• , • •., "" ,"') • I , •• ' I

. •• Pr • ' 0 ' • . ~ . I I . '\ • . . fDA~ . . / ; .$ 1 ". • " • ~ ~ . . . • . - - • . •

'$ .···,'=~ .. · . ..:_ -· .~,. \ :~·. . . . ~-· •·· . ,' ' • . . . . . .. ¢) . ~· :

Coal-Fired Unit Size Selection~ ID ~Is Bigger Better? by A. C. Cagnetta, Chief Mechanical Engineer, D. J. Kettler, Consulting Mechanical Engineer, and P.l~. Nobile, Consulting Electrical Engineer

American Power Conference, April1983

lW&rru~&c~!ID&®©@ Susitna Joint Venture

Document Number

Plear.e Return To DOCUMENT CONTROL

_j

; ~~ ,· '' .··' ' . . '

__ \a•......,·=••.,..,:; .,.. *"_..."";.:.:~-.. ;r.a-·- ?>- . , ~.....,-· ~--"'-"--·

•

.,

INTRO~UCTION Histoncally, coal-ftred generat1on has been the predomi­

nant source of electnc power in the Un1ted States. Despite the rncreased use of gas. oil and nuclear generat1on rn the stxtres and early seventies. coal continued to supply about 55 perc~nt ot the electricity generated rn the Untted States 'n 1982. Ebasco forecasts that electricity generated from coal willtncrease by more than a factor of two by the enci of tt11s century and w1ll account for about 70 percent of all electric gener3.tion in the year 2000.

Th1s sharp tncrease rn coal generatton w1ll present the utthty industry wtth many challenges whrch must be ad­dressed 1f coal 1s to be used economically w1th minimum ,mpact to the env1ronment. One such question. and the subject of th1s update to Ebasco's 1981 ASME papef.' 1

' IS

whether large s1zed coal unrts offer econom1es when con­srdering cap,tal and operat1ng costs as well as the relat1ve effects of unit ava1lab1hty on system reserve reqUirements.

A large umt s1ze offers a lower rnstalled cost per kW than a small untt s1ze. as well as a better heat rate. Offsetting these econom1c benefits is the lower avarlabrl!ty of a large untt whrch Increases the amount of reserve capac1ty neejed to ma1nta1n system rehab1hty.

Trte companson of umt sizes 1nvolves careful modeling and analyses of these factors. In recogntt1on of the Impor­tance and complextty of mak1ng su~h a companson. Ebasco·s 1981 paper simulated two generic utrl!ty systems of 3000 and 9000 MW and evaluated the tmpact that al­ternatrve coal-fired umt s1ze had on the econom1cal opera­t:on of the stmulated utility systems. This approach provided a valtd genenc companson over the broad range of un;t sizes considered. namely 200 to 1200 MW.

•: Coai-F·red Ur.·t Slze Setect•on Is B·gger Better?' by PA r-~oc Je and 0 J Kettler Eba~co Serv.ces Incorporated Presen!eC1 at !hP Jo1nt ASME IEEE Po.ver Generat•on Con!erence October .J i3 ~981

F·gure 1

2

Ul -

1981 ANALYSIS CUMULATIVE PRESENT WORTH OF

ANNUAL OWNING & OPERATING COSTS VERSUS UNIT SIZE

(Billions of Dollars) Ul 0 u m ::::J c c ~ --~§ oN 3: I

_co ceo Ci)Q) Ul ~· a~-... ll. Q> .:: -11:1 '5 E ::::J u

10 0

-Large Utility /" Sole Ownership

Small Utility

Sole0wne~ 0 h' are wners ap

,~ ,.- 200 MW i 400 MW Share t Share

200 400 600 800 1000 1200 Unit Size · MW

,;, ~-

~---"'~_..:.~-·~ ....... !

The results of this analysis, as shown in Figure 1, were: first. for a large utility system. a 1200 MW unit size was the economical choice: second. for a small utility that solely owns unrts. the optimum size was approximately 400 MW; and third. in general, for small utilities, it:~ 1nore economi­CAl to have a share in a large unit than to own a unit of that share size.

These conclusions were based on generic assumptions for system load growth and system reliabtlity cntena. as well as unrt cost and performance parameters as a func­tion of un1t size. Ebasco believed these assumptions to be reasonable based on projections made in 1981. Unfortu­nately, our economy has continued to falter, with a com­mensurate slowing of electric utility system load growth. F1gure 2 demonstrates how Ebasco's farecasted peak load growth has decreased from 4.3 percent annually rn 1979 to 3.2 percent annually in 1982.

The 1981 analysts used a 4.3 percent annual load growth projection. The analysis discussed in this paper assumes one and two percent load growth rates. Ebasco's current rndustry average load growth projectton of 3.2 percent per year is not used srnce many utrlittes are expenencmg rates below this average, and these lower rates provide a good contrast to the higher growth rate scenano in the 1981 paper.

The decline 1n load growth, coupled with financial con­srderattons. such as high interest rates. have signrficantly reduced the utility industry's Interest in buildtng new power plants and have created a new trend towards reducing system capac1ty reserve marg1ns. Although public service comm1sstons have supported reductions in reserve ca­pacity, tt rema1ns to be seen 1f the public w1ll accept poten­ttally less reliable serv1ce.

Our 1981 analysis used a reliabiltty cnterion of a loss-of· load probab1hty (LOLP) of 0.1 day/year or 1 day/10 years Ftgure 2

-~ " -., ca 0 -' .X

11:1 al a.

SUMMERPEAKLOADFORECAST Total Electricity Utility Industry

1000

1979 Projection 4.3% Load Growth

" 1982 Projection 3.2% Load Growth

0 19~7~s---·~ao----~.s·s----.9~o~--~.9~s---2~ooo

Year

r

I ·=J

I

• based on a survey of vanous utilities at that time. Recent trends have been towards a LOLP criterion in the range of 0.2 to 1. 0 day/year. Recogntztng this trend towards a lower reitabtlity level and for purposes of this paper\ a LOLP crite­non of 1.0 day/year is used.

