taxes. These annual charges, as a percentage of the “capitalized cost” of the plant, are commonly but somewhat improperly referred to as the “fixed charges”. As capital is “recovered” from customer billing over the life of the plant,

162 TABLE 1 TOM ev&ttcd

cost

of

two typical dry steam geothermal power plants compared With cod-

twd power pbnts Item

coal

Geothermal Plant B

Plant C

Plant D

Plant capacity gross (Mw) PIant capacity net (MW Turbine type - flow - last blade size (in) - last blade size (cm)

55.00 52.40 2-flow 23 58

65.0 60.0 4-flow 25-26 63.5-66.0

540.0 540.0 6-flow

Capital cost (0 x 10’)’ Cost (S/kW) net basis Capacity factor (%)

68 750 1310 80 367 16.89 885 000 1.50

85 650 1420 80 423 14.66 885 460 1.50

750 oil0 1500 70 3066

-

-

15 197

15 213

Power generated (IrWhlyr X 106)

Net turbine steam rate Ob/kWh) Twbine throttle flow (lb/h)

1985 Steam cost (S/l000 lb (455 kg)) 1987 Coal cost (S/10’ Btu) Fined charge rate (%) Fixed charge rate (S/kW yr) First-year (1985/1987) cost (cents/kWh) Fixed charges Fuei costs

C?per.and maim. costs Total firrryear (1985/l 987) cost LeveIired (1985511987) cost F&d charges Fuel (8%/yr escalation, LF = 2.0956) Oper- and maint. costs Total level&l cost

-

3.20 15 225

2.81 2.53 0.47 5.81

3.04 2.20 0.50 5.74

2.97 3.42 1.24 7.63

2.81 5.31 0.98 9.10

3.04 4.61 1.06 8.71

2.97 7.17 2.59 12.73

*Lrt&tder amble escalation and interest during construction for scheduled %-ommercil operation as d 5Iay 1985 for geothermal power plants and May 1987 for coal-fired power PBMs. Cost of geothermal resource wells, reinjection wells and associated development equip meat are not iuchtded in the power costs, but are included in the fuel (steam) costs.

it is posted to a depreciation account. The depreciation account is insufficient to build a replacement plant; it is simply equal to the capitalized cost of the plant. Funds in the a called “internally generated capital” a to help finance newer projects and the “charges on capital” in the depreciation account thus are no longer applicable to the original project. As the depreciation account and as the charges on capital in this are borne by new projects, the hexed rate applicable to the original project each year with time. For approxieconomic comparisons, it is common

practice to use a “levelized” fixed charge rate. A fixed charge rate of 15 percent has been used in this paper. This is typical of a western United States municipality owning and operating a small geothermal power plant or a group of municipalities owning and operating a large coal-fued power plant with 100 percent debt (bond) financing. For an investor-owned utility the fixed charge rate could be considerably higher, because it would be fmanced with about 65 percent debt and 35 percent equity and subject to corporate income tax equal to the dividends.

163 2.2 Fuel costs

2.3 Operating and maintenance costs

For the geothermal plants B and C, the first year (1985) steam cost of $1.50 per 455 kg (1000 lb) is used. This is assumed to be supplied by the resource operator at the power plant boundary. This is typical of cost of steam supplied by the resource operators in The Geysers area. For the coai-fired plant D, a typical western (Powder River Basin) coal is assumed with $3.20/106 Btu first year (1987) cost. The levelized annual costs are derived by multiplying the first year cost by a levelizing factor corresponding to an escalation rate of 8 percent per year and a discounting rate of 12 percent per year, over a 30-year life in a11cases.

Operating and maintenance costs are typical first-year costs levelized on the same basis as the fuel costs. 3, TOTAL GENERATING

COST

The total generating cost (busbar energy cost), and, not least, total capital cost, forms the basis for selection. Note that the capital cost of plant C is higher than the cost of plant B, but the total generating cost of plant C is lower than the plant B. Therefore, between plants B and C, plant C is an obvious choice. Figure 1 shows histograms of total busbar energy costs of plants B, C, and D. Figure 2

GEOTHERMAL DRY STEAM

1965

1987

FIRST YEAR COSTS

0 6 M CQ8TS

Ezl

FUEL COSTS

fg@

FIXED CHARGES

Fig. 1. Total busbar energy costs - histograms.

