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Home My WebLink About20020415Said Direct.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION )OF IDAHO POWER COMPANY FOR )AUTHORITY TO IMPLEMENT POWER )CASE NO.IPC-E--02-3COSTADJUSTMENT(PCA)RATES FOR )ELECTRIC SERVICE FROM MAY 16 ,)2002 THROUGH MAY 15,2003 ) IDAHO POWER COMPANY DIRECT TESTIMONY OF GREGORY W .SAID 1 Q.Please state your name and business address. 2 A.My name is Gregory W.Said and my business 3 address is 1221 West Idaho Street,Boise,Idaho. 4 Q.By whom are you employed and in what 5 capacity? 6 A.I am employed by Idaho Power Company as the 7 Director of Revenue Requirement in the Pricing and 8 Regulatory Services Department. 9 Q.Please describe your educational background. 10 A.In May of 1975,I received a Bachelor of 11 Science Degree with honors in Mathematics from Boise State 12 University. 13 Q.Please describe your work experience with 14 Idaho Power Company. 15 A.I became employed by Idaho Power Company in 16 1980.My first responsibility with the Company was to 17 develop the Secondary Transactions Simulation Model for use 18 in determining the average net power supply expenses 19 associated with multiple hydro conditions as well as the 20 expenses associated with each hydro condition. 21 In December 1981,the Company applied for an 22 increase in its general revenue requirement in Case No.U- 23 1006-185.The secondary Transactions Simulation Model 24 became the basis for determining the Company's normalized 25 net power supply expenses in that revenue requirement SAID,DI 1IdahoPowerCompany 1 proceeding. 2 In the next general revenue requirement 3 proceeding,Case No.U-1006-265,filed in September of 1985, 4 I was the Company's power supply witness providing direct 5 and rebuttal testimony as well as direct testimony upon 6 rehearing.At the same time I was also the power supply 7 witness in the Company's Oregon jurisdictional filing. 8 In 1988,the Company applied for a temporary 9 rate increase because of drought conditions.Once again,I 10 was the Company witness addressing power supply expenses. 11 In August of 1989,after nine years in the 12 Resource Planning Department,I was offered and I accepted a 13 position in the Company's Rate Department.With the 14 company's application for a temporary rate increase in 1992, 15 my responsibilities as a witness were expanded.While I 16 continued to be the Company's witness concerning power 17 supply expenses,I also sponsored the Company's rate 18 computations and proposed tariff schedules. 19 Because of my combined Resource Planning 20 Department and Rate Department experience,I was asked to 21 design a Power Cost Adjustment which would impact customers' 22 rates based upon changes in the Company's net power supply 23 expenses.I presented my recommendations to the Idaho 24 Public Utilities Commission in 1992 at which time the 25 commission established the Power Cost Adjustment as an SAID,DI 2 Idaho Power Company 1 annual adjustment to the Company's rates.I have sponsored 2 the company's annual PCA adjustment for each of the years 3 1996 through 2001. 4 Q.What is the projection of PCA expenses for 5 the period April 1,2002 through March 31,2003? 6 A.The projection of PCA expenses for the period 7 April 1,2002 through March 31,2003 is $106,509,695.This 8 amount is $33,430,567 more than the $73,079,128 normalized 9 level of PCA expenses. 10 Q.What is the basis for the projection of 11 April 1,2002 through March 31,2003 PCA expenses? 12 A.The Commission,in order No.24806 issued in 13 Case No.IPC-E-92-25,the proceeding which created the PCA, 14 adopted a natural logarithmic function of projected April 15 through July Brownlee runoff to compute the projection of 16 April through March PCA expenses.The derivation of the 17 current equation is contained on Exhibit 1.The normalized 18 purchased power expense for Qualifying Facilities ("QF")and 19 the normalized Astaris second block energy revenue are 20 constants,which have been included in the projection 21 computation.The current equation is: 22 PCA expense =1,023,185,930 23 -63,236,861 *(ln(runoff)) 24 +47,574,344 25 -9,074,032 SAID,DI 3IdahoPowerCompany 1 In this formula,the value $1,023,185,930 - 2 63,236,861 *(in(runoff))is the forecast of annual net 3 power supply expenses (fuel plus non-QF purchased power 4 minus surplus sales).The value $47,574,344 is a constant 5 for normalized QF purchased power expenses as established in 6 order No.27997 issued April 7,1999.The value $9,074,032 7 is the constant representing the market value of power 8 assumed to be acquired by Idaho Power Company for Astaris 9 second block loads.This amount,$9,074,032 is an exact 10 offset to the estimated cost of acquiring the power for 11 Astaris second block loads that is implicitly embedded as 12 non-QF purchased power within the annual power supply 13 expense projection.Although Idaho Power no longer provides 14 power for Astaris second block loads,it is still 15 appropriate for PCA projection purposes to assume that Idaho 16 Power will receive market value revenues of $9,074,032 to 17 offset the assumed $9,074,032 of non-QF purchased power. 