ML19264B960
| ML19264B960 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 12/03/1981 |
| From: | Savage N ENERGY, DEPT. OF |
| To: | Youngblood B Office of Nuclear Reactor Regulation |
| References | |
| RTR-NUREG-0848, RTR-NUREG-848 EP-422, NUDOCS 8112210382 | |
| Download: ML19264B960 (200) | |
Text
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DOE F 13253 U.S. DEPARTMENT OF ENERGY 17 -f 9) memMunCMm DATE December 3, 1981 ATT OF EP-422 Comments on Byron Station Draft Environmental SU BJE CT Statement relating to Plant Operation T O' B. J. Youngblood, Chief Licensing Branch No. 1 Division of Licensing Nuclear Regulatory Commission My comments on the Draft Environmental Statement related to operation of Byron Station Units 1 and 2 are marked on pp. 2-1 through 2-11 of the attached copy.
I have attached copies of Tables 4A.7.1 and In addition, 4A.7.2 which appear in the July 1981 DOE report on Electric Power Supply and Demand for the Contiguous United States 1981-1990 (DOE /EP-0022).
These tables project reserve for the years 1982-1990, margins for Commonwealth Edison, that lend support to Table 2.6 in the Byron DES.
' Aj Xf Norton Savage General Engineer Office of Energy Emergency operations Assistant Secretary for Environmental Protection, Safety, and Emergency Preparedness Department of Energy Attachments
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2 PNO-I-81-130 and more complete water samples (up and downstream of farms as appropriate).
The licensees consider it a possibility that there will be media interest and attention associated with this round of sampling.
The licensees plan to continue to investigate and to publish the results in the Annual Environmental Program Reports covering 1981. The licensees will continue to keep Region I apprised of any developments.
The State of New York is being informed. NRC This PN is issued for infonnation only.
will not issue a press release, and the licensees do not plan to issue one at this time.
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w T AULE UL.7.1 futudi C4P*d!LIif 49WI AN3 RESI4WE5 (MW AND PERCErst9. 1912 1995 C199 3NWI AL TH E0!5n4 Ce. PEGION 65 1482 1583 1984 1985
$UMMER WINTER SUM 9 9 Wl1TE4 SUMMER WINTER SUMMIR W14I!R 1754F 19211
!$63 F 23321 19727 21441 23952 22566
- 1. FLAhHtD CAPAd1Llif 15640 11 F3 6 16133 12;61 16614 12422 17135 12733 1d99 F4d5 2534 4263 3123 9319 374F 9773
- 2. PEAR DEMLHO 3.
FLANNED PESERWES 44 29
- 4. PLangio 6LsCavis (El (3/29513, 12.1 64..
15.5 69.5 18.R
- 72. 6 21 9
? 6. 4
- 5. NE T T R A NS AC I 10NS tlMP0ggs.guponist 624 6?4 112 312 312 112 312 31 2 6.
TOTAL C AP ARILIIT (t+%)
14171 19825 Idit9 21633 2C139 21753 21164 22878 g
2523 9189 2116 4572 3435 9331 4359 13355 5
1.
10 Ta t p(5ERWIs (6 23 8
1014L RESEPVIS (si tit 2tul34 86,4 69.4 47.5 71 1 23 7 73.1 23.7 T 8. 8 e.
m 9.
