The URL can be used to link to this page

Home My WebLink About20090514Comments.pdfWELDON B. STUTZMAN DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION POBOX 83720 BOISE, IDAHO 83720-0074 (208) 334-0318 IDAHO BAR NO. 3283 f""l. 1: L nv ., ',~ Street Address for Express Mail: 472 W. WASHINGTON BOISE, IDAHO 83702-5983 Attorney for the Commission Staff BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF ) IDAHO POWER COMPANY FOR AUTHORITY ) TO IMPLEMENT POWER COST ) ADJUSTMENT (PCA) RATES FOR ELECTRIC ) SERVICE FROM JUNE 1,2009 THROUGH MAY)31,2010. ) ) CASE NO. IPC-E-09-11 COMMENTS OF THE COMMISSION STAFF The Staff of the Idaho Public Utilties Commission, by and through its Attorney of Record, Weldon B. Stutzman, Deputy Attorney General, submits the following comments in response to Order No. 30786 issued on April 23, 2009. BACKGROUND Since 1993, the PCA mechanism has permitted Idaho Power to establish PCA rates to recover allowed variations from normal power supply costs. Base rates, established in a general rate case, recover normal power supply costs. The main components of variable power supply cost are fuel costs (coal and natural gas) and purchased power costs. These costs are offset with off-system sales revenues. Idao Power Company's power supply costs var anualy based on streamflow at hydro power generating facilties, the market price of power, and other factors. STAFF COMMENTS 1 MAY 14,2009 The annual PCA surcharge or credit is combined with the Company's "base rates," and other non-base rates, to produce a customer's overall energy rate. On April 15, 2009, Idaho Power Company fied its anual power cost adjustment (PCA) Application. In this PCA Application, Idaho Power calculates that its anual power costs have increased above normal amounts. To recover the increased power costs, the Company estimates that existing PCA rates must increase to recover an additional $93.8 milion. The proposed increase averages 11.4% but impacts different customer classes differently. The lowest proposed class increase is 3.8% and the largest proposed increase is 18.7% for a special contracts customer. THE PCA MECHANISM The anual PCA mechanism is comprised of three major components. The first component, projected or forecasted power cost, is computed using the results of the Company's most recent Operating Plan (OP Plan). This method replaces the previous method that was based on a forecast of Brownlee Reservoir inflow and a regression formula derived from rate case power supply cost data. The Commission directed use of the new method for projecting power costs in an effort to improve forecast accuracy. The old method resulted in forecasts that differed substantially from actual results. Order No. 30715. In the new method, streamflow remains a major factor used to project power costs. In addition to streamflow, the new method includes updated projections for load, market price, resource availabilty and many other varables. It also includes the costs of power supply transactions already made for the PCA year. The new method of projecting power supply costs is expected to be significantly more accurate. In general, in years of abundant snowpack and streamflow, the Company's power supply costs are lower. Hydropower is the Company's lowest cost major resource. Conversely, when snowpack and resulting streamflows are low, Idaho Power must rely increasingly upon its thermal generating resources and purchased power from the regional market. The Company's thermal generating resources (coal and gas plants) and purchased power are typically much more costly than the Company's hydro-generation. Under the PCA mechanism, beginning February 1, 2009, the Company may recover 95% of the difference between projected power costs and normal power costs included in base rates. Order No. 30715. Because the PCA includes forecasted costs, the second PCA component consists of a true up from the preceding year's forecasted costs to the actual costs incurred in the prior year. In STAFF COMMENTS 2 MAY 14,2009 recent years, the true-up balance has been reduced using revenue from the sale of sulfu dioxide (S02) allowances. The third component is the "tre-up of the true-up," or reconcilation of the previous year's true-up. This component is designed to ensure the Company recovers the actual approved costs. Idaho Power uses "normalized" power sales (measured in kilowatt-hours (kWh)) from the ensuing PCA year as the denominator to compute the adjusted tre-up rate. Over- or under- recovery is balanced with the following year's true-up. In a poor water, high cost year, Idaho ratepayers pay a large portion ofIdaho Power Company's abnormal power supply costs. In a good water, low cost year, Idaho ratepayers are credited with a large portion of the below normal cost savings. IDAHO POWER'S PCA APPLICATION A. The PCA Components This year's PCA Application includes the 2009-2010 forecast of power supply costs; a true-up of last year's forecasted costs to reflect actual costs and revenues; and reconciliation of the 2008-2009 PCA year true-up (the true-up of the true-up). The Company calculates that the net forecasted power supply cost is $260.1 millon for the 2009-2010 PCA year. This is $106.0 milion more than the $154.1 milion included in Base Rates. After adjustments and PCA sharing, this results in a forecast rate of 0.5662 ~/kWh. Idaho Power reports that the difference between last year's normal and actual power supply costs adjusted by revenue generated from the forecast rate, the true-up component, is $107.9 milion. The true-up amount becomes $103.3 milion after it is reduced by approximately $4.6 milion to reflect S02 sales revenues. Application, p. 4. The Company calculates the true- up portion of the PCA rate to be 0.7465 ~/kWh. The third PCA rate element is the ''true-up of the tre-up" or reconcilation of the previous year's true-up. Last year the Company under-collected the PCA deferral balance by $22.0 milion. Application, p. 4. Dividing this amount by the projected 2009 Idaho jurisdictional sales of 13,838,689 MWh results in a PCA surcharge rate of 0.1590 ~/kWh. Id Combining the three components - the projected power costs rate of 0.5662 ~/kWh, the true-up rate of 0.7465 ~/kWh and the true-up of the true-up rate of 0.1590 ~/kWh - results in a proposed PCA surcharge rate for the 2009-2010 PCA year of 1.4717 ~/kWh. This represents an increase of 0.6853 ~/kWh above the existing PCA rate of 0.7864 ~/kWh. STAFF COMMENTS 3 MAY 14,2009 B. Impact of the Company's Rate Proposal Idaho Power has proposed to implement the PCA rate on June 1,2009. The proposed PCA rate represents an overall average percentage increase of 11.4% in Company revenue. Although the PCA rate is an equal cents per kWh adjustment for all customers, each customer class will receive a different percentage increase due to the different energy rates in effect for the different customer classes. The table below shows the proposed increases in the PCA rates for the major customer classes: Customer Group Percentage (Schedule)Increase Residential (1)9.30% Small Commercial (7)7.56% Large Commercial (9)12.58% Industrial (19)15.64% Irrigation (24)11.08% The PCA rates for Idaho Power's three special-contract customers (Micron, Simplot, and