The tmpact of our weak economy and complex overlap­ping regulatory and environmental criteria has continued to rapidly escalate the cap1tal cost of new generating ca­pacity, regardless of unit size. Figure 3 clearly demon­strates th1s trend by companng the estimates prepared for the 1981 analysis to the updated estimatP.s prepared for the current analysis.

Us1ng the same approach as the 1981 paper, this analy­SIS will determine if the stgnificant changes tn load growth, rehabthty cntenon and cap1tal cost requirements have al­tered the genenc results of the previous analysis. Although the results presented tn this paper are reasonable, they are genenc and are only intended to be a gwde to unit size selectton. Optimum umt stze selection for a particular utility Will reqUire tndtvidual StudieS tailOred to the utility's needs, financ!al cond1tton. load growth rate, and overall system condittons.

APPROACH TO THE STUDY In order to evaluate the economtcs of unit sizes over the

full range of sizes currently available and used by the utility IndUStry. bOth the 1981 and the CUrrent analyStS Selected 200 MW. 400 MW, 600 MW, 800 MW and 1200 MW units for detatled investigatior~s. The 200 MW. 400 MW and 600 MW units constdered are subcritical (2400 psi) type un1ts; however. the 800 MW and 1200 MW untts are assumed to be supercnttcal (3500 psi) type umts. Because of this broad uritt stze range and of the broad r; mge of utility sizes tn the Un•ted States. two utility systems are again simu-

TWO UNIT INVESTMENT COSTS INCLUDING AFDC ESCALATED TO 1991

VERSES UNIT SIZE

-en 0

(.)

~ m tO ... 4) >

2800

2600

ct - 2400 c 0 'in c s )( w el5 7a ;:

s --'E ::» 0

.!

2200

2000

1800

1600

1400

($/KW)

200 400 600 BOO 1000 1200 Unit Size M MW

lated-a small system having a peak of 3000 MW in 1990 and a farge system having a peak of 9000 MW in 1990. The year 1990 was chosen as the base year to develop the utility system models, since 1991 is about the earliest that a 1200 MW unit can become commercial assuming project authorization in late 1982. The length of the study p€riod is 10 years spanning •he perl'orl100t\ +I"\ +h ... ··~~·')('\('\(\ .... ,..1, ,_

t \ - ·-...,"' "- ... 1¥ 1~'1;.0\1 ...,...., ___ , ......... _

sive.

UTILITY SYSTEM MODELS Selection of the Load Model

The load model in our 1981 study is also used in the present study to provide a basis for comparison between the results of the two papers. The annual system load duration curve selected is shown in Figure 4 and was d& veloped from Ebasco data and a survey performed by the

Figure 4

LOAD DURATION CURVE OF HOURLY LOADS

FOR ONE YEAR 10

LOAD FACTOII • .0.'1.

~ t 0 sr ... ... j ~

.~ c t

I zt-

'·- I l

0 3 s • 9 10

1'£11 UHITTIIIII

Figure 5

SUMMARY OF U.S. UTILITY SIZES

NUMBER OF 8 l PERCENT UTILITY RANGE Of PEAK LOADS UTILITIES OF TOTAL DESIGNATION

1,000 MW - 2,000 MW

2,001 MW - 3,000 MW

3,001 MW- 5,000 MW

5,001 MW- 7,000 MW

7,001 MW- 9,000 MW

9,001 MW- 11,000 MW

11.001 MW - 14,000 MW

NOTES

SMALL UTILITY

LARGE UTILITY

48 } 6~ 21

20

11

4 38!1.

3

3

110

AVERAGE PEAK LOADS

1804 MW

5951 MW

11 a-.seo ON 1978 PE-..; LOADS~ ELECTRICAL WORLD DATA

SMALL UTILITY

LARGE UTILITY

2635 MW

8685 MW

ill OBT-.INED BY INC!! EASING 1975 LO-.OS BY 3 2 PERCENT PER YEP.R

3

I

I

I

•

e~

•• ">;,,.:.,_,.._'. ,

Elecmc Light & Power magazine!21 Th1s survey Indicated that the average load factor for United States utilittes was 60 percent in 1978. Representative peak loads for the sim­ulated small and large utility systems were based on the actual1978 peak loads of 110 utility systems us1ng data published by Electrical World!31 A summary of this data is shown in Figure 5 and Indicates that 62 percent of the uHt1es had peak loads between 1000 MW and 3000 MW and 38 percent have loads between 3000 MW and 14.000 MW Based on these findings. the data is divided into two groups. The uWities between 1000 MW and 3000 MW are destgnated as the small utility group, and the remaining uttlit1es are des1gnated as ~he large utility group. The average peak load for each group was determined and then 1ncreased by a 3.2 percent per year load growth rate, Ebasco's current projection. to obtain the anticipated 1990 peak load averages of 2635 MW and 8685 MW for the small and large utility groups. respectively. These values were rounded out to 3000 MW and 9000 MW to maintain a stmple but significant difference between the generic utility system s1zes.

Selection of the Generation Model Hav1ng selected two generic utility system sizes of 3000

and 9000 MW. two actual utility systems were used as the basts for our simulated small and large systems wtth thetr generatton mixes altered to simplify the calculations and to conform to the followtng guidelines:

a) The ratto between peaking and base load generation should be reasonably representative of most uttlity sys­tems.

~ 2'Efectoc Ltght & Power magaztne. August 1979.

; E'ectr:cal World Dtrectory of Uflltties. 1979-1980.

4

J I

19 J I

10 . ., •o

!