SCHIDULED MAINTENA1CE 351 2227 372 2357 395 2447 417 2618 g
- 10. C APAS ILIIT AFIER MAINTENANCE (TR2C 4F594 1854 T 192T6 19644 19266 23T4F 2:263 5,
ll. PEsE4vEs af fir M419]ENAN:I st3 20 2472 5982 2444 6215 3343 6144 3642 7467
- 12. RESIRVE S 4FliR M411111 ANCE tti 448/285133 lie 9 53.3 15.2 51.5 19.3 55.1 21 3 58.4 13, F UL L FORCEO OUTAGES 1263 15F4 1340 1666 1923 1758 1531 1833
- 14. CAPARILITY AFTER FJLL F34CED oui AGES (11 116 46557 16324 1723F 16613 18224 17308 19246 18413
- 15. RESE4WES AFTER FULL FORCIO QuiAGES (14 28 939 4318 1134 4549 1620 5386 2141 S617
- 16. PESERVE5 641 AFIER F ULL FORCiQ Qui 44ES 614/28510J 5.8 36.9
- 6. 9 3 T. T
- 9. 8
- 43. 9 12.5 43.9
- 17. OIHE4 UNA V AIL ABL E ' APASILIV 3123 2776 3312 3153 3511 3323 3T12 3478
- 18. Actual CAPAMILlir 414 47) 13434 13 d 4 8 13375 13463 19713 19185 15534 14912
- 19. ACTUAL RESERVES 439 24 2214 1342 2238 1399 1871 1763 1571 2119
- 20. ACiual RESERVE S 639 (19/245143
-14 4 18 5 11.7 11.6
-11.4
- 14. 2 9.2 16.6 i
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2 PURPOSE AND NEED FOR THE ACTION 2.1 R6 sum 6 When the construction permits for the Byron units were is5ued in December 1975, the staff concluded that the units should be allowed to operate to assure, among other things, the reliability of service of the Commonwealth Edison Company's (CECO) System.
At that time, Units 1 knd 2 were scheduled to begin commercial operation in May 1980 and May 1981, rdspectively.
These on-line dates were selected as a result of an expected / growth in peak demand of 7.5 percent and an increase in energy requirements of 7.0 percent per year during the 1973-1982 p/ g/m/,/ M,3 f e f y 7f ?
eriod.
Actual rates of growth in demand and energy have averaged only 2.0 percent per year and 1.6 percent per year, respectively, during the 1973-1980 period.
This decline in expected growth is not unique to the CECO service area, Tbs +- b J deeMne is representative of a national trend, attributable, in part, to
'I higher prices for electricity, to conservation, and to an overall slowdown in d
economic growth.
These economic and social disincentives, coupled with dEie~ri D s >
obstacles which have recently plagued the construction of all generating
\\f facilities, have forced adjustments to utilities' generation expansion programs.
In this context, the commercial availability of the Byron units has been 9
delayed.
Current scheduling calls for Units 1 and 2 to begin operation in October 1983 and October 1984, respectively.
In this section the staff evaluates the need for the Byron Station in the context of (1) overall system production costs, (2) availability of alternative E es p
- AjWi[f d r, and (3) reliability of the bulk power supply of the Ceco service area.
2.2 Production Costs The Byron Station has been constructed to provide an economical source of baseload energy.
Since substantial capital and environmental costs associated with construction have already been incurred, the only economic f actors that are relevant for analysis, at this stage of review, are those related to the costs of producing electric energy. These " production costs" include fuel expenses and operation and maintenance (0&M) costs.
The 1980 average production costs for electric energy generated on the CECO system is shown, by type of fuel, in Table 2.1.
The breakdown of electric energy oenerated in 1980, by type of fuel, is shown in Table 2.2.
Assuming that production costs increase at an average annual rate of 10 percent from 1980 through 1984, 1984 production costs on the CECO system, by fuel type, are projected to be:*
v 'd a f/W./ G Adkf-f ~
w n n mw t, 2-4 ?
7 % a ~~-/ % w h,o y jw,s-
- Including 0 & M costs.
Byron DES 2-1
~
G Table 2.1*
Average 1980 Production Cost for Electric Energy Generated by Fuel
-- 4PeC~~ 6N Tse C.ECC C-/fryr1 l Average Production Cost **
(mills /kWh)
Fuel Type Nuclear
/?