the Deparment of Energy (INL)) would also increase. Under the Company's proposal the PCA rate increase for the three special-contract customers would be 17.68% for Micron, 18.71 % for Simplot, and 18.36% for the Idaho National Laboratory. Attachment A to these comments is a char that shows the magnitude of the PCA for each year since its inception in 1993. For 2009, both the Company and Staff proposals are shown. Attchment B shows a history of Idaho Power's residential energy rates and identifies the PCA components. The char also shows the Company and Staff proposals for 2009. STAFF AUDIT AND ANALYSIS The PCA has three components: 1) a forecast component; 2) a true-up component that corrects for the previous years forecast error; and 3) a true-up of the previous year's true-up that is a final correction. Set out below are the Staff s comments on the three PCA components. A. The PCA Forecast As previously discussed, the forecast is now prepared from the Company's most recent Operating Plan (OP Plan). The OP Plan incorporates the most curent information available in each update. An account by account breakdown of the Company's forecast proposal is shown on STAFF COMMENTS 4 MAY 14,2009 Attachment C to these comments. The char shows the amount included in Base Rates, the Forecast amount and the Difference. Account 555 - PURPA Purchases is shown separately from other Account 555 Purchases because differences in PURPA Purchases are not shared, the entire difference is passed on to customers. Lines 1 through 14 of page 1 of Attchment D show the Company's calculation of the Forecast Rate. Line 3 shows the expected reduction due to Hoku first block revenues and line 5 shows the customer sharing percentage that is applied to all power supply cost differences, except the difference in PURP A costs. Line 8, Column (g), shows the forecast rate excluding the portion of the forecast rate associated with the expected PURP A cost difference. This rate is 0.6451 ~/kWh. Lines 10 through 12 show the calculation ofthe portion of the Forecast Rate associated with the expected difference in PURP A costs. This portion of the rate is negative because expected PURP A costs are less than PURP A costs included in base rates. This rate is -0.0789 ~/kWh. The two portions of the forecast rate combined produce the forecast rate shown on line 14, 0.5662 ~/kWh. Among other things, this rate reflects expected below normal water conditions. Under the new forecast methodology, Idaho Power does its own water forecast, however, the Northwest River Forecast Center expects April through July Brownlee Reservoir inflows to be 81 % of normaL. Since the filing of this case the Company has updated its Operating Plan. Use of the updated plan reduces forecasted system power supply costs by approximately $10.7 milion. The recalculated forecast rate of 0.4967 ~/kWh is shown on page 2 of Attachment D, line 14. Staff proposes that the Commission adopt a different Forecast Rate than those previously discussed in an effort to phase in the change in forecast methodology and to mitigate the large increase proposed by the Company in this case. As shown on page 3 of Exhibit D, Staff proposes a forecast rate of 0.2500 ~/kWh. This rate is expected to recover approximately $34.6 milion of the $68.0 milion that the updated forecast would require. To the extent that this forecast rate under-recovers the difference between actual and normal power supply cost, the unecovered costs wil be captured in next year's tre-up. Staff is very much aware that the tre- up methodology was changed to improve the forecast and that a rate that does not reflect the improved forecast leaves money to be recovered the following year in the true-up just like a poor forecast would. However, Staff believes the size of the proposed increase and the size of the true up rate in place from a poor forecast last year justifies modifying the result for this year's PCA forecast. Also, the proposed increase is over the 7% threshold established by the Commission at STAFF COMMENTS 5 MAY 14,2009 which level spreading the increase over multiple years would be considered. Staffs proposal spreads the recovery of forecast costs over two years. The forecast proposed by the Company is the largest ever. The forecast proposed by Staff, produces the second largest forecast of record. This attests to the enhanced accuracy of the forecast methodology and the likelihood of a reduced true up next year. B. The PCA True-Up The PCA true-up captures the difference between normal and actual power supply costs adjusted by revenue from the forecast rate. Rates were set in the previous PCA period to collect or refud to customers the difference between the projected power supply costs and those costs reflected in rates. This difference is the PCA deferral balance. This deferral balance, when surcharged or refuded to customers is known as the PCA tre-up rate component. Exhibit NO.1 to Idaho Power witness Scott Wright's testimony ilustrates the calculation of the true-up deferral amount. To verify revenues and costs associated with Idaho Power's true- up deferrals, Staff conducted an audit of actual revenues and expenses that occured during the PCA year. These revenues and costs included the cloud seeding program, fuel expenses for coal, fuel expenses for natual gas, and power purchases and sales. Staff also examined the Emission Allowance Sales Credit and the Risk Management operating plan. Attachment E is Staff s calculation of the true-up deferral amount before it is reduced by the Emission Allowance Sales Credit. A sumar of the true-up is the following. Idaho Jurisdictional Items Last Year's Forecast Revenue Last Year's Above Normal Power Supply Costs (Shared) Last Year's Above Normal PURPA Facilties Costs Interest True-up Expense (Deferral) MILLIONS $ (3.7) $ 143.0 $ (33.9) $ 2.5 $ 107.9 Emission Allowance Sales Credit Total True-up Deferral with Emission Allowance Sales Credit $ (4.6) $ 103.3 Staffs true-up recommendation differs slightly from Idaho Power's due to a small difference in the Emission Allowance Sales Credit discussed later in these comments. The following items are included in the PCA tre-up. STAFF COMMENTS 6 MAY 14,2009 1. Base Power Supply. During the past PCA year actual power supply costs have been measured against portions of three different base periods to determine deferral amounts. The first base was in place for April and May of 2008 (2 months), the second base was in place June 2008 through Januar 2009 (8 months) and the third base was in place during Februar and March of 2009 (2 months). In the Company's last PCA case the Commission approved redistribution of the monthly AURORA base amounts to average monthly amounts. The first two base periods in this true-up year used this distribution. The third base period in this true-up year also redistributed the AURORA base. For the third base period, the Company has been authorized to redistribute or shape base power supply costs according to the monthly distribution of Idaho Jurisdictional Revenues. Since monthly deferral amounts are a calculation of the difference between the actual power supply costs and base power supply costs, monthly deferral amounts differ because the base has been redistributed or reshaped. The net difference for the true-up year in this case is approximately $3.4 milion to the customers' benefit. Monthly differences can be large and customers may not always benefit. Staff proposes to track the differences each year and to propose changes to the methodology if the differences becomes unacceptable. 