LEVELIZED

ANNUAL COSTS

C FIRST YEAR COSTS

C LEVELIZED

ANNUAL COSTS

Fig. 2. Total busbar energy costs - pie charts.

shows pie charts for the tctal busbar energy costs for plants B, C and D. Both first-year costs and levelized annual costs are shown to demonstrate the concept of and the difference between first-year and levelized annual costs. 4. CAKTAL

COSTS OF POWER PLANT

cost figures for geothermal power along in published literature 12,6 I 3) show a wide range in dollars per t due to: scope; date of estimate; date hed&d commercial operation; whether include escalation; an allowance for d during construction (AFUDC, also mterest during construction), other ts such as spare parts, client’s 9: project management: etc. ;

In general, it is interesting to note that the cost experience of nuclear, and then of coalfired, power plants in the 197Os, is now expected for geothermal power plants being built in the 1’980s. To understand the large variation due to scope differences it is necessary to examine the costs of the various components of a geothermal power plant. Figure 4 [9] shows a schematic of a dry steam process using surface condensers and a Stretford H2S Abatement System. Table 2 illustrates the trend in capital costs of three geothermal power plants and compares them with a typical, 500 MW net, coalfired, power plant. The format of estimates and definitions used is the same as used by the author in the earlier papers. The costs of coal-fired power plant components are also derived from these earlier papers, adjusted for

165 2,099

A

q

0

m E

1,500

f f2 9

z

0

0

ae

1,000

ki

ago

8 z 0’ s

:o.

a

q

d 0

0

0 0

l

500

0

5

*. 8 I 70

a

l

0

I

I

-

I1

I

72

I1 76

74

I 79

I

III 99

YEAR

ESTIMATES

___)

t

I

92

OF

COMMERCIAL

I 94

III 96

I

I 99

99

I

III1 92

94

OPERATION

BINARY LIQUID

DOMINATED

INCLUDES

FUEL

STEAM -

GATHERING

FLASH 8 REINJECTION

SYSTEM

DRY STEAM DRY STEAM

INCLUDES

ALLOWANCE

FOR FUNDS USED DURING CONSTRUCTION

Fig. 3. Capital costs of recent geothermal power plants in the western United States. AIR AND EVAPORATED WATER 3,lms t HYOROTHEAYAI.

STEAM

z,aoo.aoo pph 365v SOO.OOS Lo/k

13OF

FROM

0.w

QPM m3llr

WELLS

114 fmlm 7.8 rem

wJm

\-I

pph

27,000 krlh

I

-1

r

CONOENSAELE

+i

ELECTRICAL 113,sOO kW Y’fT

STEAM TURBINE 1

v

FOWER

:= .___

SURF@

IENSER -

1

CONDENSATE

. I

I

25

I

t

1-3

I CONDENSATE PUMPS

am

ECONOMIC ANALYSES OF GEOTHERMAL ENERGV DEVELOPMENT IN CALIFORNIA, BY STANFORD RESEARCH INSTITUTE FOR DOE, SAN 116 P 199-l MAY 1977

Fig. 4. Dry steam process using surface condensers. Source: ref. 9.

b

EXCESS STEAM CONDENSATE TO RdtJJECTION WEL .LS 1.00s aFM m3h

166 TABLE 2 Dollars per kW cost: dry steam cycle - geothermal power plants --FERC @PC) code

Subsystem number

Coal*

Geothermal

Description

Plant A

Plant B

Plant C

Planlt D

1

Land and land rights

10

10

10

5

2 3 4 5

Structures and improvements Site work Main power house (turbine bldgl Other buildings Special structures

15 65 20 10

30 70 20 20

30 90 20 20

15 6.5 11D 1O

Boiler plant equipment Well field development Steam gathering/coal handling Hydrogen sulfide/SO2 removal system Secondary abatement and particulate removal system Reinjection waste disposal system

n.a. 20 10 ID 6

Air flue gas system

n.ai.

Balance of boiler plant system

n.a.

n.a. 20 40 6 6 n.a. n.a.

n-a. 20 40 6 6 n-a. n.a.

138 39 88 47 29 33 69

13 14 15

Turbine plant equipment Turbine generator Circulating water system Balance of turbine plant equipment

100 120 60

110 130 60

150 170 60

65 30 20

315

16

Electric plant equipment

85

93

93

63

316

17

Miscellaneous plant equipment

25

25

25

8

353

18

Transmission - switch yard

30

30

30

44

566

670

770

770

74

114

100

90

640

184

870

860

60 70

92 82

80 90

50 90

TOTAL CONSTRUCTlON AND INDIRECT COST

770

958

1040

1000

Escalation (12.3%) (18%) Owner’s cost (5%) (4%) Hnterest during constr. (15%) (21.7%)

94 46 136

118 64 172

128 64 186

182 51 267

TOTAL PROJECT COS’i’ ESTIMATE

1050

1310

1420

1500

C~0mmeicla.l operation

5185

S/85

5185

S/87

310 311

312 6 7 8 9 10 11 12 314

TOTAL DIRECT COST (1982) 19

Construction

dlstributables

TOTAL CONSTRUCTION COST (1982) 20 21

22 23 24

Et@t&ng Allowance for indeterminate

res are talred from the author’s earlier papers [ lO,ll] adjusted for escalation and more recent information. Where two are given in a description (i.e. sub-system numbers 22, 23 and 241, the fust refers to geothermal applications and the refers ot coaMre4l applications.

