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Home My WebLink About20100518Comments.pdfWELDON B. STUTZMAN DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION PO BOX 83720 BOISE, IDAHO 83720-0074 (208) 334-0318 IDAHO BAR NO. 3283 RECEIVED 20ro HAY f 8 PM It: 49 Street Address for Express Mail: 472 W WASHINGTON BOISE ID 83702-5918 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 1,2010 THROUGH MAY 31, 2011. ) ) ) CASE NO. IPC-E-I0-12 COMMENTS OF THE COMMISSION STAFF COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, Weldon B. Stutzman, Deputy Attorney General, and in response to the Notice of Application and Notice of Modified Procedure issued in Order No. 31064 on April 27, 2010, submits the following comments. BACKGROUND On April 15, 2010, Idaho Power fied an Application to implement its Power Cost Adjustment (PCA) rates effective June 1, 2010 through May 31, 2011 and to change base rates. The Application states that the proposed PCA computation results from a Stipulation approved by the Commission in Order No. 30978, Case No. IPC-E-09-30 issued January 13,2010. That Stipulation provides for a sharing between customers and Company shareholders of any PCA revenue reduction that results from this case. The Stipulation provides that PCA rates wil be reduced by the full calculated amount and that base rates will be increased in an amount that STAFF COMMENTS 1 MAY 18,2010 partially offsets the PCA decrease. Idaho Power's filing calculates the PCA revenue reduction to be approximately $146.7 milion and the base rate increase to be approximately $88.7 milion. The net customer benefit is approximately $58 milion which produces an average decrease in rates of 6.47%. However, due to the fact that PCA rate changes are spread on an equal cents per kWh basis, some customer class rate changes vary widely from the average percentage. IDAHO POWER COMPANY'S FILING The Power Cost Adjustment (PCA) Mechanism In general terms, the PCA is an anual symmetrical rate adjustment mechanism that recovers abnormally high power supply costs from customers or credits customers with savings when power supply costs are abnormally low. The PCA has three components that combine to produce an anual PCA rate. The first component is the Forecast or Projection. The Projection is an estimate of the difference between normal power supply costs embedded in base rates and the coming year's power supply costs. The Company uses its Operating Plan to estimate the coming year's power supply costs. The PCA amount is converted to a rate by dividing by energy sales. In this fiing the Company calculates above normal power supply costs of $87.6 milion relative to power supply costs contained in curent base rates and above normal power supply costs of $20.9 milion relative to power supply costs contained in proposed base rates. After PCA sharng, these two amounts produce rates to recover projected above normal power supply costs of 0.5814 t/kWh and 0.1404 t/kWh respectively. The Company proposes to update base rates and use the 0.1404 t/kWh as the new PCA projection rate component. The second PCA component is the true-up. The true-up captures the difference between the previous year's projection and actual power supply costs. If the Projection proved to be 100 percent accurate, there would be no true-up. The true-up amount is converted to a rate by dividing by projected energy sales. Idaho Power calculates this amount and rate to be $11,963,777 and 0.0888 t/kWh. The third PCA component is the true-up of the true-up or reconciliation of the previous year's true-up. This component calculates the amount of the unecovered true-up. The previous year's true-up amount is not precisely recovered due to actual sales being different from the previous year's projected sales and due to the two-month lag between the end of the PCA accounting year and the implementation of new PCA rates. Idaho Power calculates the reconcilation ofthe true-up amount and rate to be $11,284,407 and 0.0838 t/kWh. STAFF COMMENTS 2 MAY 18,2010 The combination of the three components produces a 2010/2011 PCA rate of 0.3130 t/kWh (0.1404 + 0.0888 + 0.0838). The use of the lower projection rate of 0.1404 t/kWh assumes that Base Rates are updated in this case to include a new level of normalized power supply costs. The Base Rate Increase As previously mentioned the Stipulation accepted by the Commission in Order No. 30978, Case No. IPC-E-09-30, provides for a base rate increase to include, among other things, increases in normal Power Supply Costs that have occurred since the Company's last general rate case. The Company's filing includes an increase in base rates of approximately $88.7 milion. Case No. IPC-E-IO-01, Order No. 31042, caried over to this case the issue of the appropriate level of Bridger coal costs to be included in base power supply costs and, therefore, in base rates. The amount of base level Bridger coal costs included in the Company's calculations in this case is the level the Company proposed in the previous case. The Combined PCA and Base Rate Impact The combined impact of the PCA rate decrease proposed by the Company and the base rate increase proposed by the Company is shown on page 1 of Company Exhibit NO.2. The disparity in customer class rate change percentages results from the equal cents per kWh rate spread of the PCA decrease. High load factor customers get larger percentage decreases when PCA rates are reduced just as they received larger percentage increases when PCA rates go up. PCA percentage increases and decreases are relatively small for smaller, generally lower load factor customers. In this paricular case two lighting classes, Schedule 15 - Dusk to Dawn Lighting and Schedule 41 - Street Lighting, are proposed to receive net increases because the equal percentage base rate increase is larger to them than the equal cents per kWh decrease from the PCA. STAFF AUDIT AND ANALYSIS A. The peA Forecast or Projection As previously discussed, the projection is prepared using the Company's most recent Operating Plan. The Operating Plan incorporates the most curent information available in each update. An account by account breakdown of the Company's power supply forecast proposal is shown on Attachment A to these comments. The char shows the amounts included in Base Rates, Forecast amounts 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. STAFF COMMENTS 3 MAY 18,2010 Attachment B shows the Company (page 1) and Staff (page 2) PCA rate calculation. Page 1, lines 1 through 15 shows the calculation of the Forecast Rate proposed by the Company. Line 3 shows the forecast offset due to expected Hoku first block revenues. Line 4 shows an expected reduction in power supply costs associated with the sale of Renewable Energy Credits (REC) and S02 Emission Allowances. Line 6 shows the customer sharing percentage that is applied to all power supply cost differences, except the difference in PURPA costs. Line 9, Column (g), shows the forecast rate excluding the portion of the forecast rate associated with the expected PURP A cost difference. This rate is 0.1319 t/k Wh. Lines 11 through 13 show the calculation of the portion of the Forecast Rate associated with the expected difference in PURPA costs. This rate is 0.0085 t/kWh. The two pars of the forecast rate combine to produce the forecast rate shown on line 15,0.1404 t/kWh. Among other things, this rate reflects water conditions that are expected to be well below normaL. Under this forecast methodology, Idaho Power does its own water forecast; however, the Northwest River Forecast Center expects April through July Brownlee