ML19199A668

Forwards Addl Branch Input to Section 8.3, Benefits of Operating Plants. Discussion Includes Planned Generating Capacity & Installed Capacity Reserves

ML19199A668
Person / Time
Site:	Crane
Issue date:	12/16/1976
From:	Cleary D Office of Nuclear Reactor Regulation
To:	Regan W Office of Nuclear Reactor Regulation
References
NUDOCS 7905070199
Download: ML19199A668 (21)

Text

____

DEC 1 F3 PE."0RA:CU't F0P.-

Willia::: H. Regar., Jr., Chief. Environmental Projccts Branch tio. 3 FRCM:

Donald P. Cleary, Section Leader. Regional I ract Analysis Section, Cost-Benefit Analysis Francn, ET. 052

SUBJECT:

TiiREE MILE ISLAHD, U?iIT 2 PLMIT f1AME: Three Nile Island, t.' nit 2 LICEllSIt:G STAGE: OL COCKET NL"iBER 50-320 RESP 07.SI3LE BRNiCH: Enviror. mental Projects No. 3 PROJECT tttAGER: Jan fiorris DESCRIPTIO:( OF RESPG:SE: Additional Input to Section 0 Attached are additional inputs to Section 8.3 Benefits of Operating the Planttas well as ink corrections to other parts of Section C and Section 10 which resulted froci the additional inputs.

The attachment was prepared by Louis Bykoski, Cost-3enefit Analysis Branch, 492-79C6.

Donald P. Cleary, Section Leader Regional Insact Analysis Section Cost-Benefit Analysis Branch Division of Site Safety and Environmental Analysis Attachr,ent:

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Form AIC-318 (Rev. 9 55) AJCM 0240 W u. en sovsansemarr emwvine onwan sers.sae-see 7905076/Pf

. GPU and PJM determination of an adequate reserve is based on the reliability standards of the Mid-Atlantic Area Council (PAAC) which state, "On the MAAC syste.n, sufficient megawatt generating capabilities shall be installed to insure that in each year, for the MAAC system, the probability of occurrence of load exceeding the available generating capacity shall net be greater on the average, than one day in ten years."4 To meet this standard GPU and PJM have determined that the reserve margin responsibility will be a value of twenty percent reserve over forecast sumer peak load.

Table 8.1 shows the GPU System's planned capacity and Table 8:2 provides the installed cacacity reserves for the GPU System and the PJM for the years 1977 through 1980.

With the addition of TMINS-2 in 1978, the reserves in that year will stand at 28 7 per-cent for GPU and 31.7 percent for PJM.

In 1980 the GPU System is expected to have 17.7 percent with PJM expecting 26.8 percent.

Should TMINS-2 be delayed a year, the GPU Systems reserves would stand at 13.8 percent.6 cv

(

.I i

. TABLE 8.1 GPU SYSTEM - PLANNED CAPACITY Generating Capacity - Existir.g, and 1977-1980 Changes (Summer Ratings, in MW) l i

Year To tal i

Existing 11/11/76 i

6484 i

Changes in Summer 1977 Bla Changes in Summer 1978 b

ll39 Changes in Summer 1979 0

Changes in Summer 1980 c

-35 Total 1980 T669-Notes:(a) Retire Crawford 3,4 (-45 MW); add Gilbert 8 combined cyc steam postion (126 MW); transfer Gilbert 4-7 (224 MW) from combustion turbine to combine cycle category.

(b) Add Homer City 3 (325 MW); retire Crawford 1,2 (-66 MW);

add Three Mile Island 2 (880 MW);

(c)

Retire Front Street 2,3 (-3S MW).

Source:

Reference 6, Table 1.2-3 TABLE 8.2 CPU SYSTE'i, IN$TALLED CAPACITY RESERVES FOR 1977-1980 SUMMERS GPU Reserves PJM Reserves Percent Percent 1977 14.1 34.1 1978

~

28.4 31.7 1979 23.7 29.7 1980 17.7 25.8 Source: Reference 6, Table 1.2 4 Sq 1 f g.

cu I

o 3-I Since the issuance of the FES in December 1972, the load forecasts have been revised to reflect changes in the overall energy situation.