O 8
a&
, v) N')r. f1 gLJ ;w, -[k i
- um H
c p
Coal
.) e v 'Y,e' " T,vW ~
,, z 9
17 High Sulfur 1
26 5 1[*
Low Sulfur
- @ "/%
Dil diF#(( fh 64 Steam Cycle 127 -ep
[*" ' '
Combustion Turbines f
,wws 80 Gas-Combustion Turbines b T
/
- From Amendment No.1, Byron Environmental Statement, response to staff question Q320.3, July 1981.
- Production cost includes fuel, operation and maintenance.
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2-2 Byron DES
S' Table 2.2*
A Breakdown of Electric Energy Generated in 1980 by Fuel Types Fuel Type Energy Generated (GWh)
Nuclear 25,970 Hydro 15 Pumped Storage Load (input)
-1,553 Output 1,068 Geothermal Fossil Fuels-Steam Cycle 6 3 /E ' > 29,559 Coal - wt:r %.. so^ G[%
Di1-+A n z.- stea, c. n.'
6,808 Gas 491 9
Fossil Fuels-Combustion Turbines Oil (includes diesels) 153 Gas 303 Total Energy Generated 62,819 Net Energy Purchased and Interchanged 4,127 Total Energy for Load 66,946
- From Amendment No. 1, Byron Environmental Statement, response to staff question Q320.3, July 1981.
O Byron DES 2-3
bm oa Nuclear 11.7 mills /kWh Coal 30.8 mills /kWh
~d'N *~I"gg7 D Oil 117.1 mills /kWh Purchased Power 46.9 mills /kWh
<".,,w /.F7
. wea tS o
M^
Table 2.3 shows the estimated average savings in 1984 dollars associated with the operation of the Byron Station during the seven year period from 1984 through 1990 assuming that fuel escalation and discount rates remain essentially equaU during this period. This analysis is based on an average 60 percent capacity f actor for both units during the study period and replacement sources of energy supply are assumed to be approximately in proportion to the actual mix of supply during 1980.*
The results of our analysis show strong justification for issuing operating g
licenses for the Byron units.
h; V N A decision to operate the Byron units will necessitate a decommissioning 4
a expense once the units are retired from service.
In section 10.2.3.3 of
- ' P the Byron CP-FES, the staff discussed various decommissioning methodologies j
'8-
{ Q" which were, at that time, under consideration.
In January 1981, the staff published a report titled " Draft Generic Environmental Impact Statement on
~fd Decommissioning of Nuclear Facilities (NUREG-0586)." For large PWR units y
'\\
(such as the Byron facilities), the report estimates that decommissioning costs (in 1978 dollars) will range from $21.0 million (plus $40 thousand per T
' ; U.
year surveillance cost) per unit for entombment of the facility to $42.8 C
.9 3,N ' million per unit for the preparation and maintenance of the facility in a
?
" safe storage" condition. risiediaddecontamination of the facility is pro-
]j %g jected to cost $g3 million per unitkI,nm4% e n Ev _ M i
s Tq i n e g ewu,
w The operation of the Byron Station will also result in environmental impacts
)
These have been evaluated by the staff and our findinas 3 L % $
and increased risks.
3
- cs are presented in Sections 4 and 5 of this report.
f a s N $ i ;'!
2.3 Diversity of Supply s y z Regardless of the relative production cost advantages of nuclear generation versus generation from other sources, it is beneficial for bulk power systems to have diverse sources of primary power supply. Contingencies may develop which could limit the availability of desired fuels.
For example, such con-tingencies might include:
1.
Curtailments in the delivery of fuel oil as a result of revisions in national energy policy; 2.
Severe weather conditions causing freezing of coal inventories; Further Federal regulatory limits on use of natural gas as boiler fuel; 3.
Shortages in processing and enrichment facilities for nuclear fuels; 4.
- See footnote on Table 2.3.
2-4 Byron DES
Tacle 2.3 Estimated Savings in Production Costs Associated with Operation of Byron Station (1084-1990) 1984-1990 1.
Energy Generated by Byron Station 78,009 GWh 2.
