The URL can be used to link to this page

Home My WebLink About20050516Comments.pdfDONALD L. HOWELL, II DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION PO BOX 83720 BOISE, IDAHO 83720-0074 (208) 334-0312 IDAHO BAR NO. 3366 !:~CEIVEO " r~D r-~" n!1r , '~"'\.,!, r-...uUd nn"l I" ' un L i'" .' '' ( ') r r;~' ;~', ' t 1. 1.- ~ '"" ' ' I I I V v 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 , 2005 THROUGH MAY 31 , 2006. CASE NO. IPC-05- COMMENTS OF THE COMMISSION STAFF COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its attorney of record, Donald L. Howell, II, Deputy Attorney General, and responds to the Notice of Modified Procedure issued on April 25, 2005. BACKGROUND On April 15 , 2005, Idaho Power Company filed its annual power cost adjustment (PCA) Application. Since 1993 the PCA mechanism has permitted Idaho Power to adjust its rates upward or downward to reflect the Company s annual "power supply costs." Because of its predominant reliance on hydroelectric generation, Idaho Power s actual cost of providing electricity (its power supply costs) varies from year-to-year depending on changes in Snake River streamflow and the market price of power among other things. The annual PCA surcharge STAFF COMMENTS MAY 16, 2005 or credit is combined with the Company s "base rates l to produce a customer s overall energy rate. In addition to this PCA case the Company has two other base rate filings currently before the Commission, which are proposed to become effective June 1 2005. They are the Bennett Mountain Power Plant case (IPC-05-10) and the Income Tax settlement case (IPC-05-14). In Bennett Mountain, the Company seeks an average 1.84% increase in base rates, in the tax settlement case it seeks a 4.45% base rate increase, for a combined base rate increase of 6.29%. If the Company proposed rates in all three of these cases are approved, residential energy rates would increase from approximately 5.79~/kWh to 6.14~/kWh. A history of residential energy rates is shown on Attachment A. ST AFF AUDIT AND ANALYSIS The PCA has three components: 1) a projection component; 2) a true-up component that corrects for the previous years projection 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. Staff also address the rate design for the PCA as well as the two base rate requests. A. The PCA Projection The National Weather Service Northwest River Forecast Center in Portland, Oregon forecasts the April through July Brownlee Reservoir inflow this year to be 2.18 million acre-feet (mat). This is thirty-five percent (35%) of the normal expected inflow. A regression equation developed from the results of the general rate case power supply model is used to project "Net Power Supply Costs.See Order No. 24806. Using the forecasted 2.18 mafand the regression equation, Staff calculates Net Power Supply Costs for April 2005 through March 2006, to be $108 977 744. As authorized by Commission Order, Staff increased the calculated Net Power Supply Costs by expected PURPA qualifying facility purchases of$46,413 057 to generate an expected PCA expense of$155 390 801. See Staff Attachment B. This is more than $61 million above normal on a total company basis. Staff found that its calculation agreed with Idaho Power s calculation. The calculation of the projection rate component is shown on lines 1 Base rates were set by the Commission in Idaho Power s last general rate case, Case No. IPC-O3-13. STAFF COMMENTS MAY 16, 2005 through 6 of Attachment C, where the projection rate component is calculated to be 0.4288 ~/kWh. Staffs calculation of the projection rate component agrees with Idaho Power calculation. B. The PCA True-up In this year s PCA there are two separate components to the true-up rate calculation: deferrals and "lost revenue. 1. Deferrals Exhibit No.3 to Idaho Power witness Schwendiman s testimony illustrates the calculation of the first true-up component. Staffhas reviewed Idaho Power s true-up calculations and proposes two adjustments. Attachment D is Staffs calculation of true-up deferral amounts. Differences from the Company s filing are shown enclosed in boxes. The first adjustment is the February 2005 amount on line 18 , " Fuel Expense - Coal" has been reduced by $295 546 to correct a data entry error. The corrected amount is $8 274 853. The second Staff adjustment is shown on line 43 "Intervenor Funding" in the month of June 2004. Intervenor funding is reduced from $50 365 to $5 030 because, by Commission Order, the difference, with associated interest, is directly assignable to specific customer classes. The detailed amounts and rate calculations are discussed later in these comments. As shown on Attachment D , line 59 in the "Totals" column, the true-up amount with interest is $35 989 725. In rounded numbers it is composed as follows: Miscellaneous Adjustments (Lines 43, 44, 45) Interest $(30.1 Million) $ 80.7 Million $ (4.7 Million) $(10.1 million) $ 0.2 Million Last Year s Projection Revenues 90 % of Last Year s Above Normal Power Supply Costs Above Normal PURP A Facilities Costs ----------------- Total True-up Expense $ 36.0 Million Staff s rate is less