Earlier peak load forecasts have been revised dcwnward. Table 8.3 shows the most recent load forecasts for the GPU System.

In making its forecasts, GPU, annually develops a twenty-year peak load forecast for each season for each GPU operating company. The base and weather-sensitive portions of the load are projected separately and then I

conbined to derive the ceak load cro.iections. The GPU oeak load fore-cast ~is develnoed by addino the three company forecasts and applying a reduction factor for system diversity. An annual twenty-year fore-cast of average week peak leads and annual energy requirements are also creoared for GPU olannina purcoses.

Also included in capacity expansion plans are considerations of optimum mix of ur.it types and sizes. GPU's presently installed capacity, as a percent of total cacacity, is 58.9 cercent baseload,12.8 cercent intermediate load and 28.3 nercent neakinq[

Table 8.3 shows an annual compound grcwth rate cf energy requirements of 5.9 percent for 1976-1980. The applicant's energy requirements forecast appears reasonable and is below a longer-term electricity sales forecast (reference case) recently developed by FEA for the Middle Atlantic Region. Nationally, electricity consumption is projected to grow 5.4 percent per year between 1974 and 1985.9 5

L. d L

TABLE 8.3 a

Gpu SYSTEM PEAK LOADS AND ENERGY REGUIREMENTS l

Peak load MW Energy Recuirements Year Sumer Winter GWh l

1965 2729 2919 16,112 1966 2921 3093 17,610 1967 3061 3385 18,721 1968 3540 3652 20,617 1969 3868 4113 22,730 1970 4071 4448 24,675 1971 4355 4475 26,098 1972 4772 5024 28,261 1973 5450 5007 30,350 1974 5062 4955 29,931 1975 5167 5497 29,727 D

1976 5180 5653 31,349 1977 5752 5994 33,777 l

1978 5998 6228 35,779 1979 6228 6572 37,421 l

1980 6515 6816 39,477 aActual sumer peak load,1965 through 1976 and estimated 1977 and 1980; i

actual winter peak icad,1965 through 1975 and estimated 1976-1980; actual energy requirements 1965 -1975 and estimated 1976-1980.

}

1976 su:m:er peak when adjusted to normal weather conditions becomes 5450 MW.

Notes:

I I

1.

Sumer peaks may occur June to September, inclusive.

2.

Winter peaks may occur December to February to the following year

^

inclusive.

3.

Hershey Electric Ccmpany loads are rot included prior to 1967.

4.

Estimated 1976-1980 loads are from the original 1977 budget.

Source: Reference 6, Table 1.2-1.

/EA provides region forecasts for the time period 1974-1985 by major Census Region. The Middle Atlantic Region includes the States of Pennsylvania, New Jersey and New York. The grcwth rates fore-casted for the regien arc 3.38 percent for the residential sector, 4.19 percent for the ccmmercial sector and 7.44 percent for the indus-trial sector.10 Sales to others were assumed to grow at the same rate I

as the average of the three sectors. Weights were assigned by the staff to the different growth rates using the present (1975) distri-bution of electricity by customer class in the GPU system. The proportions were assumed to be relatively unchanged over the forecast period. Thus, the annual compound growth rate was determined to be 6.9 percent for the period.

Recognizing that future changes in load and energy requirements are of some consequence to the choice of an economically optiraum mix of generating capacity, Unit 2 is nevertheless one of the least cost sources of baseload power in the GPU System and, therefore, can be justified even if there is no load grcwth and energy requirements growth in the future.

