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Home My WebLink About20020722Sterling Direct.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE INVESTIGATION OF THE CONTINUED REASONABLENESS OF CURRENT SIZE LIMITATIONS FOR PURPA QF PUBLISHED RATE ELIGIBILITY (I.E., 1 MW) AND RESTRICTIONS ON CONTRACT LENGTH (I., 5 YEARS). ) CASE NO. GNR-02- DIRECT TESTIMONY OF RICK STERLING IDAHO PUBLIC UTILITIES COMMISSION JULY 22, 2002 Please state your name and business address for the record. My name is Rick Sterling.My business address is 472 West Washington Street Boise Idaho. By whom are you employed and in what capacity? I am employed by the Idaho Public Utilities Commission as a Staff engineer. What is your educational and professional background? I received a Bachelor of Science degree in Civil Engineering from the University of Idaho in 1981 and a Master of Science degree in Civil Engineering from the University of Idaho in 1983.I worked for the Idaho Department of Water Resources from 1983 to 1994. 19881 I became licensed in Idaho as a registered professional Civil Engineer.I began working at the Idaho Public Utilities Commission in 1994.My duties at the Commission include analysis of utility applications and customer petitions. What is the purpose of your testimony in this proceeding? The purpose of my testimony is to recommend changes in the variables used to compute avoided costs for Idaho Power Avista and PacifiCorp.I am also recommending two changes in the computation methods CASE NO. GNR-02-07/22/02 STERLING R (Di) STAFF employed by the spreadsheet used to develop avoided costs. Before discussing your recommended changes in variables and computation methods will you please briefly describe how avoided cost rates are determined? Avoided cost rates are determined using a spreadsheet that is intended to replicate the costs of generating energy using a gas-fired combined cycle combustion turbine i. e. the surrogate avoided resource (SAR) adopted by the Commission in 1996.There are four primary components to the cost:capital costsl fixed 0 & M1 variable 0 & and fuel costs.Exhibi t No. depicts each of these four components.Capi tal costs are based on the initial plant construction cost amortized over the 30-year life of the plant at the utility weighted cost of capital.0 & M costs are based on an initial year estimate that is escalated at a fixed rate over the life of the plant.Fuel costs are handled differently depending on whether " fueledu or "non- fueledu rates are being computed.For " fueledu rates, the fuel cost component is adjusted on July 1st each year and is based on the average monthly gas price during the previous calendar year.Thus, for " fueledu rates, the fuel cost component of the avoided cost rates changes annually and tracks gas prices.For "non- fueledu rates, CASE NO. GNR-E- 02 - 01 07/22/02 STERLING R (Di) STAFF the same initial year gas price is establishedl agaln based on the average monthly gas price in the previous calendar year but the starting gas price is escalated at a fixed rate over the 30-year plant life.Consequently for existing contracts with "non- fueledu r~tes, no ongoing annual adjustment is made based on historical gas prices. Why are you proposing changes in the computation methods used in the avoided cost spreadsheet? I am proposing a change in the way in which the fuel cost component is computed for "non-fueledu rates so that a single year of extreme gas prices will not form the basis for the fuel cost component of the avoided cost rate for the entire contract length.Under the current computation method for "non-fueledu rates, once a contract is signedl no further annual gas price adj ustments are made.A contract signed in a year when gas prices are high will enj oy the benefit of the high gas price for the duration of the contract.Conversely a contract signed when gas prices are low will suffer the consequences of the low starting gas price for the entire contract length.Exhibit No.2 shows the variation in average annual