ML20098D014

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Long-Range Projection of Power Loads & Resources for Thermal Planning,West Group Area 1973-74 Through 1992-93
ML20098D014
Person / Time
Site: 05000000
Issue date: 04/09/1973
From:
WASHINGTON PUBLIC POWER SUPPLY SYSTEM
To:
Shared Package
ML20093C821 List: ... further results
References
CON-WPPSS-111, FOIA-84-603 NUDOCS 8409270323
Download: ML20098D014 (17)
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Long-Range Projection of Power Loads-and Resources for Thermal Planning WEST GROUP AREA 1973-74 through 1992-93

. . April 9,1973 e

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8409270323 840824'

.PDR FOIA COHEN 84-603 PDR ,

1-long-Rance Projection of Power loads. '

and hesouries for Therr.a1 Pl.mning WEST GROUP AREA 1973-7h Through 1992-93 Introduction This projection of power loads and resources has been prepared by the Subcomittee on Loads and Resources of the Pacific Northwest Utility Conference Comittee at the request of the Joint Power Planning Co'ancil.

The purpose of the report is to provide estimates of additional generating capability which will be required to serve estimated pwer loads through 1992-93. Estimates are prepared on an area basis and also by major supply Eroups. The operating area covered is the same as that in the West Group Forecast report.

This report sumarizes loads .nd resources for January peak and critical perio.1 average cnergy conli t ' ons for each operating year,1973-7h through 1992-93. Studies made for the 1973 West Group Forecast report, February 1,1973, have been used as a basia for this report. The resources include those scheduled on an assured basis in the West Group Forecast report plus several hydro and combustion turbine additions. Hydro addi-tions include one unit at Mossyrock,.Mayfield, and Noxon, 8 units at Rock Island, and the effect of. raising the height of Ross Dam commencing in September 1976 Combustion turbine additions include Seattle City Light's proposed unit in 197h-75 and fGE's proposed units in 1978-79.

Potential resourcea ara shown in 'a senarite part on the summary sheet.

Summary Inads and resource- innicate deficiencies in meeting firm require-ments commencing in lo83 Eh except for a def L:it on peak cf about 300 megawatts in 197h-75. This is based on the assured resources of the

' dest Group Forecast as modified for this report. Deficiencies are shown on line 27 of Tabic 1 and they increase to abcut 18,h00 negawatts peak and 11,$00 negawatta energy by 1992-93. The Arca surplus or deficiency of assured resources over total requirements in shown en line 28 of Table 1.

These figures reflect maximum recall of CSPE power assigned to California utilities commencing Apri) 1, 197$. The N R-Hanford project has been included as a firm energy resource during the first two years (1973-7h and 197h-75) of the reporting period. It is not considered a dependable resource for peaking purposes and is not included in Table 1.

Hewever, the private utilities have elected to include their share as a firm peak resource in Table 2.

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Forced outage 'resa ,es on peak were assuned t., be $ pe* cent of y hydro, existine thermal . 5.nd ccmbustion turbine canteity and 15 per- --..- .

cent of, installed peak espability for new 3arge thermal plants. Forced cutage reserves of 5 percent were assumed for existing thermal energy ',1

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capability.

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Area Ioads and Resources c .

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A sumnary of loads and resources for the West Grcup Area is shown on Tablo 1. This year Table 1 has twc parts. Part one shows the usual load-resource talance based on resources exieting, under construction, and under active consideration. Part two commencing in 1983-8h shows ~~

the area load-resource balance based on potential hydro and thernal projects as they night be installed in the future to meet area requirenents.

The area firm load requirements are shown on this table along with the contractual arrangenents to supply. capacity and energy outside the West Group Area. Also included as a requirenent is an item called Capacity Required for Industrial Interruptible load. This iten is ccm-puted at the bottom of the table (lines 32, 33, and 3h) and assumes BPA will install capacity to carry industrial interruptible peak loads under all water conditions. During critical hydro conditions, secondary energy imports would be needed to meet industrial interruptible energy loads.

The existing and scheduled resources include Only those resources in the West Group Area which are presently existing, under construction, or under active consideration. Firm, arrangements for receipt of power from outside the area are also included.