L L)

L 8.3.2 Imoact of Energy Conservation On Acolicant's System Energy Recuirements anc Peak Load Demand Recent energy shortages have focused the Nation's attention on the importance of energy conservation as well as measures to increase the supply of alternative energy sources. The need to conserve energy and to promote substitution of other energy sources for oil and gas have been recomended by the Report to the President on the Nation's Enercy Future as ma,for ef"crts in regaining national energy self-sufficiency bi 1980.II i

There was a slowdown in growth in the applicant's service area in 1974 and 1975 as indicated by the data in Table 8.3.

Surcer peak load declined from 5450 MW in 1973 to 5062 MW in 1974 and 5167 in 1975.

Energy requirements declined from 30,350 GWh in 1973 to 29,931 GWh in 1974 and 29,727 GWh in 1975. While con-servation was listed among the factors contributing to slower growth, the applicant further cited the economic recession and the impact on new home construction as other factors.

Historically, utility rate structures were designed to encourage consumption of electricity by using the declining block rates, which reflected the declining average cost of furnishing additional kilowatt hours of electrical energy to each customer. Until recently, the economic logic for declining block rates was nq [4 w

never seriously disputed. Today, however, under conditions of increasingly scarce fusi recources, declining block rates, by lowering the price of each additional kilowatt hourt tend to encourage greater use of electricity by individual consumers and also to encourage individual consumers to use more and more electricity instead of other energy sources.

The most commonly mentioned alternatives to declining block rates to dampen demand for electricity are peak load pricing, flat rates, and increasing block rates.

According to the applicant, the GPU System has made it a practice to design rates which are cost based and include costs associated with servicing customers and costs associated with volume of energy supplied.

Costs are recovered through a minimum charge for residential rates which do not state demand charges. In rate schedules with both cnergy and demand charges, rates are developed so that the small custcmar's charges are stated separately. The costs are incorporated into the demand and energy charges for larger customers. The demand costs are u:ually spread uniformly across the energy blocks in rates where there is no stated demand charge. Demand costs are recovered by a demand charge where separate energy and demand rates are provided. Energy costs are designed +4 01

-) 'i c L. O t.

.)

l

-a-I be recovered through base rates in the form of separate energy e

charges. An energy adjustment clause provides for changes in enercy costs that are related to fuel costs.

The applicant provides residential customers with several experimental time-of-day rates on an optional basis. This serves as part of the applicant's load management program through d.iich the applicant is seeking more information on whether to extend time pricing techniques and seasonal dif-ferentiai pricing. Otner experiments include peak load pricing in conjunction with the Federal Energy Administration and State of New Jersey to ascertain the demand price relationship for peak load pricing in residential power consumption.14 l

The applicant has not conducted any elasticity studies that would determine the impact of recent rate increases on the demand i

for electricity and has cited low industrial activity and high unemployment following the oil embargo for the general dampened growth.15 n,

3 : O,.

cv t.

In addition to price and conservation, the demand for e

electricity is impacted by such other factors as (1) changes in the regional and national economy; (2) the substitution of

h h-electricity for scarce fuels; (3) growth in population and households; (4) technological change affecting substitute sources Y

of energy, efficiency in the use of energy resources, and the development cf new uses of electrical energy; (5) market forces affecting the demand for consumee investment nr durable goods which require electricity to operate; and (6) changes in consumer values, attitudes and such practices as may be affected by laws, regulations or taxes.

In the face of such a compTexity of causal forces it is exceedingly difficult, to factor out i

the extent to which price changes alone would affect the deTand for electricity in the applicant's service area. The uncertainty exists in analyzing historical data and is even greater in fore-casting future developments because of tne pnturbations of outlook fostered by the energy crisis and decisions yet to be made by custcmers and industrial and government agencies in relation to reducing demari for scarce fuels or developing additional reserves or new sources of energy to substitute for scarce fuels.

i Load shedding is an emergency measure to prevent system collapse when peak demand placed upon the system is greater than the system is capable oi providing.