gas prices at Sumas.Exhibi t No. illustrates how the annual variation in gas price affects the computation of avoided cost rates. CASE NO. GNR-02- 07/22/02 STERLING R (Di) STAFF Although recognized as a potential problem when the spreadsheet was developed in 1995, Staff did not believe it was a serious problem because only minor volatility in gas p~ices was anticipated.The recent extreme volatility in gas prices, however , has magnified the effect of starting gas price on the calculation of 20-year "non-fueledU rates.I believe that this problem should be corrected. Please describe the changes you are proposing to correct this problem. I believe that there are two possible changes that should be considered in computing the fuel cost component.First, a new method needs to be devised to establish a starting fuel price so that the effect of extreme variations in prices does not become ' permanently embedded in contracts.A single year of very high or low gas prices should not drive the avoided cost rate for a 20-year contract.There are many ways this might be done.In Staff's Supplemental Answer to Petitions for Stay, for example, it was suggested that a linear regression be performed to establish a starting gas price.By using multiple years of historic prices, this method moderates annual variations in gas price while recognizing upward trends.Exhibit No.4 illustrates this method. CASE NO. GNR-02-07/22/02 STERLING, R (Di) STAFF After further analyzing this method, however, I believe that even more moderation of annual price swings is necessary.Consequently, I am now proposing that a five-year rolling average be used.Under this method, an average of the previous five years average annual gas prices at Sumas would first be computed.Next, I would add an amount of $0.35 per MMBtu to represent the cost of delivering gas from Sumas to the SAR plant. The resulting total of $3.19 would then be used in the avoided cost spreadsheet to represent the current year fuel cost.Exhibit No.5 illustrates this method. I propose that this starting fuel price be computed each year for any new contracts.Once a non- fueled contract has been signed/ I propose that the contract rate remain fixed for the duration of the contract as it is now / and not be subj ect to rate changes due to annual fuel price changes. What other change do you propose in the manner in which fuel costs are computed in the avoided cost spreadsheet? In addition to changing the manner in which a 1 The delivery cost is based on estimates from the Northwest Power Planning Council document Draft Fuel Price Forecasts for the 5th Northwest Conservation and Electric Power Plan/ April 25/ 2002 / Appendix B - Derivation of Natural Gas Prices by Market Points andStates. I am not proposing that the delivery cost beupdated annually. CASE NO. GNR-02- 07/22/02 STERLING/ R (Di) STAFF starting fuel price is establishedl I propose that the escalation rate applied to the starting fuel price be updated annually for any new contracts.For signed contracts the fuel cost escalation rate in place at the time of contract execution would remain fixed for the duration of the contract. There are many gas price forecasts available from which to choose.I recommend the DOE/EIA Annual Energy Outlook be used because it is updated annually and is readily available without charge or subscription fees. The DOE/EIA Annual Energy Outlook forecasts annual gas prices through 20201 however I propose that a single escalation rate representing the period 2002-2020 be used.The Annual Energy Outlook 2000 forecasted- gas price escalation for this period is 1.7 percent (See Annual Energy Outlook Table 18 Energy Prices by Sector and Source Mountain).Because this forecasted rate is in real terms (2000 dollars) it must be increased by the general inflation rate of 2.70 percent (See Annual Energy Outlook Table A20 Macroeconomic Indicators GDP Chain- Type Price Index, Annual Growth 2000-2020) .Thus, the resul ting gas price escalation rate that I recommend be used in the