Existing West Grcup thernal and niscellaneous resources are included in this study as firm resources in amounts as submitted by the respective systems. They were included as peak rescurces up to maximum capability; however, not all of the available energy was included. Seattle's combustion turbine (60 megswatts in September 197h) and PGE's combustion turbines (1h6 negawatts in September 1973) were also included in this category.

In deriving the energy capability for new large thernal plants, it was assumed that for Federal net-billed shares each unit would have a 50 percent annual plant availability for the initial 12 nonths of its cc=mercial operation, 70 percent for the second 12 months of conmercial operation, and 65 percent thereafter. For private utilities' and other ncn-net-billed shares of plant cutput, each new large thermal unit would have an 83 percent annual availability for the initial 12 nonths of its conmercial operation and thereafter. The annual availability factor used for part two of Table 1 was 85 parcent.

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. In order to provide an indication of the maintenance normally under- ,

taken in the pool, estinated amounts are tabulated on line 23. These amounts of reheduled rr intenance for hydro resources are based on a procedure which utilizes a percentage.cf peak and energy capabilities by months. The critical period energy capabilities for new large thermal plants are der $ved with maintenance taken into consideration.

New Federal system planning criteria are included in thin report.

The additional Federal oyster. hydro peaking capability included brings the capcity up to the'mininum peaking capacity that is estimated to have the probability of cccurrence of once in 20 years. This differs frca firm energy capahi31ty which is based on ninimum historical stream-ficw conditions during the 30-year period of record. The Federal hydro rerources and the net-billed thernal increment have been reduced by a

' ren312ation factor of 3 percent to recognize inability of the system to

- achieve its full peaking capability at any one specific instance.

No energy reserve fer unferoscen Icad gren.th er other centingencies hos been added to the load or deducted from resources; however, a load growth reserve is shown on line 5. The peak 3 cad grcwth reserve is ecmputed ac 10 pert.cnt of the area firn peak lead less the estimated forced outage reserves shown on line 22. The energy load growth reserve is equal to one-half year's load growth of utility-type leads.

Estimated firn loads include Bonneville Power Administration's firn industrial contracts. BPA's estimated pctential firn industrial loads are shown separately on line h.

Potential hydro projects and' additional unit installations not meeting the criteria for inclusien in the West Group Forecast but considered reasonably representative of those resources which eculd be in operation by 1992-93 are shown en line 32. The potential hydro resources are shown en Table.h by croject. The Subcommittee felt that it would be infeasible to tttenpt scheduling individual hydro projects and additienal unit installations by years.

The ancunts cf potential hydro resources were estinated for each of

. the years frc. 1983-8h hrough 1992-93 and were assumed to be installed in equal increments thrcughout the 10-year pericd. In 1992-93 an arbitrary $CO-mcgawatt pumped storage project was installed to meet peak deficits. Thernal projects were installed to meet remaining deficits av 85 percent annual availability factor. Installation dates ~were determined on basis of energy requirementn.

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f." loads and Rese':rres Q }'a,icr Supply Groups iUT'F'/ ' Table 2 suxnc rbes t.he loads and resourecc by three major supply

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grmps; (1) the Federa3 system, (2) the public agencien, and (3) the

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private utilities, f" The estimated loads and resources fcr the public agency group include all the public agencies in the West Group Area as well as those in DPA's Southern Idaho area.

- _ The Federal agencies are included with the Federal systen. The estimated loads.and resources for the private utility group include the following:

Pacific Power & Light Company Portland General Electric Company Puget Scund Fever & Light Company The Washingten Water Pbwer Company This table assumes that the Federal system will supply the require-nents of the public agencies throughout the period of this report based on net billing arrangements. The private utilities will require additienal energy beginning in 197h-75 and thereafter except during 1975-76 and 1976-77.

Sumary - Recuirements of Private Utilities and Public Agencies A sumary cf the individual yeak and energy requirerents of the feur private utilities and the public agencies is shown en Table 3. Re-quirenents for public agencies 'not listed separately are shown in one total. This table has been included to indicate the probable extent, of participation in nuclear thernal generating plants by individual utilities based on their requirenents.

Subcommittee on Ioads and Resources

, Pacific Ncrtawest Utilities Conference Conmittee l

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FOOT!iOTES FOR TABLE 1 i

1/ Area firm loads are estimated January peak and critical period average energy system loads of private utilities, public a6encies, Federal agencies, and BPA industries. Loads also include transmission losses r:nd a peak cold weather factor for the non-generating public agencies.