than the rate calculated by the Company due to the two adjustments previously discussed. STAFF COMMENTS MAY 16, 2005 To verify revenues and costs associated with Idaho Power s true-up deferrals, Staff conducted an audit of all actual revenues and expenses that occurred during the PCA year. These revenues and costs included the Bonneville Power Administration (BP A) water agreement, cloud seeding programs, fuel expenses for coal, fuel expenses for gas, and power purchases and sales. Staff also examined intervenor funding expenses, Settlement Agreement Credits for Order No. 29600, IDACORP Energy credits and the Risk Management operating plans. The following items were significant: a. BP A Water Option Agreement.The Bonneville Power Administration (BP A) water option agreement was a contract between Idaho Power and the BP A that gave the BP A the option to purchase and release storage water from Brownlee Reservoir in an effort to improve passage and survival of fish through the various projects on the lower Snake and Columbia Rivers. The agreement called for the BP A to pay Idaho Power a sum of $4 000 000 to purchase the option to discharge the stored water. Bonneville Power paid the option amount but never called for the water. This provided a benefit to customers without any cost. b. Cloud Seeding Program.Idaho Power spent approximately $690 550 in total on the cloud seeding program costs during the prior PCA year. As part of the costs, Idaho Power Company hired two companies to assess the 2004 and 2005 cloud seeding operations. Desert Research Institute accounted for $283 356 and RHI Consulting accounted for $51 756 in total costs. Together these consultants accounted for 48% of the total cloud seeding program expenses. The high one-time review costs were due to abnormal test results that required follow up. Idaho Power was able to resolve concerns and further refine seeding techniques. That will allow for more efficient and effective seeding in the future. The other 52% of the program expenses were attributed to meteorologist fees, project materials, IPC labor fees, and other miscellaneous expenses. c. Fuel Expense - Coal.A large portion of Idaho Powers electricity comes from thermal power produced from coal plants. The three coal plants in operation for Idaho Power are Bridger, Valmy, and Boardman. For the audit period of April 2004 to March 2005 the total coal expense for all plants in operation was $96,430 131. Through review of the individual months in , the audit period, Staff discovered that quarterly coal pile surveys were conducted at all Idaho Power coal plants. These surveys track actual coal levels so that adjustments can be made to the coal inventory accounts. ST AFF COMMENTS MAY 16, 2005 As the Company prepared responses to Staff s audit requests, it discovered a discrepancy in the February 2005 amount. The original amount reported for coal expense was $8 570 399. The corrected amount was $8 274 853 resulting in a variance of$295 546. The corrected amount is included in Staffs true-up calculations, Attachment D. d. Fuel Expense - Gas.Idaho Power owns two gas-fired combustion turbine generating plants. The Danskin and Bennett Mountain Power Plants are both located near Mountain Home and account for 100% of gas usage. The total variable gas and gas transportation expense amounted to $3 773 145 for the PCA period. e. Power Purchases and Sales.Staff reviewed all power purchases and sales in conjunction with the Company s Risk Management Operating Plans. Our analysis concluded that all transactions were reasonable, prudent and followed the Risk Management Committee recommendations. These transactions were made with an assortment of credit-worthy partners on a timely basis, and there were no transactions conducted with IDACORP Energy or any other Idaho Power affiliate. f. Intervenor Funding.Staff analyzed all intervenor-funding reimbursement amounts included in the PCA. The amounts followed Commission Orders and, with Staff s adjustments are disbursed appropriately. In Order No. 28927 there is $281 that is attributed to interest and carrying charges from the Order issue date of June 2001 through May 2004. This interest was computed using the customer deposit rate. Included below is a breakdown of all order numbers and amounts totaling the requested amount: Intervenor Funding Schedule Idaho Power Company PCA 29371 29505 29505 29505 28927 28927 335 Schedule 24/ Idaho Irrigation Pumpers Association 000 Schedule 1/NW Energy Coalition 15,000 Schedule 24/ldaho Irrigation Pumpers Association 000 Schedule 1/Community Action Partnership Association of Idaho 749 All customers/Energy Efficiency Advisory Group 281 Interest and carrying charges accumulated from June 2001 ST AFF COMMENTS MAY 16 , 2005 As previously discussed, Staff reduced the amount included in the true-up deferral calculation to $5 030 (Attachment D, line 43) which is the amount to be recovered from all ratepayers. The remaining intervenor funding amount with interest is directly assigned to residential and irrigation customers per Commission Order. g. Settlement Agreement (Order No. 29600):.In a