2. S02 Proceeds. Commission Order No. 30790 in Case Nos. IPC-E-09-08 and IPC-E-08-14 was issued on May 1,2009 and ordered that $5,347,453 of Emission Allowance Sales ($5,299,875 plus accrued interest of$47,578 as of March 31,2009) be used to offset the Company's PCA deferral balance this year. This is a system number. The amount used by the Company for the Emission Allowance sales credit is $4,591,632. This is the Idaho jursdictional amount and includes interest through March 2009. As shown on page 3 of Attachment D, line 20 in the "Base" column of Staffs Recommendation, the S02 credit amount with interest through May 31, 2009 is $4,600,857. The difference between the amounts used by the Company in its PCA fiing and Staff s recommendation is due to interest on the S02 credit balance for April and May 2009. The S02 credit is a benefit to customers. 3. Cloud Seeding Program. Cloud seeding expenses have been recorded in the PCA since October 2006. In Case No. IPC-E-05-28, Order No. 30035, monthly cloud seeding expenses were incorporated into base rates. In this PCA period, the cloud seeding expense in base rates is $719,261. The actual amount of expense for the Cloud Seeding Program for the PCA period from April 2008 through March 2009 is $608,785. Actual expenses are less than the STAFF COMMENTS 7 MAY 14,2009 expense in base rates by $110,476. This represents a benefit to customers and is subject to jurisdictional allocation and sharing. 4. Fuel Expense - CoaL. A large portion ofIdaho Power's electricity comes from thermal power produced from coal plants. The three coal plants that Idaho Power owns an interest in are Bridger, Valmy and Boardman. The increase or decrease in the coal expense from base rates is included in the PCA for recovery from or refud to customers. For the audit period of April 2008 to March 2009, the total coal expense for all plants in operation is $135,782,138. The total coal expense included in base rates is $112,483,839. This year's PCA deferral balance includes a difference between costs currently included in rates and actual costs of $23,298,299. This cost to customers is subject to jurisdictional allocation and sharing. 5. Fuel Expense - Gas. Idaho Power curently owns and operates gas-fired combustion turbine generating plants at the Evander Andrews Power Complex (3 Danskin units) and Bennett Mountain. These plants are both located at Mountain Home and account for 100% of gas usage. For the audit period of April 2008 to March 2009 the total variable gas and gas transportation expense for both complexes was $15,196,631; down from $20,823,773 durng the last PCA period. The total gas and gas transporttion expense included in base rates is $11,108,299. The increase or decrease in gas expense from base rates is included in the PCA for recovery from or refud to customers. In this year's PCA deferral balance, the additional gas expense that is included for future recovery from customers is $4,088,322 and is subject to jurisdictional allocation and sharing. 6. Power Sales and Purchases. Staff reviewed the power purchases and sales in conjunction with the Company's Risk Management Operating Plans. Our analysis did not find any transaction that was not reasonable or did not follow the Risk Management Committee's recommendations. These transactions were made with an assortment of credit-worthy parners on a timely basis, and there were no transactions conducted with an Idaho Power affiiate. a. Power Sales. Durng the PCA year ending March 31,2009, the Company sold surlus power totaling $107,888,656. The total surlus sales included in base rates is $124,387,177. The increase or decrease in the power sales from base rates is included in the PCA for recovery from or refud to customers and is subject to jurisdictional allocation and sharng. Actual surlus sales were less than base amounts by $16,498,521. This difference is a reduction of revenues to the detriment of customers and is subject to jurisdictional allocation and sharing. STAFF COMMENTS 8 MAY 14,2009 b. Power Purchases including Telocaset and Raft River. Power purchases included in base rates are shown on Line 34, Attchment E. Market purchases, Telocaset Wind Power Parers, and Raft River (the shared portion) are combined in this base number. On the PCA spreadsheet, the actual amounts for these three purchase types are stated as separate line items. During the PCA year ending March 31, 2009, the Company made market purchases, excluding PURPA contracts. The actual amount is $151,742,384. Beginnng in November 2007, Idaho Power began receiving power from Telocaset Wind Power Parners project. This wind project was included in base rates in the last general rate case, Case No. IPC-E-07-08, Order No. 30508. The actual amount included in this year's PCA is $13,720,772. On October 5, 2007, Idaho Power Company fied an application requesting an accounting order authorizing the inclusion of all power supply expenses associated with the purchase of energy from Raft River Energy I LLC in the Power Cost Adjustment mechanism. The underlying Power Purchase Agreement (PPA) for 13 MW is pursuant to a company Request for Proposal for geothermal resources and is the initial agreement with the U.S. Geothermal, Inc. of what wil total 45.5 MW of geothermal energy. In Order No. 30485, the Commission found that the Company's proposal to recover 100% of the Power Purchase Agreement-related costs through its Power Cost Adjustment mechanism to be acceptable only for the first 10 aMW of PPA generation, and that the remaining PPA generation is subject to the PCA treatment accorded non-PURP A projects, and therefore subject to sharng. The actual Raft River amount included for non-PURP A recovery (the shared amount) is $274,426. The remaining Raft River amount is included below in section 7. The total power purchases, including market power, Telocaset Wind Power Parners and the portion of Raft River subject to sharng is $165,737,582 ($151,742,384 plus $13,720,772 plus $274,426). The total power purchases included in base rates is $40,862,142. Actual purchased power amounts exceed base amounts by $124,875,440. This difference is a cost to customers and is subject to jurisdictional allocation and sharng. 