,2/ Pirm exports include deliveries to California utilities under the CSPE agreement, peak / energy exchange contracts with PSW, transfers of Centralia power to Central Valley Project, WWF Co. contracts with

!!ontana Power Co., PP&L Co. transfers to PP&L Co. Wyoming Division, BPA wheeling payments to Idaho Power Co., BPA contracts with !<ontana Power Co. for headwater storage payments, geographic preference, wheeling payments, and WPPSS #1 exchange deliveries.

,3/ Peak lead growth reserves are computed as 10 percent of area fim peak load, without the cold weather factor, less estimated forced outage reserves. Energy load growth reserves are computed as one-half year's load growth of utility type loads.

_4/ Industrial intermptible loads not included in area firm loads (line 1 above).

j/ Hydro resources include those shown in the 1973 West Group Forecast plus !<ayfield addition in September 1976, High Ross addition in Sep; caber 1976, Rock IcIand' additions in September 1977, Mossyrock addition in

  • 991, and lioxon additions in 1982.

6/ Imports include energy return to ET# from peak / energy exchange contracts with PSW utilities; BPI.-PGE-PP&L-So. Cal. Edison contract in 1973-74; IJE Co. contracts with Pacific Gas and Electric Co.; WWF Co. centracts with Idaho Power Co., Montana Power Co. and Utah Power Co.: IGE Co.

contract with Utah Pcner Co.; PSP &L Co. contract with Montana Power Co.;

PP&L Co. contracu with Idaho Power Co., Utah Power Co.; transfers from PP&L Wyoming system and imports from Montana Power Co. for delivery to U.S. Indian Irrigation Dis trict.

7/ Combustion turbines include proposed as well as scheduled units. In-cluded are PP&L's Libby unit, PGE's Harborton & Bethel units in 1973-74, IUE's Group #2 in 1974-75 and PGE's proposed units in 1978-79, PSF 1L's South Whidbey Island unit in 1973-74, Seattle City Light's proposed unit in 1974-75, and VT#P's Othello unit in 1973-74.

S/ WPPSS #1 (Hanford) capabilities are based on production of 4 billien kilov.att-hours per year through 1974-75. The plant is assumed shut down thereaf ter. The plant is not considered dependable as a peaking rc.*ourc e. In 1974-75 the private utilities' portien of Taole II re'lecte finn peaking allocation from WPPSS #1 and therefore centradicts Table 1.

Co=mencing in July 1980, WPPSS #1 capability is based on plant conversion to a 1,233 megawatt plant.

2/ Estimated forced outage reserves on peak are co=puted as 5 percent of hydro, existing thermal and combustion turbine capacity and 15 percent af installed peak capability of new 1rtr6e thermal planta. Forced outace recerves on energy are computed ac 5 percent of existing thennal capa-b;11ty.

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Lof '!!ew Federal system planning criteria. The Federal systen hydro peak- .

-.ing capability is the minimum peaking capacity that is estimated to a have the probability of occurrence of once in 20 years. This differs from finn energy capability which is based on minimum historical streamflow conditions during the 30-year period of record. The Pe~1rni hydro resources and the net-billed thermal increment have been reduced by a factor of 3 percent to recognize inability of the system to achieve its full peaking capability at any one specific instance.

-W Potential hydro shown on Table 4 was proportioned over the ten-year period, 1983 4 4 through 1992-93, installing one-tenth of the peak and energy capability each year.

g Potential thermal was installed to meet arca deficits at 85 percent load factor. Installation dates were determined on basis of energ requirements. Plant siz,es were arbitrarily chosen and could vnry with technological advancement. , Federal - Public Agency maturity factors of 50, 70, 85 percent and 6-month delay of units of 500 megawatts and .

larger were not considered because omership was not determined.

15/ Additional peaking was required in 1992-93 and therefore a pumped storage project was installed to meet total peak load.

14/ Forced outage reserves on. potential projects were computed on the same basis as the existing projects. See footnote 9

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,1J/ Resources provided by industrial interruptible loads for the period 1983-84 throu6h 1992-93 are one-half Federal forced outage reserven.