18 Therefore,the projection computation remains the same as 19 last year. 20 Q.What is the April through July Brownlee 21 runoff forecast that you used to arrive at the projection of 22 PCA expenses? 23 A.The National Weather Service River Forecast 24 center,in its April 1 forecast,projected April through 25 July Brownlee runoff to be 3.630 million acre feet. SAID,DI 4IdahoPowerCompany 1 Inserting this value into the equation results in a 2 projection of net PCA expenses of $106,509,695 for the 3 period April 1,2002 through March 31,2003.This amount is 4 $33,430,567 more than the normalized level of PCA expenses 5 of $73,079,128. 6 The Brownlee runoff information supplied by 7 the National Weather Service is contained on Exhibit 2.The 8 Brownlee Reservoir inflow appears on page 2,line 6 of 9 Exhibit 2. 10 Q.You have stated that the projected net PCA 11 expenses are more than the normalized level of PCA expenses 12 by $33,430,567.What is the rate adjustment associated with 13 the projected increase in PCA expenses of $33,430,567 from 14 the normalized level of PCA expenses? 15 A.The normalized PCA expense of $73,079,128, 16 divided by the normalized system firm load of 13,952,283 17 MWHs is used to arrive at the normalized Base Power Cost of 18 0.5238 cents per kilowatt-hour.For the period April 1, 19 2002 through March 31,2003,the projected power cost of 20 serving firm loads is 0.7634 cents per kilowatt-hour which 21 is computed by dividing the projected PCA expense of 22 $106,509,695 by the 13,952,283 MWEs normalized system firm 23 load.The Company adjusts its rates by 90 percent of the 24 difference between the projected power cost of serving firm 25 loads (0.7634 cents per kilowatt-hour)and the normalized SAID,DI 5 Idaho Power Company 1 base power cost (0.5238 cents per kilowatt-hour.)Restated, 2 this year's computation is (.9)(O.7634-0.5238)=0.2156 cents 3 per kilowatt-hour.The resulting adjustment is a 0.2156 4 cents per kilowatt-hour increase from the Base Power Cost. 5 Q.Please describe the true-up required based 6 upon the comparison of the March 1,2001 through March 31, 7 2002 actual results to last year's projections. 8 A.In Order No.28722,the Commission granted 9 approval of the early implementation of a partial amount of 10 the 2001/2002 PCA based upon true-up values through February 11 2001.March 2001 was left to be included in this year's 12 computation of the true-up making this year's true-up based 13 upon the 13-month period March 2001 through March 2002. 14 The Power Cost Adjustment true-up deferral 15 for the 13-month period of March 1,2001 through March 31, 16 2002 is shown on Exhibit 3.This sheet compares the actual 17 results to last year's projections,month by month,with the 18 differences accumulated in a deferred expense account. 19 Interest has been applied to the deferred expense account 20 monthly.The balance in the deferred expense account at the 21 end of March 2002 was $227,593,363 as shown on page 2,line 22 83 of Exhibit 3.This is the amount that was under- 23 collected during the PCA year.Under standard practice,the 24 deferral would be amortized during the May 16,2002 through 25 May 15,2003 period. SAID,DI 6 Idaho Power Company 1 Q.Did Mr.Gale instruct·you to make an 2 adjustment to the booked true-up value of $227,593,363? 3 A.Yes.Mr.Gale instructed me to reduce the 4 booked true-up balance by $4,306,636.This amount is shown 5 on page 2,line 85,of Exhibit 3.Mr.Gale will discuss his 6 rationale for this adjustment in his testimony.When the 7 $227,593,363 is reduced by $4,306,636,the resulting true-up 8 value is $223,286,727. 9 Q.How is the adjusted true-up expense of 10 $223,286,727 reflected in the true-up portion of the PCA 11 rate? 12 A.In accordance with Order No.26455 from Case 13 No.IPC-E-96-5,the true-up rate component would be 14 calculated by dividing the adjusted deferred expense balance 15 of $223,286,727 by the 1993 normalized Idaho jurisdictional 16 firm sales of 10,802,636 MWHs.Due to the magnitude of last 17 year's true-up component,the Commission in Order No.28722 18 authorized the use of a more current normalized Idaho 19 jurisdictional firm sales volume for calculating the true-up 20 portion of the PCA rate.This year's true-up portion of the 21 PcA is also large.Therefore,the company proposes to again 22 use a more current normalized Idaho jurisdictional firm 23 sales value for this year's true-up rate component.The 24 Company recommends the use of 2000 normalized Idaho 25 jurisdictional firm sales.The use of the 2000 normalized SAID,DI 7 Idaho Power Company 1 Idaho jurisdictional firm sales number would result in the 2 following calculation for the true-up portion of the rate: 3 $223,286,727 (adjusted deferred expense account balance)÷ 4 13,209,552 (normalized Idaho jurisdictional firm sales for 5 2000 in MWHs)=1.6903 cents per kilowatt-hour. 6 Q.In addition to the projected power cost 7 component and the true-up component is there a third 8 component to PCA rate determinations for this year. 9 A.Yes.This year there is a residual PCA 10 component of 0.3826 cents per kilowatt-hour,which is the 11 incremental PCA rate that was deferred in April of 2001 and 12 later approved in September of 2001.This residual PCA rate 13 component remains in effect through September 30,2002. 