Fuel and CAM Cost of E e7 Station -
192.4 Dollarc 11 7 n.i'is/kWr.
of Troducing Ena-cay af tti Syrcr 3.
Tota' Ccit Station Avaiiaola (Line 1 tin.as Line 2) -
19F4 Collars
$ r5. 0 4 106 4.
Fuel ano OTJi Cost for Replacenent Li,ergy 1984 Dollars 49.7 mills /kWh 5.
Total Cost of Providing Replacemerit*
Energy in Lieu of Byron Station Generation (Line 2 times Liv. 4) -
1984 Dollars
$3o77.0 x 106 6.
Savings Associated with Byron Station 9
Operation (Line 5 Minus Line 3) -
S 1984 Doll es
$2964.0 x IO
- Weignted everage cost of replacement sources - 70% coal @ 30.8 mills /kWn, 20% oil @ 117.1 mills /kWh and 10% purchates G 46.9 mills /kWh.
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O Byron DES 2-5
5.
Prolonged labor strikes involving mining, drilling and/o* transportati of workers.
The occurrence of any one or a combination of, these contingencies could havt a substantial impact on 'a uti.lity's ability to 5.Jpply energy for load, parti-cularly if the impacted fuel supply is needed to furnish baseload ger.eration.
Of the total 66,946 GWh generated in 1980, 41 percent was produced by nuclear facilities and cvar 47 percent from coal fired plants. The remaining energy
'y oil and gas fue8ed steam and combustion t.urbine units, with was generater i
r-cu minim
.iput f om hydro escarces.,V 5' Y
, fgw
,/i
/
The 1981 H e of g nefating ScilitjeS by fLel type in CE;:o's hulk power system is ide,w f'ec in 1:.:lc 2.4.1 Late.2 plans call for the in;
..uticn cf an r
h.uitional 7,066 MW vf generatire capacity cs the Ceco system througa M?0 C f this new capacity, 6,M6 MW will be ger4:vaM;&y nuclear fae.:istes and.dll increase the amount of inst ?lled nuclear capr.:ity from 4,975 iW in Jarcary 1961 Le 11,491 MW iincludir.g t.he Byron Statiar.; in 198C.
This ornpA :.icn represents approximately 50 percent of all installed facilities in the CECO system in the '/ ear 1956.
Conventional generating units will comprise the remaining installed capacity, eith coal units totaling 6,937 MW, oil fueled units enounting to 3,848 MW, and nat iral gas units accounting for 677 MW.
The current and futurc mix of installed capacity allows CECO to maintain appreciable generating flexibility in the event of an impending fuel shortage.
The addition of the Byron Station will aia in inaintaining this flexibility while, concurrently, effet"ng e elatively low cost source of baso load ene 2.4 Reliability Analys_is i
Historical energy procat. Mon and demand are shown an Table 2.5 for the E60 through 1980 period.
Betwcon 1960 and 1973, CEC., electric energy prcduction and peak demand grew at average annual rates 3f 7.0 percent and 8.1 percent, respectively.
During the period '973 th ougo 1980, energy growth slowed considerably to an average 1.6 percent annually, while peak demand grcwth slowed to 2.0 percent per year. These rates cf growth were less than those experienced r,ationally, with U.S. eaeroy requirements increasing at a rate o.'
3.1 percent per year and peak demano at 3.5 parcen'. per year from 1973 through 1979.
CECO currently projects demand to in' crease at n. less tien 2.5 percent per I
year but no more than 3.5 percent per year during the 1981 through 1990 period We find these growth rates reasonable i1 light of tM state level projections developed f the NRC by the Oak Ridge National Laboratay (ORNL).3 CRNL developed tn e load growth scenarios based primarily on the sensitivity of consumer demand to the price of clectricity.