The Federal share of future potential forced outa6e reserves (line 50) was assumed to be the same proportion as the Federal deficits are to the area deficits. The Federal portien of the forced outa6e reserves vcre then added to the base Federal forced outage reserves (line 23, TableII).

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d' F00 DOTES FOR TABLE 2 t

1/ Public Agency and Private Utility commitments include entitlement and supplemental capacity, CSPE replacemc.its Eeographic preference, head-water storage payments, peak sales, and peak deliveries under peak /

energy exchange contracts.

2/ CSPE to West Group utilities is the amount retained by the utilities

. after5(c)(1) adjustments.

. ,3/ WPPSS #1 (Hanford) power allocation to West Group utilities is based on operating costs of 4.0 billion kilowatt-hours of production per year for 1973-74 and 1974-75 and amortization of the bonds thereaf ter through June 30, 1980. WPPSS #1 (NSSS)' allocation to West Group

, private utilities, be6 inning July 1,1980, is 320 megawatts peak and 272_me6anatts energy.- Allocation to the utilities for the period January 1,1975, throu8h June 30,1980, is based on a 25 percent EPA rate increase. In 1974-75, the private utilities' portion reflects firm peaking allocation frem WPPSS #1 and therefore contrudicts Table 1.

4/ Includes deliveries under CSPI: and peak /ener6y exchange contracts with California utilities, deliveries to Central Valley Project from Centralia, wheeling payments to Idaho Power Co., and deliveries to Montana Power Co. for headwater stora6e payments, geographic prefer-ence, wheeling payments, and Hanfoni exchange.

1/ 3PA allocation is private utility 20-year contract requirements through Augus t 31, 1973, d.nd for 1973-74 and 1974-75 is the private utilities' share of BPA-PGL PP&bSo. Cal. Edison Co. contract.

f/ The cold weather factor covers abnormal weather conditiens of the non-generating puilic agencies not incorporated in the load estientes.

7/ Load growth reserves for peak are computed as 10 percent of area firm loaris without the cold weather factor less esti=ated forced out, age reserves. Energy load growth reserves are computed as one-half year's load grcwth of utility type loads.

6,/ Losses include BPA's own system losses plus losses under WWP Co. peak /

enerEy exchange contracts with San Diego Gas and Electric Co.

g/ WPPS3 61 capabilities are based en production of 4.0 billion kilowatt-hours per year in 1973-74 and 1974-75. The plant is assumed to be shut down thereaf ter. The plant is not considered dependable as a peaking resource. WPPSS #1 conversion commencing July 1980 is shown under new thermal net-billed.

10/ Contract themal is Central Valley Project's purchase of Centralia power a d BPA's purchase of Centralia and PP&L's Libby combustion turbine power.

11/ New ther=al net-billed includes public agencies' portion of Trojan, WPPSS #2, Bonrdman, WPPS3 #1 (NSSS) and WPPSS #3. j

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12/ Imports to Federal nyutem consist of energy return under peak / energy exchange contracts with California utilities, imports from it.cntana i t Power Co. for delivery to U.S. Indian Irrigation District, and DPA-PGE-PP&L-So. Cal. Edison Co. ccntract in 1973-74.

l.]/ Contract resources to BPA from utilities inside the West Group area include WKP Co. losses under peak / energy exchange contracts with San Diego Gas and Electric Co. and PP&L Co. energy deliveries under the peak / energy exchange ccntract.

1,4/ Estimated forced outage reserves on peak are computed as 5% of hydro, existing themal and combustion turbine capacity and 15% of installed peak capability of new large, therm 1 plants. Forced outage reserves on energy are computed as 5fo of existing themal capability.

}.5/ New Federal systen planning criteria. The Federal system hydro peak-ing capability is the minimum peaking capacity that is estimated to have the probability of occurrence of once in 20 years. This differs fran fim energy capability which is based on mininum historical streanflow conditions during the 30-year period of record. The Pederal hydro resources and the net-billed thernal increment have been reduced by a factor of 3 percent to recognize inability of the system to achieve its full peaking capability at any one specific instance. .

16/ Public agencies' contracts are Seattle City Light's purchases from Pend Oreille Co. PUD and* Dout;1ss Co. WD's purchases from Chelan Co.