Stipulation involving Idaho Power and the Commission Staff, both parties agreed on a single comprehensive settlement amount to resolve several outstanding issues identified in the Stipulation. The parties proposed that the expense adjustment rate for growth (EARG) component in the PCA would continue at the existing value, 16.84 mills per KWH, until the next general revenue requirement case in which the Company resets the base rates for PCA computation purposes. Idaho Power also agreed to provide a $19.3 million revenue credit to Idaho Power Customers in the Company s PCA. This revenue credit would be a separate $804 166 monthly line item for the months June 2004 through May 2006 in the PCA true-up calculation and includes interest from June 1 2004 at the PCA carrying charge rate of one percent (1 %). It was also agreed that the June 2003 Valmy Unit No.2 incident issues should be resolved in the PCA. The Commission approved the Stipulation in Order No. 29600 issued in September 2004. Staff verified that all settlement components of the Stipulation were incorporated in this PCA Application. The Company has included the proper credit for customers in the amount of$8 041 667 through March 2005. 2. Lost Revenue The second component included in the true-up rate is the court ordered "lost revenue from the irrigation load reduction case, IPC-01-34. The lost revenue amount with interest is $13,482 882, per Order No. 29669. The combined true-up amount is $49 472 607. The true-up rate component of .3973 ~/kWh is calculated on line 13 of Attachment C to these comments. C. The PCA True-up of the True-up The true-up amount set for recovery in last year s PCA case (IPC- E-04-09) was $44 841 981 and the established true-up rate was 0.3540~/kWh. Including interest considerations, the approved rate under recovered the true-up amount by $635 652. As shown on Attachment C, line 15, this becomes the true-up of the true-up PCA rate component of 0051 ~/kWh. This is the same rate the Company calculated. STAFF COMMENTS MAY 16, 2005 PCA RATES The Staffs calculated PCA rate of 0.8312~/kWh is the sum of the three components listed above (0.4288 + 0.3973 + 0.0051 = 0.8312). The Staffs second component differs from the Company s by 0.0023~. This difference is attributed to the coal adjustment and the intervenor funding adjustment. However, for reasons stated in its Application, the Company does not wish to increase PCA rates at this time. Therefore, the Company proposes to continue the existing PCA rate of 0.6039~/kWh for another year. Staff agrees with the Company proposal to continue the existing PCA rates except as noted below. The continuation of the lower rate is expected to cause the Company to under recover the true-up by approximately $28.3 million, which it proposes to recover in next year s PCA. Staff believes that carrying over this relatively large amount is a reasonable risk to accept. The PCA rate of 0.6039~/kWh generates approximately $75.2 million per year. That coupled with the facts that the income tax related one year temporary surcharge will expire at the end of May next year, that there is an additional year of the settlement credit and that there is a very low probability of worse water conditions (see Attachment B) convinces Staff to recommend continuation of the existing rate. Staff believes that there is a good chance that $28.3 million can be carried over to next year without causing a PCA rate increase next year. Staff proposes an additional adjustment to the Residential and Irrigation PCA rates. Following discussions with the Company, Staff removed some intervenor funding amounts from the true-up calculations because the Commission ordered that they be directly assigned to the Residential and Irrigation classes for recovery. The amounts with interest and rate calculations are shown on Attachment C, lines 25 and 26. Staff s proposed PCA rates for the June 1 , 2005 through May 31 , 2006 PCA year are 6045~/kWh for the residential class, 0.6052~/kWh for the irrigation classes, and 0.6039~/kWh for all other classes. Lines 32 through 35 of Attachment C calculate total expected PCA revenue for the coming year of approximately $75.2 million excluding intervenor funding. Line 37 shows the amount of the true-up expected to be carried over to next year as approximately $28. million. STAFF COMMENTS MAY 16, 2005 PCA RECOMMENDATIONS Staff recommends that the Commission accept Staffs fuel expense adjustment and intervenor funding changes. Staff also recommends that last years PCA rate of 0.6039~/kWh be continued as proposed by the Company with two exceptions. Staff recommends that the PCA rates for Residential Customers and Irrigation Customers be slightly higher to recover intervenor funding amounts previously ordered by the Commission. The Residential Rate should be 6045~/kWh and the Irrigation rate should be 0.6052~/kWh. Staff recommends that the PCA rates become effective June 1 , 2005. COMBINED BASE RATES As mentioned above, Idaho Power Company has two other rate applications before the Commission which request changes in base rates on June 1 , 2005 , the same day new PCA rates