14 Q.What is the PCA rate that would become 15 effective May 16,2002 as a result of (1)the adjustment for 16 the 2002/2003 projected power cost of serving firm loads, 17 (2)the 2001/2002 true-up portion of the PCA and (3)the 18 residual PCA component that remains in effect through 19 september 2002? 20 A.The company's PCA rate for May 16,2002 21 through September 30,2002 would be 2.2885 cents per 22 kilowatt-hour.The rate is comprised of (1)the 0.2156 23 cents per kilowatt-hour adjustment for 2002/2003 projected 24 power cost of serving firm loads,(2)the adjustment of 25 1.6903 cents per kilowatt-hour for the 2001/2002 13-month SAID,DI 8 Idaho Power Company 1 true-up portion of the PCA and (3)the 0.3826 cents per 2 kilowatt-hour residual PCA component that ceases on 3 october 1,2002.On October 1,2002,the Company's PCA rate 4 would become 1.9059 cents per kilowatt-hour for the period 5 october 1,2002 though May 15,2003 as a result of the 6 ending of the residual PCA component. 7 The components used to calculate the 2.2885 8 cents per kilowatt-hour for the period May 16,2002 through 9 September 30,2002,are shown in the Company's potential 10 schedule 55 for the period May 16,2002 through 11 September 30,2002,that is Exhibit 4. 12 Q.How does the May 16,2002 through 13 September 30,2002 PCA rate of 2.2885 cents per kilowatt- 14 hour compare to the 2001/2002 PCA rate? 15 A.The 2002/2003 PCA rate of 2.2885 cents per 16 kilowatt-hour is a 0.5644 cents per kilowatt-hour increase 17 from the 1.7241 cents per kilowatt-hour rate presently in 18 effect.Of the 0.5644 cents per kilowatt-hour increase, 19 0.3826 cents per kilowatt-hour would cease on October 1, 20 2002.Exhibit 5 is the potential tariff schedule that would 21 become effective from October 1,2002 through May 15,2003. 22 Q.What would be the percentage increase to 23 customer rates on May 16,2002,if the Commission approved 24 the PCA rate of 2.2885 cents per kilowatt-hour? 25 A.The average percentage increase over all SAID,DI 9 Idaho Power Company 1 customer classes would be 10.1 percent on May 16,2002.A 2 percentage decrease of 6.2 percent would later occur on 3 October 1,2002. 4 Q.Is the Company's recommendation a rate 5 increase of 10.1 percent resulting from a PCA rate of 2.2885 6 cents per kilowatt-hour based upon traditional PCA 7 computation methodology? 8 A.No.Mr.Gale will provide testimony 9 addressing the Company's primary proposal to remove a 10 portion of PCA true-up amounts related to voluntary load 11 reduction programs for separate funding via the issuance of 12 bonds.The Company's primary proposal as described by Mr. 13 Gale would result in a rate decrease of 6.6 percent on 14 May 16,2002 rather than a rate increase of 10.1 percent 15 that would result from standard PCA treatment. 16 My computation of a PCA rate of 2.2885 cents 17 per kilowatt-hour is provided as information for the 18 Commission.If the Company's primary proposal as detailed 19 by Mr.Gale were rejected,then the Company would expect 20 traditional PCA treatment (the Company's secondary proposal) 21 resulting in the PCA rate of 2.2885 cents per kilowatt-hour. 22 Q.of the true-up balance,how much is related 23 to the voluntary load reduction programs for Astaris and 24 irrigation customers? 25 A.The portion of the true-up balance SAID,DI 10 Idaho Power Company 1 attributable to the Astaris voluntary load reduction is 2 $76,253,930.The portion of the true-up balance 3 attributable to voluntary irrigation load reduction is 4 $70,610,462. 5 Q.Were the deferrals associated with the two 6 voluntary load reduction programs determined in an identical 7 manner? 8 A.No.The Astaris amount is equal to 90 percent 9 (sharing)of the Idaho jurisdictional portion (85 percent) 10 of the direct payments to Astaris for voluntary load 11 reduction.The Irrigation amount is also equal to 90 12 percent (sharing)of the Idaho jurisdictional portion (85 13 percent)of direct payments to irrigation customers,but 14 also includes 90 percent of the Idaho jurisdictional portion 15 of reduced irrigation revenues resulting from voluntary load 16 reductions.The reduced irrigation revenues are an 17 additional cost of the Irrigation class voluntary load 18 reduction program.The cost of the Astaris voluntary load 19 reduction does not include reduced revenues due to the take 20 or pay provisions of the Astaris contract. 21 Q.Does this conclude your testimony? 