"tt Ttl

INITIAL SYSTEM MODELS ~ I OF CAPACITY MIX

S'dlLL \ITILITY LA"GE UTILITY

:jAI.. 2:2~ '-'V. .60'\l 6400 "'"' 60'11•

·.~~c ... E~rt 150 ... 1'1 •1~! 2800- 111•11

~,.\S ... ...:~at~ E. !25 ... _.. 18'\l •soo..w ''''l -:·.lL

·:-~,~til H5~,iolt 2&~'\'fDI 250>11'1

·~c;.;ytCf JOtf~W"I

w•w 5QJ,t'h

•:YYJN

250\' ... JXI\11'1 •w.-... s.-.. ..... i5:JW ...

:w .. ~ ,XC: VIA< , ......... .. ,, • .,..y,

ll'.hJA,'wtt

J•OO YW 100'\o •o:oow.

O!TAILS OF UTILITY SYSTEM MOOUS

l!lQOo,,

NET STATION 11EAT RATE AT

UNIT MAIJjHNA.NCE MAl( LCAO TYrC ~ OWEEKS'tEARSI !ITUr.wi<l

!"ALL UTILITY

C:OAL 1&2 6 9 10()

COAL no 5 95~ C:OAI. 200 6 9130 C:CA• 110 5 9350

'•IJCLfA~ 'f8 \QUO 'fi.CL(Aq t:'8 tQU.O

QT 10 J ''500 GT IO J 11500 1'1£ CAP.t.C:n• 00 0 ·~'le:)

LARGE UTILITY

..:o•t. ,,, 5 9350 COAL ·~s ) ilSO .CO~L ••1 5 i •so :OAt.. 153 6 ~jll) O.:OAl. 100 6 73e0

·~l)(: ... EAA ll8 IOUO

:;r •o 3 11500 :.• lC J •t s.oo ~T 10 J ..... 500

••E CAPACITY 00 0 '5 'lOO

' ( .• n .• , .... t..,"' fjs-.:r:; _,,,,. .. ,.,, ••u • IIJ(tlt[$£.., ·s. ... teo'\ $"-'"' t .,,. •• S( ... t$" •7\ , ..... , 4 ' lllll,lliUl•rHS 4 U'l, 1MAitf

-

b) Most utilities will either install or share in a limited amount of nuclear generation by 1990.

c) The operation of distillate fired gas turbines should not exceed 1500 hours per year at full load.

d) Each utility system would meet a loss-of-load-proba­bility criterion of one day in one year when interconnec­tions are considered as compared to our original analysis based upon one day in 10 years.

e) Interconnection capability would be about 25 percent of the system peak for both the large and small utility sys­tems in 1990 and would remain constant during the 10 year study peiiod.

The resultant utility systems are shown in Figure 6 and initially consist of 60 percent coal, more than 20 percent nuclear and about 15 percent combustion turbine, result­ing in installed capacities of 3400 MW and 10,700 MW. respectively.

TECHNICAL AND ECONOMIC DA'"fA The technical and performance parameters associated

with each unit size evaluated are the same as the 1981 analysis and are summarized in Figure 7. The operattng

Figure 7

TECHNICAL DATA

NET STATION HEAT RATES PER CAPACITY STATE (BTU/kW~)

UNIT SIZE 100% 75% 50% 25%

200 MW 9,830 10,170 11,070 14,170

400 MW 9.570 9,940 10,890 14.400

600MW 9.475 9,810 10,635 14,245

800 Mwal 9,380 9,680 10,580 14,090

1200 Mwal 9,290 9,650 10,510 13,530

PERFORMANCE DATA

EQUIVALENT MAiNTENANCE FORCED OUTAGE

UNIT SIZE WEEKS RATE%

200 MW 5 1 1 0

400 MW 6 14 2

600 MW 6 21 2

800 MW a) 6 24.2

1200 MW al 6 253

NOTE

al SUPERCRITICAL CYCLE

f

I t

t I

• pressures selected are considered typical and reasonable for the associated unit sizes. Net station heat rates were developed based on General Electric Company's publica­tion GET-2050C, "Heat Rates for Fossil Reheat Cycles Using General Electric Steam Turbine-Generators 150,000 kW ctnd Larger." The turbine heat rates were adjusted for

· bo1ler efficiency. unit auxiliary power requirements and flue c1as reheat extraction steam.

Tht~ maintenance times and equivalent forced outage\ rates were developed by Ebasco based on Edison Elec- : tnc lnst1tute/Nation~l Elec!ric Reliability Council data with .· an appropriate adjustment to reflect flue gas desulfuriza- : t1on equipment. The historical relationship, as shown in F1gure 8, that large units have progressively lower avail­ability ilhan small ones. was preserved. However, the use of h1stoncal data must be viewed cautiously because of the llmtted data base for large units (600 MW and above) and tht~ wide performance variations large units have been e;<perie...,cing. In fact, the actual operating perform­ance of some of the large units is better than that of some of the small un1ts.

Although not evaluated.in our comparison. Ebasco ex­pects the~ availability of large sized units to improve. How­ever. there would appear to be an incremental decrease in ava1lab1lity with Increasing size. The size effect. however. is probably not as dramatic as the historicel data used for this paper 1mplies. Therefore, the availability u"sed for the 800 MW and 1200 MW units should be considered conser­vatively low.

In addition to the performance data necessary for the analysis, capital cost estimates are also required. Ebasco has developed and continually updates a series of curves used to predict order-of-magnitude average investment requirements of coal-fired generating units as a function of unit s1ze. These curves are derived from actual costs of

F,gure 8

UNIT AVAILABILITY VERSUS UNIT SIZE FROM NERC DATA

)

.... Z.. 2MW --1

1200

., mttlil

Ebasco coal-fired projects in the United States and esti­mates of Ebasco's 400, 600 and 800 MW coal·fired refer­ence plants.