The base case foreust, which uses fue' cost projections developed L., thi. Department of Energy, predicts demand will increase at a rate of 2.9 perceat per year. For the low cost scenario, dema growth in the State of Il'.it ois is projected to average 4.2 percent per year.
~or the high c';,st scenaric, demand will grow :t the rate of 2.4 percent pet year.
9 Byron DES 2-6
Table 2.4 Existing Ceco Generating Ur::ts for the Summer of IP81 Type,of Year of Net Capability (W)
Stati u - Unit Unit Installation Winter Summer Bloom T.S.S. 33, 34 D
1971 126 103 Calumet 31 34 0
1969-70 276 220 Collins 1 0
1978 554 554 Coll:as 2 0
1977 554 554 Cc111ns 3 0
197' 530 530 Collins 4 0
1978 530 530
"'llins 5 0
1979 530 530 Orzwfere 7 C
1959 716 213 Crawford 8 C
1961 226 319 Crawford 31-33 NG 1968 n9 249 CresJer. l' N
1960 207 197 Dresden 2 N
1970 794 772 Dresden 3 N
1971 794 773 E'ectric Janction 31-34 NG 197D-71 243 193 Firk 13 C
19L9 321 316 Fis A 20 D
1966 11 11 Fisk 31-34 0
1963 231 157 Joliet 6 C
1959 308 298 Joliet 7 C
196L 503 499 Joliet 8 C
1956 522 518 Joliet 3 C
1967 11 11 Joliet 31, 32 NG 1969 131 103 Kincaid 1 C
1967 554 554 Kincaid 2 C
1568 354 554 9
Lombard 31-33 NG 1%9 136 108 Powerton 5 C
197 2 100 700 Powerton 6 C
1975 700 700 D
Quad-Cities I M
1972 591 576 D
Quad-Cities 2 N
1972 592 577 Ridgeland 1 0
1931 153 147 Ridgeland 2 0
1950 158 152 Ridgelar.d 3 0
1953 137 131 Ric;; eland 4 0
1955 125 120 Sectrocke 31-34 0
1969-70 135 109 State Line 3 C
1955 2 13 213 State Line 4 C
1962 318 318
'iat.kegan 6 C
1952 100 100 Waukegan 7 C
1938 328 328 Wachran 8 C
1962 297 297 Wat ' egan 31, 32 0
1968 159 113 Will Counti 1 C
1955 106 101 Will County 2 C
1955 154 148 Will County 3 C
1957 262 251 Will County 4 C
1953 52C 510 2 ion 1 N
1973 1040 1040 Zion 2 N
1974 1040 1040
- KEY: N = Nuclear, C = Coal, 0 = Oil, NG = Natural Gas, and D = DS el b0resden Unit 1 is taken out of service for chemical cleanir.q, and expected to return to service June 1986.
The capabil'**
- gures indicate CECO's 2/3 ownership of Quad Cities Station; Iowa-Ill.
C 9
E&G's 1/3 in er,t represents af 29.6 W and 288 W capability for winte and summer, T
respectively.
I 2-7
~96 9
men.
$ k; Q i d e C.a-Cd ' F1 u,g
?
~ t.
,.n Fa L.r Table 2.5*
System Peak Loads and Energy Output /
for the Years 1960 to 1980 V
/
Percent
~3 Increase Annua' Summer Increase Over s
Peak Load Previous Year Qutp_ut-Over Pre-Load Ye c.