167 escalation and updated based on more recent information [ 10,111. 4.1 Environmental and safety requirements It is extremely difficult to assess the cost of environmental pollution control and safety requirements. An attempt to do so has been made in Table 2 by presenting costs of plants A and B. Plant A is an earlier geothermal power plant which presumably does not include these requirements. Plant B is the same plant but with the costs of the above items included. 4.2 Plant design philosophy

The commercial basis of steam acquisition, the amount of power generated, and economic factors such as cost of money, greatly affect the plant design and hence the capital costs. For example, plant C in Table 2 has a more efficient turbine and a larger heat rejection system than plant B. The total capital cost of plant C ($1420 kW) is higher than that of plant B, but the higher capital cost of plant C is more than offset by savings in steam cost (Figures 2 and 3; and Table 1). 4.3 Unit size The smaller unit size of geothermal power plant renders the following advantages: (1) Geothermal plants can be expected to be completed on a shorter schedule than comparatively large-scale nuclear, fossil or hydroelectric power plants, reducing risk to the investor as well as reducing the cost of escalation and financing. Package geothermal plants are. possible in a threeyear time frame. (2) A smaller amount of money is at risk for a shorter period of time (Table 2, plants C and D for comparison).

4.4 Type of fluid and associatedpower cycle Very limited cost data are available for the liquid-dominated resource (flash cycle and flash binary cycle) power plants. During 1980 the first two pilot units to utilize the liquiddominated resource found in California’s Imperial Valley and put in commercial operation were relatively small-sized units (namely Magma Power’s 11 MW (gross) binary conversion process plant at East Mesa, and Southern California Edison Company’s 9.3 MW (net) flash conversion process plant at North Brawley). There is some evidence to show that these power plants are more expensive than the comparable size dry steam power plants. 4.5 Steam gathering and reinjection system

The capital costs of a power plant vary depending upon who shares the responsibility for the fuel gathering and reinjection system. This includes a network oi pipelines and associated structures and equipment from the geothermal resource well heads to plant boundary (entry), and from the plant boundary (exit) to the reinjection wells. If the resource operator constructs this system, it will result in a lower capital cost of the power plant component but a higher cost of energy. The reverse is also true but both practices are common. In Table 2, the steam gathering and reinjection system is included in the power plant costs. The cost of the fluid gathering and reinjection system obviously depends upon quality and quantity of fluid, the terrain, and the distance of transmission from wells to the power plant. Table 2 includes the cost of a typical dry steam gathering system for a 55 MW power plant in the Geysers area using a dry steam cycle.

168 5. WELL FIELD DEVELOPMENT

Geothermal reservoir development and operation costs are sensitive to well head temperature, well flow rate, and well cost. These three pammeters determine to a large extent the economic value of a geothermal resource. Estimates of cost to establish the capability to produce geothermal fluid are based on costs of wells, ultimate recoveries per well, and estimates of additional other costs, including taxes that must be borne by the developer [ 121. The price a seller might expect to receive from the sale of a geothermal fluid is not only based on cost plus a reasonable rate of return but also on the basis of its anticipated capability to displace fossil fuels. Recent trends in the prices of fossil fuel and in

drilling costs suggest that price annual increases of 20 to 25 percent for geothermal fluids are to be expected, whereas costs will increase only 10 to 15 percent [ 121. Table 3 shows total well costs from an article by Robert N. Chappell, adjusted by the author for 1982 dollars. Table 4 shows a cost breakdown by major components also compiled from the same source. According to the article regarding actual well costs, “Some have said that the actual well costs often depend on two aspects of well drilling which are not quantifiable: the luck of the driller and the determination of the operator” [ 131. The above data and references are presented in an attempt to show that the method of economic analysis of the well field development and operation is different from that of a power plant.

TABLE 3 Total well costs [ 13 ] (corrected to 1982 prices) -Description

Year

Depth

cost (1000’S)

drilled :RaftRiver no. 1 ‘RaftRiver no. 2 Raft River no. 3

1975 1976 1976

Raft River no. 4A Raft River no. 4B

1977 1978

Raft River no. 5 Raft River no. 6 Raft River no. 7 Indu!&y Coupled no. 1 hldustry Coupled no. 2 IndusUy coupled no. 3 hdustry couplednd).4 Mustty coupled no. 5 lndusby Coupled no. 6 Industry Coupled no. 7 Project Applications no. 1 Project Appkations no. 2 ?rojcct Applications no. 3 INEL no. 1

1978 1978 1978 1974 1976 1975 1978 1978 1978 1378 1379 1979 1978 1979

*MuMegged wells.