PUD.

l7,/ Hydro resources include those shown in the 1973 West Group Forecast plus Mayfield addition in September 1976, High Hoss addition in September 1976, Rock Island additions in September 1977, Mossyrock addition in 1981, and Noxon additions in 1982. .

J,f/ Large themal is the public , agencies' recall of Centralia power commencing January 1, 1982.

. 1]/ Combustion turbine for the public agencies consist of a proposed unit by Seattle City Light comencing in 1974-75.

20/ Private utility exports include PGE Co. exchange contract with Pacific Gas and Electric Co. and So. Cal. Edison Co., W#P Co. peak /

energy exchange contract with San Diego Gas and Electric Co., W#P Co.

contracts with Idaho Power Co. and Montana Power Co., PSP &L Co.

contract with Montana Fower Co. and PP&L's transfers to PP&L Wyoming system.

f,,1/ Private utility centracts include Cove replacemmt power, F#P Co.

transfer to BPA for losses under peak / energy exchange contracts with San Diego Gas and Electric Co., W#P Co. deliveries to PSP &L Co. and PP&L Co. energy deliveries to BPA under the peak / energy exchange contract.

,2j/ Large themal includes private utilities' share of Centralia, Trojan, Jim Bridger, Colstrip, Boaniman, WFPS3 #3.

2

c 3

2,4/.

4 Imports include ME Co. exchange centract with So. Cal. Edison Co.

i- and Pacific Gas and Electric Co.; WP Co. peak / energy exchange contract with San Diego Gas and Electric Co.; UP Co. contracts with Idaho Po ver Co., Montana Power Co., and Utah Power Co.; PP&L Co.

centracts with Idaho Power Co.-and Utah Power Co.; PP&L Co. trancfers from Wyoming; ME Co. contract with Idaho Power Co.; and PSP &L Co.

contract with Montana Power Co.

2g Net area firm surplus or deficit is the arithmetic sum of Federal System Line 28, Public Agencies Line 19, and Private Utilities Line 19 Note: Energy capabilities of new large themal plants are computed on the basis of 85% annual plant factor for private utility shares. Public agency and net-billed Federal shares are computed on the basis of a 50% re.nual plant factor for the first full year of operation, 70%

for the second full year,' and 85% thereaf ter with a 6-month delay of peaking on units over 500 megawatts.

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1 TABLE 4 BLUE BOOK POTENTIAL HYDRO RESO'JRCES Units - Megawatts ,

i Critical Period Jan. 1932-Avem ge Peak FLATHSAD - CLARK PORK PEND OREILLE - KOOTENAY 30 50 Libby Reregulating 16 7

Sullivan Creek 66 Subtotal 37 UPPER SNAB AREA- 39 0

Palisades Addition 26 104 Tuin Springs 106 Lucky Peak 17 20' 36 Upper Scriver

~,

36 120 Lower Scriver 205 93 Lyr.n Crandall 131 Garden Valley 58 6 23 Garden Valley Rereg. 766 Subtotal ,

MIDDLE SNAKE AREA 660 0

Dworthak Additions ,

7:DIO AND LOWER COLUMBIA AREA

  • O 3,600 Grand Coulee 3rd Powerplant
  • 129 O

Grand Coulee P.T. 976 262 Een Franklin -

621 Jolm Day Additions 0

-50 1,000 Antilon Lcke Pu:nped Storage 212 6,325 Subtotal PACIPTC SLOPE AREA 272 34 High Ross ,

230 127 Klamath River 122 50 Muddy-Meadows 14 11 Cougar Additions 4 3

Strube 85 45 Copper Creek 727 270 Subtotal

  • 785 8,544 TOTAL 774 3,610 Total New Projects 4,934 11 Total Additional Units April 9, 1973

7 it g k 1

r,e i,t.:.;, pali:n. rAl'At:i'lY StitEDUILD FOR SEltVICE
  • Ii .i l P y 197 i Tism H'e:it .titNF 1934 Sheet i of EXPECTED DATE NA?tEPLATE CAPAP.II. f TY OF CfENERCI AI t:N i r NO. 10 CAT IO?l RATINC.FM EXPECTFD-SM OPERATION P t.A MT _ TYPE B.mr.evi11 e Power Ailmi ni st r at i *n Tiworshak (IfSct3 1 Al.sah k i, Idaho ifydraulic 90.0 103.5 Feb 197) **

2 90.0 103.5 Mar 1973 1 220.0 253.0 Mar 197 3 The Dilles (ITSCE ) 16 l'.e s il l es , orcron flyd r au l i c 86.0 Each 98.9 Each Feb 1973 1/ Feb 1973 lb tlar 1973 19 May 1073 20 Jun 197 3 21 ,

Aug 1973 22 Sep 197I t; rant! Coulee (t!SHR ) ..