spreadsheet is 4.4 percent (1.7 + 2.7 = 4.4) . I do not recommend the forecasts prepared by DRI -WEFA or GRI because they are not available to the CASE NO. GNR - E - 02 - 01 07/22/02 STERLING, R (Di) STAFF general public at no charge.I al so do not recommend the forecast prepared by the Northwest Power Planning Council because although it is available at no cost it is not currently updated at regular intervals. Are you proposing any other changes in the computation methods employed in the avoided cost spreadsheet? Yes I also propose that those portions of the spreadsheet related to "first deficit year surplus energy costU , and "surplus escalation rate U be abandoned. As I described previously, avoided cost rates prior to a utili ty ' s first deficit year have in the past been based on "surplus energy costs. Using today s terminology, we might describe this as basing avoided cost rates on market prices up until the time when the utility needs to begin acquiring new resources.After that rates are based on the costs of a combined cycle combustion turbine. Although I still believe the rationale is sound, determination of a first deficit year and surplus energy rates is very problematic.I am propos ing to abandon this part of the computations for the reasons enumerated below: 1 )Establishment of utilities ' first deficit years requires regular filings by the CASE NO. GNR-E- 02 - 0 107/22/02 STERLING, R (Di) STAFF utilities followed by Commission orders. None of the utilities has made a filing to update its first deficit year since the first deficit years were last established in 1996. 2 )It is unclear whether determination of a first deficit year should be based on a utili ty ' s energy needs or capacity needs. For utilities with capacity deficits, is one month/ two month, three month or longer deficit period needed before the utility is considered deficit?If the utili ty can rely on the market during brief deficit periods, is it still deficit for avoided cost determinations?If a utility cannot import power during brief but very critical periods, is it considered deficit? 3 )When a utility becomes deficit depends on the conditions assumed for planning. Water conditions and reserve margins used for planning are not consistent for all of the utilities. Load forecasts are one half of the surplus/deficit equation.Load forecasts STERLING, R (Di) STAFF CASE NO. GNR-E- 02 - 0 107/22/02 are prepared entirely by each utility with little or no oversight.Utilities can easily manipulate their load forecasts to produce a desired result. 5 )Utilities increasingly rely on market purchases.Should long-term contracts that do not begin for several years be counted as resources in determining first deficit year? The difference between "surplus u energy rates and "SAR-basedu rates is not as great as it used to be therefore, there is less justification for two different bases for parts of the avoided cost computations. 7 )Utilities always plan to be surplus in the short term/ at least for as long as it takes to acquire new resources.Having too large a surplus can be as problematic as being deficit.Avoided cost rates should not provide incentives for a utility to increase its surplus period. 8 )The addition of a PURPA proj ect, particularly if it is less than 10 MW does not have a large impact on a STERLING, R (Di) STAFF CASE NO. GNR-02-07/22/02 utili ty ' s load-resource balance.The cumulative effect of many PURPA proj ects could have a significant impact, but the capacity of PURPA proj ects has historically been small. 