Based on this curve type data. plant investment esti­mates were prepared for each unit size considered. The estimates, as presented in the 1981 analysis and updated for the current analysis, are summarized in Figure 9. Thl9 estimates were developed for an initial unit and a max­imum of three extension units and assume the use of a wide range of eastern bituminous coal and Ebasco's refer-

Figure9

UNIT SIZE INVESTMENT COSTS ESCALATED 1~0 1991

($Millions) !MIT JIZI INITI.>L UftiT EXTENSION UNIT

EliTIIIIATIIIIQ DATI· .!!!!!. 1!!'! .!!!!!. ~

200 - IS...nCIII Ctrtct C:C.C .... 544 341 'Oil

Af~ ..!! .!!E. ....!! ~ TOTAL 'AOJECT COST 517 &07 31111 078

12515/kW S3235tkW S1MkW S2J90 kW

.., ... cs..o.-..u:oll

Ou.:t Coa 725 810 S65 510

AFOC 125 182 !1!1 lOll -TOUt. 'AOJ~CT COST 850 972 853 719

$2125 kW S20l011<W Sltlll.,W $1797 ...

.., 1M IS...bcto!IC.CI

O•r-=t Cm 925 1031 719 779

AFOC 175 m 120 ISS

T01AL PROJECT COST 1101 12M 803 93' StSlS •w 12:10/kW SIOOS"IIW 11558 kW

a "" tSv~rncau

Otttc1 Cwt t1'5 12f4 an 9112 AfOC 2211 21111 lSi 20"2

-out. PROJECT COST •373 1582 lOll 11~

$171nw Sl917 aW s1295ow SI<SS oW

1NDIIMf5..tQ:arrtttac.all ·-Ouw:1 COil 1582 1750 1200 lliO AfOC 3'0 .. I 2311 JO<

TOTAl ·~OJECT COST . 1902 2191 Jon 16U

11586 .... S1825ikW Sllilllk\111 SIJ'S.tW

Figure 10

FUEL AND O&M COSTS 1. !!:!.!!:.

FUEL TYPE

NUCLEAR

COAL

OIL

TIE LINE tiMPORTSJ

1912 COST SIMMBTU

1.35

3.62

15.22

~0.00

2. OPERATION AND MAINTENANCE

FIXED O&M .!:!!!!.! SIKW·YR

NUCLEAR

COAL 200 MW 5C.3

COAL .00 MW 31.6

COAL 600 MW 25.3

COAL 800 MW 20.0

COAL 1200 MW 15.2

OIL 12.1

GAS TURBINES 4.9

. . 11. ,.;

COST ESCALATION RATE %/YEAR

10.0

95

10.0

10.0

VARIABLE O&M S/MWH

2.6

2.6

2.6

2.6

2.6

1.4

5,3

5

\

lit (~'

J l ,::_, ? ,·':: --.; ·-._'

0

"'' ._.att!!z.,...'P·,..,...-'..,..·~~-~;1( '"'.

____,;;.....~ c•.J;'"' ~~,.~-, ~~""'~._.... ___ ... __ !. ~

t

e~ce plant design concepts. They include all facilities, cent per year. This analysis assumes 11 percent. t I

such as flue gas desulfurization system and cooling c) Design coal differential. The 1980 estimates were

• to'.vers. to meet regulations existing in June 1980 and June based on a dedicated source of eastern bituminous coal. 1982 when the estimates were prepared. Additionally they The current estimates include the capability of new units to reflect average United States wage rates and field labor burn a wide range of eastern bituminous coals, thereby productivity and no unusual site conditions. The costs do providing a more conservatively designed, plant.

i not include land or land rights, the plant substation beyond While operation and maintenance costs were not re-the main power transformer: any associated transmission vised from the estimate prepared for the 1981 analysis, we facilites, or owner's costs. The cost increases between the did update our fuel cost forecast to reflect significantly

I. two estimating dates are caused by: lower oil escalation rates while maintaining coal at about

a) H1gher escalation rates for material and installation. the same rate. This data is summarized in Figure 10. The

The 1980 estimates were Dclsed on a composite annual levelized fixed charge rate used for the evaluation 1s 18.1

rate of 10.5 percent for 1980. 9 percent for 1981, and 8 percent based on a 30-year life for a coal-fired unit. The

percent thereafter. The current estimates are based o~ 9.1 cost of capital is based on a 50/50 debt equity ratio wirh an

percent for 1982. 9.3 percent for 1983. 8.8 percent in 1984, interest rate of 12' percent for debt and equity return at 16 I , 8.6 percent for 1985 and 1986, and 8.0 percent thereafter. percent.

b) A higher interest rate for the allowance for funds used DEVELOPMENT OF 10.. YEAR EXPANSION PLANS during construction (AFDC). The 1980 analysis deter- To determine when unit additions are required and the mtned AFDC based on the availability of money at 9.5 per- optimum unit sizes for the two utility systems selected, 10-Figure 11

SMALL UTILITY LOAD VERSUS GENERATING CAPACITY (10/o Load Growth) r-) ,,,

YEAR 1990 '