This measure is usually not taken until all other measures are exhausted. The Federal Power Commission's report on the major load shedding that occurred during the Northeast Power Failure of November 9 and 10,1965, indicates that reliability of service of the electrical distri-On 9/'/

t_tl o

bution systems should be given more emphasis, even at the expense f

of additional costs.

This report identified severci areas that are highly impacted by loss of power, such as elevators, traffic lights, subway lighting, prison and communication facilities.

It's the serious impact on areas such as these that result in Icad shedding as only a temporary method to overcome a shortage of generating capacity during an emergency.

Load staggering has also been considered by the staff as a possible conservation measure. Basically this alternative involves shifting the work hours of industrial or commercial firms 'a avoid diurnal or weekday peaks. However, the staff considers the interference with customar and worker preferences as well as productivity to be of significant impact r.o make such pro-posals of questionable feasibility.

For interruptible load contracts to be effective in system planning, the load reduction must be large enough to be effective in system stability planning. Thus, this type contract is primarily relatc 1 to industrial customers. At the prasent time the applicant has two customers under contracts classified as curtailable service.

The contracts are ecual to 24.3 megawatts and have been included 17 in the applicant's forecasts.

The acceptability of inter-ruptible load contracts to industrial customers depends upon balancing the potecti ti economic loss resulting from unannounced interruptions acair.st the savincs resulting from the reduced pric<a n a

-) ~/ q iU L

of electricity.

If the frequency or duration of interruptions increase as a result of insufficient installed capacity, the custcmers will convert to a normal industrial load contract.

None of the above measures can be considered as a viable alternative for required additional capacity and does little to solve the energy shortage.

mw qq.).g L. u t

l REFERENCES 1.

Moody's Public Utility Manual, Moody's Investor's Service, Inc.

1974, pp.1556,1565,1577,1578.

2.

Federal Power Cor:nission, "The 1970 National Power Survey, Part II Electric Power in the Northwest, 1970,19E0,1990," p. 11-1-78.

3.

Ibid., p. II-1-84.

4.

Mid-Atlantic Area Council, MAAC Systems Plans, FPC Order 383-3, Docket R-362, April 1, 1976, p. III-C-1.

5.

Metropolitan Edison Company, Jersey Central Power and Lighting Company, Pennsylvania Electric Company, Environmental Recort, Ocerating License Stage, Three Mile Island Nuclear Station, Unit 2, Supplement II, Cocket No. 50-320, February,1975, p.1.2-8.

6.

Letter to Jan Norris from GPU Service Corporation, November 30, 1976, Table 1.2-4.

l l

7.

Reference 5, pp. 1.2-4 and 5.

i 8.

Reference 6,,page 3.

9.

Federal Energy Administration, National Energy Outiock, U.S.

Government Printing Office, February,1976, p. 238.

I 10.

Ibid., Tabl e 13a, p. 6-29.

11.

D. L. Ray, Chairman, United States Atomic Energy Comission, The Nation's Energy Future, U.S. AEC Report WASH-1281, U.S. Government Printing Office, Washington, D.C., December 1,1973.

1

12. Reference 6, page 7.

' }

L

13. Reference 6, page 33.

i 14.

Ibid.

15. Reference 6, page 28.

16. Federal Power Comission, " northeast Power Failure," U. S.

i Government Printing Office, Washington, December,1965.

17. Reference 6, page 34.

18. Reference 5, Appendix V, p. v-i.

19.

Refer 2nce 5, Appendix V, p. v-ii.

na 94Q j

o uu

- ~ ~

S.'NEED FOR PLANT 8.1 RE!JM5 The discussion of need for power presented in FES. Dece-cer 1972 is still valid. An additional discussion of the acclicant's rel4tionship to the Pennsylvania-dew Jersey-Maryland Intercen-nection (PJM) and the Mid-Atlantic Area Cecrdinating Council (MAC) is presented in Section 8.2.

The revised load and energy forecasts reflecting national events since the Cecember 1972 FE5 and the reserve margins are discussed in Section 8.3.1 and shown in Table 8.1.