9 )If surplus energy rates are retained in the avoided cost analysis, determination of the prices to be used during a utility s surplus period poses some difficulty because of recent extreme variations in market prices. What would be the effect of abandoning those portions of the avoided cost computations related to first deficit year? The effect of first deficit year on avoided cost rates depends, of course, on how far into the future the first deficit year is.The further into the future the first deficit year is, the greater the effect on the avoided cost rate.The "surplus u energy rate paid during the surplus period also affects the avoided cost rate. In terms of sensitivity on avoided cost rates, first deficit year probably ranks second to gas price and gas escalation rate. Using Avista as an example, the avoided cost rate (stayed by Commission Order No. 29069) for a 20-year CASE NO. GNR-E- 02 - 0 107/22/02 STERLING, R (Di) STAFF levelized non-fueled contract with a 2002 on-line date is 58.24 mills/kWh assuming a first deficit year of 2010. However, if the first deficit year portion of the computations is disabled and all other variables remain unchanged/ the comparable avoided cost rate is 75. mills/kWh.Using my recommendations for changing other variables and computation methods in the spreadsheet, the 20-year levelized rate is 46.15 mills/kWh with no first deficit year and 43.04 mills/kWh with a 2010 first deficit year.Thus, if my other recommendations are accepted, abandoning first deficit year has only a minor impact on rates. What avoided cost computation variables do you propose to update? I propose that the variables related to the capital costs and the 0 & M costs of a combined cycle combustion turbine be updated.At the time these variables were first established in 1996, the Commission chose to adopt plant cost data provided by the Northwest Power Planning Council.I believe that the Council is still a reliable source for this information and that we should continue to rely on it.The Council is currently working to prepare its Fifth Power Plan.A draft of the Fifth Power Plan is scheduled to be completed and released for public comment in August, with the final CASE NO. GNR-02-07/22/02 STERLING, R (Di) STAFF plan being complete in the spring of 2003.A Generating Resources Advisory Committee has been formed to assist the Council in developing cost data for new generation sources.That committee has already developed preliminary cost data for combined cycle plants.The Council staff does not anticipate significant changes to the data prior to completion of the draft plan. I propose that the combined cycle plant cost data developed by the Council's Generating Resources Advisory Committee be used in the avoided cost computations.The Advisory Committee s draft data lists costs as follows: Plant Cost:$624/kW $10.70/kW/yrFixed 0 & Variable 0 & 8 mills/kWh 6980 BTU/kWhHeat Rate: Because the plant cost adopted by the Advisory Committee is an "overnightU cost, I recommend that an additional amount of $55/kW be added to the plant cost to approximate AFUDC that would be required if a plant were to be constructed.Thus, I recommend that an "SARU plant cost of $679 (year 2000 dollars) be used in the spreadsheet. I also recommend that a slightly higher heat rate be used.My recommended heat rate is 7100 Btu/kWh. CASE NO. GNR-E- 02 - 0107/22/02 STERLING, R (Di) STAFF Because heat rate increases with elevation, and because most plants built to serve Idaho loads would likely be at a higher elevation than the rest of the Northwest reglon, I believe such an increase is warranted. I am not proposing any change to the "SARU plant life (currently 30 years) or to the "SARU capacity factor (currently 92 percent) Are there any other variables that you recommend be updated? Yes, I recommend that the escalation rates used in the spreadsheet be updated based on current forecasts. I recommend that the escalation rates for "SARU construction costs and the "tiltingU rate be set at 2. percent.This rate is based on the Northwest Power Planning Council's Fifth Power Plan preliminary data which forecasts a 0.6 percent real decrease in combined cycle plant costs.This rate is then adj usted upwards by a 2.70 percent inflation rate from DOE/EIA (See Annual Energy Outlook 2002, Reference Case Forecast, Table A20, GDP Chain-Type Price Index , Annual Growth 2000-2020) . recommend that the escalation rate for 0 & M be set at 70 percent, the same inflation rate from