22 A.Yes,it does. SAID,DI 11 Idaho Power Company BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION Case No.IPC-E-02-3 Idaho Power Company Schedule 55 Power Cost Adjustment Effective 10-01-02 Exhibit No.5 G.Said ¡DAHO POWER COMPANY EVENTH REVISED SHEET NO.55-1 CANCELS l.P.U.C.NO.26,TARIFF NO.101 TENTH REVISED SHEET NO.55-1 SCHEDULE 55 POWER COST ADJUSTMENT APPUCABlUTY This schedule is applicoble to the electric energy delivered to all Idaho retail Customers served under the Company's schedules,to the primary portion of the FMC Special Contract,and to all otherIdahoretailSpecialContracts.These loads are referred to as "firm"load for purposes of this schedule. BASE POWER COST The Base Power Cost of the Company's rates is computed by dividing the Company's powercostcomponentsbyfirmkWhload.The power cost components are the sum of fuel expense andpurchasedpowerexpense(including purchases from cogeneration and small power producers),lessthesumofoff-system surplus sales revenue and FMC secondary load revenue.The Base Power Cost is0.5238 cents per kWh. PROJECTED POWER COST The Projected Power Cost is the Company estimate,expressed in cents per kWh,of the powercostcomponentsfortheforecastedtimeperiodbeginningApril1eachyearandendingthefollowingMarch31.The Projected Power Cost is 0.7634 cents per kWh. E-UP The True-up is based upon the difference between the previous Projected Power Cost and thepowercostsactuallyincurred.The True-up is 1.6903 cents per kWh. POWER COST ADJUSTMENT The Power Cost Adjustment is 90 percent of the difference between the Projected Power CostandtheBasePowerCostRIystheTrue-up. The monthly Power Cost Adjustment applied to the Energy rate of metered schedules andSpecialContractsis1.9059 cents per kWh.The monthly Power Cost Adjustment applied to the per unitchargesofthenonmeteredschedulesisthemonthlyestimatedusagetimes1.9059cents per kWh. EXPIRATION 'The Power Cost Adjustment included on this schedule will expire May 15,2003. Exhibit No.5 Case No.IPC-E-02-3 G.Said,IPCo-Dir Page 1 of 1 IDAHO Issued by IDAHO POWER COMPANYIssued-April 15.2002 John R.Gale,Vice President,Regulatory AffairsEffective-October 1,2002 1221 West Idaho Street,Boise,Idaho BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION Case No.IPC-E-02-3 Idaho Power Company Schedule 55 Power Cost Adjustment Effective 5-16-02 thru 9-30-02 Exhibit No.4 G.Said IDAHO POWER COMPANY TENTH REVISED SHEET NO.55-1 CANCELS l.P.U.C.NO.26,TARIFF NO.101 ...NINTH REVISED SHEET NO.55-1 SCHEDULE 55 POWER COST ADJUSTMENT APPLICABILITY This schedule is applicable to the electric energy delivered to all Idaho retail Customers servedundertheCompany's schedules,to the primary portion of the FMC Special Contract,and to all otheridahoretailSpecialContracts.These loads are referred to os "firm"load for purposes of this schedule. BASE POWER COST The Base Power Cost of the Company's rates is computed by dividing the Company's powercostcomponentsbyfirmkWhload.The power cost components are the sum of fuel expense andpurchasedpowerexpense(including purchases from cogeneration and small power producers),lessthesumofoff-system surplus sales revenue and FMC secondary load revenue.The Base Power Cost is0.5238 cents per kWh. PROJECTED POWER COST The Projected Power Cost is the Company estimate,expressed in cents per kWh,of the powercostcomponentsfortheforecastedtimeperiodbeginningApril1eachyearandendingthefollowingMarch31.The Projected Power Cost is 0.07634 cents per kWh. JE-UP The True-up is based upon the difference between the previous Projected Power Cost and thepowercostsactuallyincurred.The True-up is 2.0729 cents per kWh. POWER COST ADJUSTMENT The Power Cost Adjustment is 90 percent of the difference between the Projected Power CostandtheBasePowerCostRIystheTrue-up. The monthly Power Cost Adjustment applied to the Energy rate of metered schedules andSpecialContractsis2.2885 cents per kWh.The monthlyPower Cost Adjustment applied to the per unitchargesofthenonmeteredschedulesisthemonthlyestimatedusagetimes2.2885 cents per kWh. EXPIRATION *The Power Cost Adjustment included on this schedule will expire September 30,2002. Exhibit No.4 Case No.IPC-E-02-3 G.Said,IPCo-Dir Page 1 of 1 IDAHO Issued by IDAHO POWER COMPANYIssued-April 15,2002 John R.Gale,Vice President,Regulatory AffairsEffective-May 16,2002 1221 West Idaho Street,Boise,Idaho BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION Case No.IPC-E-02-3 Idaho Power Company True-up Deferral Exhibit No.3 G.Said Po w e r Co s i Ag u s t m e n t Su m m a r y Ma r c h 20 0 1 th r u Ma t t e 20 0 2 Mit t l i t Ap d f Ma x diin e Jti l y Au g u s 1 Sa o l a t u h a t Orl o b e r No v e m b a t De c e m b e r da t t u a r y En i x u a r y Ma r c t i In t a l s PC A An v e n u e No r m a i z e d R i m i n a d 1,1 0 6 0 8 0 99 1 . 1 7 6 10 3 3 . 1 1 7 1.1 4 3 . 5 4 5 13 5 2 2 1 9 0 0 1,4 2 2 2 6 3 1.2 0 6 7 9 9 1tt 2 , 3 9 8 1.0 3 0 , 8 3 5 1, 1 6 2 5 4 5 12 2 9 0 8 3 11 8 2 2 2 3 ft0 6 0 8 0 †5 . 0 5 8 , 3 6 3 0 0 PC A C o m p o n e n t R a t e 18 3 2 18 3 2 38 6 1 38 6 1 36 8 1 38 6 1 38 6 1 38 6 1 38 6 1 38 6 1 38 8 1 38 6 f 30 4 1 Ae v e n u e e l B 5 % 1,7 2 2 3 8 8 1.5 4 3 , 4 5 9 33 9 0 . 