Section 3.3.2 dis-cusses the fact that TMINS-2 provides the least cost alternative to meeting base 1 cad require-ments as well as improving system reliability. The staff's conclusion that the p? ant shculd be operated remains unchanged.

8.2 APPLICANT'S SERVICE AREA AND REGIONAL RELATICMSHIPS 8.2.1 Aeolicant's Service area The General Public Utilitiet Corporation with its subsidiaries of the Metropolitan Edisen Company, the Pennsylvania Electric Cc=pany, and the Jersey Central Power and Light Cemeany supplies elec.tricity to an area of about 24.C00 scuare miles in parts of Pennsylvania, and New Jersey with a populatien of about 4.C00.0C0 (see Figure 8.1).

Metropolitan Edison Concany operates in an area of 3.274 square miles in eastern Pennsylvania.

Pennsylvania Electric Ccepany supplies an area of 17.500 square miles in western, northern, and south central Pennsylvania with Jersey Central Power and Lignt Ccepany operating in an area of 3.256 square miles in north central, east central, nort.* western and western New Jersey.1 8.2.2 Reqfonal Relationships The General Public Utilities (GPU) system service area is included in the Federa! Pcwer Cem-mission (FPC) Northeast Pcwer Survey Regien and located within the FPC's gewer supply area.

PSAS. The GPU system is a member of the Pennsylvania-New Jersey-Maryland Interconnections (PJN) which is a formal power pool that serves three-cuarters of Pcnnsylvania, most of New Jersey, more than half of Maryland, a small part of Virginia, and all of the District of Columcie, and Celaware.1 In addition to cooroination of planning, the cori.enies in PJM conduct economic dispatch within the pcol and share in any load curtailment or voltage reduction if conditions warrant it.

The applicant is a member of the Mid-Atlantic Area Cecrdination Ccuncil (MAAC). The cc.rcantes which compose PJM are also included in the meetership of MAAC. MAAC is concerned primarily with reviewing and evaluating plans from the standpoint of bulk pcwer reliability.3 8.3 8ENEFITS OF CPERATING THE PLANT

/

S.3.1 5,ystem Peak toads and Enerev reevir.-ents

~

Three Mile Island Nuclear Station. Unit 2. is a base load plant which will contribute to meeting the continucus energy demand placec en the system. Efficiency, reliability and lowest possible operating ccsts arc critical factors which characterize baseload plants. In addition to pro-vidnn an economic tource of baselcad generation energy. TMINS-2 will also be expected to contribute to meeting grcwth 1 cad demand as well as increased system reliability.

h* ' a usuance of the FE5 in Deceeter 1972. the load forecasts have been revised to ~.

changes in tne overa.

.a n.

Earlier peak icad forecasts hava

. sea cownward.

Table 8.1 shows the most recent Icao. Jri..... ' ~

-*a 99 ' -

secognizing that future changes in Icad and energy recuire-ents are a'

...nsecue..u

. '-

• ice of an econceically optimum mix of generating cac""

..4 ts nevertheless one of the least ccs2 m. a '

~

y requirements growth in the fu.ture.

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baseload ocwer ia system and, therefore, can be justified even if there is no load

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TABLE 8.1 I

• PU SYSTEM SUMMER LOAD AND CAPACITY FCRECAST. 1975-79 l

Sumer Summer Percen i

Year ecity lead pese'rve s s

(

1975 6.954 5.237 32 g

1976 6.569 20 1977 6.695 5.708 17 i

1978 7

0 6.011 3

1979 7.738 6.235 23 SOECE:

"V davit of Paul E. Winter, before the Atemic Safety and Licensing

.,oard in *he i.atter of ?'etropolitan Edisen Company et al., " applicant's

{

response to intervenor's intarregat:ry. Nos. 24 and 25. July 14.19/5 t

Table 1.