1991 1992 1993 1994 1995 1996 1997 1998 ,999 2000

r LOAD 3000 '3030 3060 3091 3122 3153 3185 3216 3249 3281 3314

200 MW UNITS ADDED CAPACITY-MW 200 200

0 TOTAL INSTALLED CAPACITY-MW 3400 3600 3600 3600 3600 3600 3600 3600 3800 3800 3800

RESERVE-MW 400 570 540 509 478 447 415 384 451 419 486

RESERVE-% 13 19 18 16 15 14 13 12 17 16 15

400 MW UNITS ADDED CAPACITY-MW 400

TOTAL CAPACITY -MW 3400 3800 3800 3900 3800 3800 3800 3800 3800 3800 3800 \

RESERVE-MW 400 770 740 709 678 647 615 584 551 519 486

RESERVE-% 13 25 24 23 22 21 19 18 17 16 15

WJO MW UNITS (100 MW Share) ADDED CAPACITY-MW 100 100 100 100

TOTAL INSTALLED CAPACITY -MW 3400 3500 3500 3500 3500 3600 3600 3600 3700 3700 3ROO

AESERVE-MW 400 470 440 409 378 447 ~15 384 451 419 486

RESERVE-% 13 16 14 13 12 14 13 12 14 13 15

BOO MW UNITS (200 MW Share) ADDED CAPACITY-MW 200 200

TOTAL INSTALLED CAPACITY-MW 3400 3600 3600 3600 3600 3600 3600 3800 3800 3800 3800

RESERVE-MW 400 570 540 5CS 478 447 415 584 551 519 486

RESERVE-% 13 19 18 16 15 14 13 18 17 16 15

800 MW UNITS (400 MW ::;hare) ADDED CAPACITY-MW 400 400

TOTAL INSTALLED CAPACITY-MW 3400 3800 3800 3800 3800 3800 3800 3800 3800 4200 4200

• RESERVE-MW 400 770 740 709 678 647 615 584 55~ 919 886

RESERVE-% 13 25 24 23 22 21 t9 1S 17 28 27

6

•

0

•

year expansion plans were developed based on Ebasco's loss-of-load-probability computer program using a LOLP criterion of 1.0 day/year. This program determines the probability of not having sufficient generation to meet daily peak loads. The key inputs to this program are the load model to represent seasonal and daily load variations, the size and equivalent forced outage rate c>f new units, as well as maintenance outage requirements. The program

Figure 12

scheduies each unit for maintenance and calculates the LOLP tor each week and for the year.

Tabulated in Figures 11 and 12 for the small utility, assum­ing a one and two percent expected peak load growth, respectively, between 1990 and 2000, are the different ac­ceptable generation expansion plans. For each alternative plan, new units were added to maiAtaln the established minimum LOLP of 1.0 dayiyear. These figures show the

SMALL UTii.ITY LOAD VERSUS GENERATING CAPACITY (2o/o Load Growth)

YEAR LOAD

200 MW UNITS

ADDED CAPACITY-MW

TOTAL INSTALLED CAPACITY-MW

RESERVE-MW

RESERVE-0'0

400 MW UNITS

ADDED CAPACITY-MW

TOTAL CAPACITY-MW

RESERVE-MW

RESERVE-%

600 MW UNITS

ADDED CAPACITY-MW

TOTAL INSTALLED

1990 3000

3400

400

13

3400

400

13

CAPACITY-MW 3400

RESERVE-MW 400

RESERVE-% 13

800 MW UNITS (100 MW Share)

ADDED CAPACITY-f.1W

TOTAL INSTALLED CAPACITY-MW

RESERVE-MW

RESERVE-%

3400

400

13

BOO MW UNITS (200 MW Share)

ADDED CAPACITY-MW

TOTAL INSTALLED CAPACITY-MW

RESERVE-MW

RESERVE~%

3400

400

13

800 r.m UNITS (400 MW Sh;re)

ADDED CAPACITY-MW

TOTAL INSTALLED CAPACITY-MW

RESERVE.;MW

RESERVE-%

3400

400

13

1991 3CiO

200

3600

540

18

400

3800

740

24

600

4000

940

31

100

3500

440

14

200

3600

540

18

400

3800

740

24

1992 3121

3600

47:1

15

3800

679

22

4000

879

28

3500

379

12

3600

479

15

3800

679

22

1993 31&4

3600

416

13

3800

616

19

4000

816

26

100

3600

416

13

3600

416

13

3800

616

19

200

3800

533

17

3800

553

17

4000

753

23

100

3700

453

14

200

3800

553

17

3800

553

17

1995 3312

3800

488

15

3800

488

15

600

4600

1288

39

100

488

15

3800

488

15

400

4200

888

27

1996 1997 1998 1999 2000 3378 3446 3515 358~ 3657

200

3800 4000 4000

422 554 485

12 16 14

400

4200 4200 4200

822 754 685

24 22 19

4600 4600 4600

1222 1154 1CE5

36 33 31

100 100 100

3900 4000 4100

522 554 585

15 16

200 200

4000 4200 4200

622 754 685

18 22 19

400

4200. 4200

822 7~ 1085

24 22 31

200

4200

615

17

400

4600

1015

28

-600

5200

1615

45

100

4200

615

17

200

4400

815

23

1015

28

4200

543

15

4600

943

26

5200

1543

42

100

4300

643

17

4400

743

20

400

5000

1343

37

7 l . r

I

'I --h • J • •

·l~,-~-'.:<, .

( >• - -' ~--..· ... -- ,, ,- ~~- -. , 0 /<.

.......,._~,'-"'''"* ........... ,., .............. ""'~~~~--,,. -~ ~--- "~-----~

[' I ' ? !;

yearly peak load. new generat1on additions, total system Figures 13 and 14 provide the same information for the f

·nsialled capac1ty additions, and system reserves ex- large utility. At one percent load growth, five 200 MW, three

• pressed 1n megawatts and percentage . 400 MW. two 600 MW. two 800 MW and two 1200 MW As seen in Figure 11. based on one percent load growth, units would meet system requirements. At two percent

only two 200 MW or one 400 MW solely owned umts are load growth eleven 200 MW. six 400 MW. five 600 MW. five requtred to meet system load over the 10-year study pc- 800 MW or four 1200 MW units would meet system re-nod. A 600 MW unit addition was not considered over the quirements.

t study penod because this size is not practical for a small A comparison of Figures 11 and 12 or 13 and 14 demon-ut!hty with one percent load growth. Similarly, if a small util- strates that reserve requirements appear to be more sensi-1ty were to share in 800 MW units, four 100 MW, two 200 tive to unit size at two percent load grmvth. At one percent MW or two 400 MW shares are reqUired over the study load growth, for both the small and large utility, reserve penod. The 400 MW share alternative provides a signifi- requirements in the year 2000 are almost constant. except cantty higher reserve margin 1n the year 2000 than solely for the largest sizes constdered for each utility, At two per~ own1ng 400 MW size un1ts. cent load growth for each utility system. a direct relation-