5 3 5 3.7 5 2 , 9 4 3 44 3 7 7 7 9 9 3 4,8 6 7 6 5 A 3.9 6 0 5 3 3 36 5 0 , 7 2 3 3.3 8 3 , 0 4 6 3,8 1 5 2 9 8 40 3 3 6 6 6 38 1 4 2 4 2 36 2 9 9 9 9 45 . 8 0 2 , 2 5 6 0 5 Lo a d Œa n g e Ad j u s t m e n i Ac t u a l Fir m la a d Ag u s t e d Mw h 1.1 4 4 14 0 1.0 9 9 M 2 1 27 0 . 2 2 3 1,4 4 1 . 4 7 3 1 505 74 7 00 1.5 2 2 447 1.1 8 5 500 † 12 5 , 1 7 4 1.1 2 8 73 3 1.3 6 6 44 7 1 334 81 4 1 16 0 . 7 4 6 1 16 7 07 9 16 , 4 5 8 . 2 0 5 0 0 No r m a l i z e d F i r m L o a d Ma n 1,1 0 6 0 0 0 99 1 . 1 7 e 10 3 3 . 1 1 7 1.1 4 3 . 5 4 5 13 5 2 2 1 9 0 0 1.4 2 2 2 6 3 9.2 0 6 , 7 9 9 1.1 1 2 . 3 9 8 1.0 3 0 8 3 5 1.1 6 2 5 4 5 12 2 9 0 8 3 11 6 2 . 2 2 3 11 0 6 0 8 0 15 . 0 5 8 . 3 8 3 0 0 Lo a d Ch a n g e Mw h 35 050 10 8 . 5 0 0 23 7 . 1 0 6 29 7 . 9 2 8 15 6 52 8 00 10 0 184 (2 1 . 2 9 9 ) 15 . 7 7 6 97 89 0 203 90 2 10 5 73 1 (1 . 4 7 7 ) 60 99 9 1.3 9 9 . 8 4 2 00 Ex p e n s e hju n i m e n t (O lo 04 ) (6 4 0 930 ) (2 . 3 2 3 . 9 3 0 ) (3 99 2 , 8 6 5 ) (5 , 0 1 7 . 1 0 0 ) (2 83 5 931 52) (1 . 8 8 7 099 ) 35 5 67 5 (26 5 66 5 ) (1 , 5 4 8 60 2 ) (3 , 4 3 3 71 0 ) (1 78 0 51 0 ) 24 . 8 7 3 (1 02 7 223 ) (2 4 . 0 7 0 , 0 2 7 92) Ac t u a l No n O F PC A Ex p e n s e Ad j u s e n e n t S 44 0 9 3 0 4 23 2 3 9 2 9 sa 39 9 2 8 6 5 0 4 50 1 7 1 0 7 52 26 3 5 9 3 1 52 168 7 0 9 8 56 35 8 6 7 5 16 26 5 6 6 7 84 18 4 8 6 0 2 32 34 3 3 7 0 9 68 17 8 0 5 1 0 04 24 8 7 2 68 10 2 7 2 2 3 10 -2 4 0 7 0 0 2 7 92 Pu r c h a s e d Wa t e r $ 0 0 0 0 0 00 0 o o O O O O 0 0 00 Pm g r a m e Co s t S O 7 53 7 . 7 0 6 15 85 0 . 0 3 7 18 , 9 1 0 , 5 7 5 27 74 4 29 8 13 35 . 3 1 4 , 9 6 0 25 , 1 3 6 73 7 19 . 9 9 1 . 4 8 1 4.6 3 5 83 9 13, 7 5 1 07 2 e 35 8 , 4 8 3 5 31 4 . 5 4 3 5 35 2 48 9 18 5 , 9 3 t , 1 2 3 18 Mo t s e Ge n o r m i k m Co s t a $ 0 0 1.1 4 7 , 7 7 3 25 . 6 9 5 1.1 9 4 98 8 05 76 0 . 1 8 0 1,3 9 4 . 4 3 2 72 4 , 2 2 8 25 9 0 9 8 (1 4 02 9 ) 0 0 0 5.4 9 1 54 3 1 t Fu e l Ex p o n e s t o e l 5 7.9 8 1 848 e 44 9 , 3 0 2 7,0 8 5 . 4 9 4 8.8 5 2 . 8 1 8 8 318 03 2 28 8.4 8 3 . 9 4 3 e,7 8 5 18 7 7 85 1 , 3 5 4 80 3 4 97 4 5,2 2 6 471 9 87 0 . 7 6 8 8.8 8 5 . 9 1 9 8 97 0 . 7 3 0 10 5 , 3 6 5 81 7 30 Fu e l Ex p o n e e d n a $ 0 0 0 0 23 8 00 0 00 24 4 , 4 0 0 25 5 . 4 0 6 28 8 85 0 49 4 88 0 784 01 3 29 7 , 4 8 4 28 8 , 6 4 8 46 7 . 1 6 3 3,3 3 7 553 12 No n - F i r m P u r c i t a a e s $ 23 . 7 9 7 9 9 3 27 5 3 1 , 8 1 4 39 5 4 4 , 1 5 1 53 . 0 4 2 . 1 7 7 55 . 0 1 3 7 8 1 2 9 45 . 3 1 7 , 0 5 7 34 , 2 7 0 . 5 0 7 1,1 5 8 . 0 0 1 5.6 2 8 0 8 0 8.0 1 4 9 1 7 83 8 7 , 4 7 1 1.2 7 9 . 8 4 1 18 8 4 . 3 2 7 30 4 . 8 5 1 0 0 6 0 1 Qu a n d n e d Pa r r c t i s s e im m BP A $ 0 0 0 0 0 00 0 0 1,1 4 8 . 5 4 6 0 0 0 0 0 1,1 4 8 54 6 00 Sh i g i u s S a l e s S (3 7 , 2 9 5 2 2 4 ) (3 2 4 7 1 . 7 1 0 ) (1 5 . 0 5 2 , 3 4 4 ) (5 , 4 5 4 . 5 0 0 ) (2 9 , 5 8 1 1 4 7 8 7 ) (3 1 , 1 5 1 , 8 7 3 ) (2 5 , 0 7 5 . 6 5 4 (3 , 8 5 8 . 6 5 4 ) (4 . 3 7 5 3 1 7 ) (3 , 0 1 0 6 4 0 ) (8 0 5 9 . 1 5 3 ) (1 , 5 2 5 , 4 6 3 ) (7 3 6 6 . 6 7 2 ) (2 0 5 . 9 2 1 1 9 1 0 8 ) FM C 2h d GIk En g y Cm d t y Pri c a Ord y 3 0 0 0 0 0 00 0 0 0 0 0 0 0 0 0 00 fo l a l N o F I $ (0 , 1 5 9 , 3 1 3 1 5 1 8.7 2 3 . 1 8 2 7 4 44 , 0 1 2 . 2 4 8 4 8 89 . 3 2 8 . 7 8 0 3 4 81 , 2 8 4 8 7 8 9 5 57 , 2 6 1 , 7 8 8 4 8 43 1 0 ð , 2 4 0 0 5 26 . 8 4 1 0 6 6 2 6 13 . 0 2 9 , 8 3 9 2 5 24 . 2 9 7 . 8 9 3 9 2 15 , 0 7 4 , 5 0 3 3 5 14 , 0 6 6 , 4 5 9 1 7 8,2 8 4 , 8 1 3 8 5 37 7 , 1 3 4 3 6 9 7 0 BA S E Fu e l Em p a n a s S 4,7 3 7 . 0 0 0 3 34 1 . 0 0 0 2.2 9 3 , 0 0 0 2.8 4 3 . 0 0 0 5.0 7 6 00 0 00 8.4 4 5 00 0 5 557 00 0 6,0 2 6 . 0 0 0 8 90 9 , 0 0 0 7,1 2 7 . 0 0 0 6.0 5 1 . 0 0 0 5.0 5 1 . 0 0 0 4.7 3 7 , 0 0 0 68 . 2 2 3 . 0 0 0 00 Nm - F i m b P a r r e h n e e s $ 29 8 , 0 0 0 33 8 , 0 0 0 1,3 5 6 , 0 0 0 1,8 7 2 , 0 0 0 2.4 7 3 0 0 0 0 0 1,2 5 2 , 0 0 0 81 5 . 0 0 0 16 2 , 0 0 0 34 5 , 0 0 0 84 4 , 0 0 0 07 9 , 0 0 0 64 2 . 0 0 0 29 5 . 0 0 0 11 . 3 7 1 . 0 0 0 0 0 Su r p l u s Sa l e s 5 (2 . 7 4 2 , 0 0 0 00 ) (3 . 1 9 5 0 0 0 00 ) (5 9 7 . 0 0 0 00 ) (2 0 5 . 0 0 0 00 ) (1 4 2 00 0 00 ) (5 0 5 , 0 0 0 00) (1 . 5 7 0 . 0 0 0 00 ) (3 . 0 2 2 . 0 0 0 00 ) (3 . 8 8 3 0 0 0 00 ) (2 . 8 0 9 oo o oo) (2 , 9 7 8 . 0 0 0 00 (2 . 7 8 i 00 0 00 ) (2 . 7 4 2 00 0 00 ) (2 7 . 2 6 4 , 0 0 0 00) FM G 2n d Bik En g y 4 md r y Pa c e On l y 3 (8 8 9 . 4 1 5 62 ) (8 2 8 . 0 6 2 77 ) (0 7 9 . 6 5 3 11) (6 9 3 . 1 5 0 51) (5 0 0 808 00 ) (7 4 5 , 1 4 1 451 (6 4 4 . 2 4 5 0 1 ) (7 4 2 . 2 3 9 54 ) (8 2 5 . 5 3 9 88 ) (7 3 9 128 10 ) (7 9 9 . 2 8 6 67 ) (7 0 9 107 02 ) (5 8 9 47 5 82 ) 18 . 9 8 3 . 5 1 3 40 ) Ne l 9 0 % Ite i n e 5 1.4 0 1 , 5 2 4 38 (3 4 1 . 0 8 2 77 j 2.0 7 2 , 3 1 6 89 3,8 1 3 , 8 4 9 49 8 806 19 2 00 6,3 5 8 , 8 5 8 55 3,9 8 7 , 7 5 4 99 2,4 2 3 . 7 6 0 18 2.7 4 5 , 3 5 0 32 4.4 2 2 87 1 90 3 15 2 . 7 3 3 33 2 14 2 50 2 90 1.4 0 1 52 4 38 40 35 8 , 4 8 5 60 an g e F r o m B a s e S (7 , 5 0 0 , 8 3 7 5 3 ) 70 8 4 . 2 4 5 5 1 41 . 9 3 9 . 9 2 9 5 7 65 . 5 1 4 . 9 1 0 8 5 54 . 4 7 8 6 8 6 9 5 50 . 9 0 4 . 9 2 9 9 3 39 , 1 4 0 . 