are to be effective. The other two cases are the Bennett Mountain case (IPC-05-10) and an income tax case (IPC-05-14). These two cases include three revenue requirement amounts and three different rate design methods. Staffhas already filed comments in the Bennett Mountain case but deferred the final calculation of the Bennett Mountain revenue requirement and rates to these comments. The two separate amounts to be passed on to customers in the income tax case were previously established by Commission Order. The proposed income tax rate designs are discussed in these comments. Attachment E shows current and Staff calculated base rates and the rate increments from the three rate designs using the Company s proposed methodology. Column c shows current rates. Columns e, f and g show the three increments that add to base rates to produce the rates shown in Column h. The three rate design proposals are discussed in more detail below. A. Bennett Mountain (IPC-O5-10) The Company calculated its Bennett Mountain revenue requirement to be $9 402 996 which requires an average increase of 1.84%. It then spread that increased revenue requirement to energy, demand and lighting rates on a uniform percentage basis. Staff proposes a revenue requirement associated with Bennett Mountain of$9 391 958 which is based on the adjustments Staff recommended in its comments in the Bennett Mountain STAFF COMMENTS MAY 16, 2005 case (based upon the change order adjustment). Attachment E, Column e, shows rate increments produced with Staff adjustments and the revenue spread proposed by the Company. Staff recommends later in these comments to spread the revenue requirement uniformly among all classes. B. Income Taxes (IPC-O5-14) The income tax case has two revenue requirement components. The first is a permanent base rate increase of $11 ,504 677 per year, or approximately 2.25%. The Company proposed to spread this increase to all customer classes on a uniform percentage basis. Within customer classes the Company spread the increase to the demand and energy rates on a uniform percentage basis. The amount of this increase was previously approved by Commission Order No. 29601. The rates and rate increments contained in the Company s filing have been checked by Staff and are correct as filed. These rate increments are found in Column f of Attachment E. The second income tax-related revenue increase is a temporary base rate increase of about 2.2% or $11 638 229 for one year (June 1 2005 to May 31 2006). Once again, this amount was previously approved by Commission Order No. 29601. In its filing the Company proposes to spread the increase to all customer classes on a uniform percentage basis. Within classes the Company proposes an equal cents per kWh increase. The rates included in the Company s filing are correct except for schedule 41 rates which were calculated using an incorrect factor. Staff Attachment E, Column f shows Staff s calculated rates which are the same as the Company s except for the Schedule 41 rate increments. C. Base Rates Column h of Attachment E shows the new base rates for all schedules when the Company s revenue allocation and rate design methodologies are applied to Staff s recommended revenue requirements. Attachment F shows the combined effects of the base rates calculated by the Staff. As shown on Attachment F, the average increase is 6.28% and the effects of the base rate changes are approximately a uniform percentage increase to the classes. It is not exactly a uniform percentage increase to customer classes for two reasons. First the Bennett Mountain increase is spread uniformly to all demand and energy rate components and not first spread uniformly to customer classes based on total revenue. Second, the one year STAFF COMMENTS MAY 16, 2005 temporary tax increase was spread uniformly to the customer classes based on 2004 normalized revenues and the resulting rates were then applied to normalized 2003 billing determinants. The class revenue relationships in 2004 were not the same as they were in 2003. This second item also explains why the Attachment F total revenue adjustment of $32 144 937 is $389 927 less than the combined revenue requirements of the two cases which is $32 534 864. Rates calculated using higher energy, demand and customer billing determinants in 2004 produce lower rates than would be calculated using 2003 billing data. When the lower rates are applied to 2003 billing data the restated revenues are lower than they would be if applied to 2004 billing data. CONSUMER ISSUES As of May 13 , 2005 the Commission had received about 40 written comments from customers. Only two customers specifically referred to the Power Cost Adjustment (PCA) and the Company s proposal to defer it until next year; those two commenters were in favor of the proposal to defer any PCA increase. Because there are two other Idaho Power cases that will affect customers ' base rates many comments referred to all three cases. All commenting customers oppose increases in rates. Nearly one-half of the comments were from senior citizens, low-income or fixed income customers who are concerned