Fgure 12, based on two percent load growth, indicates ship between increasing unit size and increasing reserves :our 200 MW. three 400 MW or three 600 MW solely is observed. This observation highlights the adverse effect owned un~ts would meet system requirements. AI- that lower availability of large units can have on system ternatvely. based on shares of 800 MW units, nine 100 reserve requ1rements. wh1ch is the major economical d1s-MW shares. five 200 MW shares or four 400 MW shares advantage of large units. .vould meet system reqUirements. Based upon the 10-year expansion plans developed by

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LARGE UTILITY LOAD VERSUS GENERATING CAPACITY (1D/o Load Growth)

YEAR 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 LOAD 9000 9090 9181 9273 9365 9459 9554 9fA9 9746 9&43 9942

200 MW UNITS

0 ADDED CAPACITY-MW 200 200 200 200 200

TOTAL INSTALLED CAPACITY-MW 10700 10900 10900 10900 11100 11100 11300 11300 11500 11500 11700 ~· RESERVE-MW 1700 1810 1719 1627 1735 1641 1746 1651 1754 1657 1758

RESERVE-% 19 20 19 18 19 17 18 17 18 17 18

400 MW UNITS

ADDED CAPACITY-MW 400 400 400

TOTAL INSTALLED CAFACITY-MW 10700 1 1100 11100 11100 11100 11100 11500 11500 11.,~00 11900 11900 I

! RESERVE-MW 1700 2010 1919 1827 1735 1641 1946 1851 1754 2057 1958 l

RESERVE-% 19 22 21 20 19 17 20 19 18 21 20 l· 600 MW UNITS

r ADDED CAPACITY-MW 600 600

TOTAL INSTALLED l CAPACITY-MW 10700 11300 11300 11300 11300 11300 11300 11900 11900 11900 11900 l RESERVE-MW 1700 2210 2119 2027 1935 1841 1746 2251 2154 2057 1958

RESERVE-% 19 24 23 22 21 19 18 23 22 21 ~0

BOO MW UNITS

ADDED CAPACITY-MW BOO BOO t I

TOTAL INSTALLED }

CAPACITY-MW 10700 11500 11500 11500 11500 11500 11500 12300 12300 12300 12300 I RESERVE-MW 1700 24100 2319 2227 2135 2041 1946 2651 2554 2457 2358 I RESERVE-% 19 27 25 24 23 22 20 27 26 25 26 l 1200 MW UNITS

AODED CAPACITY-MW 1200 1200

TOTAL INSTALLED

• CAPACITY -MW 10700 11900 11900 11900 11900 11900 11900 13100 13100 13100 13100

RESEAVE-MW 1700 2810 2719 2627 2535 2441 2346 3451 3354 3257 3158

RESERVE-% 19 31 30 28 27 26 25 36 34 33 32

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MW untts even though both alternatives require the same 'nstai!ed capactty .

The lower fixed charges associated with the 200 MW un1ts are a result of being able to spread the installation of these un1ts to better fit projected load growth. Large units, due to large capacity 1ncrements on a small system. result tn excess capacity for several years as load S:owly in­creases. This phenomenon 1s even more prevalent for the 100 MW and 200 MW shares of 800 MW units. Here both alternatives have the same capital cost ($/kW), essentially ehm,nattng effects of economy of scale, but the present worth of fixed charges for the 100 MW share size is lower because the smaller share s1ze can be more closely tatlored to projected load growth.

F•gures 15 and 16 also tndicate that unit sharing is more economical than sole ownership of units. Small shares of

CUMULATIVE PRESENT WORTH OF ANNUAL OWNING & OPERATING

COSTS VERSUS UNIT SIZE SMALL UTILITY

(Billions of Dollar) Load Growth 2%

.J:: -... Sole Ownership,. ~ 0 ~(fj --(fj co ~u cu­... ttl

1····---~-----........-... ••• ••• , 4

Load Growth 1% Snare of 800 MW ..

CL ~ 5.5 ~ a

... Sole Ownership~ _..,

'••••• •••e~-i- <1: ~~'-:;o E :1 u

T 0

••• ...... -----=~=Share of 800 MW

I ! j I 100 200 300 400 500 600

Unit Size (MW)

Figure 16

SMALL UTILITY ECONOMIC COMPARISON OF ALTERNATIVES

NO, TOTAL CUMULATIVE PRESENT OF NEW WORTH-$ MILLION

UNITS CAPACITY OR INSTALLED- FIX EO PRODUCTION TOTAL

1~. LOAD GROWTH ~ MW ~~ COST .£Q!L 200 NW UNITS 2 £00 749 '591 5339 400 MW UNITS 400 918 4418 533& 601) MW UNITS NOT EVALUATED

100 MW SHARE OF 800 MW UNITS 4 400 325 4796 5122 200 '>1\V SHARE OF BOO 111W UNITS 2 400 £85 4641 5125 400 MW SHARE OF BOO MW UNITS 2 800 860 4413 5273

t LOAD GROWTH

200 '>1W UNITS 4 BOO 1202 4865 6066 .100 IVIW UNITS 3 1200 1398 41;14 6082 600 MW UNITS 3 1800 1907 4457 6364 100 MW SHARE OF 300 MW UNITS 9 500 714 5000 5713 200 \1W SHARE OF aDO 't.W UNITS 5 1000 891 4828 5720 400 '<IW SHARE OF SOO MW UNITS 4 1600 1302 •5n 5a.'7i

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large units provide a small utility wtth the load fitting advan­tage of small unit sizes. as well as the economy of scale advantage of large units.

The variation of present worth owning and operating costs as a function of unit size is plotted in Figure 17 for the large utility. It can be seen that the curve has an optimum around 400 MW for two percent load growth. However the curve for one percent growth is relatively flat indicating little significant difference among units ranging in s1ze from 200 to600 MW.

Figure 18 shows the increases required in installed ca­pacity as unit size increases due to the historical trend of declining unit performance with Increasing size. At either load growth, the installation of 1200 MW umts requires more than twice the new capac1ty than the installation of either 200 MW or 400 MW units.