3,5.3 34.2 Ocerating Costs j

At the operating nicense stage a determination must be made #< ether it is econcmical to cperate

{

the plant or not. Once a plant is constructed the capital P.s must be censidered as sunk i

costs and the acerating costs beccme the incartart cests te consider. Since Three Mile Island

~

hu'. lear Station. Unit 2 will be ene of the least expensive base load clant in the GPU systeat to cparate, cost savings will be realized through its cperation. Only Three Mila Island Nuclear Station-Unit I and two small hydrcelectric plants totaling 2." l'We are expected to have lower operating costs in the GPU system than TMINS-2.* f f Ti.... : :-* ** elder fossil-fired plants totaling 162 W (surrer ratind " ^" -

in 1979. The retire ent of trese um a 2"-

r eiateo to the en:ected operation of TMINS 1 W'"

^.

a.

..e mcre a matter of timing of new

,.u.a.

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-sg.......

ra tner 2:an new capacity additicns.'

f. 4 Table ++ represents the staff's com;arison of a nuclear plant of 380 MW with a coal unit of 880 MW coerating in 1978 at varicus plant capacity facters. The table provides the differential total costs and differential operating costs =nien show the nuclear alternative to be more ecu omicaljp add to the system. The nuclear fuel costs, assuuing a 50 percent plant capacity factor, amount to 514.10 per kW-year cercared to the c:al costs of $64.65 cer kW-year for the same plant cacacity factor. In terms of total ocerating ecsts (including fuel costs) the nuclear slant costs would be 556.37 per kW-year less than *.he coal alternative using a 50 ae* cent :lant capacity factcr. The savings in operating costs increase at higner ca:acity

- factors. Figure 8.2 (plotted frem Taole S.T) rovides a ecmparison of the total generating cost between the nuclear and coal plant as a function of plant capacity fact;r with the break-even point estimated at 34 plus percent.

Even if the assumption were made that system energy requirements did not grew after 1974 TMINS-2 should still be ccerated because of fuel and ocerating cost savings. With TMINS-2 cn line in May 1978, the applicant estimatec an overall system operating cost savings uf ever

$55. million in 1978 based on assuccticn of no grcwth in system energy requirement 2 from 1974

' through' 1978

• The overall staff's cenclusien that the plant shculd te operated remains

=

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1 8-6 i

e REFERENCES t,.

Meedy's Public Utility Kanbal, Pecdy's Investor's Serv e, Inc., 1974, pp. 1556, 15c5, a577, 1578.

2.

Federal Power Cornission, "The 197 National ?cwer Survey, Part II Electric Pewy in the Northeast, 1970, 1980, 1990',

1%78.

l 4

3.

Ibid., p. II-1-84.

i i

4.

f.tetr politan Edison Conany, Jef y Central Pcwe nd 1.ighting Company, Pennsylvania Ele:tric Cccoany Envirerrentrr Recert, Ocerating i.. ense Stace, Three Mila Island Nuclear Station, Unit 2, i ep tement 11. Locxet No. 50.. Fecruary 1975 Appenoix V, p. v-1.

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5.

Ibid., p. l.2-10'.

6.

Ibid., Appea x Y, p. v-fi.

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. m :.cwu.n-u=,,wg.renza2:_D.

---_n 9.

ALTERNATIVES CCNSICERED AND CCNSECUE' ICES CF THE PRCFCSE7 ACTICM 9.1 R$5UME j

The discussions of alternatives presented h the FES, Cecerter 1972, still remain valid. An additional discussion of alternative ;ractices for cperstlen of the cooling system are presented in Secticn 9.3.

Acciticnal discussion of snavoidable adverse effects on terrestrial and aquatic biota is in Section 9.4.

Additional information relating to irreversibl,e and irre-trievable ccomitment of resources is provided in Section 9.5.

9.2 ALTERNATIVE ENERGY SCURCES AND SITE 5 In the FES of Cecember 1972, the staff evaluated the alternative energy sources and sites.