4 8 5 0 6 24 , 4 1 7 . 3 0 8 1 0 10 , 2 8 4 , 4 7 8 9 3 19 , 8 7 5 0 2 2 0 2 11 9 2 t , 7 7 0 0 2 1\9 2 3 6 5 6 1 9 58 6 3 2 8 9 4 7 33 8 7 8 7 . 8 5 3 1 0 Sh a r i n g Pe r c a n i n g e 90 % 90 % 90 % 90 % 90 % 90 % 90 % 90 % 90 % 90 % 9D % 90 % 90 % id s h o A l l o c a t i o n 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % Þk m 4 F De l e n a i $ (5 . 7 5 4 , 0 4 0 71 ) 5. 4 0 4 , 1 4 7 82 32 . 0 8 4 . 0 4 8 12 50 , i ! 8 . 9 1 2 92 41 . 8 7 6 19 5 54 35 , 9 4 2 . 2 7 1 39 29 , 9 4 2 . 4 7 1 07 18 . 8 7 9 . 2 4 0 70 7, 8 6 7 , 6 2 6 38 15 . 2 0 4 . 3 9 1 85 9 12 0 15 4 06 9 121 59 6 98 5 25 0 . 4 1 0 45 257 82 7 , 4 3 0 57 Ac t u a l OF (In c e u d e . Ma r k i a n Am o r t i $ 3.3 0 6 67 9 4 02 5 . 3 6 5 5. 2 4 5 . 9 8 9 2.9 1 3 . 6 3 0 5,7 5 7 56 3 41 5 48 0 579 4,3 4 2 . 4 6 5 3.1 6 0 42 6 2. 3 9 6 . 4 6 4 2,5 4 0 238 2.8 4 9 . 4 4 2 2.3 5 7 . 4 1 4 2 33 4 . 2 1 8 48 54 1 , 4 4 9 28 Ba s s Q F 3 f.3 1 4 4 4 5 20 3 8 . 2 6 5 3. 0 2 4 , 7 3 5 5,1 0 8 , 3 2 5 5.3 1 7 4 7 5 0 0 50 5 9 7 5 5 3, 5 3 1 . 2 9 5 2,4 3 8 4 2 5 1.5 3 9 . 0 9 5 1,7 1 3 5 8 5 1. 5 8 7 , 8 4 5 1.4 5 9 , 7 8 5 13 1 4 , 4 4 5 35 4 2 8 . 6 0 5 0 0 Dia n g s F r o m B a s e $ 19 9 2 2 3 4 19 8 8 , 1 0 0 2.2 2 1 , 2 3 4 (2 , 1 9 4 , 6 9 5 ) 47 0 0 8 8 4 1 42 0 7 9 4 81 1 , 1 7 0 72 2 0 0 1 55 6 , 5 6 9 82 6 3 5 1 1,0 8 1 , 5 9 7 89 7 . 6 2 9 10 1 9 , 7 7 3 11 1 1 2 , 8 4 4 2 8 Ou a n t i f i e d Be n e n t f r a m e P A $ 0 0 0 0 00 0 o o 95 0 4 9 (1 2 8 , s o n g o o o o (3 3 . 5 5 5 0 0 ) To t a l N o n - s h a r e d D e f e n a l $ 19 9 2 2 3 4 19 8 8 . 1 0 0 2.2 2 1 . 2 3 4 (2 . 1 9 4 , 6 9 5 ) 47 0 0 8 8 4 ? 42 0 7 9 4 81 1 . 1 7 0 81 7 0 5 0 72 7 . 9 8 5 82 6 3 5 1 ?,0 8 1 5 9 7 89 7 , 6 2 9 10 1 9 , 7 7 3 11 0 7 9 . 2 8 9 2 8 Sh a r i n g Pe r c o n i n g e 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % 10 0 % Id a h o A l l o c a l l o n 85 0 % 85 0 ¾ BS D % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % 85 0 % OF D e l e w a l $ 18 9 3 . 3 9 9 18 8 9 8 8 5 1, 8 8 8 . 0 4 9 (1 8 6 5 , 4 9 1 ) 39 9 5 7 5 1 5 35 7 , 6 7 5 68 9 , 4 9 4 69 4 4 9 3 81 6 , 7 7 0 70 2 3 9 8 91 9 . 3 5 7 78 2 , 9 5 5 86 8 . 0 0 7 94 1 7 , 3 9 5 0 9 Mo t i l e Ho m e Me t e r i n g Cos t e 5 0 0 0 0 19 83 7 71 10 . 4 5 0 10 . 1 8 4 6 841 8 84 1 11 68 5 14 , 3 5 3 12 , 9 0 9 12 , 8 4 9 10 6 . 5 2 8 87 in t e r v e n o r Fu n d i n g $ 0 0 0 0 9 66 1 84 20 . 1 3 4 0 0 0 0 0 0 0 29 . 7 9 8 03 Cre ( 5 1 Fro m iD A C O R P En e r g y S O O O O (16 8 66 8 87) (1 6 6 . 6 8 7 ) (1 6 4 . 6 6 7 ) (16 6 66 7 ) (1 6 6 . 6 6 7 ) (16 6 667 ) (1 8 8 . 6 6 7 ) (1 6 8 . 6 ô 7 ) (1 8 6 , 6 6 7 ) (1 500 00 0 03 ) To t a t Da t e n a i $ (5 , 8 93 02 9 65 ) 5,5 5 0 , 5 7 3 45 30 , 5 8 1.5 6 0 23 44 , 5 0 0 . 4 7 8 65 37 , 4 9 9 62 3 64 34 , 4 9 6 20 9 85 28 . 5 1 4 94 9 13 15 , 5 8 2 . 9 8 3 04 4 94 5 , 5 2 4 80 11 , 9 3 6 . 4 9 0 59 5 85 3 , 5 3 1 48 5 91 8 , 5 8 2 60 2 33 3 . 4 1 5 60 21 9 87 8 , 8 9 5 28 Pri n c i p u i Ba l a n œ s Be g i n n i n g B a l a n æ $ 00 0 (5 . 8 1 3 0 2 9 8 5 ) (2 6 2 , 4 5 6 2 1 ) 30 . 3 1 9 1 0 4 0 2 74 . 8 1 9 5 8 2 8 8 11 2 . 3 1 9 , 2 0 8 3 2 14 8 , 8 1 5 , 4 1 8 1 7 17 3 3 3 0 3 8 5 3 0 18 8 . 8 9 3 . 3 4 9 1 4 19 3 . 8 3 5 . 8 7 3 9 4 20 5 . 7 7 5 3 8 4 5 3 21 1 6 2 8 8 9 8 0 0 21 7 . 5 4 5 , 4 7 8 6 7 00 0 Am a u n t Da t e n e d 5 (5 , 0 1 3 , 0 2 9 65) 5.5 5 0 57 3 45 30 . 5 5 1 . 5 6 0 23 44 , 5 0 0 47 5 65 37 . 4 9 9 623 64 34 . 4 9 5 , 2 0 9 85 26 . 5 1 4 , 9 4 9 13 15 58 2 983 84 4.9 4 5 . 5 2 4 so 11 . 9 3 6 , 4 9 0 59 5,5 5 3 531 46 5 91 6 582 88 2.3 3 3 , 4 1 6 00 21 9 878 89 5 28 En d n g B a l a n a 5 (5 , 5 1 3 . 0 2 9 6 5 ) (2 6 2 4 5 6 2 1 ) 30 . 3 1 9 . 1 0 4 0 2 74 . 8 1 9 5 8 2 8 8 11 2 . 3 1 9 2 0 8 3 2 14 8 , 8 1 5 . 4 1 8 1 7 17 3 . 3 3 0 . 3 6 5 3 0 10 8 8 9 3 3 4 9 1 4 19 3 , 8 3 8 . 8 7 3 9 4 20 5 . 7 7 5 . 3 6 4 5 3 21 f . 8 2 8 8 9 6 o o 21 7 5 4 5 4 7 6 6 7 21 9 . 5 7 8 . 8 9 5 2 e in t e r e s t Ba l a n c e s Ac c r u a l th r u Pri o r Mo n i h 5 0 00 0 00 (4 2 . 8 2 6 42 ) (3 6 . 8 2 4 61 | 11 4 . 7 7 0 91 47 8 92 8 60 1.0 2 9 . 3 5 1 92 1,7 8 3 . 5 1 3 64 2.6 2 2 . 4 1 5 47 3.5 7 4 , 5 2 6 58 4,4 5 2 83 0 45 5 56 6 . 1 2 1 57 8,6 2 6 . 5 3 5 t 1 Mo n i h l y In t e r e s t Ra l e " 0 00 % 0 00 % 6 00 % 6 00 % 5 00 % 0 00 % 6 00 % 5 00 % 6 00 % e 00 % 5 00 % 6 00 ¾ 6 00 % Mo n i h t y in t e r e s t in c t ( E x Þ ) 5 00 0 (2 9 0 6 5 15 ) (1 . 3 1 2 28 ) 15 1 . 5 9 5 52 37 4 , 0 9 7 91 56 1 59 8 03 73 4 07 7 08 86 6 . 6 5 1 83 94 4 . 4 6 6 75 96 9 . 1 9 4 37 1,0 2 5 87 6 82 1,0 5 8 . 1 4 4 48 f.0 8 7 , 7 2 7 39 7 14 6 . 0 5 0 75 Pel o r Mo n i h e In t e r e a l Arg u s t m n t s 5 0 00 (1 3 58 1 27) 7. 1 1 4 09 0 00 (9 . 0 4 0 22 ) (1 1 17 2 72 ) 18 4 64 (7 , 0 4 8 99 ) 7,6 4 1 36 (9 1 , 0 9 0 50 84 61 4 30 2.2 6 9 06 20 4 94 (3 1 . 5 8 3 31 ) To t a l Cu r r e n t Mo n t h In t e r e s t 5 0 00 (42 626 42 ) 5.0 0 1 81 15 1 . 5 9 5 52 36 4 . 1 5 7 89 55 0 423 31 73 4 28 1 72 85 8 . 5 0 4 84 95 2 . 1 0 5 11 87 8 , 1 0 3 87 1,i 1 3 491 12 1,0 6 0 41 3 54 1,0 8 7 . 9 3 2 33 7 71 4 . 