(ft)

(ml

5007 6561 5917* 5532* 5853* 2840 5427* s115* 4925 3888 3858 4300 5100 4000 5400 6000 7735 5200 1500 2176 4266 10356

1526 2000 1804 1686 1784 866 11654 1559 1501 1185 1176 1311 1554 1219 1646 1829 2358 1585 457 663 1300 3156

Inflation factor

1982 Costs (1000’S)

810 800 662

1.93 1.76 1.76

1563 1408 1165

305 830

1.57 1.40

479 1162

995 325 275 385 370 290 550 800 2079 1232 214 296 451 2960

1.40 1.40 1.40 2.28 1.76 1.93 1.40 1.40 1.40 1.40 1.30 1.30 1.40 1.30

1393 455 385 878 651 560 770 1120 2910 1724 278 385 623 3848

169 6. COST

COMPETITION ALTERNATIVES

WITH

OTHER

It is appropriate for state PUCs to require utilities to demonstrate the cost advantages to consumers, of a requested geothermal plant, relative to other generating facilities that could be constructed. Table 5 shows

such a comparison for the proposed plant at Heber, along with the CPUC staffs estimate of fuel escalatibn affects. In that case the CPUC withheld approval [ 141. REFERENCES 1

TABLE 4

2

Well cost breakdown [ 131: component percent of total and range Item description

cost expressed as

Average* % of total

Location preparation Mobilization and demobilization Drilling Drill bits Drilling fluid Cementing Equipment rentals Transportation Supervision Logging Casing Well head Miscellaneous

5 10 30 3 5 16 4 2 2 3 9 2 9

3

Range* * percentages

4

1.2-19.9 5-12 25-40 2-5 3-8 8-27 3-7 l-6 1.7-2.4 1.7-7.1 6-12 l-5 1.2-19.9

5 6

7 8

9 TOTAL

100

*Average of four values. **Range of seven values.

10

Kestin, J., et al., 1980. Sourcebook on the Production of Electricity from Geothermal Energy. U.S. Department of Energy, March 1980, Chapter 7. Berman, I.M., 1981. Developments in geothermal power plants, Power Engineering, July 1981. Bierman, S.L., et al., Development of Geothermal Energy in the Western United States, Innovation Versus Monopoly. Praeger Publishers. Decision no. 93035, May 19, 1981, before the Public Utilities Commission of the State of California; Appiication No. 59512 filed March 10, 1980, by Southern California Edison Company. Rex, R.W., 1979. Factors limiting geothermal development, Geothermal Energy, 7(12) (December): 30. Krumland, L.R. and Flower, J.E., 1981. Status of geothermal energy development for the Pacific coast, Pacific Coast Electric Association Engineering & Operating Conference, March 19-20, 1981, Los Angeles, CA. Campbell, R., 1979. Conference on Nuclear Power and the Public, Kansas City, Missouri, February 26, 1979. Tucker, R.E., Klienhans, P.V. Jr., and Kielman, L.R., 1980. SMUDGE0 #l, Economic impacts on geothermal power plant design, Transactions Geothermal Resource Council, 4 (September). Economic analysis of geothermal energy development in California, Stanford Research Institute, D.O.E. SAN 115 PlOS-1, May 1977. Popat, L.V., 1980. Analysis of published cost data for parametric estimating of coal-fired power plants,

TABLE 5 Economic cost comparison of alternatives

[4] : 1982 common year levelized delivered power cost (13 percent cost of capital)

Edison Heber WW

Coal ($/kWh)

Generation facilities lnitlal fuel inventory Related facilities Operating & maintenance Fuel

1744 51 -

0.2 2.4 10.1

TOTAL

1795

17.9

Capacity factor (%)

5.2

75

WW

Existing oil Q/kW

PUCC Staff Heber (WW

WkW

(W’W

,352 45 90

5.0 0.3 0.3 1.4 4.0

0.3 16.3

0.2 2.5 15.7

11.0

16.6

24.3

1487 65

-

65

--

5.9

7s

dons American tit&on of Cost Engineers, 1980,24tb Annual Meeting, July 1980, Washtigton DC. 11 Papat, L-V., 1981. Analyti of published data for Parametric es&at@ of bo2er plants, Part-HI, Transactmns Arr&can Association of Cost Engineers, 1981, 25th Annual Meeting, July 1981, Toronto. 12 &ward, JH.. 1980. Price and cost esiimate# for hot

water geothermal energy, Transactions Geothermal Resource Council, 4 (September). 13 Chappeil, R.N., et ai., 1979. Geothermal well drilling estimates based on past well costs, Transactions Geothrxmai Resource Council, 3, September. 14 PUC denies geothermal plant approval, Geothermal Resource Council Bulletin, July 1981.