7. Actual Qualifying Facilties Purchases Including Net Metering and Raft River. A Qualifying Facilty (QF) is a generating facility which meets the requirements for QF status under the Public Utilty Regulatory Policies Act of 1978 (PURPA) and Part 292 of the Federal Energy Regulatory Commission's Regulations (18 C.F.R. Part 292), and which has obtained certification of its QF status. There are two types of QFs - cogeneration facilties and small STAFF COMMENTS 9 MAY 14,2009 power production facilties. Qualifying Facilties are sometimes referred to as cogeneration/small power producers or by the acronym CSPP. A Cogeneration Facilty is a generating facilty that sequentially produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, residential or institutional puroses, and otherwse meets the requirements of 18 C.F.R. §§ 292.203(b) and 292.205 for operation, efficiency and use of energy output. A Small Power Production Facilty is a generating facility whose primar energy source is renewable (hydro, wind, solar, etc.), biomass, waste, or geothermal resources, and that otherwse meets the requirements of 18 C.F.R. §§ 292.203(a), 292.203(c) and 292.204. Small power production facilties are limited in size to 80 MW, with the exception of certain types of facilties certified prior to 1995 and designated as "eligible" under section 3(17)(E) of the Federal Power Act (FPA) (15 U.S.C. § 796(17)(E), which have no size limitation. For the audit period of April 2008 through March 2009 the actual QF expense is $46,967,783. The Raft River amount included in the tre-up deferral balance at 100% recovery is $4,758,932. The total actual QF expense, including Raft River is $51,726,715. The QF expense included in base rates is $87,541,896. The increase or decrease in the QF expense from base rates is included in the PCA for recovery from or refud to customers. In this year's PCA deferral balance, the actual QF expense was less than the base QF by $35,815,181. This amount is a benefit to customers and reduces the PCA deferral balance. PURP A contracts are not curently subject to sharing. They are subject to jurisdictional allocation. 8. Third Pary Transmission. In Order No. 30715, Case No. IPC-E-08-19, the Commission found that third-pary transmission costs that are incurred in conjunction with market purchases and sales should be tracked through the PCA like other variable power supply costs, and that including the expenses in the PCA is a straightforward treatment of power supply costs that fluctuate with power purchases and sales. For the audit period of April 2008 to March 2009, the actual third par transmission expense is $790,343. The Third Pary Transmission expense included in base rates is $1,650,586. This year's PCA deferral balance includes a difference between costs curently included in rates and actual costs of $860,243. Since the actual costs are less than the amount included in base rates, this amount represents a benefit to customers. This benefit to customers is subject to jurisdictional allocation and sharng. STAFF COMMENTS 10 MAY 14,2009 9. Water Lease Purchases. The actual amount included in the balance for water lease purchases in the curent PCA period is $2,391,740. This is an expense that does not occur in every PCA period. For example, in the last PCA period there were no water lease purchases. However, the PCA is the proper venue for recovery of water lease purchases. This expense is a cost to customers and is subject to jurisdictional allocation and sharing. C. The PCA True-Up of the True-Up The PCA true-up of the true-up amount is the difference between what was anticipated to be collected or refuded when the PCA rate for last year's true-up was set and what was actually collected or refuded. The amount represents the under or over recovery of the true-up amount from the previous year due to a different amount of kWh being sold than was anticipated in the rate design. The true-up of the true-up is a benefit to both the Company and customers because any true-up over collection is returned to customers, and any true-up under collection is recovered by the Company. The true-up amount set for recovery in last year's PCA case (Case No. IPC-E-08-07) was approximately $124.1 millon and the rate calculated to recover that amount from customers was 0.7504 ~/kWh. With other adjustments and interest considerations, the approved rate under collected the true-up amount by $22.0 milion. As shown on page 3 of Attchment D, line 23, this amount is used to calculate the true-up of the true-up PCA rate component of 0.1590 ~/kWh. This is the same rate the Company calculated. PCARATES The Staffs calculated PCA rate of 1.1554 ~/kWh is the sum of the three components listed above (0.2500 + 0.7464 + 0.1590 = 1.1554). This rate is shown on page 3 of Attchment D, line 26. As previously discussed, Staff includes approximately one-half of the Company's updated forecast for the coming year and, therefore, proposes 0.2500 for the forecast rate. The true-up rate, 0.7464, is based on the true-up amounts included in the Company's filing with a small interest adjustment proposed by Staff. The true-up of the true-up rate, 0.1590, is the same rate included in the Company's fiing. Staff Attchment F sumarizes all PCA rate components and their associated expense amounts. Page 1 shows the Company's case and page 2 shows the Staffs case. The Attchments also show amounts allocated to other jursdictions and amounts shared with shareholders. STAFF COMMENTS 11 MAY 14,2009 Page 1 of Attachment G shows the proposed average increase above base rates by class and page 2 of Attachment G shows the proposed average increase above existing rates by class. Staff proposes that existing rates be increased by $50.5 milion which produces an average increase to Idaho Power's customers of6.14%. This compares to the Company's fied proposal to increase rates $93.8 milion, approximately 11.4%. Attachment G shows the proposed increases for all customer classes. Staffs proposed increase for residential customers is 5.01 %. In both of these attachments the percentage increase to larger customers is substantially more than the average percentage increase. When power supply costs increase rates, larger customers receive larger than average percentage increases. This results because large customers have lower base rates than other customers and an equal cents/kWh increase makes a larger percentage difference to them than it does to smaller customers whose base rates are higher. CONSUMER ISSUES Idaho Power's PCA Application, fied on April 15, 2009, contained both the customer notice and press release. Staff reviewed them and determined that they complied with the notice requirements ofIDAPA 31.21.02.102. The customer notice was mailed with Idaho Power's cyclical bilings beginning April 24, 2009 and ending May 22,2009. Customers had until May 14, 2009 to fie comments. An informational customer workshop was scheduled in Boise on May 5, 2009 at 7:00 p.m. No customers attended the meeting. By May 13,2009, thirty-four customers had sent comments to the Commission regarding the PCA. One-third of those who sent comments mentioned that water was seemingly plentiful this year and so did not understand why poor water was cited by Idaho Power as a major factor in its need to increase rates in this year's PCA filing. One-half of those commenting questioned why the curent economic downtur was not a valid reason for the Commission to tell the Company "no" to any rate increases at this time. PCA RECOMMENDATIONS The Staffs recommendation differs substantially from the Company's in the amount of the forecast to be passed to customers in this year's PCA rates. In addition to the reasons for Staffs recommendation that have been previously given, Staff believes that the large tre up rate that will almost certainly be put in place in this case will expire next year. Staff believes that it is STAFF COMMENTS 12 MAY 14,2009 probable that the remainder of the unecovered forecast can be moved to next year's true up without a rate increase. Staff recommends that a PCA rate of 1.1554 ~/kWh be established by the Commission with an effective date of June 1,2009. Respectfully submitted this 144J day of May 2009. 