about how they will be able to pay for increases in energy rates. One customer from Nampa who said he had moved to Idaho from New York wrote , " Why can Idaho Power offer a benefit for over 55 seniors like some utilities do?" Four more customers wrote similar comments requesting special lower rates for low-income or senior citizens. Sixteen people asked the Commissioners to consider just saying "" to Idaho Power when it ask for rate increases. "Just Say No" has become a very common phrase found in customer comments regarding rate increases. RECOMMENDATIONS CONCERNING OVERALL COMBINED BASE RATES After evaluating the revenue requirement impact, Staff is not comfortable with the percentage differences that exist between customer classes as shown on Attachment F. To make the results more uniform and equitable, Staff recommends the Commission adapt an alternative revenue spread. It is our recommendation that the $32 144 937 total revenue requirement shown STAFF COMMENTS MAY 16, 2005 on Attachment F be spread to all customer classes on a uniform percentage basis. Under this proposal each class would experience an approximate 6.28% increase. Within each class the Bennett Mountain and permanent income tax increases would be spread on an equal percentage basis to energy and demand components and the temporary income tax increase would be spread to energy rates on an equal ~/kWh basis. Placing the temporary income tax rate increase on the energy rates makes the rates easier to adjust in a year when this increase expires. Staff further recommends that the Company be directed to file new tariff schedules that incorporate these rate changes to be effective June 1 , 2005. Respectfully submitted this (p-ft, day of May 2005. Donald L. Hower Deputy Attorney General Technical Staff:Keith Hessing Alden Holm Eric Johnson i:umisc:commentslipceO5. 1 5dhkhah ST AFF COMMENTS MAY 16, 2005 oC / ) n ~ S- PJ : : t .. . . . . . . ~ VJ 0\ 1 - - 0 1 - ) ( 1 ) ( " ) on z e - I- - - ; : : s .- + (1 ) "'- :: s I ... . . . - - vr tr J ... . . . . . Ba s e R a t e PC A I n c r e a s e PC 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 - ho u r 85 ~ 70 4 .. J 1 1 1 1 1 ! ! ! ! ! 1 4 . 86 4 90 4 4 . 74 4 4 . 75 1 1 5 . D6 \ ! 93 t f t 19 9 4 19 9 5 19 9 6 19 9 7 19 9 8 U:\ k h e s s i n \ I P C E 0 5 1 5 \ P C A H i s t o r y C h a r t - 2 0 0 5 B a s e C h a n g e 4/ 2 2 / 2 0 0 5 K D H 87 ~ 66 ~ 19 9 9 20 0 0 20 0 1 Ma y 20 0 1 Oc t . 20 0 2 20 0 3 19 t f t 20 0 4 14 ~ 54 t f t 20 0 5 Pr o p o s e d O( / ) ( ) ~ V1 .. . . . . . ~ ... . . . . -- - ~ en ... . . . . ... . . . . . . (D ~ ~( ) Z ~ f- I ~ "" C ; j . . . . . . . (D ( ) t:J j ... . . . . t I 1 en I ... . . . . . . 14 0 , 00 0 00 0 12 0 00 0 , 00 0 10 0 00 0 , 00 0 tI J 1; ) 8 0 , 00 0 00 0 ~ 6 0 , 00 0 , 00 0 ::: : J L. 4 0 00 0 00 0 0. . 2 0 , 00 0 , 00 0 .. . . . (2 0 , 00 0 , 00 0 ) (4 0 00 0 , 00 0 ) ID A H O P O W E R ' S 2 0 0 5 P C A P R O J E C T I O N IP C - O5 - 15 Th i r t e e n t h A n n u a l PC A A A t: . t: . PC A E x p e n s e = N P S C + Q F E x p e n s e = 1 0 8 97 7 74 4 + 4 6 , 4 1 3 , 05 7 - 1 5 5 39 0 80 1 18 M i l l i o n A c r e - Fe e t A I P C - 03 - 13 D a t a t: .D. bt : . t: . Re g r e s s i o n L i n e 20 0 5 F o r e c a s t b. A I:: : . tP . tJ . tJ . tJ . tJ . tJ . I: : : . tJ . t: . t: . tJ . ,6 . t: . t: . 00 0 , 00 0 00 0 00 0 6 00 0 00 0 8 , 00 0 , 00 0 1 0 00 0 00 0 Ap r i l t h r o u g h J u l y Br o w n l e e I n f l o w ( A c r e - Fe e t ) 00 0 00 0 00 0 00 0 , 2005-2006 PCA - Thirteenth Annual I PC-05- Staff Case (a)(b)(c)(d)(e)(f) (g) Line Descri tion Units Base Forecast Difference Rate Projection 2005-2006: PCA Expense ($) 101 157 155 390 801 289 644 Normalized System Firm Sales (MWH)863,484 863,484 Energy Rate (rt/kWh)73154 20800 0.47646 Sharing Percentage (%) 90% Energy Rate Difference (rt/kWh)0.428816016 0.4288 MWh (f/,/kWh) True-Up of 2004-2005:989 725 Lost Revenue Adjustment 13,482 882 Total True Up 49,4 72 607 12,453 880 972465368 3973 True-Up of the True-Up:635 652 12,453 880 051040479 0051 PCA Rates: Calculated PCA Rate Adj. From Base (rt/kWh)8312 Proposed PCA Rate Adj. from Base (rt/kWh)6039 PCA Rate Currently in Effect (rt/kWh)6039 Difference - Last Year to This Year (rt/kWh)0000 PCA Rates with Class AssiQnable Intervenor Fundin!Intervenor Funding Increment Rate MWh (f/,/kWh) Residential Rate 188 372 299 0006 6045 Irrigation Rate 20,488 624 801 0013 6052 All Other PCA Rates 0000 6039 Expected PCA Revenues:Rate Energy Revenue /MWh MWh Forecast Revenue 288 12,453 880 53,402 237 True Up Revenue 700 12,453,880 171 596 True Up of True Up Revenue 051 12,453 880 635 148 Total 039 208 981 Expected True Up Amount to be Carried Over to Next Year:301 011 Note: Negative rates and amounts indicate benefits to ratepayers. U:\khessin\IPCE0515\Company Case\TRUE UPS & RATES 5/10/2005 Attachment C Case No. IPC-05- Staff Comments 05/16/05 TRUE-UP CALCULATIONS FOR 2004 - 2005 FOR IDAHO POWER COMPANY PCA CASE NO.IPC-05- Staff Case 2004 2004 2004 2004 2004 2004 2004 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 842 500 878 149 002 040 185 074 303 702 164,116 925,105 5 Forecast Rate m/KWh 2.460 