4 8 7 44 In t e r e e t Ac c r u e d t o da t e 5 00 0 (42 52 5 42 ) (3 6 . 8 2 4 81) 11 4 . 7 7 0 91 47 8 928 50 1.0 2 9 351 92 1.7 8 3 4 1 3 64 2.6 2 2 . 4 1 8 47 3.5 1 4 , 5 2 6 58 4.4 5 2 . 6 3 0 45 5,5 6 6 12 1 57 5,6 2 6 535 14 7.7 1 4 , 4 6 7 44 Ba l a n c e in Al Ac r o u n t s $ (5 . 8 1 3 , 0 2 9 85) (3 0 5 052 63 ) 30 , 2 8 2 . 2 7 9 41 74 , 9 3 4 . 3 5 3 59 11 2 . 7 9 8 13 4 93 14 7 , 8 4 4 768 09 17 5 . 0 9 3 97 8 94 19 1 , 5 1 5 . 7 8 7 67 19 7 4t 3 , 4 0 0 52 21 0 . 2 2 7 , 9 9 4 98 21 7 , 1 9 5 01 7 57 22 4 , 1 7 2 013 79 22 7 , 5 9 1 . 3 6 2 72 227 59 3 . 3 6 2 72 Na g e l i v e am o u n t s ir w i c a l e be n e n i to th e ra t a p o y e r s Pd c i n g Arg u s t m e n t (4 10 6 . 6 3 5 82) (4 30 6 . 5 3 5 62 ) " In t e r e s t ra t e ch a n g e d per IP U C Or d e r 24 8 0 8 nn i n g ba l a n c e per IP U C Or d e r 28 3 5 8 Ba t a n c o in Art Ac c o u n i s Mth Pd c i n g Ad i t 22 1 2M , 7 2 7 223 2M 72 6 40 Ex h i b i t No . 3 Ca s e No . IP C - E - 0 2 - 0 3 G. Sa i d , IP C o - D i r Pa g e 1 of 1 BEFORE THEIDAHOPUBLICUTILITIESCOMMISSION Case No.IPC-E-02-3 Idaho Power Company National Weather ServiceApril1Forecast Exhibit No.2 G.Said Water Supply Forecast 2 3 FGUS66 KPTR 060110 4 ESPPDR 5 SEASONAL6WATERSUPPLYFORECASTS7ISSUEDBY8NATIONALWEATHERSERVICE9NORTHWESTRIVERFORECASTCENTER10PORTLANDOREGON11APR-02FINAL 1 W A TER SUPPLY FOREC A STS12 13 75%PREC FIRST HALF OF APR;NORMAL PREC REST OF WAY14 15 STREAM AND STATION PERIOD FORECAST %AVERAGE16COLUMBIARIVER17MICARESERVOIRINFLOW,BC FEB-SEP 12100.0 93 12960.18 APR-SEP 11700.0 94 12500.19 ARROW LAKES INFLOW FEB-SEP 24800.0 94 26460.20 APR-SEP 23700.0 94 25110.21 BIRCHBANK,BC (1)APR-SEP 41200.0 95 43500.22 GRAND COULEE,WA (1)JAN-JUL 61100.0 97 62900.23 APR-SEP 63400.0 99 63990.24 ROCK ISLAND DAM BLO,WA (1)APR-SEP 70100.0 101 69540.25 THE DALLES NR,OR (1)APR-SEP 92800.0 94 98650.26 JAN-JUL 96400.0 90 107300.27 APR-AUG 87800.0 94 93090.28 KOOTENAI RIVER29LIBBYRES INFLDW,MT (1)APR-SEP 6570.0 99 6638.KOOTENAY RIVER KOOTENAY LAKE INFLOW,BC APR-SEP 15600.0 95 16450.32 DUNCAN RIVER33DUNCANRESERVOIR INFLOW,BC FEB-SEP 2230.0 97 2305.34 APR-SEP 2170.0 97 2227.35 CLARK FORK36ST.REGIS,MT (1)APR-SEP 3730.0 95 3907.37 PEND OREILLE RIVER38PENDOREILLELAKE IN,ID (1)APR-SEP 13600.0 98 13910.39 S.F.FLATHEAD RIVER40HUNGRYHORSERES IN,MT (1)APR-SEP 2060.0 97 2124.41 FLATHEAD RIVER42FLATHEADLAKE INFLOW,MT (1)APR-SEP 6460.0 96 6713.43 COEUR D'ALENE RIVER44COEURD'ALENE LAKE IN,ID APR-SEP 3510.0 132 2650.45 SIMILKAMEEN RIVER46NIGHTHAWKNR,WA (1)APR-JUL 1310.0 97 1350.47 OKANAGAN RIVER48TONASKETNR,WA (1)APR-SEP 1670.0 95 1766.49 CHELAN RIVER50LAKECHELAN INFLOW,WA (1)APR-SEP 1290.0 109 1185.51 WENATCHEE RIVER52PESMASTIN,WA APR-SEP 1680.0 103 1635.53 YAKIMA RIVER54PARKERNR,WA APR-SEP 2190.0 114 1918.55 SKAGIT RIVER56CONCRETE NR,WA APR-SEP 6720.0 106 6365.57 COWLITZ RIVER58MAYFIELD RES INFLOW,WA APR-SEP 2060.0 107 1922.59 APR-JUL 1810.0 107 1689.JAN-JUL 3310.0 103 3217.CASTLE ROCK,WA APR-SEP 2670.0 101 2639. ExhibitNo.2CaseNo.IPC-E-02-3 G.Said,\PCo-DirPagelof3 SNAKE RIVER JACKSON LAKE INFLOW,WY (1)APR-JUL -680.0 83 815.3 PALISADES RES INFLOW,ID (1)APR-JUL 2530.0 76 3331.4 HEISE NR,ID APR-JUL 2670.0 75 3561.5 WEISER,ID (1)APR-JUL 3210.0 56 5765.6 BROWNLEE RES INFLOW APR-JUL 3630.0 58 6313.7 LOWER GRANITE RES IN,WA (1)JAN-JUL 24200.0 81 30020.8 APR-JUL 19200.0 89 21550.9 TETON RIVER 10 ST.ANTHONY NR,ID APR-JUL 335.0 83 403.11 HENRYS FORK 12 REXBURG NR,ID APR-JUL 995.0 64 1559.13 PORTNEUF RIVER14TOPAZ,ID APR-SEP 59.0 62 95.15 BIG LOST RIVER16MACKAYRESERVOIR INFLOW,ID APR-JUL 109.0 77 142.17 BIG WOOD RIVER18RAILEY,ID (1)APR-JUL 189.0 74 256.19 MAGIC RESERVOIR INFLOW,ID APR-JUL 182.0 63 291.20 LITTLE WOOD RIVER 21 CAREY NR,ID APR-JUL 62.0 71 87,22 OWYHEE RIVER23OWYHEERES INFLOW,OR MAR-JUL 610.0 100 613.24 BOISE RIVER25BOISENR,ID (1)APR-JUL 1210.0 86 1414.26 MALHEUR RIVER 27 DREWSEY NR,OR MAR-JUL 99.0 90 110.28 N.F.MALHEUR RIVER29BEULAHRESINFLOW,OR (1)MAR-JUL 78.0 96 81.30 PAYETTE RIVER HORSESHOE BEND NR,ID (1)APR-JUL 1470.0 91 1617.WEISER RIVER 33 WEISER NR,ID (1)APR-JUL 365.0 93 391,34 POWDER RIVER35SUMPTER NR,OR MAR-JUL 60.0 86 70.36 SALMON RIVER37WHITEBIRD,ID (1)APR-JUL 4930.0 84 5851.38 GRANDE RONDE RIVER39LAGRANDE,OR MAR-JUL 194.0 78 249.40 TROY,OR (1)MAR-JUL 1490.0 94 1578.41 CLEARWATER RIVER 42 OROFINO,ID (1)APR-JUL 5170.0 111 4645.43 N.F.CLEARWATER RIVER44DWORSHAKRESINFLOW,ID (1)APR-JUL 3050.0 115 2644.45 APR-SEP 3230.0 115 2803.46 CLEARWATER RIVER47SPALDING,ID (1)APR-JUL 8390.0 113 7435.48 APR-SEP 8820.0 112 7849.49 UMATILLA RIVER50GIBBONNR,OR APR-JUL 76.0 104 73.51 PENDLETON,OR APR-JUL 153.0 103 149.52 S.F.WALLA WALLA RIVER53MILTONNR,OR APR-JUL 52.0 98 53.54 M.F.JOHN DAY RIVER55RITTER,OR (1)APR-JUL 99.0 80 123.56 N.F.JOHN DAY RIVER57MONUMENTNR,OR APR-JUL 470.0 79 597.58 JOHN DAY RIVER59SERVICECREEK,OR (1)APR-SEP 720.0 83 865.60 DESCHUTES RIVERclBENHAMFALLS,OR APR-SEP 450.0 85 528.CROOKED RIVERPRINEVILLE RES INFLOW,OR MAR-JUL 118.0 64 184. ExhibitNo.2 Case No.IPC-E-02-3 G.Said,IPCo-Dir Page2of3 OCHOCO CREEK