0~ Weldon B. Stutzman Deputy Attorney General Technical Staff: Keith Hessing Kathy Stockton Marilyn Parker i:umisc/commentsipce09. I I wskhklsmp comments STAFF COMMENTS 13 MAY 14,2009 enl-Z::o~ ic ico C. LLo ~ol- en-i: iesudo o cio(' ocioN ociin qo -qoin-qoin ocio'\ qoinN (SJeIiOa jO suomiw) ¡unow'f 'f~d en en0O'0 inN'\ en I'0 ct00NN tX 00((0 0N'\ I'I'00 0N(' CD tX0((0 "'N - in '\0 ct0NI' "'tX0ci0NI' ('~00 '\N tX N N0ci ~0 "'caNN~'\N0ci c:0 NNN 00tXD-O -.0N '\ en NenctenN'\- tX ('en i-en'\'\ I'I'en cOen'\'\- CD CDenI'en '\'\- inen exen "'I'en -.en '\ ('enenen-.'\ (J a-..c:::0 00E'\-oc ocÜ0- Il ÀtÜichlint A Case No. IPC-E-09- i i Staff Comments 05/14/09 (f UJi- ~ )- )- Z CD rÎa: ~ UJ 0.. ZUJ Ü S -T-J a: ;: 4: UJ ; i- $ gZ O~UJ a. !.o 0 'Ë (f i ~UJ 4:a: 0 UJ a: CD 0 ~ u. UJ ~ ~.. ..o cD ~., ~.... ..;i.,~~". ..~., ~.. ¡g". Q) 5l'" '" ~ m ~'" 0 Q)a:.! 0 ~ (3 (3ai 0- 0- III ~~I ~ ..'.'.¡ I, ¡ß.. ! ~ ~.. g.. R.. 8N 8N igoN ..ooN ;b ~ ~E gIf $LL Q)If:e g l!LL ~ ~ l5 ~ ~:: ~ ~ju: ~ ItooN (l:; C" ~ 8N o ti:;0 ..~æ !UJ ~ ~ ~() ~ a) E'~() ~o¡: ~ ~ §E ~ ~ ~ g ~ l Q)If~I- .. ;.o os :; :: ogN aiaiai.. co 8l.. .. 8l.. CD 8l.. It 8l.. ¡.. ~ ~ ~ ~ ~ ~ ~ IAttaclient B ji Case No. IPC-E-09- i 1 :; Staff Comments 05/14/09 z0-I-Uw~0cr '-t't'Q.cv t' )0 J(Jl-e:0 V)U iUJ0C.iUU0a.'l0 . 2=N 0z Q.Ol OJQ.0 V'ro::0 uNV) crw S OJ0V'roQ.co.IDmII oom oIIN oo.- o ~ oII.- oII ôe g.--ÔII.-- (SUOHIIII) asuadx3 AlddnS JaMOd ttac ent C Case No. IPC-E-09- i i Staff Comments .05/14/09 ca:ii:i: c:..-i: (1(1- T"i: T" ~ en(1 9 en U¡ i (. c: a.U C-o"Io~0'ooN Q)IIns(.::r: nsc. Eo(. ~.9 s ~~ ~ ~ ê ~I ~i: ~ ~ (5 -in 8 ~ou. ~I ~I i o:. ..._ 0 .. T"to 0in NQ) i00)ooN r:o ~ Q) ~a. .. LO -. -. ..-. 0) -. M LOqòO.CD.;'t- LO CD .LO 0000o .. LOcr .. ..0) 0).. -. .. MM 0) -.t- C\ -. r- cr a5t- M M c- LO. 00.00 00 0)0.. 00C\ .. C\o LO.o00t-.o0) ~~___-_I :§tF tF tF ef tF ~ ~-----~ ~--~ i:on::"0 enQ) Q)a: ëiQ) (/ê E~ ü:Q) Q) Een~a: 0lQ) E0.. COu.$Q)LOu ëi:~~~o Q)Q)~Q)ff ~~(/efen_Q)Q)t:~:£ a5 .¡g u a. 0 N .. o.x u. a5 gi "OQ) ëi .E :: ...- EUJ..:mCiCi...$ -t 0 ._ .r .r 0 coüiO(/(/za:a. .. LO-. CDÒ õ) -. õ)CD M 00C\ CD t-. - 0C\ CD .0000LO LO --~..~.. oC\CDr- CDt-... LO 0)0000. 0) CD"!M CD ~Î~tF 3: .---;2 ~--~ en Q)ëi(/ E ü: en ~ E Eo .$ .$o en-~$~Q) "0 0en Q) 0 a5 .!: :: ~ ëi .E UJ E .$ -t 0 coÜ z a:a. õ) N00 cot- co~ It 8- ò :2 ~~ ~ ii cou~ou. ëi ~ I CD Ñ It0) M cot- M -.t- 0 t-Ò e,c: o m.. c: .. -. M.. CD LO.. 00 00-. t- CD"'òò l!~co0. .$~ .92~i: Q).0 ~ 'õ.!2i:::o E co "0i: co en ~ Q).:: ñíOl Q)z 2oz ~ :s1.. C\ M -. LO CD t- 00 0) ~ ~ ~ ~ :; LO CD t ~ ~ ~ N gi ~ ~ ~ ~ ~ g; ~ g I LO 00CD -.LO t-CD CD00 0)M t-CD ..0) Mt- Mr- òi I 0) 0)00 00CD CD a5 a5M M00 00 C" C".. .. § 0) C\ t-CD M Mt-. ~ .... ..00) 0) 000. LO. M. t- -. Mo 0.. .. õòoi0)oiUJ Ó _ 0) a. co0--o c:~~ z co Q)o eno coN8..:= o "0~:: Ü i C\Q) 0~ (/l-I- CDLO0)CD000)0)00ia 0)00 CD a5M00. M.. LOMM. MooÑC\ :2:2 :2 ~ ~ ~-. -. -."$ "$ "$-- ---- ::I Q) 2I- Q).r-..o ::i Q)~l-I- ..Q) ¡gtJ )-m _ .!! E U.ro:m f- ù: UJ .9 C .5 rnQ) :: Q)E ;i )-_ i:_~ ~ en 'õ :; ~lI-tü i -ê.$.$~n. co co i: a: a: a: ~ c( -t -t :m(. ~ ~ i:a. ÁttacbmentD Case No. IPC-E-09-11 Staff Comments 05/14/09 Page 1 of3 'i:: i:i: CIi: a: c: Q. :5 0i: "Q) Q)~ ñSi: 'l "'l C. ~ ~ :: Q) 9 .iCI W ~ . cj ~ c: Q. ~(. CIQ. ()o ~~ CIo c.~ Een 0o ()oN ~-9 s ~ ~~ ~ ê ~c ~ Q):io -en ~ ~ou. ~I ~I ~ o:; ..._ 0'- 'l() 0en NQ) . o enooN i:o ~ Q)o..Q. ~I LO LO 00 -. coC" Ol 0 C" LO LO. c: Ol. co. tõC\ C" co .I" LO 00 0C" Ol LOet M"¡00 00.. 00 .. I"C\ Ol C"C" "! o. C\ Ol C"Ol C" LOco LO .. i- et cr Ol .. I".. .. C\o LOo001".oOl ~~-. -. .. .. ..:i 5 E/H/7 El ~ El S :s------"'''~ ""--~ i:o~::"0 enQ) Q)ci ëõQ) C/ê EQ) i. ã) Q) Een~ci 0lQ) Q) E0.. j9U..Q)LO U i: i: !!::~o ~~cí~Q)ãi ..Q) 0en .. Q) 0.Q) !É ~ OlLOi: en u 0 .N_ ..~ù:i:Ol"O-OX Q)i:Q)tI_:: ...- EUJ.. & (¡ (¡ .. 2c: 0 .- .. .. 0 tiüiOC/C/zcia. co LOI" LO c: m'V ã)co C" 00C\ co I". .0C\ co .0000LO LO --~.... ..-- oC\co. I"co1"... LO Ol0000. Olco"! C"co ~Î¡El S ~--:2 ~--~ en Q) ëõC/ E _ ü: rn ~ E Eå 2 2o en - ~ di '#Q) "0 0en Q) 0i: N.. ~= 5x ti -UJ E 2c: 0 tiüz cia. õì00I"o e. "'CD ~c: :2 ~--~ ~ci 1itiU ~ou. ßoI- I co ÑinOl C" CDI" C" -.I' 0 "'o e. c: oenin.. c: N -. 00N co LO000..-. I" co .. c: c: ~ Q)~a.2~ .9.l 'ai: Q).0 ~'õ.5 .li:::oEti "0i:ti en ~ ~~ á3z .$oZ E §I.. C\ C" -. LO co I" 00 Ol ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ N ~ ~ ~ ~ ~ ~ ~ g¡ g I LO 00co -.LO I"co co00 OlC" I"co ..Ol C" I' "lI" 9 I Ol Ol00 00co co et etC" C"00. CX C" C".. .. § Ol Ñ I"co C" C" 1". co. ..'I T" aOl Ol 000 LO C"i- .. Mo --0.. cooiOlo W0_en a. ti0-: Õo 0 I-~ Z CO Q)o g¡~8 Õ :g~:: ü . C\ Q) 0 ;: C/..i- coLOOlco00OlOl00 LC Ol00co. 00C"00. C".. LOC"C"MooÑC\ :2 :2:2 ~ ~ ~-- -- --"$ "$ "$"'''.. ::. Q);:..i- Q).i- Õ .. g¡ ~ti rCO en E 1: :e0&1- ù: UJ .9 C .5 ro Q) ;: Q) E:¡ r.. i: ..~ ~ en 'õ :s jen c: ü i ~ 2 2 ~'"~ ti ti i:~ ci ci ~ c( c: c: &,,, ü ü.-..0.0.0Q. ::. Q);:..i- Attachmenfb Case No. IPC-E-09-11 Staff Comments 05/14/09 Page 2 of3 20 0 9 - 2 0 1 0 p e A - S e v e n t e e n t h A n n u a l IP C - E - 0 9 - 1 1 St a f f C a s e (a ) (b ) (c ) (d ) (e ) (f ) (g ) Li n e De s c r i p t i o n Un i t s Ba s e Fo r e c a s t Di f f e r e n c e Ra t e 1 Pr o j e c t i o n 2 0 0 9 - 2 0 1 0 : 2 PC A E x p e n s e ( 9 5 % ) ($ ) 90 , 7 8 0 , 5 0 2 15 9 , 8 2 0 , 1 0 2 3 Ho k u F i r s t B l o c k R e v e n u e R e d u c t i o n ($ ) 18 , 5 3 9 , 2 9 1 4 Di f f e r e n c e ($ ) 14 1 , 2 8 0 , 8 1 1 50 , 5 0 0 , 3 0 9 5 Sh a r i n g P e r c e n t a g e (% ) 0. 9 5 6 Sh a r e d D i f f e r e n c e ($ ) 47 , 9 7 5 , 2 9 3 7 No r m a l i z e d S y s t e m F i r m S a l e s (M W H ) 14 , 5 8 6 , 6 3 4 8 Ra t e f o r 9 5 % I t e m s (Ø / k W h ) 0. 3 2 8 9 0. 3 2 8 9 9 10 PC A E x p e n s e ( 1 0 0 % ) ($ ) 63 , 2 6 9 , 8 8 9 51 , 7 6 7 , 6 2 0 (1 1 , 5 0 2 , 2 6 9 ) 11 No r m a l i z e d S y s t e m F i r m S a l e s (M W H ) 14 , 5 8 6 , 6 3 4 12 Ra t e f o r 1 0 0 % I t e m s (Ø k W h ) (0 . 0 7 8 9 ) (0 . 0 7 8 9 ) 13 14 To t a l F o r e c a s t R a t e (Ø / k W h ) 0. 2 5 0 0 15 16 17 æ (M W h ) ($ / M W h ) (r t / k W h ) 18 19 Tr u e - U p o f 2 0 0 8 - 2 0 0 9 : 10 7 , 8 9 1 , 7 6 9 13 , 8 3 8 , 6 8 9 7. 7 9 6 3 8 6 5 6 5 0. 7 7 9 6 20 S0 2 C r e d i t ( O r d e r N o . 3 0 7 9 0 ) (4 , 6 0 0 , 8 5 7 ) 13 , 8 3 8 , 6 8 9 -0 . 3 3 2 4 6 3 3 5 7 (0 . 0 3 3 3 ) 21 To t a l 10 3 , 2 9 0 , 9 1 2 0. 7 4 6 4 22 23 Tr u e - U p o f t h e T r u e - U p : 22 , 0 0 3 , 3 3 5 13 , 8 3 8 , 6 8 9 1. 5 8 9 9 8 6 9 5 6 0. 1 5 9 0 24 25 PC A R a t e s : 26 PC A R a t e A d j u s t m e n t F r o m B a s e (Ø / k W h ) I 1. 1 5 5 4 1 oc n ( ' ~ 27 PC A R a t e C u r r e n t l y i n E f f e c t (Ø / k W h ) 0. 7 8 6 4 ~ i t i : : : 28 Di f f e r e n c e - L a s t Y e a r t o T h i s Y e a r (Ø / k W h ) 0. 3 6 9 0 ¡: t : ~ í ! ô( ' Z š ' 29 1. 