DOE/EIA' Annual Energy Outlook. Would you please summarize your proposed changes? CASE NO. GNR-E- 02 - 0 1 07/22/02 STERLING, R (Di) STAFF A summary of my proposed changes is included as Exhibit No. How would you proposed changes affect avoided cost rates? My proposed changes would decrease the avoided cost rates for each of the three utilities.Exhibi t No. 7 shows the non-fueled rates that would result if my recommended changes in variables and computation methodology are adopted.Exhibi t No.8 shows the fueled rates that would result. Does this conclude your direct testimony in this proceeding? Yes, it does. CAS E NO. GNR - E - 02 - 0 1 07/22/02 STERLING, R (Di) STAFF 10 0 .. c : (J l :! ! : :: 0 ( " ) t I 1 po ~ cn ' " P" ' .- - . ( t ) - , ~ Z E" - O z qQ 6 ~ cn Z - pj ; ; 0 tI 1 -. J N -- N - Av o i d e d C o s t C o m p o n e n t s Ye a r o f C o n t r a c t :: 0 ( " ) t I 1 po g. , cn ' " .. . . . ( t ) ~ z ~ 0 ... . . ~ . gq Q ~ ~~ N po , tI 1 -. J N -- , N - , " " " " " " " ' ' ": ' ; " ;., '; . " " :' i i' : " , , " ' ' " " : " " ' ' , ;, " ' " " " .' " ' " , " " , " " ' " " " " " " ;- " ' " .'- ;; : " " , 'i - ' , " " ' , " " " "" ' $ 4 . 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' , " GU R R E N T ; : ' ~~ ~ i ~~ ~ ~ ~ " 1" , ; , ), " PA T A , , ,, ' .., , " TY P E ,,' VA R I A B L E S ' " .,, , ' ", , 0" " ' " ' , , ' , , "; " "; ; " ' , " , " "" ; " " " SU R P L U S E N E R G Y C O S T ( m i l / k W h ) : 19 , Ab a n d o n SU R P L U S C O S T B A S E Y E A R : 19 9 4 Ab a n d o n SA R " P L A N T L I F E ( Y E A R S ) : No C h a n g e SA R " P L A N T C O S T ( $ / k W ) : $6 6 7 $6 7 9 No r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , G e n e r a t i n g R e s o u r c e s Ad v i s o r y C o m m i t t e e BA S E Y E A R O F " SA R " C O S T : 19 9 4 20 0 0 No r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , G e n e r a t i n g R e s o u r c e s Ad v i s o r y C o m m i t t e e SA R " C A P A C I T Y F A C T O R ( % ) : 92 % No C h a n g e SA R " F I X E D O & M ( $ / k W ) : $7 . 4 3 $1 0 , No r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , G e n e r a t i n g R e s o u r c e s Ad v i s o r y C o m m i t t e e SA R " V A R I A B L E O & M ( m i l / k W h ) : No r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , G e n e r a t i n g R e s o u r c e s Ad v i s o r y C o m m i t t e e CU R R E N T Y E A R F U E L C O S T ( $ / M M B t u ) : $5 . $3 , St a f f P r o p o s e d 5 - Ye a r R o l l i n g A v e r a g e BA S E Y E A R , O & M E X P E N S E S : 19 9 4 20 0 0 No r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , G e n e r a t i n g R e s o u r c e s Ad v i s o r y C o m m i t t e e ES C A L A T I O N R A T E ; " SA R " ( % ) : 60 % 10 % In f l a t i o n - a d j u s t e d N o r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n Ge n e r a t i n g R e s o u r c e s A d v i s o r y C o m m i t t e e ES C A L A T I O N R A T E ; S U R P L U S ( % ) : 50 % Ab a n d o n ES C A L A T I O N R A T E ; O & M ( % ) : 21 % 70 % DO E / E I A An n u a l E n e r g y O u t l o o k 20 0 2 ES C A L A T I O N R A T E ; F U E L ( % ) : 00 % 4. 4 0 % In f l a t i o n - a d j u s t e d D O E / E I A An n u a l E n e r g y O u t l o o k 20 0 2 TI L T I N G " R A T E ( % ) : 60 % 10 % In f l a t i o n - a d j u s t e d N o r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , Ge n e r a t i n g R e s o u r c e s A d v i s o r y C o m m i t t e e HE A T R A T E ( B t u / k W h ) : 73 5 0 71 0 0 St a f f - a d j u s t e d N o r t h w e s t P o w e r P l a n n i n g C o u n c i l , F i f t h P o w e r P l a n , Ge n e r a t i n g R e s o u r c e s A d v i s o r y C o m m i t t e e AVISTA UTILITIES AVOIDED COST RATES FOR NON-FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July 1 , 2002 - June 3D, 2003 mills/kWh LEVELIZED ."' ' NON~LEVELIZED , " ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005 2006 2007 YEAR RATES 35,36,38,39.41 40,42,2002 35. 36,37,38,40,41,43,2003 36, 36,37,39,40.42,43,2004 38. 