(MW)
(MW)
Percent (GWh) vious Year Factor 1960 4,590 357 8.4 24,822 5.1 59.8 1961 1,840 250 5.4 26,178
- 5. 5 60.1 1962 5,143 303 5.9 28,165 7.6 60.9 1903 5,372 229 4.5 30,037 6.6 62.0 1964 u,162 730 13.6 32,352 7.7 58.5 1965 6,468 366 6.0 3e 788 7.5 59.5 1966 7,491 1,023 15.8 38,189 9.8 58.2 1967 7,643 152 2.0 40,018 4.8 59.8 1968 8,950 1,307 17.1 43,457
- 8. 6 55.3 1969 9,265 315 3.5 46,972 8.1 57.9 1970 10,027 762 8.2 30, 51 5.9 56.6 1971 10,943 916 9.1 52 144 4.8 54.4 1972 11,750 807 7.4 56,063 7.5 54.3 1973 12,462 712 6.1 60,058 7.1
.0 1974 12,270 (192)**
(1.5) 59,274 (1.3) 1 1975 12,305 35 0.3 60,310 1.7 0
1976 12,907 602 4.9 62,567 3.7 55.2
~
1977 13,932 1,025 7.9 65,110 4.1 53.3 1978 13,720 (212)
(1.5) 67,927 4.3 56.5 1979 13,804 84 0.6 67 6E0 (0.4) 55.9 1980 14,228 424 3.1 M9'46)
(1.0) 52.7
- From Amendment No. 1, Byron Environmental Statement, p. 1.1-22
- Parentheses indicate negative values.
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Byron DES 2-8
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The applicant proycts peak demand will increase from 14,228 MW in 1981 to N-,
19,800 Mi in 1990 Comparable figures for energy growth are 66,946 GWh in j
1981 and 91,700 Gn'h in 1990.
CECO plans the installat. ion of 6,516 MW of
- D This p
generating capacity through the year 1986 to meet its projected demand.
c A
u new capacity, if commercially available as planned, will increase current a}
instilled generating capacity to 22,953 MW.
J 7
Table 2.6 depicts CECO's projected capacity and reserve situation duri;.g the 3
summer peak periode of 1982 through 1990. This tabulation shows the results
,Q of four capacity wcilability scenarios:
d, T h
Lines 9 and 10 show reserve margin and percent reserve for the CECn x
1.
9 i
^1 system with capacity available as planned.
CJ
\\
2.
Lines 11 and 12 show reserve margin and percent reserve with r unit postponed (sliprd) one full year.
2 N;
3.
Lines 13 and 14 show reserve margin and percent reserve with units :'ipped 2 full years.
T>
3 4.
Lines 15 and 16 show the erfect, on reserves and percent reserves, of an T]s
^
+-
t indefinite postponement in the availability of Units 1 and 2.f_
w 4
Based on CECO's mi-imum installed reserve criterionA5 percnt; system
~
reserve margins under capacity Scenario No. 1 are adequate throughout the study period with the exception of the 1982 summer peak.
However, CECO states eN that " appropriate steps will be taken to eliminate..." this deficiency.4 r
A i
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With the Byron units postponed or.e yur (Scenario No. 2), reserve deficiency s
occurs during the 1984 seamer peak period - about 431 MW short of the 248?, MW n;cessary to sjQisfy the minimum installed reserva criterion. This deficiency could(conceivably) be mitigated through some of the same procedares_ CECO intends 3
to implement during the 1982 peak period. nowever, the magnitude cT tWe
'G deficit is such that considerably more capacity must be available for these y
i procedures to be effective.
e The 1985 reserve level exceeds the minimum requirement (with Unit 1 available) and the 1986 reserve is nearly double the requirement (with both units avail-able). With a two year slippage of both units (Scenario No. 3) reserve capacity f alls to 9.1 percent of demand in 1985 and recovers to 18.7 percent in 1986 (the year in which Unit 1 becomes commercially available). During the 1987 summer peak period, the period in which both units are available, the system reserve margin increases to 28.5 percent of anticipated peak demand.
The 1985 deficit is sufficiently critical to support the contention that slippage of more than one year in tiie availability of Unit I will cause an appreciable decline in the reliability of the CECO System. However, based on the amount of reserve available to the syste:h in 1986 (Scenario No. 2) and in 1987 (Scenario No. 3), it is reasonable to assume that no appreciable relia-bility problem would result if the time between installation dates of Units 1 and 2 were extended f rom one to two yea s.