0 0 ~. t Ð 30 No t e : N e g a t i v e r a t e s a n d a m o u n t s i n d i c a t e b e n e f i t s t o r a t e p a y e r s . -I : "t " t . . tÐ ( ' C I ~ I : i tÐ ¡ ; t ¡ VJ 0 0 1. i .. - VJ - MWh mlKWh $ TRUE.UP CALCULATIONS FOR 2008.2009 FOR IDAHO POWER COMPANY PCA CASE NO. IPC.E-09-11 Units 2008 APR 2008 MAY 976,345 1.888 1,843,339 1,332,870 1,224,099 108,771 (3,414,866) o 126,300 8,351,409 523,859 192 15,471,139 840,326 20,317 (8,438,165) (3,414,866) 13,480,511 5,895,851 201,811 91,967 729,244 (3,994,247) 62,270 (117,779) 2,869,118 2008 JUN 1,119,936 0.000 o 1,472,374 1,426,753 45,621 (1,432,271) o 20,562 9,218,290 980,515 292,746 9,038,922 1,172,124 o (5,257,208) (1,432,271 ) 14,033,679 9,956,571 532,587 661,799 3,797,607 ( 12,252,659) 74,340 (118,945) 2,651,300 2008 JUL 1,321,246 0.000 o 1,765,357 1,702,096 63.261 (1,986,079) o 32,578 12,316,271 1,848,884 61,966 24,467,254 1,615,081 o (8,082,568) (1,986,079) 30,273,387 9,956,571 532,587 661,799 3,797,607 (12,252,659) 74,340 (118,945) 2,651,300 2008 AUG 1,413,185 0.000 o 1,628,972 1,588,393 40,579 (1,273,978) 1,080,695 29,738 13,603,945 2,764,934 1,245,723 21,546,747 1,238,395 o (9,669,473) (1,273,978) 30,566,726 9,956,571 532,587 661,799 3,797,607 (12,252,659) 74,340 (118,945) 2,651,300 2008 SEPT 1,272,063 0.000 o 1,268,631 1,247,908 20,723 (650,599) 1,108,842 44,700 12,226,463 2,525,520 68,538 10,351,039 722,368 23,424 (13,698,132) (650,599) 12,722,162 9,956,571 532,587 661,799 3,797,607 (12,252,659) 74,340 (118,945) 2,651,300 2008 OCT 1,035,883 0.000 o 1,115,235 1,130,773 (15,538) 487,816 (6,797) 55,584 10,452,157 651,098 21,307 8,032,251 1,156,550 34,159 (8,694,596) 487,816 12,189,529 9,956,571 532,587 661,799 3,797,607 (12,252,659) 74,340 (118,945) 2,651,300 12 DESCRIPTION 3 PCA Revenue 4 Normalized Idaho Jurisd. Sales 5 Forecast Rate 6 Revenue 7 8 Load Change Adjustment 9 Actual System Firm Load - Adjusted 10 Normalized Firm Load 11 Load Change 12 Expense Adjustment 13 14 Non-QF PCA 15 ACTUAL: 16 Water Lease Purchases 17 Cloud Seeding Program 18 Fuel Expense - Coal 19 Fuel Expense - Danskin 20 Fuel Expense - Bennett Mountain 21 Non-Firm Purchases 22 Telocaset Wind Power Partners 23 Raft River 90% 24 Third Part Transmission 25 Surplus Sales 26 Expense Adjustment27 Sub-Total 28 29 BASE: 30 Fuel Expense - Coal 31 Fuel Expense - Danskin 32 Fuel Expense - Bennett Mountain 33 Third Party Transmission 34 Non-Firm Purchases 35 Surplus Sales 36 Cloud Seeding Expense 37 Cloud Seeding Benefit38 Sub-Total 39 40 Change From Base 41 Emission Allowance Sales Credit42 Sub-Total 43 44 Deferral (Shared and Allocated) 45 46 OF Deferral 47 Actual (includes Net Metering) 48 Raft River 100% 49 Base 50 51 Change From Base 52 Deferral (Allocated) 53 54 Total Deferral (-6+41+48) 55 56 Principal Balances 57 Beginning Balance 58 Amount Deferred 59 Ending Balance 60 61 Interest Balances 62 Accrual thru Prior Month 63 Interest I! 5% per Year 64 Prior Month's Interest Adj. 65 Total Current Month Interest 66 Interest Accrued to Date 67 Balance (True-Up & Interest) 68 69 True-Up of the True-Up 70 True-Up Revenues (Collections) 71 72 Beginning Balance 73 Adjustments: 74 2007-08 PCA Transfer - ON 30563 75 Emmission Allowance - ON 30529 76 Correction for Change in Base77 Sub-Total 78 Interest 1!5% per Year 79 Revenue Applied to Interest 80 Revenue Applied to Balance 81 True-Up ofthe True-Up Balance 82 83 Note: Negative amounts indicate benefi to ratepayers 963,083 1.888 1,818,301 MWh MWh MWh $ 1,118,663 1,099,424 19,239 (604,008) 10,611,393 o 10,611,393 9,044,090 4,220,848 317,768 7,756,719 11,382,379 o 11,382,379 9,701,202 6,252,968 398,539 7,756,719 27,622,087 o 27,622,087 23,542,305 7,018,593 406,222 7,756,719 27,915,426 o 27,915,426 23,792,317 6,117,259 488,600 7,756,719 10,070,862 o 10,070,862 8,583,396 4,459,879 398,661 7,756,719 9,538,229 o 9,538,229 8,129,432 3,415,233 411,525 7,756,719 $ $ $ $ $ $ $ $ $ $ $ $ o 24,877 7,833,016 795,176 345,664 8,746,377 722,694 9,927 (8,677,754) (604,008) 9,195,968 $ $ $ $ $ $ $ $ $ 5,895,851 201,811 91,967 729,244 (3,994,247) 62,270 (117,779) 2,869,118 $ $ $ 6,326,849 o 6,326,849 $5,392,374 $ $ $ 2,265,467 264,768 7,756,719 $ $ (5,226,485) (4,949,481 ) $(1,375,408) $ $ $ o (1,375,408) (1,375,408) $ $ $ $ $ $ o o 440 440 440 (1,374,968) $529,379 $4,862,487 $ $ $ $ $ $ $ $ 124,101.211 I (9,937,989) o 119,025,709 495,940 495,940 33,439 118,992,270 (3,218,104) (3,047,544) 4,153.207 (1,375,408) 4,153,207 2,777,799 440 (5,731) 58 (5,672) (5,233) 2,772,567 554,444 118,992,270 o o (6,63,350) 112,528,920 468,871 468,871 85,573 112,443,347 (1,105,212) (1,046,636) 8,654,566 2,777,799 8,654,566 11,432,365 (5,233) 11,574 (50,713) (39,139) (44,371) 11,387,994 3,944,458 112,443,347 o (6,503,62) o 105,939,886 441,416 441,416 3,503,042 102,436,843 (331,905) (314,314) 23,227,991 11,432,365 23,227,991 34.660,356 (44,371)47,635 176 47,811 3,440 34,663,796 11,411,725 102,436,843 o o o 102,436,843 426,820 426,820 10,984,905 91,451,939 (1,150,860) (1,089,865) 22,702,453 34,660,356 22,702,453 57,362,809 3,440 144,418 71 144,489 147,929 57,510,737 11,485,090 91,451,939 o o o 91,451,939 381,050 381.050 11,104,041 80,347,898 (2,898,179) (2,744,576) 5,838,820 57,362,809 5,838,820 63,201,629 147,929 239,012 2,840 241,852 389,780 63,591,409 10,337,799 80,347,898 o o o 80,347,898 334,783 334,783 10,003,016 70,344,882 (3,929,962) (3,721,674) 4,407,759 63,201,629 4,407,759 67,609,387 389,780 263,340 (32) 263,308 653,088 68,262,476 8,225,629 70,344,882 N..o o o o 70,344,882 293,104 293,104 7,932,525 62,412,357 ....I0-o ,~) '" eu.. ~ OJJiUeu(l~e: Si: ~ Ó § 0-.. Z U ~g eui::!:i ~ (i---:uri;g TRUE-UP CALCULATIONS FOR 2008 - 2009 FOR IDAHO POWER COMPANY PCA CASE NO. IPC-E-09-11 1 2008 2008 2009 2009 2009 2 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS 3 PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 979,253 1,077,805 1,164,548 1,126,968 1,050,386 13,500,701 5 Forecast Rate mlKWh 0.000 0.000 0.000 0.000 0.000 6 Revenue $0 0 0 0 0 3,661,640 7 8 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 1,114,596 1,347,176 1,320,346 1,138,662 1,148,734 15,771,616 10 Normalized Firm Load MWh 1,173,167 1,370,562 1,323,48 1,184,072 1,181,622 15,652,317 11 Load Change MWh (58,571)(23,386)(3,102)(45,410)(32,888)119,299 12 Expense Adjustment $1,838,837 734,203 97,387 1,209,268 875,807 (4,118,482) 13 14 Non.QF peA 15 ACTUAL: 16 Water Lease Purchases $0 69,000 140,000 0 0 2,391,740 17 Cloud Seeding Proram $61,444 79,398 133,603 0 0 608,785 18 Fuel Expense - Coal $13,006,576 10,978,921 13,243,306 11,994,470 12,557,316 135,782,138 19 Fuel Expense - Danskin $484,053 839,095 255,231 155,487 297,782 12,121,634 20 Fuel Expense - Bennett Mountain $0 490,939 105,014 100,123 342,784 3,074,997 21 Non-Firm Purchases $9,473,727 23,680,009 10,059,449 6,255,708 4,619,761 151,742,384 22 Telocaset Wind Power Partners $1,217,317 1,713,806 828,367 1,551,481 942,263 13,720,772 23 Raft River 90%$47,280 56,565 44,961 37,794 0 274,426 24 Third Party Transmission $159,220 631,123 790,343 25 Surplus Sales $(4,910,636)(12,847,951)(8,360,403)(6,018,465)(13,233,304)(107,888,656) 26 Expense Adjustment $1,838,837 734,203 97,387 1,209,268 875,807 (4,118,482) 27 Sub-Total $21,218,598 25,793,987 16,546,916 15,445,087 7,033,532 208,500,082 28 29 BASE: 30 Fuel Expense - Coal $9,956,571 9,956,571 9,956,571 10,914,656 10,124,913 112,483,839 31 Fuel Expense - Danskin $532,587 532,587 532,587 454,259 421,390 5,539,968 32 Fuel Expense - Bennett Mountain $661,799 661,799 661,799 46,692 43,313 5,568,331 33 Third Party Transmission $856,271 794,315 1,650,586 34 Non-Firm Purchases $3,797,607 3,797,607 3,797,607 4,680,739 4,342,058 40,862,142 35 Surplus Sales $(12,252,659)(12,252,659)(12,252,659)(9,533,614)(8,843,798)(124,387,177) 36 Cloud Seeding Expense $74,340 74,340 74,340 719,261 37 ClOud Seeding Benefi $(118,945)(118,945)(118,945)(1,187,118) 38 Sub-Total $2,651,300 2,651,300 2,651,300 7,419,003 6,882,191 41,249,830 39 40 Change From Base $18,567,298 23,142,687 13,895,616 8,026,084 151,341 167,250,251 41 Emission Allowance Sales Credit $0 0 0 0 0 0 42 Sub-Total 18,567,298 23,142,687 13,895,616 8,026,084 151,341 167,250,251 43 44 Deferral (Shared and Allocated)$15,824,908 19,724,512 11,843,234 7,227,529 136,283 142,941,582 45 46 OF Deferral 47 Actual (includes Net Metering)$2,858,837 3,020,493 2,740,686 2,358,238 2,239,284 46,967,783 48 Raft River 100%$476,488 491,282 419,932 380,527 304,621 4,758,932 49 Base $7,756,719 7,756,719 7,756,719 5,174,557 4,800,146 87,541,896 50 51 Change From Base $(4,421,394)(4,244,945)(4,596,101)(2,435,793)(2,256,242)(35,815,180) 52 Deferral (Allocated)$(4,187,060)(4,019,963)(4,352,507)(2,308,888)(2,138,691 )(33,921,198) 53 54 Total Deferral (-6+41 +48)$11,637,848 15,704,549 7,490,726 4,918,641 (2,002,408)105,358,743 55 56 Principal Balances 57 Beginning Balance $67,609,387 79,247,235 94,951,784 102,442,511 107,361,152 58 Amount Deferred $11,637,848 15,704,549 7,490,726 4,918,641 (2,002,408)105,358,743 59 Ending Balance $79,247,235 94,951,784 102,442,511 107,361,152 105,358,743 60 61 Interest Balances 62 Accrualthru Prior Month $653,088 933,061 1,263,257 1,658,845 2,085,687 63 Interest I§ 5% per Year $281,706 330,197 395,632 426,844 447,338 2,581,965 64 Prior Month's Interest Adj.$(1,733)(0)(45)(2)0 (48,940) 65 Total Current Month Interest $279,972 330,196 395,588 426,842 447,338 2,533,025 66 Interest Accrued to Date $933,061 1,263,257 1,658.845 2,085,687 2,533,025 67 Balance (True-Up & Interest)$80,180,296 96,215,042 104,101,356 109,446,839 107,891,769 107,891,769 68 69 True-Up of the True-Up 70 True-Up Revenues (Collections)$7,443,790 8,294,817 9,233,397 8,568,835 7,837,555 87,866,917 71 -N 72 Beginning Balance $62,412,357 55,228,619 47,163,921 38,127,041 29,717,069 4,862,487 -..i 73 Adjustments:0\00N742007-08 PCA Transfer - ON 30563 $0 0 0 0 0 124,101,211 i~vi Q) 75 Emmission Allowance - ON 30529 $0 0 0 0 0 (16,441,450)-OJ~Ù Q 76 Correction fOr Change in Base $0 0 0 0 0 (6,463,350)Q) tt-~S ~77 Sub-Total $62,412,357 55,228,619 47,163,921 38,127,041 29,717,069 106,058,897 Q - 78 Interest I§ 5% per Year $260,051 230,119 196,516 158,863 123,821 Æ ó S 0\ZOO79 Revenue Applied to Interest $260,051 230,119 196,516 158,863 123,821 3,811,355 U __ 80 Revenue Applied to Balance $7,183,738 8,064,698 9,036,880 8,409,972 7,713,734 84,055,562 Co Q) s. ~ 81 True-Up of the True-Up Balance $55,228,619 47,163,921 38,127,041 29,717,069 22,003,335 22,003,335 ~ vi 't ::~ tt_on 82 U C/ 0 83 Note: Negative amounts indicate benefi to ratepayers Di v i s i o n o f P o w e r C o s t s IP C - E - 0 9 - 1 1 Co m p a n y C a s e De s c r i p t i o n In i t i a l Al l o c a t e d Sh a r e d Id a h o C u s t o m e r Id a h o Am o u n t to O t h e r wi t h Re v e n u e PC A Ju r i s d i c t i o n s S h a r e h o l d e r s Re q u i r e m e n t Ra t e s ($ ) ($ ) ($ ) ($ ) (t / k W h ) Fo r e c a s t ( 2 0 0 9 - 2 0 1 0 ) No n - O F P o w e r S u p p l y C o s t D i f f e r e n c e 99 , 0 5 7 , 9 4 1 5, 1 6 0 , 9 1 9 4, 6 9 4 , 8 5 1 89 , 2 0 2 , 1 7 1 OF P o w e r S u p p l y C o s t D i f f e r e n c e (1 1 , 5 0 2 , 2 6 9 ) (5 9 9 , 2 6 8 ) (1 0 , 9 0 3 , 0 0 1 ) Su b - T o t a l 87 , 5 5 5 , 6 7 2 4, 5 6 1 , 6 5 1 4, 6 9 4 , 8 5 1 78 , 2 9 9 , 1 7 0 0. 5 6 6 2 Tr u e U p ( 2 0 0 8 - 2 0 0 9 ) Re v e n u e f r o m F o r e c a s t R a t e (3 , 6 6 1 , 6 4 0 ) (3 , 6 6 1 , 6 4 0 ) No n - O F P o w e r S u p p l y C o s t D i f f e r e n c e 17 1 , 3 6 8 , 7 3 3 9, 0 7 7 , 0 6 0 15 , 9 4 0 , 4 2 0 14 6 , 3 5 1 , 2 5 3 Lo a d G r o w t h A d j u s t m e n t (4 , 1 1 8 , 4 8 2 ) (2 2 0 , 1 5 6 ) (4 8 8 , 6 5 5 ) (3 , 4 0 9 , 6 7 1 ) OF P o w e r S u p p l y C o s t D i f f e r e n c e (3 5 , 8 1 5 , 1 8 0 ) (1 , 8 9 3 , 9 8 2 ) 0 (3 3 , 9 2 1 , 1 9 8 ) In t e r e s t D u r i n g D e f e r r a l P e r i o d 2, 5 3 3 , 0 2 5 2, 5 3 3 , 0 2 5 Su b - T o t a l 13 0 , 3 0 6 , 4 5 6 6, 9 6 2 , 9 2 2 15 , 4 5 1 , 7 6 6 10 7 , 8 9 1 , 7 6 9 Em i s s i o n A l l o w a n c e C r e d i t ( I P C - E - 0 9 - 0 8 ) (4 , 5 9 1 , 6 3 2 ) (4 , 5 9 1 , 6 3 2 ) Su b - T o t a l 12 5 , 7 1 4 , 8 2 4 6, 9 6 2 , 9 2 2 15 , 4 5 1 , 7 6 6 10 3 , 3 0 0 , 1 3 7 0. 7 4 6 5 Tr u e U p o f t h e T r u e U p Am o u n t C a r r i e d F o r w a r d 4, 8 6 2 , 4 8 7 4, 8 6 2 , 4 8 7 Ot h e r L i m i t e d T e r m A d j u s t m e n t s : 20 0 7 - 0 8 P C A T r a n s f e r - O N 3 0 5 6 3 12 4 , 1 0 1 , 2 1 1 12 4 , 1 0 1 , 2 1 1 Em m i s s i o n A l l o w a n c e - O N 3 0 5 2 9 (1 6 , 4 4 1 , 4 5 0 ) (1 6 , 4 4 1 , 4 5 0 ) Co r r e c t i o n f o r C h a n g e i n B a s e (6 , 4 6 3 , 3 5 0 ) (6 , 4 6 3 , 3 5 0 ) In t e r e s t D u r i n g A m o r t i z a t i o n 3, 8 1 1 , 3 5 5 3, 8 1 1 , 3 5 5 o r : ( J ~ ' Co l l e c t i o n s f r o m T r u e U p R a t e (8 7 , 8 6 6 , 9 1 7 ) (8 7 , 8 6 6 , 9 1 7 ) Vl . . ~ g -- ~ ' " :¡ ~ ( l n Su b - T o t a l 22 , 0 0 3 , 3 3 5 0 0 22 , 0 0 3 , 3 3 5 0. 1 5 9 0 -- ( J Z § ' 00 0 '0 § . ( l -: : '" . . To t a l P o w e r C o s t A d j u s t m e n t ( P C A ) 23 5 , 2 7 3 , 8 3 2 11 , 5 2 4 , 5 7 2 20 , 1 4 6 , 6 1 7 20 3 , 6 0 2 , 6 4 2 1 1. 4 7 1 7 1 '" ( l ( J ' " ~ : : l ~ ~ ~ 0 0 '0i .. - N - Di v i s i o n o f P o w e r C o s t s IP C - E - 0 9 - 1 1 St a f f C a s e De s c r i p t i o n In i t i a l Al l o c a t e d Sh a r e d Id a h o C u s t o m e r Id a h o Am o u n t to O t h e r wi t h Re v e n u e pe A Ju r i s d i c t i o n s S h a r e h o l d e r s Re q u i r e m e n t Ra t e s ($ ) ($ ) ($ ) ($ ) (~ / k W h ) Fo r e c a s t ( 2 0 0 9 - 2 0 1 0 ) No n - O F P o w e r S u p p l y C o s t D i f f e r e n c e 50 , 5 0 0 , 3 0 9 2, 6 3 1 , 0 6 6 2, 3 9 3 , 4 6 2 45 , 4 7 5 , 7 8 1 OF P o w e r S u p p l y C o s t D i f f e r e n c e (1 1 , 5 0 2 , 2 6 9 ) (5 9 9 , 2 6 8 ) (1 0 , 9 0 3 , 0 0 1 ) Su b - T o t a l 38 , 9 9 8 , 0 4 0 2, 0 3 1 , 7 9 8 2, 3 9 3 , 4 6 2 34 , 5 7 2 , 7 8 0 0. 2 5 0 0 Tr u e U p ( 2 0 0 8 - 2 0 0 9 ) Re v e n u e f r o m F o r e c a s t R a t e (3 , 6 6 1 , 6 4 0 ) (3 , 6 6 1 , 6 4 0 ) No n - O F P o w e r S u p p l y C o s t D i f f e r e n c e 17 1 , 3 6 8 , 7 3 3 9, 0 7 7 , 0 6 0 15 , 9 4 0 , 4 2 0 14 6 , 3 5 1 , 2 5 3 Lo a d G r o w t h A d j u s t m e n t (4 , 1 1 8 , 4 8 2 ) (2 2 0 , 1 5 6 ) (4 8 8 , 6 5 5 ) (3 , 4 0 9 , 6 7 1 ) OF P o w e r S u p p l y C o s t D i f f e r e n c e (3 5 , 8 1 5 , 1 8 0 ) (1 , 8 9 3 , 9 8 2 ) 0 (3 3 , 9 2 1 , 1 9 8 ) In t e r e s t D u r i n g D e f e r r a l P e r i o d 2, 5 3 3 , 0 2 5 2, 5 3 3 , 0 2 5 Su b - T o t a l 13 0 , 3 0 6 , 4 5 6 6, 9 6 2 , 9 2 2 15 , 4 5 1 , 7 6 6 10 7 , 8 9 1 , 7 6 9 Em i s s i o n A l l o w a n c e C r e d i t ( I P C - E - 0 9 - 0 8 ) (4 , 6 0 0 , 8 5 7 ) (4 , 6 0 0 , 8 5 7 ) Su b - T o t a l 12 5 , 7 0 5 , 5 9 9 6, 9 6 2 , 9 2 2 15 , 4 5 1 , 7 6 6 10 3 , 2 9 0 , 9 1 2 0. 