Alternative ener;y sources considered were hydrcelectric potential, fossil-fired generating plants, including oil, natural gas and coal-fired plants, and the purchase of power frcm other companies. The applicant's site selection was also evaluated. There have been no major changes in the information relied upon by the staff for the previous evaluations that would materially alter tha consideration of alternative energy sources and alternative sites. at the a:erating license review stage. Oc % w -' '" " '

_ =,

2. No feasible alterna-tive energy source recu1 ring capital Investment as well as c;erating and fuel cost is ec:ncmically compet1*ive with TNINS-2.

9.3 ALTERNATIVE OPERATING PRACTICES 9.3.1 Cooling Syste-s Design alternatives were discussed in the Cecember 1972 FES (see Acpendix 3). There are limited operating alternatives wnich have been considered in reviewing the a;clicati:n fer an c;erating license for the station. These alternatives include the selection of makeuo and blewdown rates and the selection of chemicals to be used in "e circulating water system for control of scaling and fouling. The selection Of the makeu: and L 'cwdown rates include a determinatier 9 the concentration fact:r in the circulating water s. stem. This in turn affects the regr nent for chemicals to control scaling.

Cperatien at a higher c:ncentration factor would reducs makeus requirements end would thereby reduce entrainment and possibly immingement losses. The hignca factor would require the use of more acid to control scaling. Both the aischarge concentration ud the total release rate of sulfates would thereby be increased. Furttemcre, the potential fur an impact due to drift increases as solids c:ncentraticn increases. There is a limit on the cencentration facter beyond which the for :aticn of scale cannot be c:ntrolled by acid accition. Acid addition controls the carbenate scale which would otherwise fem at a icw concentration facter. The sulfate or silica scale which m1ght form at a higher concentration factor is less readily controlled.

Alternatively, operation at a 1cwer concentration fact:r might reduce er eiiminate the acid requi r* men ts.

This would be done at the ex;ense of entrainment and impingerent losses.

There are alternatives to the selecticn of chemicals prc: sed by the a:plicant. For example, hydruchloric acid could be used in place of sulfuric acid for controlling scale. This would be significantly more costly but wculd substitute chlorides f0r sulfates in the blowdcwn and drift.

Conceivably this cculd be preferable in the bicwdcwn but would be less desirable in the drift since vegetation tends to be more sensitive to chlorides.

The blacides wnich might be used as an alternative to chlorine f r centrol of fouling wculd also be more costly. Furthernere, they would be of questicnable effectiveness and would introduce b

environmental concerns similar to those regarding chlorine (Cevele: ment Cccurent for Effluent Limitations Guidelines and New Source Perfor.ance Standarcs for the Steam Electric Power Generating Point Source Category, EPA, Cct:eer,1974). Since the need for fculing control in the circulating water system is confined to the Oreblem of algal grewth in the distributicn I

trays of the cooling tcwers, tha need for biocide treatment of this system might be eiRinated 4

entirely by constructing a shade over the trays. Since ex erience with Unit 1 indicated virtually k

immeasurabic chlorine in the plant discharge due to circulating system treatment, there would be no environmental benefit derived by pursuing alternatives for this system.

Review of impact of the coerating practices prec0 sed by the a;plicant detemined that they are acceptable based on present kncwledge of requirements for ;rotecting the other uses of the f

9-1 93

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10. BENEFIT-COST ANALYSIS

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10.1 RESUME The Benefit-Cost Analysis presented in the FE5 issued in Cecember 1972 remains valid with the updated information on the benefits presented in See:1on 10.2 and with the updated and,idi-tional cists presented in Sections 10.3 tnrcugh 10.6.

The overall staff's recomendatien that the constructicn permit should be concinued and the operating license be granted remains unchanged.