37.38,40,41.48 43,44.2005 39.41 37,39.40,42,43,45,2006 40, 38.43 39.41,42,44.42 46,2007 42, 39,40.47 41,43,45,46,2008 43, 39,41,42,44,45,47,2009 45, 40,41,43,44,46.49 48.22 2010 47, 40,42,43.45.48 47,48,2011 49, 41.42,44.48 46,47,49,2012 50, 41.43.48 45,46,48.50,2013 52. 42.49 44,45,47.49,50,2014 54, 43,44,46,48,49,51,2015 56, 43,45,46.48,50.43 52.2016 58. 44,45,47.45 49,51.52,2017 61. 44.46.48,49,51.53,2018 63.46 45,46,48,50,52,54,2019 65, 45,47,49,50,52,54,2020 68. 46,47,49.51.53.45 55.46 2021 70. 2022 73, 2023 76, 2024 79.47 2025'82. 2026 85. 2027 89, Exhibit No, 7 Case No, GNR-02- R, Sterling, Staff Page 1 of 3 7/22/02 IDAHO POWER COMPANY AVOIDED COST RATES FOR NON-FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July 2002 - June 30, 2003 mills/kWh LEVELIZED ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005 2006 2007 YEAR RATES 35,37.38.49 39.41.42,2002 35. 36.46 37.39,40,42.43.2003 37. 37.38.42 39.41,42.44.2004 38.49 37.39,40.49 41,43,45,2005 39, 38.39,41.42,44,45,2006 41, 38,40,41,43,44,46.2007 42, 39,40,42.45 44,45,47,2008 44.44 40,41,43,44.46,48,2009 46, 40,42,43,45.47,48,2010 47, 41,42,44,45,47,49.45 2011 49. 41.43,44.46,48,50,2012 51.40 42,43,45,47,49.50.2013 53. 42.44,46,47,49.51,2014 55, 43.49 45,46,48.49 50.52,2015 57, 44,45,47,49,50,52.2016 59, 44,46,47.49.51,53.46 2017 61, 45,46,48.48 50,52,54.2018 64, 45,47,49,50,52,54.2019 66, 46,47,49,51.41 53.55,2020 69. 46.48,50,51.53,55,2021 71, 2022 74, 2023 77.23 2024 80. 2025 83, 2026 86.46 2027 89, Exhibit No. 7 Case No, GNR-02- R. Sterling, Staff Page 2 of 3 7/22/02 PACIFICORP AVOIDED COST RATES FOR NON-FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July 2002 - June 30, 2003 mills/kWh LEVELIZED' ,NON-LEVELIZED ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005 2006 2007 YEAR RATES 36,37,38,40.41,43,2002 36. 36,38,39.40 40.42,43,2003 37, 37,38.40,41,43,44,2004 38, 37,39.40,42,43.45,2005 40, 38,39.41,42,44.45 46,2006 41. 39,40.42,43.45,46,2007 43. 39,41,42,44,45,47,2008 44, 40.41,43.26 44,46,48,2009 46. 40,42,43,45.49 47.48,2010 48. 41,42.44.48 46,47.49,2011 49. 41.43.47 45,46,48.45 50.2012 51. 42.47 44.45,47,49,50.2013 53, 43,44,46,47.49,51.2014 55, 43,45,46.77 48,50.29 52.2015 57, 44,45,47,49,50,52.77 2016 59. 44,46,47,49,51.46 53,2017 62. 44.46,48,50,52.53.2018 64.41 45.45 47,48,50,52,54,2019 66, 45,47,49,51,53,55,2020 69, 46,48,49,51,53.55,2021 72. 2022 74. 2023 77, 2024 80, 2025 83. 2026 86, 2027 90, Exhibit No, 7 Case No, GNR-02- R. Sterling, Staff Page 3 of 3 7/22/02 AVISTA UTILITIES AVOIDED COST RATES FOR FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July , 2002 - June , 2003 mills/kWh LEVELIZED NON-LEVELIZED ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005 2006 2007 YEAR RATES 12,13,13,13,13,14.2002 12, 12,13,13.47 13.79 14.14.43 2003 13, 13.13,13.13,14.14,2004 13, 13.13.45 13.14,14.40 14,2005 13, 13,13,13.14,14,14,2006 13, 13.41 13.72 14,14.14.15.2007 14, 13,13.14,14,14.15.2008 14, 13,13.14,14,14.15.2009 14, 13,14.14.44 14,15,15.46 2010 15, 13,14.24 14.14,15.15.2011 15, 14,14.14.15,15.15,2012 16, 14,14.48 14,15.15,15.2013 16, 14.14.14.15.27 15,15.2014 16, 14,14,15,15,15.75 16.2015 17, 14.48 14,15.15,15,16,2016 17. 14.14,15.15.15.16,2017 17. 14.15.15.15,16,16.47 2018 18. 14.15,15.48 15.16,16,2019 18. 14,15.15.15,16,16,2020 19, 14,15.15,16,16.41 16,2021 19, 2022 20, 2023 20, 2024 21, 2025 21. 2026 22. 2027 22, EFFECTIVE DATE 7/1/02-6/30/03 ADJUSTABLE COMPONENT 22, The total avoided cost rate in each year is the sum of the annually adjustable component and the fixed component from either of the tables above, Example 1, A 20-year levelized contract with a 2002 on-line date would receive the following rates: Years Rate 14,98 + 22, 14.98 + Adjustable component in each year Example 2, A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates: Years Rate 12.73 + 22, 13.03 + Adjustable component in year 2003 13,33 + Adjustable component in year 2004 13,63 + Adjustable component in year 2005 Exhibit No. Case No. GNR-02- R. Sterling, Staff Page 1 of 3 7/22/02 IDAHO POWER COMPANY AVOIDED COST RATES FOR FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July 1 2002 - June 30, 2003 mills/kWh LEVELIZED NON~LEVELlZED J' , ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005'2006 2007 YEAR RATES 13,13,49 13.14,14.44 14,2002 13, 13,13,13,14,14,14,2003 13.49 13.48 13,14,14.43 14,15,2004 13, 13.13,14,14,14,15,2005 14, 13,14.14,14,15,15.41 2006 14.44 13,14,14,14,15.15,2007 14.78 14,14,14,15,15,15,2008 15. 