OCHOCO RES INFLOW,OR MAR-JUL 25.0 71 35.3 S.SANTIAM RIVER 4 WATERLOO,OR APR-SEP 660.0 112 587.5 N.SANTIAM RIVER 6 MEHAMA,OR APR-SEP 950.0 114 834.7 WILLAMETTE RIVER 8 SALEM,OR APR-SEP 5200.0 108 4804.9 CLACKAMAS RIVER10ESTACADA,OR APR-SEP 900.0 120 748.11 MCKENZIE RIVER 12 VIDA NR,OR APR-SEP 1250.0 104 1201.13 ROGUE RIVER 14 RAYGOLD,OR APR-SEP 740.0 83 889.15 SILVIES RIVER16BURNSNR,OR APR-SEP 71.0 72 99.17 18 THESE FORECASTS ARE SELECTED FROM THOSE PREPARED BY:NATIONAL19WEATHERSERVICE,NATURAL RESOURCE CONSERVATION SERVICER,AND B.C.20 HYDRO AND POWER AUTHORITY.FOR VARIOUS PROJECT INFLOWS,THE21FORECASTSHAVEBEENCOORDINATEDWITHTHEU.S.ARMY CORP OF22ENGINEERSANDTHEU.S.BUREAU OF RECLAMATION.23 ALL FORECASTS ARE IN THOUSANDS OF ACRE-FEET24ALLAVERAGESAREFORTHEPERIOD1971THROUGH 200025END......NOAA/NWS/NORTHWEST RFC....26 2728 http://www.nwrfc.noaa.gov/cgi-bin/r_fcst_d?prod=ESPPDR&desc=Northwest_Seasonal_Volume_Forecasts ExhibitNo.2 Case No.IPC-E-02-3G.Said,lPCo-Dir Page3of3 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION Case No.IPC-E-02-3 Idaho Power Company Current Regression Exhibit No.1 G.Said SUMMARY OUTPUT Repression Statistics Multiple R.0.920131533 R.Square 0.846642039AdustedR.0.844207785 Standard Err.12,686.495.39Observation65 ANOVA df Repression 1 Residual 63Total64 Coefficients Intercept 1,023,185,930 X Variable 1 (63,236,861.2) RESIDUALOUTPUTOBS.YEAR RUNOFF LN(RUNOFF)NPSC Observation Predicted Y 1 1928 6,750,571 15.72514 $6,241,000 1 28,777,582.78219293,516,226 15.07290 $60,671,000 2 70,023,119.69319302,730,186 14.81988 $82,320,000 3 86,023,216.51419312,252,206 14.62742 $106,526,000 4 98,193,754.89519324,693,051 15.36159 $77,389,000 5 51,766,976.26619334,072,824 15.21985 $80,101,000 6 60,730,566.58719342,284,655 14.64173 $101,827,000 7 97,289,161.20819353,091,888 14.94429 $103,686,000 8 78,155,781.45919364.976,479 15.42023 $75,854,000 9 48,058,785.131019373,027,697 14.92331 $89,454,000 10 79,482,468.231119386,995,998 15.76085 $38,288,000 11 26,519,320.021219393,340,542 15.02164 $69,283,000 12 73,264,336.781319404,217,857 15.25484 $67,478,000 13 58,517,873.221419413,812,543 15.15381 $67,679,000 14 64,906,741.281519424,777,672 15.37946 $61,084,000 15 50,636,902.281619439,358,641 16.05181 $10,512,000 16 8,119,808.021719443,363,907 15.02861 $63,258,000 17 72,823,574.161819455,107,273 15.44618 $22,367,000 18 46,418,231.911919466,864,248 15.74184 $27,110,000 19 27,721,565.262019475,145,808 15.45369 $42,921,000 20 45,942,893.052119485,701,715 15.55628 $40,564,000 21 39,455,764.682219495,284,463 15.48028 $41,482,000 22 44,261,513.242319506,666,559 15.71261 $24,971,000 23 29,569,514.382419516,887,280 15.74519 $24,297,000 24 27,509,738.2225195210,645,884 16.18068 $16,180,000 25 (29,731.86294)26 1953 6,266,915 15.65079 $30,786,000 26 33,478,793.542719545,375,988 15.49745 $44,669,000 27 43,175,650.002819553,663,733 15.11399 $58,885,000 28 67,424,444.032919567,679,163 15.85402 $19,935,000 29 20,627,397.13 Exhibit No.1 Case No.IPC-E-02-03 G.Said,IPCo-Dir Page 1 of 2 30 1957 8,142,974 15.91267 $19,918,000 30 16.918,876.92I 31 1958 7,347,318 15.80985 $33,513,000 31 23,420,898.633219593,990,168 15.19934 $58,383,000 32 62,027,129.723319604,207,224 15.25231 $63,415,000 33 58,677,491.363419612,917,876 14.88637 $88,633,000 34 81,818,836.923519624,838,084 15.39203 $59,122,000 35 49,842.307.343619634,901,728 15.40510 $51,038,000 36 49,015,863.443719646,173,173 15.63572 $30,226,000 37 34.431.851.433819658,808,795 15.99126 $5,756,000 38 11.948,764.143919663,085,249 14.94214 $71,438,000 39 78,291,711.644019675,295,808 15.48243 $37,363,000 40 44,125,898.104119683,178,096 14.97179 $53,367,000 41 76,416,744.514219696,851,881 15.74003 $29,438,000 42 27,835,598.964319706,400,738 15.67192 $12,586,000 43 32,142,656.3244197111,081,252 16.22077 $5,243,000 44 (2,564,349.539)45 1972 8,051,202 15.90133 $15,647,000 45 17,635,608.094619733,795,548 15.14934 $22,988,000 46 65,189,259.524719749,837,354 16.10170 $6,450,000 47 4,965,130.6554819758,899,862 16.00155 $6,411,000 48 11,298,365.634919767,742,737 15.86227 $15,129,000 49 20,106,029.075019772,036,372 14.52668 $95,568,000 50 104,564,260.805119785,885,210 15.58795 $46,375,000 51 37,452e,710.715219793,662,618 15.11369 $47,708,000 52 67,443,692.115319806,180,456 15.63690 $16,932,000 53 34,357,289.685419813,880,244 15.17141 $52,133,000 54 63,793,670.225519829,629,565 16.08035 $5,952,000 55 6,315,156.63756198310,537,116 16.17041 $2,348,000 56 619.676.376557198412,447,717 16.33705 $2,971,000 57 (9,917,693.726)58 1985 5,467,688 15.51437 $28,551,000 58 42,106,094.185919868,603,101 15.96763 $17,008,000 59 13,442,920.556019872,657,135 14.79276 $76,325,000 60 87,738,280.126119882,461,731 14.71638 $104,676,000 61 92,568,546.416219894,426,855 15.30320 $58,475,000 62 55,459,598.196319902,853,052 14.86390 $98,643,000 63 83,239,557.726419912,622,549 14.77966 $101,823,000 64 88,566,792.346519921,798,651 14.40255 $125,185,000 65 112,414,032.80 AVERAGE $48,039,308 Exhibit No.1 Case No.IPC-E-02-03 G.Said,IPCo-Dir Page 2 of 2