4: rand Coulee, W;ishingt on liyd raul ic $0.0 Each 50.0 Each Apr 1973 Pump-Generator Additions P7 Iun 1971 PH 19 Ifydraulic 600.0 Each 600.0 Each Jun 1975 3rd Power Plant Jan 1976 20

.' s Mav 1976 Jul 1978 22 Jan 1979 23 J'al 1979 24 Wwaw il , Washi ngton flyd raul ic 1 35.0 Each 155.25 Each Apr 1975 tower e;ranite (liSCE) 1, 2 , 'l Feb 1979 5# Mar 1979 gn, g97o 6i 4 Pasca, Wa .hington  !!yd raul ic 110.96 Each 1 27.6 Each Feb 1975 Ice liart or * ( t!SCE) f t.a r 1975 5

Apr 1975 6 >

rr er 4

1 A.I11t' anal units at existing plants ini.-lu. fed in critical ear reculat ions and 30-year stu lies. incremental capabilities P attributable to these units are shown on January peak anil e r i t i t a' perin.1 energy capabi!I ty summary tabulations. $

13 U

rt

    • 1.7 ftAF usabic s t os aP.e lune 197 3; ?.0 f tAF n:.ahi c storace .f u ne 1974 N

hte: A c hronological t abulat inn of new installations appears in the wr t inn on namepl at e rat ing . .

p-t ('

, tau a;1.f3f RATING ( APAGITY StilLIMil E!) TOR SERVICE .contd.

.f ANT??,RY 197 3 'lifP0f! :l! It!!!E 19H4 Sheet 2 o f ".

EXPECTED DATE NAMEPIATE CAPABILITY OF C(fttERCI AL PIA'IT If?!!T No. I4 W'A T IO*! TYPE RATING-?M EXPFCTED4M opFRATION R.mncvill e Power Admi n i < t r a t i.m -c on t d .

I. i t.hy WSCE) 1 Jennings. Montana flydraulic 105.0 Each 120.75 Each Jul 1975 **

2 Oct 1975 3 Jan 1976 4 Aer 1976 5 (ec t 1982 6 Jan 1983 7 Apr 1983 8 Jul 1983 let Creek (t*SCE) 1 Mcl.emi. Gregon ,

Ilydraulic 2445 Each 28.2 Each oct 1975 -

2 Dec 1975 Teton (USBR) 1

  • Teton, Idaho . Ilyd raulic 10.0 Each 10.0 Each Jun 1976 2 Sep 1976 3 Jul 1979 Chief Joseph * (USCE) 17 Bridgepor t, Washington Ilydraulic 95.0 Each 109.25 Each Mar 1977 18 Jun 1977 19 Sep 1977 20 Dec 1977 21 Mar 1978 22 May 1978 23 Jul 1978 24 Sep 1978 25 Nov 1978 26 Jan 1979 27 Mar 1979 Little Coose * (t:SCE) 4 Riparia, brashington Ilyd raul ic 135.0 Each 155.25 Each Feb 1979 5 Mar 1979 6 Apr 1979 lowesr '4omiment al * (USCE) 4 Ma t t h ew . 1.'a sh i nr t an liydraulic 135.0 Each 155.25 Each Feb 1980 5 Mar 1989 6 Apr 1980 2 A.tdi t ional unit s at existing plants inci mlcet in critical-vear regulation- amt 30-year s ti,d ies. Incremental capabilities at t r itnatahic to these uni t s are shtssi on .f anuary peak an l c ri t ic al p. r io ! rnere.y car ibil i t y .umary tabulations.

c :- tuli storaec available July 1 **71, con t i ng,vn t up m f il l i ne, af ter Apre! I 'v 7 1.