Reservoir inflow to be 52% of normaL. Although this year's PCA rate is proposed to be substantially lower than last year's PCA rate, power supply costs are projected to be approximately $20 millon above normaL. The Staff has reviewed the Company's Operating Plan based Forecast and believes that it is reasonable. The forecast wil not be perfect but the difference between forecast and actual is trued- up in the following year's PCA. B. The peA True-Up The PCA true-up captures the difference between actual and projected power supply costs experienced in the past year. With some adjustments, this difference becomes the PCA true-up deferral balance. This deferral balance divided by expected sales is known as the PCA true-up rate component. Lines 4 through 78 of Exhibit NO.1 to Idaho Power witness Scott Wright's testimony calculate the true-up deferral amount. Attachment C to these comments is Staffs verification of the Company's true-up deferral calculations. In Case No. IPC-E-08-19, Order No. 30715, the Commission authorized Idaho Power to redistribute monthly base power supply costs in a specific maner to meet some paricular needs of the Company. The monthly redistribution was to leave anual base power supply costs unchanged, which it has. However, the redistribution caused $215,027 of additional interest to be deferred. Attachment D is Staffs calculation of the true-up deferral amount when base power supply costs are not redistributed. Line 60 in both Attachments STAFF COMMENTS 4 MAY 18,2010 shows accumulated true-up interest. Attachment C interest is $265,945 and Attachment D interest is $50,918. In Order No. 30715 when discussing "Forecast and Expense Distribution" the Commission said: The remaining issues addressed in the Stipulation do not affect the overall PCA cost responsibilty between customers and shareholders. Clearly the Commission envisioned no cost difference as a result of the redistribution. Therefore, Staff proposes that the interest difference be removed from the true-up balance proposed by the Company. The Staff shows the removal of the interest difference on Attachment B, page 2, line 21, as par of Staf s true-up rate calculation. This year's true-up calculation includes a negative Load Growth adjustment of approximately $23.7 milion. Actual loads during the true-up year were below normal loads in 10 of 12 months. The total below normal load was 889,235 MWh. This represents a 5.6% load decline. The adjustment is the product of the negative load growth and the load growth adjustment rate (LGAR) of26.63 $/MWh. The LGAR is composed of the variable and fixed costs of production embedded in base rates. When load grows the adjustment reduces power supply costs to avoid double counting production costs. When load declines the adjustment reimburses the company for lost fixed production costs and makes the Company whole with respect to variable production costs. The result is that $21.3 milion (after Jurisdictional Allocation and PCA sharing) has been added to the deferral balance for recovery from customers in this year's PCA. This amounts to 51 % of the Company's request to recover approximately $41.9 milion in above normal costs. Negative monthly load growth has previously been included in PCA calculations and is par of the approved calculation methodology. Nevertheless, Staff is curently reviewing the justification for the adjustment when load declines, and plans to meet with the Company to discuss possible load growth adjustment modification. Staff is recommending no change to the load growth adjustment amounts or methodology in this case. To verify revenues and costs associated with Idaho Power's true-up deferrals, Staff conducted an audit of actual revenues and expenses that occured durng the PCA year. These revenues and costs included water lease expenses, fuel expenses for coal, fuel expenses for natual gas, power sales and purchases, third party transmission expenses, Hoku First Block Energy expenses, green tag Sales Credit (RECs), and Qualifying Facilties expenses. Staff also examined the Emission Allowance Sales Credit passed onto customers in the true-up of the true-up, and the Risk Management operating plan. STAFF COMMENTS 5 MAY 18,2010 The following items are included in the PCA true-up: 1. Water Leases. The Company leases water for the production of power from several entities. The increase or decrease in the water lease expense from base rates is included in the PCA for recovery from or refund to customers. This year's PCA deferral balance includes actual water lease expenses of $2,205,906 and the amount included in base rates is $67,519, with the difference of$2,138,387 included in the deferral balance. This increase in water lease expenses from base expenses is a cost to customers and is subject to jurisdictional allocation and sharing. 2. 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 refund to customers. For the audit period of April 2009 to March 2010, the total coal expense for all plants in operation is $128,504,371. The total coal expense included in base rates is $133,454,723. This year's PCA deferral balance includes a difference between costs currently included in rates and actual costs of $4,950,352. This reduction in coal costs from base costs is a benefit to customers and is subject to jurisdictional allocation and sharing. 3. 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 2009 to March 2010 the total variable gas and gas transportation expense for both complexes was $18,420,326. The total gas and gas transportation expense included in base rates is $6,125,180. 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 $12,295,146 and is subject to jurisdictional allocation and sharing. 4. Power Sales and Purchases. Staff reviewed the power purchases and sales in conjunction with the Company's Risk Management Operating Plan. Staff 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 affiliate. a. Power Sales. During the PCA year ending March 31, 2010, the Company sold surplus power totaling $94,357,434. The total surlus sales included in base rates is $116,568,567. STAFF COMMENTS 6 MAY 18,2010 The increase or decrease in the power sales from base rates is included in the PCA for recovery from or refund to customers and is subject to jurisdictional allocation and sharing. Actual surplus sales were less than base amounts by $22,221,133. This difference is a reduction of revenues to the detriment of customers and is subject to jurisdictional allocation and sharing. b. Power Purchases. During the PCA year ending March 31, 2010, the Company made market purchases, excluding PURPA contracts. The actual amount is $83,632,863. The total power purchases included in base rates is $57,231,921. Actual purchased power amounts exceed base amounts by $26,400,942. This difference isa cost to customers and is subject to jurisdictional allocation and sharing. 