2.460 2.499 2.499 2.499 2.499 2.499 6 Revenue 072,550 160 247 504 098 961 500 257 951 909 126 311 837 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 036 225 192 903 1,437,674 590 212 1,464 897 173 332 073,670 10 Normalized Firm Load MWh 991 176 033 117 258 858 1,491 793 1,424 633 179 173 055 943 11 Load Change MWh 45,049 159 786 178 816 98,419 264 (5,841)17,727 12 Expense Adjustment (((Y16.84)(758 625)690 796)011 261)657 376)(678 046)98,362 (298 523) 14 Non-QF PCA 15 ACTUAL: 16 BPA Water Option Agreement 000 000) 17 Cloud Seeding Program 18 Fuel Expense - Coal 292 689 286 332 810 652 135,422 520 606 8,473 631 503 811 19 Fuel Expense - Gas 216 597 196 636 429 861 002,631 904,767 152,449 363,797 20 Non-Firm Purchases 195,701 098 396 21,378 551 26,408 680 685 833 353 203 560 224 21 Surplus Sales (12 584 352)(13 226,444)(10 126 531)720 252)(10 296 193)(15 010,445)461 295) 22 Expense Adjustment (tQ216.84)(758 625)690 796)011 261)657 376)(678 046)362 (298 523) Sub-Total 362,010 664 124 16,481 272 169 105 136 967 067,200 668 014 25 BASE: 26 Fuel Expense 341 000 293 000 344 900 714 800 721 300 8,446 500 727 700 27 Danskin 275 700 279 600 280 000 264,800 272,300 28 Non-Firm Purchases 339 000 356 000 931,000 335 100 842 900 480 800 700 29 Surplus Sales 195 000)(597 000)558 900)385,400)371 000)702 300)(4,982 500) 30 Surplus Sales Adder (826 063)(979 683) Sub-Total (341,063)072 317 992 700 944 100 8,473 200 3,489 800 053 200 33 Change From Base 703,073 591 807 11,488 572 225 005 663 767 577,400 614 814 34 Deferral (Shared and Allocated)892,851 277 732 729 671 506,457 12,418 744 876 600 061 386 36 QF Deferral 37 Actual (includes Net Metering)837,750 620 158 634 991 841 368 040 365 277 232 903 909 38 Base 038 265 024 735 508 847 702,897 6,422 258 081 395 792 830 40 Change From Base 799,485 595,423 (873 856)(861 529)381 893)(804 163)(888 921) 41 Deferral (Allocated)679 562 506 110 (822 298)(810 699)300 361)(756 717)(836,475) 43 Intervenor Funding 030 I 44 Credit From IDACORP Energy (166 667)(166 667)(166 667)(166 667)(166 667)(166 667)(166 667) 45 Settlement Agreement (ON 29600)(3,216 667)(804 167) 46 Total Deferral 6+34+41 +43+44+45)333 196 2,456 929 241,638 567 591 693 765 172 577)(1,057 759) 48 Principal Balances 49 Beginning Balance 333 196 790 125 031 763 599 354 293 119 120,543 50 Amount Deferred 333 196 2,456 929 241 638 567 591 693 765 172,577)057 759) 51 Ending Balance 333 196 790,125 031 763 599 354 293 119 120,543 062 783 53 Interest Balances 54 Accrual thru Prior Month 599 257 117 603 53,493 55 Interest ((Y1% per Year 611 658 860 15,499 911 267 56 Prior Month's Interest Adj.(12)(14)(4,021) 57 Total Current Month Interest 599 658 860 15,485 890 19,246 58 I nterest Accrued to Date 599 257 117 603 53,493 739 59 Balance (True-Up & Interest)333 196 793 724 041 020 619,471 328 722 174 036 22,135 522 61 True-Up of the True- 62 True-Up Revenues True Up Rate rt/kWh 3579 3579 3564 3540 3579 3540 3540 Actual Idaho Sales kWh 840 704 656 939 127 871 054 848 703 325 929 728 309 551 663 137 579,165 975 839,218 Total 008 882 361 139 759 284 694 355 686 855 975,988 3,454,471 67 Begmning Balance 841 981 870,467 544 221 817 057 151 716 25,489 987 21,535 241 68 Interest ((Y1% per Year 37,368 892 32,120 014 25,126 242 946 69 Revenue Applied to Interest 368 892 120 014 126 242 946 70 Revenue Applied to Balance 971 514 326 247 727 164 665 341 661 729 954 747 3,436,525 71 True-Up of the True-Up Balance 870,467 38,544 221 817 057 151 716 25,489 987 535 241 098 716 73 Level of Customer Sharing 90%90%90%90%90%90%90% 74 Idaho Jurisd. Energy Allocator 85.85.94.94.94.94.94. 75 Load Change Adjustment Rate $/MWh (16.84)(16.84)(16.84)(16.84)(16.84)(16.84)(16.84) 76 Interest Rate 00%00%00%00%00%00%00% Note: Negative amounts indicate benefit to ratepayers Attachment D Case No. IPC-05- U:lkhessinlipce0515\Company CaselTRUE UPS & RATES 5/10/2005 KDH Staff Comments 05/16/05 Page 1 of 2 TRUE-UP CALCULATIONS FOR 2004 - 2005 FOR IDAHO POWER COMPANY PCA CASE NO.IPC-05- Staff Case 2004 2004 2005 2005 2005 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS PCA Revenue 4 Normalized Idaho Jurisd. Sales MWh 885 609 965 920 043 993 968 236 909 048 073,492 5 Forecast Rate m/KWh 2.499 2.499 2.499 2.499 2.499 6 Revenue 213 137 2,413 834 608 939 2,419,622 271 711 104 551 Load Change Adjustment 9 Actual System Firm Load - Adjusted MWh 097 209 225,417 238 145 059 141 056 166 644 991 10 Normalized Firm Load MWh 079 817 220,491 207 127 032 883 040 475 015,486 11 Load Change MWh 392 926 018 258 15,691 629 505 12 Expense Adjustment ((g)16.84)(292 881)(82 954)(522,343)(442 185)(264 236)(10 600 864) 14 Non-QF PCA 15 ACTUAL: 16 BPA Water Option Agreement 000 000) 17 Cloud Seeding Program 216 027 49,388 027 357 108 690 550 18 Fuel Expense - Coal 706 276 942 215 8,427 310 274 8531 056 333 96,430,130 19 Fuel Expense - Gas 179 777 870 185,485 70,522 (19 247)773,145 20 Non-Firm Purchases 836 816 15,401 617 878 876 791 393 996 146 181 585,436 21 Surplus Sales 176 261)(10,596,420)(11 380 113)849 553)(11 891,264)(121 319,123) 22 Expense Adjustment (~16.84)(292,881)(82 954)(522 343)(442 185)(264 236)(10 600 864) 23 Sub-Total 