The present wortl1 bf the fixed charges for small (200/ 400 MW) unit alternatives is lower than the larger un1t al­ternatives for a large utility because of 1) the ability to spread out the installation of small units for better load fit­ting and 2) the significantly lower Installed capacity needed to meet the LOLP cnterion. Fixed charges. at one percent growth, are increasing over the size range consid­ered at a rate greater than the decline in production costs associated with the better eff1c1ency of larger units; there­fore the economy of scale principle does not overcome reliability considerations reflected in higher installed ca­pacity requirements for large un1ts. This result is essentially the same for two percent growth, except that on a fixed charge basis the 400 MW size represents the lowest present worth cost.

As shown earlier, our 1981 analysis indicated that larger units (1000 to 12,000 MW or larger) on a shared bas1s for a small utiiity and on a sole ownership basis for a large utility were more econom1cal. The effect of reduced load

Figure 17

CUMULATIVE PRESENT WORTH OF ANNUAL OWNING & OPERATING

COSTS VERSUS UNIT SIZE LARGE UTILITY

s (Billions of Dollars) en 0 u -; :I c c < -0 .c 1: 0 ~ -c G) en ! Q. G) > ; 11~0 .!!

•

:I § 10·0 ...__2~o~~o~""'4oo~~s"!"oo~~8~o"!"o-1~ooo~-1 .... 200 (,)

Unit Size (MW)

l r

ANd M

ta \1.7

•

growth. even with the moderating effect of the decreased LOLP cnterion. sh1fts the analysis dramatically to smaller untt shares or sizes.

CONCLUSIONS Ftgure 19 compares the results of the 1981 and current

analyses. • As in our 1981 study, for a small utility the optimum choice

is the use of a share of a large. such as an 800 MW. unit. The optimum unit share s1ze is between 100 MW and 200 MW irrespective of a one percent or two percent load growth. For sole ownership. there is relatively little difference in cumulative present worth costs for unit sizes ranging from 200 to 400 MW. However. the small­est umt share (100 MW) or the smallest sole ownership (200 MW) untt has the advantage of significantly lower fixed charges because of the abtlity to match load re­qUirements more closely.

• For the large ut1lity. tt is clear that the reduct1on of load growth srgnificantly modifies the conclusions of the 1981 study whtch mdrcated that brgger 1s better. Based upon our present analysis. the optimum un~t stze is around 400 MW wrth two percent load growth. For one percent load growth. the present worth cost curve is flatter. and any untt rn the 200 MW to 600 MW range appears economtcal. However. present plann~ng and economrc uncertatnttes favor the installat1on of sm?ller un~ts; there­fore 200 MW ~mtts probably w1ll be preferred. when con­srdenng thts size will result m the lowest required tnstalled capactty. reduce cash flow requirements and provtde greater flexibility to match load.

• Gonsistent with our prevtous study and as would be ex­pected. the selection of smaller un1ts reduces the system reserve requirements. Many regulators today seem to feel a reserve of 20 percent or less 1s adequate: however. th1s wlll not assure reliable operat1on if larger units are added to the system 1n a cost effect1ve manner. As shown tn our sample analysts, the use of 1200 MW units reqUires 30-40 percent reserve on the large system. in comparison to the 18 to 20 percent required tf 200 MW untts are used.

F•gure 18

LARGE UwriLITY ECONOMIC COMPARISON OF ALTERNATIVES

NO TOl'AL CUMULAliVE PRESENT OF NEW WORTH - S MILLION

UNITS CAPACITY OR INSTALLED- FIXED PRODUCTION TOTAL

1% LOAD GROWTH ~ MW CHARGES COST ~ 200 M\'1 UNITS 5 1000 135-4 11801 13156 400 MW UNITS 3 1200 1398 11706 13105 600 MW UNITS 2 1200 1553 11638 13191 800 MW UNITS 2 1600 1938 11W 13421

1200 MW UNITS 2 2400 2684 11~18 14102

2". LOAD GROWTH

200 MW UNITS 11 2200 2825 1;603 15-428 ~00 MW UNITS 6 2400 2 .. 92 12383 14875 600 MW UNITS 5 3000 2771 12415 15186 BOO MW UNTIS 5 4000 3305 12263 15568

12CO 1,'1\'r UNITS 4 4800 4063 12076 16139

• Although not practical to consider in a genenc paper. the selection of the optimum unit size for a utility must also evaluate the impact of specific financial consider­ations, such as the more favorable cash flow requtre­ments and shorter schedules assoc1ated w1th smaller units as well as the disadvantage of potentially requiring more plant sites.

• In this era of unprecedented uncertainty, electric utili­ties have been battered on all sides. Utilities must f,. nance the capacity necessary to meet load demand tn today's money market with high interest rates. Unstable fuel costs and the need to improve and mainta1n ex1st1ng facilities are competing for whatever funds are avatlable. Unfortunately, government policies have served to ag­gravate rather than improve the situat1on. Difficult plan­ning decisions are made more difficult in an unstable planning environment. With these factors 1n mind and considenng the overall Implications of our present and 1981 study, our general conclusion is that shared owner­ship of large untts should be considered by small utthttes. Irrespective of utility size. at growth rates of one or two percent. smaller unit sizes than have generally been considered to be economic in the past can result 1n lower overall costs and should be given prudent constd­eratton.