5. Actual Qualifying Facilties Purchases Including Net Metering and Raft River. A Qualifying Facility (QF) is a generating facility which meets the requirements for QF status under the Public Utility Regulatory Policies Act of 1978 (PURPA) and Par 292 of the Federal Energy Regulatory Commission's Regulations (18 C.F.R. Par 292), and which has obtained certification of its QF status. There are two types of QFs - cogeneration facilties and small power production facilties. Qualifying Facilities are sometimes referred to as cogeneration/small power producers or by the acronym CSPP. A Cogeneration Facility 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 purposes, and otherwise 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 facilty whose primary energy source is renewable (hydro, wind, solar, etc.), biomass, waste, or geothermal resources, and that otherwise meets the requirements of 18 C.F.R. §§ 292.203(a), 292.203(c) and 292.204. Small power production facilities 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 2009 through March 2010 the actual QF expense is $64,344,768. The QF expense included in base rates is $63,269,889. The increase or decrease in the QF expense from base rates is included in the PCA for recovery from or refund to customers. In this year's PCA deferral balance, the actual QF expense was more than the base QF by $1,074,879. This amount is a cost to customers and increases the PCA deferral balance. PURPA contracts are not currently subject to sharing. They are subject to jurisdictional allocation. STAFF COMMENTS 7 MAY 18,2010 6. Third Pary Transmission. In Order No. 30715, Case No. IPC-E-08-19, the Commission found that third-pary transmission costs that are incured 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 2009 to March 2010, the actual third party transmission expense is $6,692,114. The Third Pary Transmission expense included in base rates is $10,469,726. This year's PCA deferral balance includes a difference between costs currently included in rates and actual costs of$3,777,612. Because 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 sharing. 7. Hoku First Block Energy. In Order No. 31042, Case No. IPC-E-I0-0l, the Commission established the base level for net power supply for 2010. In this Order, the Commission accepted the Staff s recommendation that the Hoku expenses be captured in the PCA, and not in base rates for 2010. Therefore, the actual costs are included in the PCA deferral, and there are not corresponding base level amounts of Hoku expenses. In this deferral balance, there is a credit of $611 included in the deferral balance. This represents a benefit to customers and is subject to jurisdictional allocation and sharing. 8. Green Tag Sales Credit. In Order No. 30818, Case No. IPC-E-08-24, the Commission ordered that green tag sales benefits flow to customers, subject to jurisdictional allocations and sharing. The amount included in the deferral balance is $665,788. This is a benefit to customers. The true-up of the Deferral Balance is composed of the following items: Deferral Balance Components Load Growth Adjustment Water Leases Fuel Expense - Coal Fuel Expense - Gas Surlus Sales Non-Firm Purchases Third Pary Transmission Hoku Energy Subtotal $23,680,328 $2,138,387 $ (4,950,352) $12,295,146 $22,211,133 $26,400,942 $ (3,777,612) $(611) $77,997,362 Subtotal $69,644,815 (After Jurisdictional Allocations and Sharing) STAFF COMMENTS 8 MAY 18,2010 Qualifying Facilties (After Jurisdictional Allocations) $1,018,985 Total all Expense Items $70,663,800 Less Jurisdictional Forecast Revenue $58,965,969 Deferral Balance $11,697,831 Staff Interest on the Deferral Balance $50,918 Deferral Balance (True-Up) $11,748,749 The Company-proposed true-up rate is 0.0888 t/kWh as shown on Staff Attachment B, page 1, line 20. The Staff-proposed true-up rate is 0.0872 t/kWh as shown on Staff Attachment B, page 2, line 20. The only difference is Staffs true-up interest adjustment. C. The peA True-Up of the True-Up The PCA reconciliation of the true-up amount is the difference between what was approved to be collected or refunded 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 and the fact that the true-up period included only 10 months with the true-up rate in place. 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. Included in this year's true-up of the true-up is the benefit to customers from the 2008-2009 S02 Emission sales. Per Order No. 30790, the Company recorded the proceeds from the sale of the 2008-2009 S02 credits in the curent year's PCA. The Idaho Jursdictional portion of the S02 allowance proceeds, including interest but net of tax were recorded in the PCA deferral account and included in the true-up of the tre-up section in the months of April 2009 and June 2009. The total system S02 amount is $5,229,875 plus accrued interest. The Idaho jurisdictional amount after jurisdictional allocation and sharing is $4,591,632. This is a benefit to customers. Last year's unecovered true-up amount to be recovered in this case is approximately $11.3 milion. This amount is calculated on Company Exhibit No.1, lines 80 through 97. The Staff calculates the same amount on Attachment D, page 2, lines 64 through 76. The true-up of the true- up rate is calculated on Attachment B, page 1 (Company Case) or page 2 (Staff Case), line 24, to be 0.0838 t/kWh. The Staff and Company calculate the same rate for the true-up of the true-up. STAFF COMMENTS 9 MAY 18,2010 PCARATES The Staff s calculated PCA rate of 0.3114 t/k Wh is the sum of the three components described above (0.1404 + 0.0872 + 0.0838 = 0.3114). This rate is shown on Attachment B, page 2, line 27. This rate is well below the 1.4022 t/k Wh currently in place. This PCA rate decrease is not a refud of below normal power costs but simply a lower surcharge than the surcharge currently in place. Attachment E, page 1, shows the impact on all Idaho Power customer classes of the PCA rate decrease. Base Rates A. Bridger eoal eosts The Settlement Stipulation accepted by the Commission in Case No. IPC-E-09-30, Order No. 30978, provided for an increase in base rates ifPCA rates were reduced in this fiing. The magnitude of the base rate increase includes, as a component, normal power supply costs. Normal power supply costs were identified in Case No. IPC-E-IO-01, Order No. 31042, as approximately $63.7 millon more than are included in present base rates. The one unresolved issue from that case that could affect this amount was the cost of Bridger coaL. The Bridger coal cost issue was cared over to this case to obtain a timely decision in the cited case and to allow other pertinent information to be made available. That information is now available. The Bridger coal cost issue has come up because the coal supply contract with Bridger Coal Company recently expired and coal costs under the new contract are significantly higher than they were under the old contract. Also, Bridger Coal Company is a wholly-owned subsidiar of Idaho Power Company and PacifiCorp who own the Jim Bridger power plant. The concern is whether customers are getting the coal prices they should given the fact that the contract is with an affiiate. When a regulated utilty contracts with an unregulated affliate, it is common practice to reflect in rates the lower of the actual cost or the comparable market cost. The issue was first raised in Oregon PUC Docket No. UE 214 where direct and rebuttal testimony have been filed and discovery requests have been asked and answered. That case continues and will be decided later in the year. The IPUC Staff has reviewed the new contract, testimony and production requests in the Oregon case, a white paper prepared by Idaho Power Company to address the issues (including the lower of cost or market issue), responses to production requests asked by Idaho Staff and Intervenors and Idaho Power witness Tom Harey's testimony in this case. The Staff concludes that Idaho Power's positions with regard to Bridger coal costs appear logical, reasonable and STAFF COMMENTS 10 MAY 18,2010 consistent. In addition, Bridger Coal Company profits flow to Idaho Power subsidiar IERCO and IERCO profits flow back to customers in Idaho Power Company general rate cases. Staff has not identified any justification to reject or modify the Bridger coal costs proposed by the Company and included in