7 4 6 4 Tr u e U p o f t h e T r u e U p Am o u n t C a r r i e d F o r w a r d 4, 8 6 2 , 4 8 7 4, 8 6 2 , 4 8 7 Ot h e r L i m i t e d T e r m A d j u s t m e n t s : 20 0 7 - 0 8 P C A T r a n s f e r - O N 3 0 5 6 3 12 4 , 1 0 1 , 2 1 1 12 4 , 1 0 1 , 2 1 1 Em m i s s i o n A l l o w a n c e - O N 3 0 5 2 9 (1 6 , 4 4 1 , 4 5 0 ) (1 6 , 4 4 1 , 4 5 0 ) Co r r e c t i o n f o r C h a n g e i n B a s e (6 , 4 6 3 , 3 5 0 ) (6 , 4 6 3 , 3 5 0 ) o r . ( " ~ ! In t e r e s t D u r i n g A m o r t i z a t i o n 3, 8 1 1 , 3 5 5 3, 8 1 1 , 3 5 5 ~ S ' P o : : Co l l e c t i o n s f r o m T r u e U p R a t e (8 7 , 8 6 6 , 9 1 7 ) (8 7 , 8 6 6 , 9 1 7 ) ¡: ~ r t ~ Su b - T o t a l 22 , 0 0 3 , 3 3 5 0 0 22 , 0 0 3 , 3 3 5 0. 1 5 9 0 -- ( " Z § " 00 0 '0 § . G .. : : 'i ' i - To t a l P o w e r C o s t A d j u s t m e n t ( P C A ) 18 6 , 7 0 6 , 9 7 5 8, 9 9 4 , 7 2 0 17 , 8 4 5 , 2 2 8 15 9 , 8 6 7 , 0 2 7 1 1. 1 5 5 4 1 G ( " " T cf : : i G ¡ ; t ; IV 0 0 '0i .. .. IV .. IP C - E - 0 9 - 1 1 Id a h o P o w e r C o m p a n y Su m m a r y o f R e v e n u e I m p a c t St a t e o f I d a h o No r m a l i z e d 1 2 - M o n t h s E n d i n g D e c e m b e r 3 1 , 2 0 0 8 ST A F F C A S E Ba s e R a t e s t o 6 / 1 / 0 9 p e A (1 ) (2 ) (3 ) (4 ) (5 ) (6 ) (7 ) (8 ) Ra t e 20 0 8 A v g . 20 0 8 S a l e s 04 / 0 1 / 0 9 06 / 0 1 / 0 9 Li n e Sc h . Nu m b e r of No r m a l i z e d Ba s e PC A To t a l A v e r a g e P e r c e n t No Ta r i f f D e s c r i p t i o n No . Cu s t o m e r s (k W h ) Re v e n u e Ad j u s t m e n t Re v e n u e it / k W h Ch a n o e Un i f o r m T a r i f f R a t e s : 1 Re s i d e n t i a l S e r v i c e 1 39 1 , 3 7 6 5, 0 6 2 , 8 3 1 , 1 4 8 32 7 , 4 8 2 , 7 6 9 58 , 4 9 5 , 9 5 1 38 5 , 9 7 8 , 7 2 0 7. 6 2 4 17 . 8 6 % 2 Re s i d e n t i a l S e r v i c e E n e r g y W a t c h 4 62 96 5 , 8 6 6 61 , 4 8 1 11 , 6 0 72 , 6 4 1 7. 5 2 1 18 . 1 5 % 3 Re s i d e n t i a l S e r v i c e T i m e - o f - D a y 5 87 1, 2 8 9 , 9 3 4 82 , 2 4 3 14 , 9 0 4 97 , 1 4 7 7. 5 3 1 18 . 1 2 % 4 Sm a l l G e n e r a l S e r v i c e 7 31 , 7 1 19 0 , 5 8 6 , 2 2 6 15 , 4 8 8 , 2 4 3 2, 2 0 2 , 0 3 3 17 , 6 9 0 , 2 7 6 9. 2 8 2 14 . 2 2 % 5 La r g e G e n e r a l S e r v i c e 9 26 , 8 4 8 3, 6 0 1 , 5 7 8 , 4 3 0 16 3 , 7 6 5 , 1 3 4 41 , 6 1 2 , 6 3 7 20 5 , 3 7 7 , 7 7 1 5. 7 0 2 25 . 4 1 % 6 Du s k t o D a w n L i g h t i n g 15 - 5, 9 5 7 , 0 9 4 1, 0 0 4 , 3 2 3 68 , 8 2 8 1, 0 7 3 , 1 5 1 18 . 0 1 5 6. 8 5 % 7 La r g e P o w e r S e r v i c e 19 11 1 2, 1 2 3 , 6 0 8 , 4 1 5 74 , 4 8 7 , 2 8 5 24 , 5 3 6 , 1 7 2 99 , 0 2 3 , 4 5 7 4. 6 6 3 32 . 9 4 % 8 Ag r i c u l t u r a l I r r i g a t i o n S e r v i c e 24 15 , 4 8 4 1, 5 5 1 , 3 2 2 , 6 6 1 81 , 6 6 8 , 2 5 6 17 , 9 2 3 , 9 8 2 99 , 5 9 2 , 2 3 8 6. 4 2 0 21 . 9 5 % 9 Un m e t e r e d G e n e r a l S e r v i c e 39 0 0 0 0 0 0. 0 0 0 0. 0 0 % 10 Un m e t e r e d G e n e r a l S e r v i c e 40 1, 8 5 5 16 , 7 3 9 , 1 6 9 96 6 , 3 2 3 19 3 , 4 0 4 1, 5 9 , 7 2 7 6. 9 2 8 20 . 0 1 % 11 St r e e t L i g h t i n g 41 14 0 22 , 0 8 4 , 2 9 7 2, 3 1 4 , 2 5 8 25 5 , 1 6 2 2, 5 6 9 , 4 2 0 11 . 6 3 5 11 . 0 3 % 12 Tr a f f i c C o n t r o l L i g h t i n g 42 22 0 4, 2 0 7 , 3 0 5 16 4 , 5 1 4 48 , 6 1 1 21 3 , 1 2 5 5. 0 6 6 29 . 5 5 % 13 To t a l U n i f o r m T a r i f f s 46 7 , 3 5 4 12 , 5 8 1 , 1 7 0 , 5 4 5 66 7 , 4 8 4 , 8 2 9 14 5 , 3 6 2 , 8 4 4 81 2 , 8 4 7 , 6 7 3 6. 4 6 1 21 . 7 8 % Sp e c i a l C o n t r a c t s : 14 Mi c r o n 26 1 70 3 , 4 0 4 , 6 4 0 21 , 2 0 4 , 2 3 8 8, 1 2 7 , 1 3 7 29 , 3 3 1 , 3 7 5 4. 1 7 0 38 . 3 3 % 15 J R S i m p l o t 29 1 18 9 , 5 6 9 , 6 7 7 5, 3 1 9 , 2 8 1 2, 1 9 0 , 2 8 8 7, 5 0 9 , 5 6 9 3. 9 6 1 41 . 1 8 % 16 DO E 30 l 21 5 , 0 0 0 , 0 0 1 6, 1 7 7 , 9 3 5 2, 4 8 4 , 1 1 0 8, 6 6 2 , 0 4 5 4. 0 2 9 40 . 2 1 % '1 7 To t a l S p e c i a l C o n t r a c t s 3 1, 1 0 7 , 9 7 4 , 3 1 8 32 , 7 0 1 , 4 5 4 12 , 8 0 1 , 5 3 5 45 , 5 0 2 , 9 8 9 4. 1 0 7 39 . 1 5 % ~~ Q ~ , . ;: ~ t r g i , .¡ . - 0 ( ' , õ r : z Š ' 1 8 To t a l Id a h o R e t a i l S a l e s 46 7 , 3 5 7 13 , 6 8 9 , 1 4 4 , 8 6 3 70 0 , 1 8 6 , 2 8 3 15 8 , 1 6 4 , 3 7 9 85 8 , 3 5 0 , 6 6 2 6. 2 7 0 22 . 5 9 % -. 0 0 , S ; . g , S " " " " "" 0 r : c i ' ~: : i o ¡ ¡ t p - 0 0 -.i .. - tv - ciu- i:..C' ø... 0_ CI ..U .. ,:: 0 E -0i: Q. CI 0o E U _Q. - CIECIoC CL.. ::.. O)W ;:""Oi:O V)c 0- U CI "0 .5 c: CLo..~-"OU~ Wi CI Clõ i:u. CL:i ii W u. aiUO-CIlic:a.0'ë:5t-a. ° ~lñ i:V).. 0 °o E :::! E ~:: ..V) "0 CI.!:Õ E°z coooC' ã3 ë ~Q) C S: 0 Q) .!a. U ~~o 3: Qi ;,~oc E ~ Q) o E .. Q)o ~l- Q)æ 0-1 .._g-e~~oU"t.. a. :J'U .o "Doc ..0- C Q)o Q) :J;... t: C"'~:JQ)-gu ~-. _ Q)0:; æ -C ~;:U ciø.o...-..~ V) Q)o (V V'-co8C' "D .~ ~~oz Ó¡ õ ~~ '- Q) -oc Q) EC'co.oo-oE"to :J :JC' Z U - 2 .! ~'I:: 0 Uæ V' 5 ~I ~~~~~~~~~~~~I~~COf'f'f'-.C'f'OOOOL.ooqOf'O-.o-OL.C'f'O' Lt Lt L. -. 'U C\ có Lt 0 Lt rr f' L. ~~~~~~~~§~~~I~r-r-f'o-L.có-.'UOf' L.'U 'U'U-.-.o-Oo-L.Of'C'~COO-'UC'-.Of''UC'COC''UO- c' ct a5 0 .. a5 LÒ ctL.f'o-o-f'o-COC'co o--.oCO'U, r-o- '0 '~ ~ 00 'U 'U coi C'COf'C'L.co C' C' 0- ct r- f' c'COC'~C'~ 'U C' ~.. c' r-C'co f' -. 0 C'"''U'U'U cx L. f' C' ct -. ctco 0'U f' a5 o~o:~!~ f' "' L. L. .. .. L. -.'UCO~C'"'-."' -. C' L.C' cocx 0:0- ~co C'C'ct ~ -. -.C' C'co f' r- LÒ 0- C' "' ~ L. tX "' -. 0C' f' L. C' f' f' C' 'UC'~CO~OC'L.L.o 0 ct r- c' -. 0- 0-f'f'o-COCOf'"'oC'~OOo-V r--. 'ctLÒ,~ 0- 0- 0-(' co L. C'! C'~CO~C'~ f' f'-. c' LÒ ~ a5C' "' 0 0~ L. C' f'.. c' 0cof' CO'U-.'UO-.L.~O"''UC'C'C'o-~'UCOo-C'-.O"''U .. LÒ 0- -. a5 r- a5 c'(''UCOCOf'L.OC'COo-C'L.L.O-'UC'c' ' 0 .. LÒ ct ..'U 0-0 C'L.o 'U ~ L.LÒ ct c'' 0- f' L.l L.'Uo-o"'~ C' C' L.0- -. f' 0C'COOf'f' 0 C' ~ -. c' "' ..~ C' coL.c' 'U C' f'f' 'U co~ 0-C' -. 0 L. 0tX L.-."' cx~LÒ °l"'C' L.C' C'r-'U"' ~ cof' "'~ co- -. C' C' ~-.L.f'o-L.o-~~e"'~ Co:. .!U :: Õ 03:9 Q)Q)Q).. - .~ U U~ 9 ~ .- .-'-Q) Q)~~~EQ)Q)O) V'aa 0)w¡,uUCQ)C- C (ß Q) Q) Q) .~ .~ :E .~ :2 ~ ~ :E ~~ .~ .~ .~ a a g ~ ß ~ ~ g '5 _ Q) Q) Q)O ~ cV':§()() O)ol-E :c V' V' V' Qi Q) ~ Qi - "D "D .~ ..oooocco~~Q)Q):Ecol-:.:.:. Q) Q)O O:J '- '- 0)0:- E C C C()() oa... Q) Q)::U C'- Q) Q) Q) Q) .. Q) "' (j (j U ::O"D"D"D= ;, U E E Q):¡-~ .~ .~ .~ ~ ~ ~ ~.~ C C Æ Q 2:: æ æ æ V' -l 0 -l oc :: :: V' l- i2 'CUV) Q)o--'Col- C'C'"'L.'Uf'COo-°C' C' ~~~I~C'COo-COLl°ca~0-00-0- ~ 8 ~I~ -. -. "' -. ~~C'~L.co L. 0- C'-. L. -. L... c' 'U 0'U "' ~ C'co 'U co C' 0- r- co -.C' -. C'C'O~L.'U ~ L. C'L. L. C' "' LÒ 0- C' a50- 0- 0- coL. 'U f' 0c' -. co 0- C'¡ 0~C'"'o0- 0 ~ ~ LÒ ct C' c''U"'C'C'C' 0- 0 C' r- -. co c'C' -. o f' ~ co"' f' 0'U 'U 0 C'-. 0- 0 -.o 'U 0 f'"' L. 0 0- ct 0- L. r-o co 0f' ~ C' , ~i C' 'U 0- 0C' C' (' V)ü ~..Co ÕU Q. o C E () e V5Q) U V' ~ ~ ~U ~..CoU :§U (1QV) o Eo i2 -. L. 'U f' ~-. .. coC'.. ~"'ctL."' titX L."'0-c' L.oL. C'C'L.o"'0-c'C'co C''Uco-."' 0-co'Uct f'L.C'r-'U"' .;oV) :e CIii °.i ~ :2~ co Attachment G Case No. IPC-E-09-11 Staff Comments 05/14/09.. Page 2 of2 CERTIFICATE OF SERVICE I HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF MAY 2009, SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO. IPC-E-09-11 BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE FOLLOWING: DONOV AN E WALKER BARTON L KLINE IDAHO POWER COMPANY POBOX 70 BOISE ID 83707-0070 E-MAIL: dwalker(iidahopower.com bkline(iidahopower .com SCOTT WRIGHT GREGORYWSAID IDAHO POWER COMPANY PO BOX 70 BOISE ID 83707-0070 E-MAIL: swright(iidahopower.com gsaid(iidahopower.com Jo~ SECRETARY ~ '. CERTIFICATE OF SERVICE