14,14.48 14,15,15,15,2009 15.46 14,14.14,15,15,16,2010 15, 14.40 14,15,15.42 15,16,2011 16, 14.14,15,15,15,16.2012 16, 14,14,15,15,16,16.41 2013 16, 14,15,15.45 15.16.16,2014 17, 14,15,15,15,16.16,2015 17, 14,15,15,16.16.41 16.79 2016 18, 15,15.43 15,16.16.16,2017 18, 15,15,15,16,16,17,2018 18, 15,15,16,16,16,17,2019 19.43 15.15,16,16.48 16,17,2020 19. 15.48 15,16,16.16.17,2021 20, 2022 20. 2023 21, 2024 21, 2025 22, 2026 22, 2027 23, EFFECTIVE DATE ADJUSTABLE COMPONENT 7/1/02-6/30/03 22, The total avoided cost rate in each year is the sum of the annually adjustable component and the fixed component from either of the tables above. Example 1, A 20-year levelized contract with a 2002 on-line date would receive the following rates: Years Rate 15.48 + 22, 15.48 + Adjustable component in each year Example 2, A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates: Years Rate 13,19 + 22, 13.49 + Adjustable component in year 2003 13,80 + Adjustable component in year 2004 14.12 + Adjustable component in year 2005 Exhibit No, 8 Case No, GNR-02- R, Sterling, Staff Page 2 of 3 7/22/02 PACIFICORP AVOIDED COST RATES FOR FUELED PROJECTS SMALLER THAN TEN MEGAWATTS July 2002 - June 30, 2003 mills/kWh LEVELlZED"NON-LEVELIZED ON-LINE YEAR CONTRACT NON-LEVELIZED 2002 2003 2004 2005 2006 2007 YEAR RATES 13.42 13,14,14,14.15,2002 13.42 13.13,14,14,14,15,2003 13, 13,14,14,14,15,15,2004 14. 13,14,14.49 14,15,15,2005 14. 13.14,14,14,15.15,2006 14, 14.14.44 14.15,15.46 15.2007 15, 14,14,14,15.15,15,2008 15, 14,14,15,15.15,16.2009 15. 14,14,15,15,15,16,2010 16. 14,14.15,15,16,16.2011 16.46 14.15,15.43 15.16,16,2012 16, 14,15,15,15,16,16,2013 17, 14,15,15.16,16,16.2014 17. 15,15.42 15,16,16,16,2015 18. 15,15.15,16,16,17,2016 18.44 15,15,15,16,16.17,2017 18, 15,15,16,16.46 16,17,2018 19, 15.47 15.16,16.16,17,2019 19, 15,15,16,16,17.17.43 2020 20.21 15,16,16.16,17,17,2021 20, 2022 21, 2023 21. 2024 22, 2025 22, 2026 23, 2027 23. EFFECTIVE DATE 7/1/02-6/30/03 ADJUSTABLE COMPONENT 22, The total avoided cost rate in each year is the sum of the annually adjustable component and the fixed component from either of the tables above, Example 1. A 20-year levelized contract with a 2002 on-line date would receive the following rates: Years Rate 15,65 + 22. 15.65 + Adjustable component in each year Example 2. A 4-year non-Ievelized contract with a 2002 on-line date would receive the following rates: Years Rate 13.42 + 22, 13,72 + Adjustable component in year 2003 14.04 + Adjustable component in year 2004 14,36 + Adjustable component in year 2005 Exhibit No, 8 Case No. GNR-02- R. Sterling, Staff Page 3 of 3 7/22/02 CERTIFICATE OF SERVICE HEREBY CERTIFY THAT I HAVE THIS 22ND DAY OF JULY 2002 SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN CASE NO. GNR-02-, BY MAILING A COpy THEREOF, POSTAGE PREPAID TO THE FOLLOWING: ROBERT J LAFFERTY BLAIR STRONG A VISTA CORPORATION PO BOX 3727 SPOKANE W A 99220 MARK WIDMER ACIFICORP 825 NE MUL TNOMAH, SUITE 800 PORTLAND OR 97204 JOHN M ERIKSSON STOEL RIVES LLP 201 S MAIN ST STE 1100 SALT LAKE CITY UT 84111 BARTON L KLINE SENIOR ATTORNEY IDAHO POWER COMPANY PO BOX 70 BOISE ID 83707-0070 CONLEY WARD GIVENS PURSLEY LLP PO BOX 2720 BOISE ID 83701-2720 WILLIAM J NICHOLSON POTLATCH CORPORATION 244 CALIFORNIA ST STE 610 SAN FRANCISO CA 94111 DEAN J. MILLER McDEVITT & MILLER LLP PO BOX 2564 BOISE, ID 83701 PETER J RICHARDSON RICHARDSON & O'LEARY PLLC PO BOX 1849 EAGLE ID 83616 OWEN H ORNDORFF ORNDORFF LAW OFFICES 1087 W RIVER STREET STE 230 BOISE ID 83702 RONALD C BARR EARTH POWER RESOURCES INC 3203 S OW ASSO AVENUE TULSA OK 74105 jJ fk-v SECRET ---