base power supply costs in this fiing. Therefore, Staff continues to support additional normalized base power supply costs of$63.7 millon. B. Rates The Company and Staff are both proposing a substantial decrease in PCA rates of approximately $147 milion. Under the Stipulation a PCA reduction of this magnitude allows the Company to move $63.7 milion (Case No. IPC-E-IO-01, Order No. 31042) in increased normal power supply costs into base rates along with $25 milion in other costs. The Stipulation fuher requires that the Base Rate increase be spread to customer classes and rate components within each customer class on an equal percentage of revenue basis, except for Residential and Small Commercial customer charges, which are to remain unchanged. Company witness Tatum provided the calculation of the new base rates in Exhibit No.2, pages 2 through 25. Staffhas reviewed these calculations and agrees that they are correct. Staff Attachment E, page 2, shows the average increase in base rates by customer class. Combined PCA and Base Rates Attachment E, page 3 shows the combined impact by customer class of Staff-proposed changes in PCA and base rates. The impact is measured against all biled revenue, not just base rates. Again, the percentage changes var widely. The decrease is $58.2 milion, which averages 6.49% across all customer classes. The Schedule 1 Residential class decrease is 3.24%. Other PCA Attachments The Staff has included three other Attachments that provide summary or historical information concerning the PCA. Staff Attachment F summarizes PCA expense amounts and rate components for this case. Page 1 shows the Company's case and page 2 shows the Staffs case. The Attachments also show amounts allocated to other jurisdictions and amounts shared with shareholders. Attachment G is a bar graph that shows the amount of each PCA since its inception including the Company and Staff Proposals in this case. Attachment H graphically shows base rates and PCA rates for the Residential Customer Class from 1994 to the present time. It also shows the impact of the Company and Staffbase rate and PCA rate proposals in this case. STAFF COMMENTS 11 MAY 18,2010 CONSUMER ISSUES Idaho Power's PCA Application, fied on April 15, 2010, contained both the customer notice and press release. Staff reviewed the notice and press release and determined that they complied with the requirements of Rule 125, IPUC Rules of Procedure, IDAPA 31.01.01. The customer notice was mailed with Idaho Power's cyclical bilings beginning April 23, 2010 and ending May 24, 2010. Customers had until May 18, 2010 to file comments. In addition to describing the current filing, the customer notice also mentions proposed rate increases associated with the recovery of Advanced Metering Infrastructure investment (Case No. IPC-E-I0-06), the anual Fixed Cost Adjustment (Case No. IPC-E-I0-07), and the recovery of Defined Benefit Pension Expense (Case No. IPC-E-I0-08). The customer notice recognizes that the Company proposed 6.5% overall rate decrease in this case (lPC-E-IO-12) wil be offset by any increase granted by the Commission in the other three cases. The notice states, "If the three proposals are approved along with the proposed PCA reduction, customers wil experience a $46.6 milion overall rate reduction, or an average of 5.2%." As of May 17, 2010, two customers had submitted comments to the Commission regarding the PCA. One customer is in favor of the proposed reduction in the PCA charge, though the customer feels that the reduction should be larger. The other customer questions why the proposed PCA reduction is less for residential customers than the overall proposed decrease. The customer also feels that residential customers are subsidizing other classes of customers, all electric residential customers are being unfairly penalized, and it is wrong to use rate schedules to force energy conservation. STAFF RECOMMENDATION The Staff recommends that the Commission approve the base rate increases fied by the Company and reviewed by Staff. The increase has been filed in conformance with Order No. 30978 issued in Case No. IPC-E-09-30. The Staff fuher recommends that the Commission approve a PCA rate of 0.3114 t/kWh for the June 1,2010 through May 31, 2011 period. This PCA rate differs from the Company's proposal due to the true-up interest adjustment recommended by Staff in these comments. The Staff recommends that base rate changes and PCA rate changes be effective June 1,2010. STAFF COMMENTS 12 MAY 18,2010 Respectfully submitted this \ ß ~ay of May 2010. O-=~Weldon B. Stutzman Deputy Attorney General i:umisc:comments/ipce 10. 12wskhklset.doc STAFF COMMENTS 13 MAY 18,2010 z0-I-U LL QJ-t II11i:0 \C QJ11C.Xci~w ro NQ.QI 'r~i0l-e:'r IIQJ I IIV)U IILU.i0C.i u..U ::U ~a.Q,~0 . 2=0NZ II QJIIQ.OJ II0.i Q.V'i U~.. CO ::::0 u Q, NV) ~ ci QJIIi:LL QJC. ~x ~ w OJ0V' co ':: Q.co q.\Crt11 VI OJ::c: OJ;: OJex~u .2 CO..VI..u.::~0:i VI OJ"'::Uc: * Ô Ô011....-- ..0 X11W ñi0u 0 0 0 0 0 0 0 ô011011011ertNN.... (SUO!lIlW) asuadx3 ÁlddnS JaMOd Attachment A Case No. IPC-E-I0-12 Staff Comments 5/18/1 0 20 1 0 - 2 0 1 1 p e A - E i g h t e e n t h A n n u a l IP C - E - 1 0 - 1 2 Co m p a n y 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 1 0 - 2 0 1 1 : 2 PC A E x p e n s e ( 9 5 % ) ($ ) 15 7 , 9 1 8 , 6 8 3 20 5 , 8 9 2 , 8 3 7 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 ($ ) (2 0 , 6 7 0 , 4 0 5 ) 4 Re n e w a b l e E n e r g y C r e d i t s & S 0 2 B e n e f i t s ($ ) (7 , 6 0 6 , 8 6 0 ) 5 Di f f e r e n c e ($ ) 17 7 , 6 1 5 , 5 7 2 19 , 6 9 6 , 8 8 9 6 Sh a r i n g P e r c e n t a g e (% ) 0. 9 5 7 Sh a r e d D i f f e r e n c e ($ ) 18 , 7 1 2 , 0 4 5 8 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 , 1 8 8 , 5 7 9 9 Ra t e f o r 9 5 % I t e m s (Ø k W h ) 0. 1 3 1 9 0. 1 3 1 9 10 11 PC A E x p e n s e ( 1 0 0 % ) ($ ) 62 , 8 5 1 , 4 5 4 64 , 0 5 4 , 9 9 3 1, 2 0 3 , 5 3 9 12 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 , 1 8 8 , 5 7 9 13 Ra t e f o r 1 0 0 % I t e m s (Ø / k W h ) 0. 0 0 8 5 0. 0 0 8 5 14 15 To t a l F o r e c a s t R a t e (Ø / k W h ) 0. 1 4 0 4 16 17 18 æ (M W h ) ($ / M W h ) (é / k W h ) 19 20 Tr u e - U p o f 2 0 0 9 - 2 0 1 0 : 11 , 9 6 3 , 7 7 7 13 , 4 6 7 , 9 2 9 0. 8 8 8 3 1 6 0 1 4 0. 0 8 8 8 21 22 23 24 Tr u e - U p o f t h e T r u e - U p : 11 , 2 8 4 , 4 0 7 13 , 4 6 7 , 9 2 9 0. 8 3 7 8 7 2 4 7 5 0. 0 8 3 8 25 Vl r z n ~ 2 6 PC A R a t e s : ;: S ' e i : : 2 7 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 0. 3 1 3 0 I 00 : : G ~ ;: n Z ~ 2 8 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 ) 1. 4 0 2 2 00 0 3 2 9 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 ) (1 . 0 8 9 2 ) 'i 3 : . G i ~ 3 ' i a 3 0 G g n O j l 3 1 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 . ~ f . t ; I o _ .. 0 N i -N 20 1 0 - 2 0 1 1 p e A - E i g h t e e n t h A n n u a l IP C - E - 1 0 - 1 2 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 1 0 - 2 0 1 1 : 2 PC A E x p e n s e ( 9 5 % ) ($ ) 15 7 , 9 1 8 , 6 8 3 20 5 , 8 9 2 , 8 3 7 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 ($ ) (2 0 , 6 7 0 , 4 0 5 ) 4 Re n e w a b l e E n e r g y C r e d i t s & S 0 2 B e n e f i t s ($ ) (7 , 6 0 6 , 8 6 0 ) 5 Di f f e r e n c e ($ ) 17 7 , 6 1 5 , 5 7 2 19 , 6 9 6 , 8 8 9 6 Sh a r i n g P e r c e n t a g e (% ) 0. 9 5 7 Sh a r e d D i f f e r e n c e ($ ) 18 , 7 1 2 , 0 4 5 8 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 , 1 8 8 , 5 7 9 9 Ra t e f o r 9 5 % I t e m s (Ø / k W h ) 0. 1 3 1 9 0. 1 3 1 9 10 11 PC A E x p e n s e ( 1 0 0 % ) ($ ) 62 , 8 5 1 , 4 5 4 64 , 0 5 4 , 9 9 3 1, 2 0 3 , 5 3 9 12 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 , 1 8 8 , 5 7 9 13 Ra t e f o r 1 0 0 % I t e m s (Ø / k W h ) 0. 