Ftgure 19

OPTIMUM CHOICES

LOLP CRITERIA

LARGE UTILITY 19000 MWl

43". LOAD GROWTH

2'\i. LOAD GROWTH

1'\, LOAD GROWTH

SMALL UTILITY (3000 MWI

4 31;, LOI>.D GROWTH

1981 ANALYSIS

1 DAY/10 YEARS

1200 MW OR LARGER

SdARED CA?AClTY 200 MW

SOLE CAPACITY 450 MW

2% L01\D GROWTH

SHARED CAPACITY

SOU; CAPACITY

,.,_LOAD GROWTH

SHARED CAF'ACITY

SOLE CAPACITY

ACKNOWLEDGMENT

CURRENT ANALYSIS

1 DAY 11 YEAR

4QOMW

200 TO 600 \'!\'<

100 TQ 200

200 TO 400

100 TO 200

20() TO 400

The authors w1sh to acknowledge the valued assts­tance of other Ebasco personnel m the preparat1on of thts paper includtng:

G. G. Karady. Ch1ef Engtneer. Computer Technology

T. W Duktch. Techn1c1an

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EBASCO EBASCO SERVICES INCORPORATED

CORPORATE HEADQUARTERS Two World Trade Center. New Vorl<. NY 10048 Tel {2121839·1000

REGIONAL OFFICES ATLANTA 145 Technology Park Norcross. GA 30092 Tel t404t 449·5800

HOUSTON· 10375 Richmond Avenue, Houston TX 77042. Tel i7131 954·2600 LOS ANGELES 3000 West MacArthur Boulevard. Santa Ana. CA 92704 Tet t714) 662·4000

SEATTLE. 400 112th Avenue Northeast. Bellevue WA 98004 Tel (206!451·4500 BRANCH OFFICES: Anchorage, AK; Ch1cago.IL; Dallas. TX. Golden. CO. Greensbaro NC. Jencho. NY Kear11y. NJ. Lyndhurst NJ. Mountam V1e'h CA

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3. Pr·oject Econonaics and Sensitivity Analysis

A. Sensitivity testing

1. Capital costs and f1nanc1~g 2. Operating costs

. . 3. Revenues from Utility rate payers 4. Allocation of costs aNd benefits bet~een ut111t1es

B.. Analysis of s111ll project sizes

1. Capital costs 2. Operating costs 3. Revenues from Utility rate payers 4. Comparison with 1,000 tpd and 2,000 tpd projects

C. Analysis of 3,000 tpd regional facility

1. Capital costs 2. Operating costs 3. Flow of solid waste from other jurisdictions 4. Revenues from Utility rate payers

4. Ftorecast of Solid waste Stream and Customer Price Responses

.... .. .. A • Preliminary model of solid waste stream

1. Detenmine variables affected waste disposal choices 2. Develop behavioral nodel

B. Select forecasting methodology

1. Collect data on variables affecting size of solid waste stream

2. Select forecasting approach that w111 give best results, given availability of data

c. Estimate demand for solid waste disposal of different costs of service

D. Detenaine appropriate fac11ty size, given demand at different cost of service levels

E. Sensitivity analysis - evaluate likely changes 1n variables and esti111te effects on the baseline forecast

5. Financing

A. Options

68498 -117-

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c. Private ownership and public operation

D. Private ownership and operation

2. ~isk Assessment

A. Project phase

1. Construction 2. Operations

B. Distribution

1. City 2. Vendor 3. Oper1tor 4. Energy market

C. Mitigation ~asures (e.g., insurance)

PART IV - NEED FOR POWER STUDY

1. Estimate cost of power from proposed facility alternatives- fixed and variable.

· 2. Estimate Seattle City light service area electric power demand through .~01 0.

3. Identify need for additional generator facilities.

4. Identify alternative sources of electrit power to serve Seattle City Light service area and cost out each.

5. Compare cost of power from proposed facility alternatives; present worth each to year 1n which proposed facilities would go on line.

6. Estimate effects on rate payers and system generation costs of adding proposed facilities to system.

TASK II - PREPARATION OF DRAFT EIS BY ENVIROSPHERE

This task will be carried out in the seven subtasks set forth below:

Subtask 1 -Subtask 2 -Subtask 3 -·Subtask 4 -Subtask 5 -

Subtask 6 -Subtask 7 -

68498

Submit detailed work plan Develop a Table of Contents Develop an annotated outline Prepare the draft •Alternatives• section Prepare the draft •Affected Environment, Significant liiPacts, and Mitigation Measures., section Prepare the PreliMinary Draft EIS Complete Draft EIS

-119-

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X.

-.r ~ .~"" ..J c. '(."'> ....

-4 to"· .. ---•z ~ ~ ~,

0

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----~ ___ _ _. _____ ------- .. ------~---.. ----- _ .. _____ ~-~----· ~~:i~~L

Subtask 6 - Prepare the Pre11•1nary Draft EIS

Envirosphere w111 complete the 9reparation of material for the EIS, including developing a fact sheet and 1 sunnary, and prepare a Pre1111inary Draft EIS. The sunnary will provide a comprehent1ve statement of the objectives of each alternative, the .ajor conclusions •.. significant areas of controversy and uncertainty, and the issues to be

• resolved. · ·

The Seattl~ Engineering Department and the independent peer review group w111 review the Preliminary Draft EIS and provide comments.

Subtask 7 - Complet~ Draft EIS

Env1rosphere will revise the Preliminary Draft EIS on the basis of the above comments, and prepare a •camera-ready• copy of the Draft EIS to be s~bmitted to the Seattle Engineering Department for reproduction and distribution.

TASK III - PREPARATION OF THE FINAL EIS

This task will include the subtask breakdown below:

. -·

Subtask 1 - Public review and conment Subtask 2 - Respond to comments Subtask 3 - Revise Draft EIS Subtask 3 - Prepare Final EIS

Subtask 1 - Public Review and Comment

~nvirosphere will support the Seattle Engineering Department in the public review and comment process through three activities: 1) attending public .eetings; 2) providing technical information concerning the alternatives' environmental impacts and proposed mitigation measures, including elaboration on environmental impact analysis ~~ethods and assumptions; and 3) processing and recording responses to the Draft EIS.

Subtask 2 - Respond to COMments

After all connents have been received, analyzed. and logged in, and the SED directs Env1rosphere to prepare the Final EIS, a listing of comments requiring a change 1n the Draft EIS will be prepared. Env1rosphere, with the support of the other technical consultants, will prepare respo~ses to each comment, including an evalu&tion of the comment's i~act on the Draft EIS text. The public cOMments and the responses along w1th public and agency workshop summaries will be bound 1nto a public ca.ment document and submitted to the SED.

68498 -121-

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