Lt e: A . b ronol .>r. i c al t abula t i on o f new i n:,t all at ions app.ars in the 'es t i m ute namepl at e rat i ngs.

4

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NLW 4.I'4f:NATIE ( APAt.f tY M'tZIMf!ED FG SIAVIE -contd, t Wae:y t s7 t t ita n s.;g f t*NE 19M4 Sheet 3 of 4 EXPECTED DATE PIA *iT NAMEPil.TE CAPABILITY OF CWyLRCI AL l*3 f T Net. 1 M tTfsFf TYPE , RATINC-MJ FXPFrT!3 WW or FD A T Y P*:

9 P. .i.+efte P e r A.Nini.re..eio. -sontd.

Bacneville * (UStE) 11 Bonn.-wille, West.ington flyd raul ic 68.0 Each 2rkt Powerf.oesse 12 77.8 Each May 1982 13 Jul 1982 14 Sep 1982 l5 Nov 1982 I ts .Ian 1981 II Mar 19H1 IM May 1993 Jul 1983 Puret SwnJ Power & t igh t Cetman y South LSldbey i Island 1 1. anele.. Washinrton Comb. Turbine 26.5 28.7 Jan 1973 e olstrip (50% of unit s di and #2) I Colstrip. **ontana Stearn 330.0 Each 350.0 Each Jul 1975 Jul 1976 E. C. !!ydro and P wer Anthority

  • Mica (Canadian Storage) . Near Argenta,!!. C.

Downstream Benefits Apr 1973 Por t l and Ceneral El ec t r ic Company Ifarborton I thru 4 Por t l amf , Or egon Corih. Turbine 63.6 Each 64.4 Each Sep 1973 Bethel 1,2 Salem, Oret;en Comb. Turbine 63.6 Each 63.8 Each Sep 1973 Cambustio,TurSines Croup d2 - -

Comb. Turbine -

432.0 Aug 1974 Trojan I Near Prescot t, Oregon Nuclear 1,216.0 1,130.0 .lut 1975 Pac i f ic Power & I icht t- Tany li-* !!r idcer (Ivrt.4 f rom out side of Area) 2 R oc k S,r i ne s , Wy wn i nr. S t eare 500.0 Each 500.0 Each 1 Sep 1975 Sep 1976 Washi nton Public Pnwer %mPlv Syst ens -

WPPss #2 I Richt. newt, Washington N+aclear 1,100.0 1,100.0 Sep 1977 ne Washineton W. iter Powr ro nan, othello 1 Othelle, Wash ington Comb. Turbine -

32.8 Jun 1973 4

A.!Jitional ernits at existing plant s inc tmfe<! i n c r i t ical-vear rec *it at ions and 30-year stmfies. Incremental capabilities at trib.2 table to these unit s are shown on Jamsary p cak and c r it ical perio.1 energy capabili ty .umary tatmlat ions.

Cate: A chronological tabeilat ion of new ir*st all.it ion . .eppe.o r s in the n+ r t ion on naricplat e ra t inc.s.

.}

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NEll CENERATING CAPACITY SCitEDULED FOR SERVICE -contd.

.TANUARY 1971 T1tRolffm .itfME 1984 Sheet 4 o f !.

Note: These new thermal units have been included as scheduled resources in this report al though they do not meet the established criteria for inclusion ir the West Group Forec a s t . The preliminary planning has been completed, and the units have also been included under the flydro-Thernal Program as reheduled resources in meeting West Group planned requircrent s.

EXPFCTEL DATE NA?!EPTATE CAPABILIT( OF CtEMERCIA!.

PTANT l' NIT NO. 10 CATION TYPE RATING-FM EXPECTED-MJ OPERATION Pucer So.md Power & Lie.hr Company ,

colstrip 3 Colstrip, Montana Steam 1 700.0 Each Sep 1978 (75% of units #3 and #4) 4 . Sep 1979 Portland General Electric Company Boardman 1 Boardman, Oregon Nuc1 car --

1150.0 Sep 1990 W~ shine, ton Public Power Supply System WPPSs #1 1 Richland, Washincton Nuclear --

1233.0 Sep 1980 WPPss #1 1 -- Nuclear -- 1100.0 Sep 1981 m

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