0 0 8 5 0. 0 0 8 5 14 15 To t a l F o r e c a s t R a t e (Ø / k W h ) 0. 1 4 0 4 16 17 18 æ (M W h ) ($ / M W h ) (Ø / k W h ) 19 20 Tr u e - U p o f 2 0 0 9 - 2 0 1 0 : 11 , 9 6 3 , 7 7 7 21 St a f f I n t e r e s t A d j u s t m e n t (2 1 5 , 0 2 8 ) 22 To t a l T r u e - U p 11 , 7 4 8 , 7 4 9 13 , 4 6 7 , 9 2 9 0. 8 7 2 3 5 0 0 8 4 0. 0 8 7 2 23 24 Tr u e - U p o f t h e T r u e - U p : 11 , 2 8 4 , 4 0 7 13 , 4 6 7 , 9 2 9 0. 8 3 7 8 7 2 4 7 5 0. 0 8 3 8 25 VI r J ( " ~ 2 6 PC A R a t e s : ~ S e i g 2 7 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 0. 3 1 1 4 1 00 : : ( l n ~ ( " Z g 2 8 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 ) 1. 4 0 2 2 00 0 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 ) (1 . 0 9 0 8 ) S' ( l i 2 9 "" - l : J' ~ ( ! a 3 0 ~ ~ t T I 3 1 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 . ti i ' o _ .. 0 N ~ N TRUE.UP CALCULATIONS FOR 2009.2010 FOR IDAHO POWER COMPANY PCA CASE NO.IPC.E.10.12 Base Costs are Redistributed 1 2009 2009 2009 2009 2009 2009 2009 2 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT 3 PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 968,949 998,195 1,152,831 1,361,266 1,424,275 1,310,616 1,062,389 5 Forecast Rate m/KWh 0.000 0.000 4.967 4.967 4.967 4.967 4.967 6 Revenue $0 0 5,726,112 6,761,408 7,074,374 6,509,830 5,276,886 7 8 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 1,061,759 1,297,111 1,200,919 1,700,075 1,502,171 1,285,192 1,065,182 10 Normalized Firm Load MWh 1,077,297 1,254,940 1,437,122 1,734,214 1,593,733 1,282,425 1,138,449 11 Load Change MWh (15,538)42,171 (236,203)(34,139)(91,562)2,767 (73,267) 12 Expense Adjustment $413,777 (1,123,014)6,290,086 909,122 2,438,296 (73,685)1,951,100 13 14 Non-QF peA 15 ACTUAL: 16 Water Lease Purchases $0 0 0 0 1,200,045 400,015 0 17 Fuel Expense - Coal $8,481,367 8,571,464 5,925,943 11,314,410 12,577,179 11,720,992 11,894,343 18 Fuel Expense - Gas $307,966 481,747 506,772 3,180,020 9,211,177 1,366,288 326,326 19 Non"Firm Purchases $2,886,846 2,623,404 3,764,629 21,356,025 14,694,297 12,543,806 3,655,533 20 Third Part Transmission $482,242 178,933 1,114,419 1,283,666 1,108,210 399,525 656,302 21 Surplus Sales $(12,227,758)(7,805,582)(5,537,025)(8,962,762)(4,675,499)(8,657,434)(8,671,753) 22 Hoku First Block Energy $ 23 Expense Adjustment $413,777 (1,123,014)6,290,086 909,122 2,438,296 (73,685)1,951,100 24 Sub-Total $344,439 2,926,952 12,064,823 29,080,481 36,553,705 17,699,506 9,811,850 25 26 BASE: 27 Water for Power (Leases)$ 28 Fuel Expense - Coal $ 29 Fuel Expense -.Gas $ 30 NOn-Firm Purchases $ 31 Third Part Transmission $ 32 Sur Ius Sales $ 33 Sub-Total $6,365,307 6,271,320 7,590,945 9,234,803 9,929,745 8,818,026 6,713,617 34 35 Change From Base $(6,020,868)(3,344,368)4,473,878 19,845,678 26,623,960 8,881,480 3,098,233 36 Emission Allowance Sales Credit $0 0 0 0 0 0 0 37 Green Tag Sales Credit $0 0 0 0 0 0 0 38 Sub-Total $(6,020,868)(3,344,368)4,473,878 19,845,678 26,623,960 8,881,480 3,098,233 39 40 Deferral (Shared and Allocated)$(5,422,394)(3,011,938)4,029,175 17,873,017 23,977,538 7,998,661 2,790,269 41 42 QF Deferral 43 Actual (includes Net Metering)$ 44 Base $ 45 46 Change From Base $(1,129,462)559,706 2,288,525 2,750,564 1,519,977 1,116,146 792,167 47 Deferral (Allocated)$(1,070,730)530,601 2,169,521 2,607,534 1,440,938 1,058,106 750,975 48 49 Total Deferral (-6+40+47)$(6,493,124 )(2,481,336)472,584 13,719,143 18,344,103 2,546,938 (1,735,642) 50 51 Principal Balances 52 Beginning Balance $0 (6,493,124 )(8,974,460)(8,501,876)5,217,267 23,561,370 26,108,308 53 Amount Deferred $(6,493,124)(2,481,336)472,584 13,719,143 18,344,103 2,546,938 (1,735,642) 54 Ending Balance $(6,493,124 )(8,974,460)(8,501,876)5,217,267 23,561,370 26,108,308 24,372,665 55 56 Interest Balances 57 Accrual thru Prior Month $0 221 (10,600)(25,556)(39,726)(31,030)12,518 58 Interest (g 2% per Year $0 (10,822)(14,957)(14,170)8,695 39,269 43,514 59 Prior Month's Interest Adj.$221 0 2 0 0 4,280 0 60 Total Current Month Interest $221 (10,822)(14,956)(14,170)8,696 43,549 43,514 61 Interest Accrued to Date $221 (10,600)(25,556)(39,726)(31,030)12,518 56,032 62 Balance (True-Up & Interest)$(6,92,903)(8,985,061 )(8,527,432)5,177,541 23,530,340 26,120,826 24,428,697 63 64 True-Up of the True-Up 65 True-Up Revenues (Collections)$7,549,074 7,461,834 9,159,672 11,231,894 12,693,477 11,529,057 9,507,677 66 67 Beginning Balance $22,003,335 119,733,074 112,470,795 101,719,115 90,656,754 78,114,371 66,715,505 68 Adjustments: 69 2008-09 PCA Transfer - ON 30828 $107,891,769 0 0 0 0 0 0 70 Emission Allowance - ON 30790 $(2,815,134)0 (1,776,498)0 0 0 0 71 Correction for Change in Base $(9,606)0 0 0 0 0 0 72 Sub-Total $127,070,364 119,733,074 110,694,297 101,719,115 90,656,754 78,114,371 66,715,505 73 Interest (g 2% per Year $211,784 199,555 184,490 169,532 151,095 130,191 111,193 74 Revenue Applied to Interest $211,784 199,555 184,490 169,532 151,095 130,191 111,193 75 Revenue Applied to Balance $7,337,290 7,262,279 8,975,182 11,062,362 12,542,383 11,398,866 9,396,485 76 True-Up of the True-Up Balance $119,733,074 112,470,795 101,719,115 90,656,754 78,114,371 66,715,505 57,319,020 77 AtÙichienfC78Note: Negative amounts indicate benefi to ratepayers Case No. IPC-E-I0-12 Staff Comments 5/18/10 Page 1 of2 U:\khessin\ipce1012\Staff Case\2009-2010 peA TRUE UP CALCULATIONS 511012010 KDH TRUE-UP CALCULATIONS FOR 2009 - 2010 FOR IDAHO POWER COMPANY PCA CASE NO.IPC-E-10-12 Base Costs are Redistributed 1 2009 2009 2010 2010 2010 2 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS 3 PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 1,000,733 1,125,561 1,221,034 1,165,642 1,047,199 13,838,690 5 Forecast Rate m/KWh 4.967 4.967 4.967 4.967 4.967 6 Revenue $4,970,641 5,590,661 6,064,876 5,789,744 5,201,437 58,965,969 7 8 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 1,114,814 1,370,795 1,234,086 1,057,786 1,084,503 14,974,393 10 Normalized Firm Load MWh 1,184,277 1,443,579 1,351,898 1,184,072 1,181,622 15,863,628 11 Load Change MWh (69,463)(72,784)(117,812)(126,286)(97,119)(889,235) 12 Expense Adjustment $1,849,800 1,938,238 3,137,334 3,362,996 2,586,279 23,680,328 13 14 Non-QF PCA 15 ACTUAL: 16 Water Lease Purchases $0 148,500 0 186 457,160 2,205,906 17 Fuel Expense - Coal $10,530,410 11,423,333 12,256,779 11,916,054 11,892,098 128,504,371 18 Fuel Expense - Gas $284,138 1,802,820 278,633 279,653 394,787 18,420,326 19 Non-Firm Purchases $4,362,872 7,003,524 4,149,052 3,736,883 2,855,994 83,632,863 20 Third Party Transmission $419,383 79,664 274,338 364,046 331,387 6,692,114 21 Surplus Sales $(3,465,388)(1,466,704)(11,007,285)(12,553,414)(9,326,830)(94,357,434) 22 Hoku First Block Energy $(2,350)2,350 0 (611)(611) 23 Expense Adjustment $1,849,800 1,938,238 3,137,334 3,362,996 2,586,279 23,680,328 24 Sub-Total $13,981,213 20,927,025 9,091,200 7,106,405 9,190,265 168,777,864 25 26 BASE: 33 34 35 Change From Base $7,564,035 13,658,999 1,231,504 (318,120)2,302,951 77,997,362 36 Emission Allowance Sales Credit $0 0 0 0 0 0 37 Green Tag Sales Credit $0 0 0 0 (665,788)(665,788) 38 Sub-Total 7,564,035 13,658,999 1,231,504 (318,120)1,637,163 77,331,574 39 40 Deferral (Shared and Allocated)$6,812,170 12,301,294 1,109,092 (286,499)1,474,429 69,644,815 41 42 OF Deferral 64,344,768 63,269,889 47 Deferral (Allocated)$322,125 (1,110,795)(1,615,261)(2,128,062)(1,935,968)1,018,985 48 49 Total Deferral (-6+40+47)$2,163,654 5,599,838 (6,571,045)(8,204,305)(5,662,976)11,697,832 50 51 Principal Balances 52 Beginning Balance $24,372,665 26,536,319 32,136,157 25,565,112 17,360,808 53 Amount Deferred $2,163,654 5,599,838 (6,571,045)(8,204,305)(5,662,976)11,697,832 54 Ending Balance $26,536,319 32,136,157 25,565,112 17,360,808 11,697,832 55 56 Interest Balances 57 Accrual thru Prior Month $56,032 96,653 140,883 194,450 237,010 58 Interest ~ 2% per Year $40,621 44,227 53,560 42,609 28,935 261,481 59 Prior MOnth's Interest Adj.