253 727 970 355 638 603 913 057 234 840 146 559 274 25 BASE: 26 Fuel Expense 8,445 200 727 000 8,460 000 371 000 282 200 874 600 27 Danskin 264 700 272 800 272 500 257 500 273,400 713 300 28 Non-Firm Purchases 610 900 884 100 397 900 700 700 379 800 29 Surplus Sales (1,414 700)357 300)811 600)681 800)074 900)(51 132,400) 30 Surplus Sales Adder 805 746) 31 Sub-Total 906 100 526 600 318 800 35,400 (441 600)029 554 33 Change From Base 347 627 6,443 755 319 803 877,657 676 440 529 720 34 Deferral (Shared and Allocated)988 205 5,457 216 739,841 212,288 501 177 662,169 36 QF Deferral 37 Actual (includes Net Metering)987 548 074 999 007,543 814,515 589 967 630,345 38 Base 204 739 193 531 164 012 073 610 292 773 44,499 892 40 Change From Base (217 191)(118 532)(156,469)(259 095)(702 806)869,547) 41 Deferral (Allocated)(204 377)(111,539)(147 237)(243 808)(661 340)709 180) 43 Intervenor Funding 030 44 Credit From IDACORP Energy (166 667)(166 667)(166 667)(166,667)(166 667)(2,000,000) 45 Settlement Agreement (ON 29600)(804 167)(804,167)(804 167)(804 167)(804 167)041,669) 46 Total Deferral 6+34+41 +43+44+45)(1,400 142)961 010 012 832 578 024 597 292 811 798 48 Principal Balances 49 Beginning Balance 062 783 662 641 623 651 636,483 214 507 50 Amount Deferred (1,400 142)961 010 012,832 578 024 597 292 35,811 798 51 Ending Balance 662 641 623 651 27,636,483 214 507 811 798 53 Interest Balances 54 Accrual thru Prior Month 739 124 108 343 127 196 150 224 55 Interest (g)1 % per Year 386 219 853 030 679 181,973 56 Prior Month's Interest Adj.(3)047) 57 Total Current Month Interest 386 219 853 027 27,703 177 926 58 Interest Accrued to Date 124 108,343 127 196 150 224 177,926 59 Balance (True-Up & Interest)753 766 731 994 763 679 364 730 989 725 989,725 61 True-Up of the True- 62 True-Up Revenues True Up Rate rf,/kWh 3540 3540 3540 3579 3540 Actual Idaho Sales kWh 890,496,444 005 408 010 078 920 738 016 643 093 954 795 701 529 844 990 Total 152 357 559,144 819 379 638 566 340 328 44,450,749 67 Beginning Balance 18,098,716 961,441 11,414 764 604 897 972,669 68 Interest (g)1 % per Year 082 12,468 512 337 311 69 Revenue Applied to Interest 15,082 12,468 512 337 311 244,419 70 Revenue Applied to Balance 137,275 546 676 809 867 632 228 337,017 206,329 71 True-Up of the True-Up Balance 961,441 11,414,764 604 897 972,669 635 652 73 Level of Customer Sharing 90%90%90%90%90% 74 Idaho Jurisd. Energy Allocator 94.94.94.94.94. 75 Load Change Adjustment Rate (16.84)(16.84)(16.84)(16.84)(16.84) 76 Interest Rate 00%00%00%00%00% Note: Negative amounts indicate benefit to ratepayers Attachment D Case No. IPC-05- U:lkhessinlipce0515\Company CaselTRUE UPS & RATES 5/10/2005 KDH Staff Comments 05/16/05 Page 2 of 2 (a) Schedule (b) Billing Unit Cust Min 300 kWh kWh Cust Min Energy Watch Hours kWh kWh Cust Min On-Peak Mid-Peak Off-Peak Off-Peak (c) Current 07/28/04 Base Rates 050863 057253 050863 200000 050863 050863 064781 058090 049725 050863 061177 068915 061177 2.75 029062 025926 125. 10. 025464 022825 Commission Staff Calculation Idaho Power Company Summary of Rate Changes State of Idaho Current Base + Bennett + Tax (d)(e) Cust Min 300 kWh kWh ( f) (g) 06/01/05 rate increments IPC-O5-l0 IPC-O5-14 IPC-O5- Bennett Perm Tax Temp Tax increment increment increment Rate Description summer winter 000980 001103 000980 Cust Min BLC BLC kWH kWH Cust Min BLC BLC kWh kWh summer winter 000000 000980 000980 summer summer summer winter 001248 001119 000958 000980 summer winter 001179 001328 001179 summer winter summer winter summer winter 000560 000500 summer winter summer winter summer winter 000491 000440 U:\khessin\IPCEO515\Staff Case\2005 Summary of Changes to Rates 001214 001363 001214 000000 001214 001214 001506 001351 001156 001214 001482 001 662 001482 000659 000586 000590 000501 001214 001214 001214 000000 001214 001214 001214 001214 001214 001214 001479 001479 001479 000817 000817 000817 000817 (h) Staff Calculated 06/01/05 Base Rates 054271 060933 054271 200000 054271 054271 068749 061774 053053 054271 065317 073384 065317 031098 027829 125. 10. 027362 024583 Attachment E Case No. IPC-05- Staff Comments 05/16/05 Page 1 of 4 Cust 1 25.125. Min 10.10. BLC 0.43 summer BLC 0.43 winter summer winter kWh 024897 summer 000480 000569 000817 026763 kWh 022414 winter 000432 000511 000817 024174 195 cust blc summer blc winter summer on-peak summer winter kwh 030335 on-summer 000584 000675 000612 032206 kwh 028822 mid-summer 000555 000640 000612 030629 kwh 026863 off-summer 000518 000595 000612 028588 kwh 025932 mid-winter 000500 000573 000612 027617 kwh 024761 off-winter 000477 000546 000612 026396 19P cust 125.125. blc 0.79 summer blc winter 2.79 summer on-peak summer winter kWh 025860 on-summer 000498 000577 000612 027547 kWh 023342 mid-summer 000450 000519 000612 024923 kWh 021755 off-summer 000419 000482 000612 023268 kWh 02111 7 mid-winter 000407 000467 000612 022603 kWh 020147 off-winter 000388 000444'000612 021591 191 cust 125.125. blc 0.40 summer blc 0.40 winter 2.72 summer on-peak summer winter 2:63 kwh 025504 on-summer 000491 000582 000612 027189 kwh 023019 mid-summer 000444 000524 000612 024599 kwh 