I

}

10.2 BENEFITS I

l The primary benefit frem the coeration of Three Mile Island Nuclear Station, Unit 2, will be the addition of 906 MWe (830 MW sumer rating) net generating capacity which will provide I

increased production of electrical energy at a fuel, and operation and maintenance cost lower than all but three other base load units in the GPU system. This unit will produce electricity at considerably less per kWe of output than will a large efficient base load coal-fired plant scheduled to ccme on line at approximately the same time. Any reduction in base loed coeration due to an unlikely decline in need for base load capacity would be achieved with existing units even less e#ficient than the coal-fired unit used for comparison.

Secondary benefits irclude tax revenues, increased local employment and paym11, and local purchase of materials and sucaliea. Tax revenues related to Three "11e Island Nuclear Station.

Unit 2 that will accrue to the Comonwealth of Pennsylvania will amount to about $22.8 million in 1979. The one percent earned income tax will yield a total of abcut $20,000 a year to the townships in which the workers will reside. The 165 new per.anent jobs are expected to have an anr.ual payroll estimated at 53 04 million. Local purchase of cperating supplies and materials are estimated to amount to $125,000 per year.

10.3 ECONCMIC COSTS The project costs related to plant operation include fuel costs and operatien and maintenance and are estimated by the applicant to be 53,529,C00 and $6.528,0C0, respectively, in 1973 for an assumed net generation of 3,C68,C00 MWh. There will be no significant econcate costs imposed on surrounding corx: unities due to operation of TMI-2.

10.4 ENVIRCNMENTAL COSTS The envircnmental costs as discussed in FES (December 1972) are still valid with the follcuing mcdtfications:

(a) the comparisen of total operating costs between nuclear and coal baseload plants is now shown in Section 8.3 3 0f this sucolement in lieu of Section XI.B.1; (b) the j

environmental costs associated with radioactive effluents are these discussed in Section 5.4 of this supplement in lieu of those discussed in Section V.O. of FES, December 1972; (c) acdi-tional envirencental cost involves accuisition of a 175 foot wide right of way alcng an existing 150 foot wide 230-kV transmission line corridor for a 7.36 mile extension of the 500-kV trans-mission line frem Bechtelsv111e to Hcsensack. This consists of clearing of 21 acres of wcodland; spanning nver 124.5 acres of agricultural land; and diverting of 0.4 acres from agriculture to I

use under tcwer bases (Section 4.4.1).

1 10.5 SCCIETAL COSTS No significant econom1c or social costs are expe'.ted from plant operating p.isonnel living in the area.

10.6 ENVIRCNMENTAL COSTS OF THE URUtIUM FUEL CYCLE AND TRANSPORTATION The cuntribution of environmental effects associated with the uranium fuel cycla are indicated in Table 5.5 and the effects of transportaticn of fuel and waste to and frem the facility are sumarized in Secticn 5.4.1.4 These effects are sufficient.y small as not to affect signifi-

- cantly The conclusion of the Cost-Benefit Salance.

10-1 51 9Q8

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-ng 10-2 10.7

SUMMARY

OF SENEFIT-CCST As tne result of this supplemental review of potential 2nvireneental, enconomic, and social impacts, the staff h4 4 been able to forecast more accurately on the effects of

~e plant's operatien.

The additicnal and the updated informaticn provided in this suppl 6v9t does not alter the staff's previcus positen related to the overall balancing of the bene sts of this plant versus the enviranmental costs. Consequently, it is tne staff's belief t at this plant can be operated with only minimal envirenmental imoacts. The staff finds.that tre primary benefits of minimizing system prod.ction costs.ano/or tnr. a1diti:n to basd:Icad generating

~

capacity g eatly outweignt the envirencental and social costs.

~

Based on this evaluation, the 3taff c:ncludes that the averati staff's rec:mmendaticn that the

~

~

construction permit CPPR-66 should be c:ntinued and that the c;erating license for Unit 2 should granted, a,s expresse.d in FES, Decemeer 1972.(Summary and Conclusions), remains uncnanged.

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