$0 3 6 (48)0 4,464 60 Total Current Month Interest $40,621 44,230 53,567 42,561 28,935 265,945 61 I nterest Accrued to Date $96,653 140,883 194,450 237,010 265,945 62 Balance (True-Up & Interest)$26,632,973 32,277,040 25,759,562 17,597,818 11,963,777 11,963,777 63 64 True-Up of the True-Up 65 True-Up Revenues (Collections)$8,389,342 9,972,366 10,552,232 8,867,580 8,576,349 115,490,555 66 67 Beginning Balance $57,319,020 49,025,210 39,134,552 28,647,544 19,827,710 22,003,335 68 Adjustments: 69 2008-09 PCA Transfer - ON 30828 $0 0 0 0 0 107,891,769 70 Emission Allowance - ON 30790 $0 0 0 0 0 (4,591,632) 71 Correction for Change in Base $0 0 0 0 0 (9,606) 72 Sub-Total $57,319,020 49,025,210 39,134,552 28,647,544 19,827,710 125,293,866 73 Interest ~ 2% per Year $95,532 81,709 65,224 47,746 33,046 74 Revenue Applied to Interest $95,532 81,709 65,224 47,746 33,046 1,481,096 75 Revenue Applied to Balance $8,293,810 9,890,658 10,487,008 8,819,834 8,543,303 114,009,459 76 True-Up of the True-Up Balance $49,025,210 39,134,552 28,647,544 19,827,710 11,284,407 11.284,407 77 AttachieiifC78Note: Negative amounts indicate benefi to ratepayers Case No. IPC-E-I0-12 Staff Comments 5/18/1 0 Page 2 of 2 U:\khessin\ipc1012\Staf Cae\200g.2010 PCA TRUE UP CALCULATIONS 51101010 KDH TRUE-UP CALCULATIONS FOR 2009 - 2010 FOR IDAHO POWER COMPANY PCA CASE NO.IPC-E-10.12 Base Costs are AURORA Outputs (Not Redistributed) Units 2009 APR 2009 MAY 998,195 0.000 o 1,297,111 1,254,940 42,171 (1,123,014) o 8,571,464 481,747 2,623,404 178,933 (7,805,582) (1,123,014) 2,926,952 4,664 9,055,548 316,922 2,041,687 723,272 (10,712,129) 1,429,964 2009 JUN 1,152,831 4.967 5,726,112 1,200,919 1,437,122 (236,203) 6,290,086 o 5,925,943 506,772 3,764,629 1,114,419 (5,537,025) 6,290,086 12,064,823 5,646 10,823,695 316,969 5,556,509 875,465 (7,561,791) 10,016,493 2009 JUL 1,361,266 4.967 6,761,408 1,700,075 1,734,214 (34,139) 909,122 o 11,314,410 3,180,020 21,356,025 1,283,666 (8,962,762) 909,122 29,080,481 6,868 12,052,676 1,634,262 13,343,476 1,065,051 (1,499,742) 26,602,591 2009 AUG 1,424,275 4.967 7,074,374 1,502,171 1,593,733 (91,562) 2,438,296 1,200,045 12,577,179 9,211,177 14,694,297 1,108,210 (4,675,499) 2,438,296 36,553,705 7,385 12,079,460 897,427 7,771,064 1,145,199 (1,507,699) 20,392,836 2009 SEPT 1,310,616 4.967 6,509,830 1,285,192 1,282,425 2,767 (73,685) 400,015 11,720,992 1,366,288 12,543,806 399,525 (8,657,434) (73,685) 17,699,506 6,558 11,659,568 374,68 4,853,324 1,016,984 (5,290,199) 12,620,933 2009 OCT 1,062,389 4.967 5,276,886 1,065,182 1,138,449 (73,267) 1,951,100 o 11,894,343 326,326 3,655,533 656,302 (8,671,753) 1,951,100 9,811,850 4,994 12,068,932 364,846 2,253,223 774,282 (9,136,293) 6,329,984 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 Fuel Expense. Coal 18 Fuel Expense. Gas 19 Non-Firm Purchases 20 Third Party Transmission 21 Surplus Sales 22 Hoku First Block Energy 23 Expense Adjustment 24 Sub.Total 25 26 BASE: 27 Water for Power (Leases) 28 Fuel Expense - Coal 29 Fuel Expense. Gas 30 Non-Firm Purchases 31 Third Party Transmission 32 Surplus Sales33 Su b. Total 34 35 Change From Base 36 Emission Allowance Sales Credit 37 Green TagSaies Credit38 Su b. Total 39 40 Deferral (Shared and Allocated) 41 42 Qf Deferral 43 Actual (includes Net Metering) 44 Base 45 46 Change From Base 47 Deferral (Allocated) 48 49 Total Deferral (-6+40+47) 50 51 Principal Balances 52 Beginning Balance 53 Amount Deferred 54 Ending Balance 55 56 Interest Balances 57 Accrual thru Prior Month 58 Interest t1 2% per Year 59 Prior Month's Interest Adj. 60 Total Current Month Interest 61 I nterest Accrued to Date 62 Balance (True-Up & Interest) 63 64 True-Up of the True-Up 65 True-Up Revenues (Collections) 66 67 Beginning Balance 68 Adjustments: 69 2008-09 PCA Transfer. ON 30828 ( 70 Emission Allowance - ON 30790 71 Correction for Change in Base72 Sub-Total 73 Interest t1 2% per Year 74 Revenue Applied to Interest 75 Revenue Applied to Balance 76 True-Up oUhe True-Up Balance 77 78 Note: Negative amounts indicate benefit to ratepayers MWh mlKWh $ 968,949 0.000 o 1,496,988 o o 1,496,988 1,348,187 4,930,532 5,203,607 2,048,330 o o 2,048,330 1,844,726 7,579,069 7,860,134 2,477,890 o o 2,477,890 2,231,587 9,186,803 8,118,697 16,160,869 o o 16,160,869 14,554,478 8,440,558 7,871,301 5,078,573 o o 5,078,573 4,573,763 7,261,911 6,284,831 3,481,866 o o 3,481,866 3,135,769 5,471,254 4,566,064 MWh MWh MWh $ 1,061,759 1,077,297 (15,538) 413,777 $ $ $ $ $ $ $ $ $ o 8,481,367 307,966 2,886,846 482,242 (12,227,758) 413,777 344,439 $ $ $ $ $ $ $ 4,734 7,770,564 412,108 1,622,208 734,112 (16,822,354) (6,278,628) $ $ $ $ 6,623,067 o o 6,623,067 $5,964,734 $ $ 3,306,868 4,113,148 $ $ (806,280) (764,354) $5,200,380 $ $ $ o 5,200,380 5,200,380 $ $ $ $ $ $ o o 221 221 221 5,200,602 $7,549,074 $22,003,335 $ $ $ $ $ $ $ $ 107,891,769 (2,815,134) (9,606) 127,070,364 211,784 211,784 7,337,290 119,733,074 (273,075) (258,875) 1,089,312 5,200,380 1,089,312 6,289,693 221 8,667 o 8,667 8,889 6,298,582 7,461,834 119,733,074 o o o 119,733,074 199,555 199,555 7,262,279 112,470,795 (281,065) (266,450) (4,147,835) 6,289,693 (4,147,835) 2,141,857 8,889 10,483 2 10,484 19,373 2,161,230 9,159,672 112,470,795 o (1,776,498) o 110,694,297 184,490 184,490 8,975,182 101,719,115 1,068,106 1,012,564 (3,517,257) 2,141,857 (3,517,257) (1,375,399) 19,373 3,570 o 3,570 22,943 (1,352,456) 11,231,894 101,719,115 o o o 101,719,115 169,532 169,532 11,062,362 90,656,754 569,257 539,656 8,019,760 (1,375,399) 8,019,760 6,644,361 22,943 (2,292) o (2,292) 20,651 6,665,012 12,693,477 90,656,754 o o o 90,656,754 151,095 151,095 12,542,383 78,114,371 977,080 926,272 (1,009,795) 6,644,361 (1,009,795) 5,634,566 20,651 11,074 4,280 15,354 36,005 5,670,571 11,529,057 78,114,371 o o o 78,114,371 130,191 130,191 11,398,866 66,715,505 905,190 858,120 (1,282,997) 5,634,566 ( 1,282,997) 4,351,569 36,005 9,391 o 9,391 45,396 4,396,965 9,507,677 66,715,505 o o o 66,715,505 111,193 111,193 9,396,485 57,319,020 Attachment D Case No. IPC-E-I0-12 Staff Comments 5/18/10 Page 1 of2 TRUE-UP CALCULATIONS FOR 2009 - 2010 FOR IDAHO POWER COMPANY PCA CASE NO.IPC-E-10-12 Base Costs are AURORA Outputs (Not Redistributed) 1 2009 2009 2010 2010 2010 2 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS 3 PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 1,000,733 1,125,561 1,221,034 1,165,642 1,047,199 13,838,690 5 Forecast Rate mlKWh 4.967 4.967 4.967 4.967 4.967 6 Revenue $4,970,641 5,590,661 6,064,876 5,789,744 5,201,437 58,965,969 7 8 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 1,114,814 1,370,795 1,234,086 1,057,786 1,084,503 14,974,393 10 Normalized Firm Load MWh 1,184,277 1,443,579 1,351,898 1,184,072 1,181,622 15,863,628 11 Load Change MWh (69,463)(72,784)(117,812)(126,286)(97,119)(889,235) 12 Expense Adjustment $1,849,800 1,938,238 3,137,334 3,362,996 2,586,279 23,680,328 13 14 Non-QF PCA 15 ACTUAL: 16 Water Lease Purchases $0 148,500 0 186 457,160 2,205,906 17 Fuel Expense - Coal $10,530,410 11,423,333 12,256,779 11,916,054 11,892,098 128,504,371 18 Fuel Expense - Gas $284,138 1,802,820 278,633 279,653 394,787 18,420,326 19 Non-Firm Purchases $4,362,872 7,003,524 4,149,052 3,736,883 2,855,994 83,632,863 20 Third Part Transmission $419,383 79,664 274,338 364,046 331,387 6,692,114 21 Surplus Sales $(3,465,388)(1,466,704)(11,007,285)(12,553,414 )(9,326,830)(94,357,434) 22 Hoku First Block Energy $(2,350)2,350 0 (611)(611) 23 Expense Adjustment $1,849,800 1,938,238 3,137,334 3,362,996 2,586,279 23,680,328 24 Sub-Total $13,981,213 20,927,025 9,091,200 7,106,405 9,190,265 168,777,864 25 26 BASE: 27 Water for Power (Leases)$4,774 5,406 5,846 5,522 5,122 67,519 28 Fuel Expense - Coal $11,704,004 12,108,968 11,834,031 11,045,620 11,251,657 133,454,723 29 Fuel Expense - Gas $467,067 370,512 348,031 306,063 316,275 6,125,180 30 Non"Firm Purchases $4,933,733 7,084,747 4,332,527 1,895,241 1,544,182 57,231,921 31 Third Party Transmission $740,094 838,222 906,460 856,271 794,314 10,469,726 32 Surplus Sales $(4,058,642)(6,138,836)(9,823,963)(22,608,930)(21,407,989)(116,568,567) 33 Sub-Total $13,791,030 14,269,019 7,602,932 (8,500,213)(7,496,439)90,780,502 34 35 Change From Base $190,183 6,658,006 1,488,268 15,606,618 16,686,704 77,997,362 36 Emission Allowance Sales Credit $0 0 0 0 0 0 37 Green Tag Sales Credit $0 0 0 0 (665,788)(665,788) 38 Sub-Total 190,183 6,658,006 1,488,268 15,606,618 16,020,916 77,331,574 39 40 Deferral (Shared and Allocated)$171,279 5,996,200 1,340,334 14,055,320 14,428,437 69,644,815 41 42 OF Deferral 43 Actual (includes Net Metering)$4,812,274 3,893,759 3,773,989 2,929,766 2,757,985 64,344,768 44 Base $3,994,318 4,427,260 3,784,877 3,795,312 3,250,340 63,269,889 45 46 Change From Base $817,956 (533,501)(10,888)(865,546)(492,355)1,074,879 47 Deferral (Allocated)$775,422 (505,759)(10,322)(820,537)(466,752)1,018,985 48 49 Total Deferral (-6+40+47)$(4,023,939)(100,220)(4,734,864)7,445,039 8,760,247 11,697,832 50 51 Principal Balances 52 Beginning Balance $4,351,569 327,630 227,410 (4,507,454)2,937,585 53 Amount Deferred $(4,023,939)(100,220)(4,734,864)7,445,039 8,760,247 11,697,832 54 Ending Balance $327,630 227,410 (4,507,454)2,937,585 11,697,832 55 56 Interest Balances 57 Accrual thru Prior Month $45,396 52,648 53,197 53,582 46,022 58 Interest (§ 2% per Year $7,253 546 379 (7,512)4,896 46,454 59 Prior Month's Interest Adj.$0 3 6 (48)0 4,464 60 Total Current Month Interest $7,253 549 385 (7,560)4,896 50,918 61 Interest Accrued to Date $52,648 53,197 53,582 46,022 50,918 62 Balance (True-Up & Interest)$380,278 280,607 (4,453,872)2,983,606 11,748,749 11,748.749 63 64 True-Up of the True-Up 65 True-Up Revenues (Collections)$8,389,342 9,972,366 10,552,232 8,867,580 8,576,349 115,490,555 66 67 Beginning Balance $57,319,020 49,025,210 39,134,552 28,647,544 19,827,710 22,003,335 68 Adjustments: 69 2008-09 PCA Transfer - ON 30828 (I $0 0 0 0 0 107,891,769 70 Emission Allowance - ON 30790 $0 0 0 0 0 (4,591,632) 71 Correction for Change in Base $0 0 0 0 0 (9,606) 72 Sub-Total $57,319,020 49,025,210 39,134,552 28,647,544 19,827,710 125,293,866 73 Interest (§ 2% per Year $95,532 81,709 65,224 47,746 33,046 74 Revenue Applied to Interest $95,532 81,709 65,224 47,746 33,046 1,481,096 75 Revenue Applied to Balance $8,293,810 9,890,658 10,487,008 8,819,834 8,543,303 114,009,459 76 True-Up of the True-Up Balance $49,025,210 39,134,552 28,647,544 19,827,710 11,284,407 11.284,407 77 78 Note: Negative amounts indicate benefi to ratepayers AtÚichmèiiTD Case No. IPC-E-lO-12 Staff Comments 5/18/1 0 Page 2 of 2 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 Fo r e c a s t e d 1 2 - M o n t h s E n d i n g M a y 3 1 , 2 0 1 1 St a f f P r o p o s a l 6/ 1 / 2 0 0 9 P C A R a t e s t o 6 / 1 / 2 0 1 0 P C A R a t e s (1 ) (2 ) (3 ) (4 ) (5 ) (6 ) (7 ) (8 ) Ra t e Av e r a g e No r m a l i z e d Cu r r e n t B a s e PC A Cu r r e n t B a s e & Li n e Sc h . Nu m b e r o t En e r g y & C u r r e n t P C A Re v e n u e Pr o p o s e d P C A Av e r a g e Pe 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 s Re v e n u e it / k W h Ch a n q e 1 Un i t o r m T a r i f f R a t e s : 2 Re s i d e n t i a l S e r v i c e 1 39 3 , 8 8 1 4, 9 8 7 , 3 8 6 , 9 9 0 $3 9 9 , 1 4 3 , 0 6 2 ($ 5 4 , 4 0 2 , 4 1 7 ) $3 4 4 , 7 4 0 , 6 4 5 6. 9 1 2 2 -1 3 . 6 3 % 3 Ma s t e r M e t e r e d M o b i l e H o m e P a r k 3 22 4, 9 1 0 , 0 7 7 $3 7 5 , 1 8 4 ($ 5 3 , 5 5 9 ) $3 2 1 , 6 2 5 6. 5 5 0 3 -1 4 . 2 8 % 4 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 51 81 5 , 6 3 5 $6 4 , 4 1 3 ($ 8 , 8 9 7 ) $5 5 , 5 1 6 6. 8 0 6 5 -1 3 . 8 1 % 5 Re s i d e n t i a l S e r v i c e T i m e - o t - D a y 5 78 1, 1 9 8 , 5 6 4 $9 4 , 5 3 3 ($ 1 3 , 0 7 4 ) $8 1 , 4 5 9 6. 7 9 6 4 -1 3 . 8 3 % 6 Sm a l l G e n e r a l S e r v i c e 7 28 , 2 1 4 16 5 , 7 5 3 , 1 8 7 16 , 0 4 8 , 3 9 1 ($ 1 , 8 0 8 , 0 3 6 ) $1 4 , 2 4 0 , 3 5 5 8. 5 9 1 3 -1 1 . 2 7 % 7 La r g e G e n e r a l S e r v i c e 9 30 , 9 9 6 3, 4 8 9 , 8 2 3 , 0 4 6 21 3 , 7 0 2 , 5 3 7 ($ 3 8 , 0 6 6 , 9 8 9 ) $1 7 5 , 6 3 5 , 5 4 8 5. 0 3 2 8 -1 7 . 8 1 % 8 Du s k t o D a w n L i g h t i n g 15 - 6, 6 0 5 , 7 7 0 1, 0 8 0 , 5 6 0 ($ 7 2 , 0 5 6 ) $1 , 0 0 8 , 5 0 4 15 . 2 6 7 0 -6 . 6 7 % 9 La r g e P o w e r S e r v i c e 19 11 6 2, 0 2 4 , 6 5 0 , 4 0 9 10 0 , 1 5 3 , 4 4 4 ($ 2 2 , 0 8 4 , 8 8 5 ) $7 8 . 0 6 8 , 5 5 9 3. 8 5 5 9 -2 2 . 0 5 % 10 Ag r i c u l t u r a l I r r i g a t i o n S e r v i c e 24 16 , 3 7 9 1. 6 3 7 , 0 9 1 , 1 9 11 0 , 5 1 4 , 3 6 5 ($ 1 7 , 8 5 7 , 3 9 6 ) $9 2 , 6 5 6 , 9 6 9 5. 6 5 9 9 -1 6 . 1 6 % 11 Un m e t e r e d G e n e r a l S e r v i c e 40 1. 9 1 1 16 , 5 1 8 , 8 6 2 1, 1 8 5 , 0 8 2 ($ 1 8 0 , 1 8 7 ) $1 , 0 0 4 , 8 9 5 6. 0 8 3 3 -1 5 . 2 0 % 12 St r e e t L i g h t i n g 41 26 2 22 , 9 7 5 , 5 8 1 2, 7 2 7 , 1 4 7 ($ 2 5 0 , 6 1 8 ) $2 , 4 7 6 , 5 2 9 10 . 7 7 9 0 -9 . 1 9 % 13 Tr a f f i c C o n t r o l L i g h t i n g 42 30 7 4, 0 1 2 , 6 1 3 21 6 , 4 3 2 ($ 4 3 , 7 7 0 ) $1 7 2 , 6 6 2 4. 3 0 3 0 -2 0 . 2 2 % 14 To t a l U n i f o r m T a r i f f s 47 2 , 2 1 7 12 , 3 6 1 , 7 4 2 , 4 5 3 $8 4 5 , 3 0 5 , 1 5 0 ($ 1 3 4 , 8 4 1 . 8 8 4 ) $7 1 0 , 4 6 3 , 2 6 6 5. 7 4 7 3 -1 5 . 9 5 % 15 16 Sp e c i a l C o n t r a c t s : 17 Mi c r o n 26 1 51 1 . 9 1 6 , 5 3 0 $2 2 , 6 8 1 , 3 4 5 ($ 5 , 5 8 3 , 9 8 6 ) $1 7 , 0 9 7 , 3 5 9 3. 3 3 9 9 -2 4 . 6 2 % 18 J R S i m p l o t 29 1 18 6 , 8 9 2 , 5 3 2 8, 2 0 3 , 1 2 9 ($ 2 , 0 3 8 , 6 2 4 ) $6 , 1 6 4 , 5 0 5 3. 2 9 8 4 -2 4 . 8 5 % 19 DO E 30 1 24 8 , 8 3 2 , 7 5 1 10 , 6 3 6 , 1 0 5 ($ 2 , 7 1 4 , 2 6 8 ) $7 , 9 2 1 , 8 3 7 3. 1 8 3 6 -2 5 . 5 2 % 20 Ho k u 32 1 15 8 , 5 4 5 , 0 0 0 7, 4 1 4 , 3 0 5 ($ 1 , 7 2 9 , 4 0 9 ) $5 , 6 8 4 , 8 9 6 3. 5 8 5 7 -2 3 . 3 3 % 21 To t a l S p e c i a l C o n t r a c t s 4 1, 0 6 , 1 8 6 , 8 1 3 48 , 9 3 4 , 8 8 4 ( 1 2 , 0 6 6 , 2 8 7 ) 36 , 8 6 8 , 5 9 7 3. 3 3 2 9 -2 4 . 6 6 % 22 23 24 To t a l I d a h o R e t a i l S a l e s 47 2 , 2 2 1 13 , 4 6 7 , 9 2 9 , 2 6 6 $8 9 4 . 2 4 0 , 0 3 4 ($ 1 4 6 , 9 0 8 , 1 7 1 ) $7 4 7 , 3 3 1 , 8 6 3 5. 5 4 9 0 -1 6 . 4 3 % Vi r : ( ) ~ ~ S ' ~ : : i ~: : ~ ~ ¡ õ Q ~ S 1 '" 3 ; . g i if 3 ' " - I (l ( l ( ) t T = I i ~& S t p ! o . - i .. 0 1 W , i .- , N ¡ ....oN..Û C" ~ 8. ~ 6 E :Ea.Q;oCl-E :: .. .5: ~Oi:o"CoUQ)"CJja... ;: - 0Q) Q)õ Il..~a: :sa.o-oQ)c::ia. 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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 s Re v e n u e it / k W h Ch a n q e 1 Un i f o r m T a r i f f R a t e s : 2 Re s i d e n t i a l S e r v i c e 1 39 3 , 8 8 1 4, 9 8 7 , 3 8 6 , 9 9 0 $4 0 1 , 7 8 1 , 3 9 0 ($ 1 3 , 0 0 4 , 9 5 4 ) $3 8 8 , 7 7 6 , 4 3 6 7. 7 9 5 -3 . 2 4 % 3 Ma s t e r M e t e r e d M o b i l e H o m e P a r k 3 22 4, 9 1 0 , 0 7 7 $3 7 7 , 7 8 1 ($ 1 5 , 0 4 4 ) $3 6 2 , 7 3 7 7. 3 8 8 -3 . 9 8 % 4 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 51 81 5 , 6 3 5 $6 4 , 8 4 4 ($ 2 , 2 3 7 ) $6 2 , 6 0 7 7. 