This estimate is contingent upon Unit 1 being available no later than the summer peak period of 1985 and all other projected capacity additions being available as scheduled.
Byron DES 2-9
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Table 2.6 CECO System Projections of Summer Peak Load Capacity, and Reserves 1982-1990 M,
v 1982 1983 1984 1985 1986 1987 1988 1989 1990 1.
Installed Capacity -
seasonally adjusted-17485 18533 19653 20773 21863 22953 22953 22953 22953 2.
Het of Firm Purchases and Sales 624 312 312 312 87 312 0
0 0
3.
Total Hesources (1 + 2) 18109 18845 19965 21085 21950 23265 22953 22953 22953 4.
Unavailable Capacity 197 197 197 197 0
0 0
0 0
5.
Operable Resources (3-4) 17912 18648 19768 20888 21950 23265 22953 22953 22953 6.
Peak Hour Demand 15600 16050 16550 17050 17550 18100 18650 19200 19800 7
!$ 7.
Reserve Margin (5-6) 2312 2598 3218 3838 4400 5165 4303 3753 3153 8.
Scheduled Outage 40 40 40 40 0
0 0
0 0
9.
Adjusted Margin (7-8) 2272 2558 3178 379C 4400 5165 4303 3753 315.2
+ 10.
Percent Reserve (9 + 6) (X100.0) 14.6 15.9 19.2 22.3 25.1 28.5 23.1 19.5 15.9 11.
Reserve Margin with One Byron Unit Postponed One Year 2272 2558 2050 2678 4400 5165 4303 3753 3153
-p 12. Percent Reserve 14.6 15.9 12.4 15.7 25.1 28.5 23.1 19.5 25.9 13.
Reserve Margin with Byron Units Postponed Two Years 2272 2558 2050 1558 3280 5165 4303 3753 3153
, 14.
Percent Reserve 14.6 15.9 12.4 9.1 18.7 28.5 23.1 19.5 15.9 15.
Reserve margin without Byron Units 2272 2558 2050 1558 21(O 2925 2063 1513 913 h 16.
Percent Reserve 14.6 15.9 12.21 9.1 12.3 16.2 11.1 7.9 4.6
, qn~ o wp-i w A r me scLLu es
. u & mo n3,,,y.
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p O.M-la scAdki es%)o t'
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With the exception of the summer peak period of 1987 (the period in which the Braidwood No. 2 facility is schedtiled), reserve margins under Scenario No. 4 remain well below CECO's 15% minimum ica,uirement.
If the Byron units were not allowed to operate, severe reliability consemences could result during the 1985-1990 period.
- 2. 5 Conc %sions The results of the staff's assessment of purpose and need support a decision The concern of to issue operating licenses for Byron Station, Units 1 and 2.
overriding importance is that the addition of these units to the CECO system is Further-expected to result in significant savings in system p,roduction costs.
more, the 'vailability of Byron Station will assist @ VCECo%maintaininga
? diverse mix of generating resources.
y Although the operation of the Byron Station will result in increased envi-j ronmental costs and risks, the staff has found them to be small.
If the Byron
'j units are not allowed to operate,,, environmental costs and risks would, never-theless, result due to increased 6se of other generating facilities.
b.s ew Although decommissioning is identified as an additional cost of operating the Byron Station, it should be noted that this cost represents less than 3% of the projected cost savings resulting from the operation of Byron Station for the seven year period 1984-1990.
References 6
Amendment 1, Byron Station Units 1 and 2, Environmental Report July 1981, 1.
response to staff question Q320.3 page Q320.3-2.
2.
Ibid, page 1.1-22.
The ORNL State Level Electricity Demand Forecasting Model, W. S. Chern 3.
NUREG/CR-1295, July 1980.
l'i tii t1' tin Regional Reliability Council Coordinated Bulk Power Supply Procram, 4.
April 1, 1981 Report to the Department of Erergy, p. 38-5 j-l 3
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