6 7 6 -3 . 4 5 % 5 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 78 1, 1 9 8 , 5 6 4 $9 5 , 1 6 7 ($ 3 , 3 0 6 ) $9 1 , 8 6 1 7. 6 6 4 -3 . 4 7 % 6 Sm a l l G e n e r a l S e r v i c e 7 28 , 2 1 4 16 5 , 7 5 3 , 1 8 7 16 , 1 3 6 , 0 7 4 (8 2 , 2 6 1 ) 16 , 0 5 3 , 8 1 3 9. 6 8 5 -0 . 5 1 % 7 La r g e G e n e r a l S e r v i c e 9 30 , 9 9 6 3, 4 8 9 , 8 2 3 , 0 4 6 21 3 , 7 0 2 , 5 3 7 (1 7 , 3 4 7 , 7 7 5 ) 19 6 , 3 5 4 , 7 6 2 5. 6 2 6 -8 . 1 2 % 8 Du s k t o D a w n L i g h t i n g 15 - 6, 6 0 5 , 7 7 0 1, 0 8 0 , 5 6 0 52 , 1 7 5 1, 3 2 , 7 3 5 17 . 1 4 8 4. 8 3 % 9 La r g e P o w e r S e r v i c e 19 11 6 2, 0 2 4 , 6 5 0 , 4 0 9 10 0 , 1 5 3 , 4 4 4 (1 3 , 0 6 0 , 7 8 1 ) 87 , 0 9 2 , 6 6 3 4. 3 0 2 -1 3 . 0 4 % 10 Ag r i c u l t u r a l Ir r i g a t i o n S e r v i c e 24 16 , 3 7 9 1, 6 3 7 , 0 9 1 , 7 1 9 11 0 , 5 1 4 , 3 6 5 (6 , 8 4 7 , 1 7 5 ) 10 3 , 6 6 7 , 1 9 0 6. 3 3 2 -6 . 2 0 % 11 Un m e t e r e d G e n e r a l S e r v i c e 40 1, 9 1 1 16 , 5 1 8 , 8 6 2 1, 8 5 , 0 8 2 (6 0 , 2 9 3 ) 1, 1 2 4 , 7 8 9 6. 8 0 9 -5 . 0 9 % 12 St r e e t L i g h t i n g 41 26 2 22 , 9 7 5 , 5 8 1 2, 7 2 7 , 1 4 7 51 , 7 8 9 2, 7 7 8 , 9 3 6 12 . 0 9 5 1. 9 0 % 13 Tr a f f i c C o n t r o l L i g h t i n g 42 30 7 4, 0 1 2 , 6 1 3 21 6 , 4 3 2 (2 3 , 6 3 0 ) 19 2 , 8 0 2 4. 8 0 5 -1 0 . 9 2 % 14 To t a l U n i f o r m T a r i f f s 47 2 , 2 1 7 12 , 3 6 1 , 7 4 2 , 4 5 3 $8 4 8 , 0 3 4 , 8 2 3 ($ 5 0 , 3 4 3 , 4 9 2 ) $7 9 7 , 6 9 1 , 3 3 1 6. 4 5 3 -5 . 9 4 % 15 16 Sp e c i a l C o n t r a c t s : 17 Mi c r o n 26 1 51 1 , 9 1 6 , 5 3 0 $2 2 , 6 8 1 , 3 4 5 ($ 3 , 6 3 4 , 7 2 0 ) $1 9 , 0 4 6 , 6 2 5 3. 7 2 1 -1 6 . 0 3 % 18 J R S i m p l o t 29 1 18 6 , 8 9 2 , 5 3 2 8, 2 0 3 , 1 2 9 ( 1 , 3 3 6 , 6 9 5 ) 6, 8 6 6 , 4 3 4 3. 6 7 4 -1 6 . 2 9 % 19 DO E 30 1 24 8 , 8 3 2 , 7 5 1 10 , 6 3 6 , 1 0 5 (1 , 8 1 5 , 6 0 9 ) 8, 8 2 0 , 4 9 6 3. 5 4 5 -1 7 . 0 7 % 20 Ho k u 32 1 15 8 , 5 4 5 , 0 0 0 7, 4 1 4 , 3 0 5 (1 , 0 7 6 , 6 7 5 ) 6, 3 3 7 , 6 3 0 3. 9 9 7 -1 4 . 5 2 % 21 To t a l S p e c i a l C o n t r a c t s 4 1, 1 0 6 , 1 8 6 , 8 1 3 48 , 9 3 4 , 8 8 4 (7 , 8 6 3 , 6 9 9 ) 41 , 0 7 1 , 1 8 5 3. 7 1 3 -1 6 . 0 7 % 22 23 24 To t a l Id a h o R e t a i l S a l e s 47 2 , 2 2 1 13 , 4 6 7 , 9 2 9 , 2 6 6 $8 9 6 , 9 6 9 , 7 0 7 ($ 5 8 , 2 0 7 , 1 9 1 ) $8 3 8 , 7 6 2 , 5 1 6 6. 2 2 8 -6 . 4 9 % ~W ( ' ~ .. e i i : ee ~ C 1 ~ .. ( ' Z : : 00 0 3 , 'i 3 ' C 1 ! ~ 3 . . : : (J ' i - C1 g n t t w ¡ ¡ t ¡ o . . .. 0 W i ..N Di v i s i o n o f P o w e r C o s t s IP C - E - 1 0 - 1 2 Co m p a n y C a s e De s c r i p t i o n In i t i a l Al l o c a t e d Sh a r e d Id a h o C u s t o m e r Id a h o Am o u n t to O t h e r wi t h Re v e n u e PC A Ju r i s d i c t i o n s Sh a r e h o l d e r s Re q u i r e m e n t Ra t e s ($ ) ($ ) ($ ) ($ ) (t / k W h ) Fo r e c a s t ( 2 0 1 0 - 2 0 1 1 ) 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 19 , 6 9 6 , 8 8 9 1, 0 2 4 , 2 3 8 93 3 , 6 3 3 17 , 7 3 9 , 0 1 8 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, 2 0 3 , 5 3 9 62 , 5 8 4 1, 1 4 0 , 9 5 5 Su b - T o t a l 20 , 9 0 0 , 4 2 8 1, 0 8 6 , 8 2 2 93 3 , 6 3 3 18 , 8 7 9 , 9 7 3 0. 1 4 0 4 Tr u e U p ( 2 0 0 9 - 2 0 1 0 ) Re v e n u e f r o m F o r e c a s t R a t e (5 8 , 9 6 5 , 9 6 9 ) (5 8 , 9 6 5 , 9 6 9 ) 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 54 , 3 1 7 , 0 3 4 2, 8 2 4 , 4 8 6 2, 5 7 4 , 6 2 7 48 , 9 1 7 , 9 2 1 Lo a d G r o w t h A d j u s t m e n t 23 , 6 8 0 , 3 2 8 1, 2 3 1 , 3 7 7 1, 1 2 2 , 4 4 8 21 , 3 2 6 , 5 0 3 Gr e e n T a g S a l e s C r e d i t (6 6 5 , 7 8 8 ) (3 4 , 6 2 1 ) (3 1 , 5 5 8 ) (5 9 9 , 6 0 9 ) 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, 0 7 4 , 8 7 9 55 , 8 9 4 0 1, 0 1 8 , 9 8 5 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 26 5 , 9 4 5 26 5 , 9 4 5 Su b - T o t a l 19 , 7 0 6 , 4 2 9 4, 0 7 7 , 1 3 6 3, 6 6 5 , 5 1 7 11 , 9 6 3 , 7 7 7 0. 0 8 8 8 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 22 , 0 0 3 , 3 3 5 22 , 0 0 3 , 3 3 5 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 : Ul e n ( ' ~ 20 0 8 - 2 0 0 9 P C A T r a n s f e r 10 7 , 8 9 1 , 7 6 9 10 7 , 8 9 1 , 7 6 9 ;: S e i : : ~: : ( ' ~ , Em i s s i o n A l l o w a n c e - O N 3 0 7 9 0 (4 , 5 9 1 , 6 3 2 ) (4 , 5 9 1 , 6 3 2 ) .. ( ' Z : : 00 0 : 3 Co r r e c t i o n f o r C h a n g e i n B a s e (9 , 6 0 6 ) (9 , 6 0 6 ) "" : 3 ' ( ' ~ : 3 t : : : : (J ( ' ( ' ' T 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 1, 4 8 1 , 0 9 6 1, 4 8 1 , 0 9 6 (' : : , .. . . t I Co l l e c t i o n s f r o m T r u e U p R a t e (1 1 5 , 4 9 0 , 5 5 5 ) ( 1 1 5 , 4 9 0 , 5 5 5 ) o t r ~ .. 0 Su b - T o t a l 11 , 2 8 4 , 4 0 7 0 0 11 , 2 8 4 , 4 0 7 0. 0 8 3 8 N i ..N 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 ) 51 , 8 9 1 , 2 6 4 5, 1 6 3 , 9 5 8 4, 5 9 9 , 1 4 9 42 , 1 2 8 , 1 5 7 1 0. 3 1 3 0 I -o In s: -æ ~ ~ ~:E c. 0: :¡- ..Q) ..E c .9 Q) Q)(/ :: E:J ~ æ ~ü ;: '5 - o Q) C".i ci Q)~ ci ~ Q)"0 "0æ fi 0 -.. '§ ~ e C/ co.cC/ f/..f/o(... 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N õ) ~ co co (j I' -eto Ct N CO I' .. 0en 0 Ct I' co en ""i. I' Ó i. "" 0 ~to .. co to I' in enen Ct to to 0 ""ct"'C"-~ oiin in N ..- .... ..en N to to in I'to Ct 0 en in 0I' to to 0 in ""....oi..ó..en en - co en coCO in "" "" NI'"' .. i. ..0- ...... ..- inCtCt CtooNN C/l-Z::o :æ c: c:(.e- LLo ~ol- C/-:i ooo(' C!oinN ooin C!o ôoin-oooN ooin ooo.. (SJeIiOa JO SU0!l!W) lunow'f 'f~d 0 ~0 ::N 0 ~~0 NN~ 0)00ci0N~ CO 00cD00N~ l"f'00 0NM (0 êò0cD0N:: I!~0 M0NI" ~CO0c:0N ~" M ~i.00 ro CON ~N N0c:c:0 ~N N (.~N 0.0 c:0 NNN 0 CO0..0N ~ 0)C\0)M0)~~ CO M0)r-0)~~ I"~0)cD0)~~~ (0 (ò0)r-0)~~~ I!~0)0)cx~ (l I" 0)..~~ M 0)0)0)..~ .l..c0:;0 00~..-c:Üa.II AttachrienfG Case No. IPC-E-I0-12 Staff Comments 5/18/10 _B a s e Ra t e l! l m m Æ I W ! P C A I n c r e a s e _ P C A D e c r e a s e AV E R A G E R E S I D E N T I A L E N E R G Y R A T E S FO R I D A H O P O W E R C O M P A N Y Ce n t s p e r K i l o w a t t - h o u r 6. 8 7 1 1 6. 1 4 1 1 5. 7 9 1 1 5. 0 6 1 1 4. 7 0 i 4. 8 5 1 4 . 9 3 1 1 4 . 7 4 1 4 . 7 5 1 4. 8 6 i I . . . . . " . ! 4 . 9 0 i 19 9 4 19 9 5 5. 1 9 i 19 9 6 1 9 9 7 1 9 9 8 19 9 9 2 0 0 0 2 0 0 1 2 0 0 1 2 0 0 2 2 0 0 3 Ma y O c t . 20 0 4 20 0 5 2 0 0 6 2 0 0 7 Th e s e r a t e s d o n o t i n c l u d e t h e m o n t h l y S e r v i c e C h a r g e . S P A C r e d i t , E n e r g y E f f c i e n c y R i d e r , F i x e d C o s t A d j u s t m e n t o r a n y L o c a l F r a n c h i s e F e e s t h a t m a y a p p l y . ~$ 4 ( " ~ .. ~ ¡ ; : : , ei : : f D K Õ ( " Z 2 1 00 3 , 3 ; . g : 3 ' i . . ' fD ( " : : :: i ~ t p ..o r C A H i s t o y C h a t 4 / 2 9 / 2 0 1 0 K D H i..N 5. 8 3 i 20 0 8 6. 6 0 i 20 0 9 7. 7 4 1 1 7 . 7 4 1 7A 3 i ~ tt & ~ e V' a . 20 1 0 2 0 1 0 CERTIFICATE OF SERVICE I HEREBY CERTIFY THAT I HAVE THIS 18TH DAY OF MAY 2010, SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO. IPC-E-IO-12, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE FOLLOWING: LISA D NORDSTROM DONOV AN E WALKER IDAHO POWER COMPANY POBOX 70 BOISE ID 83707-0070 E-MAIL: lnordstrom§idahopower.com dwalker§idahopower.com PETER J RICHARDSON GREG M ADAMS RICHARDSON & O'LEARY PO BOX 7218 BOISE ID 83702 E-MAIL: peter§richardsonandoleary.com greg§richardsonandoleary.com ERIC L OLSEN RACINE OLSON NYE BUDGE & BAILEY CHARTERED PO BOX 1391 POCATELLO ID 83204-1391 E-MAIL: elo§racinelaw.net SCOTT WRIGHT GREG SAID IDAHO POWER COMPANY POBOX 70 BOISE ID 83707-0070 E-MAIL: swright§idahopower.com gsaid§idahopower.com DR DON READING 6070 HILL ROAD BOISE ID 83703 E-MAIL: dreading§mindspring.com ANTHONY Y ANKEL 29814 LAKE ROAD BAY VILLAGE OH 44104 E-MAIL: tony§yanel.net ~~.b1SECRETARY CERTIFICATE OF SERVICE