021455 I"\ff-sumrY'lc non A 1 ~n nnnA88 000612 022968VI r II 11'-'U'"TI-..J VUV'"T kwh 020782 mid-winter 000400 000472 000612 022266 kwh 019827 off-winter 000382 000450 000612 021271 245 bill 12.In-Season 12. bill Out-Season min In-Season Out-Season kwh 032618 In-Season 000628 000738 000946 034930 kwh 032618 Out-Season 000628 000738 000946 034930 U:\khessin\IPCEO515\Staff Case\2005 Summary of Changes to Rates Attachment E Case No. IPC-05- Staff Comments 05/16/05 Page 2 of 4 24T bill 12.In-Season 12. bill Out-Season In-Season Out-Season kwh 031028 In-Season 000598 000721 000946 033293 kwh 031028 Out-Season 000598 000721 000946 033293 255 bill 12.In-Season 12. bill Out-Season meter min In-Season Out-Season kwh 059178 On-Peak 001140 001346 000946 062610 kwh 033816 Mid-Peak 000652 000756 000946 036170 kwh 01 6907 Off-Peak 000326 000363 000946 018542 kwh 033816 Out-Season 000652 000756 000946 036170 min 1.50 kwh 051713 000996 001157 001138 055004 032080 000618 000710 000687 034095 Lamp Charges (a)(b)(c)(d)(e)(f) (g) (h) 7/28/04 kWh 06/01/05 lamp Base per Bennett Perm Tax Temp Tax Base Schedule MRU Rate Lamp increment increment increment Rate Min 1CSA 112642 2CSA 0.225284 2CSF 11.. 68 225284 11. 4CHF 18.44 137 0.43 0.453881 19. 4CSA 14.137 0.453881 15. 4CSF 16.137 0.453881 17. 1 KHF 33.342 0.78 1 .133046 36. Street Liqhtinq - Company Owned 70S 0 "r- I r-...." uooo/ 100S 079991 200S 156080 400S 166 323866 10. 175M 136570 C6. 92 400M 10.77 163 318013 11. 150S 6.41 117060 250S 104 202904 1.71 U:\khessin\IPCEO515\Staff Case\2005 Summary of Changes to Rates Attachment E Case No. IPC-05- Staff Comments 05/16/05 Page 3 of 4 street Lightinq - Company Owned - METERED 70S 5.27 100S 200S 400S 166 250S 104 Meter Chg energy 043257 000833 001951 047047 1.71 Street Liqhtinq - Customer Owned 100S 079991 200S 4.41 156080 250S 5.29 104 202904 400S 166 323866 25CI 128766 175M 136570 400M 163 318013 1 KM 13.388 756988 14. 70S 056579 Street Liqhtinq - Customer Owned - METERED 100S 1.62 1.69 200S 1.65 1.72 250S 1.62 104 1.69 400S 1.64 166 25CI 1.65 1.72 175M 1.69 400M 1.73 163 1.80 1KM 2.47 388 70S 1.82 Meter Chg 00. energy 043257 000833 001006 001951 047047 Special Contracts (a)(b)(c)(d)(e)(f) (g) (h) Name 07/28/04 06/01/05 Billing Base Bennett Perm Tax Temp Tax Base Schedule Unit Rate Description increment increment increment Rate Micron 204 Excess Demand 000 000 204 1.58 Contr. Demand 1.65 6.43 Demand ' 0. kwh 013111 Energy 000253 000294 000544 014202 Simplot 204 Excess Demand 000 000 204 1.45 Contr. Demand 1.51 Demand kwh 013173 Energy 000254 000304 000507 014238 DOE Demand kWh 014122 Energy 000272 000319 000515 015228 Attachment E Case No. IPC-05- U:\khessin\IPCEO515\Staff Case\2005 Summary of Changes to Rates Staff Comments 05/16/05 Page 4 of 4 Co m m i s s i o n S t a f f C a l c u l a t i o n 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 - Mo n t h s E n d i n g D e c e m b e r 3 1 , 20 0 3 ( 1 ) (2 ) (3 ) (4 ) (5 ) (6 ) (7 ) (8 ) Ra t e 20 0 3 A v g . 20 0 3 S a l e s 07 / 2 8 / 0 4 Be n n e t t & T a x Pr o p o s e d Li n e Sc h . Nu m b e r o f No r m a l i z e d Ba s e Re v e n u e Ba s e Av e r a g e Pe r c e n t Ta r i f f D e s c r i ti o n No . Cu s t o m e r s 1k Y Y b l Re v e n u e Ad j u s t me n t Re v e n u e (t / Ch a n q e Un i f o r m T a r i f f R a t e s : Re s i d e n t i a l S e r v i c e 33 5 , 60 5 4, 1 4 1 , 39 3 , 4 2 6 22 8 , 28 8 , 64 4 14 , 29 7 , 31 8 2 4 2 , 58 5 , 96 2 85 8 26 % Sm a l l G e n e r a l S e r v i c e 32 , 31 6 26 5 , 33 5 , 66 7 17 , 89 2 , 03 3 1, 1 1 4 , 68 7 19 , 00 6 , 7 2 0 16 3 23 % La r g e G e n e r a l S e r v i c e 17 , 4 1 5 01 4 , 4 2 6 , 98 6 11 1 , 28 9 , 82 3 97 5 , 90 2 1 1 8 , 26 5 , 7 2 5 92 3 27 % Du s k t o Da w n L i g h t i n g 87 2 , 58 6 89 2 , 76 7 56 , 86 4 94 9 , 63 1 16 . 17 1 37 % La r g e P o w e r S e r v i c e 10 5 97 8 , 82 4 , 23 7 56 , 67 4 , 30 7 50 6 , 75 0 60 , 18 1 , 05 7 04 1 19 % 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 13 , 51 7 62 0 , 93 0 , 93 1 69 , 17 8 , 27 4 4, 4 3 2 , 4 7 8 73 , 61 0 , 7 5 2 54 1 6. 4 1 % Un m e t e r e d G e n e r a l S e r v i c e 22 4 16 , 05 4 , 94 2 82 6 , 01 7 52 , 83 7 87 8 , 85 4 5. 4 7 4 6. 4 0 % St r e e t L i g h t i n g ,4 2 0 17 , 87 8 , 7 4 2 67 8 , 72 2 10 4 , 35 4 1, 7 8 3 , 07 6 97 3 22 % Tr a f f i c C o n t r o l L i g h t i n g 38 4 , 21 8 29 3 , 81 1 90 9 31 2 , 7 2 0 33 2 6. 4 4 % To t a l U n i f o r m Ta r i f f s 40 1 , 6 6 0 11 , 0 7 0 , 10 1 , 7 3 5 48 7 , 01 4 , 39 8 30 , 56 0 , 09 9 5 1 7 , 57 4 , 4 9 7 67 5 27 % Sp e c i a l C o n t r a c t s : Mi c r o n 63 6 , 96 7 , 67 0 15 , 88 5 , 37 0 00 5 , 81 0 16 , 89 1 , 1 8 0 65 2 33 % J R S i m p l o t 18 6 , 68 4 , 66 5 34 0 , 05 0 27 7 , 91 1 61 7 , 96 1 2. 4 7 4 6. 4 0 % DO E 20 3 , 08 4 , 14 6 82 4 , 34 2 30 11 7 12 5 , 4 5 9 52 4 24 % To t a l S p e c i a l C o n t r a c t s 1 , 02 6 , 7 3 6 , 4 8 1 25 , 04 9 , 76 2 1 , 58 4 , 83 8 26 , 63 4 , 60 0 59 4 33 % b( / ) n ~ V1 " " " ::+ -- - - ~ IZ J "" " ~( 1 ) ~ ~n z ~ To t a l I d a h o Re t a i l S a l e s 40 1 , 6 6 3 12 , 09 6 , 83 8 , 21 6 51 2 , 06 4 , 16 0 32 , 14 4 , 93 7 5 4 4 , 20 9 , 09 7 4. 4 9 9 28 % (1 ) ~: : s ~. . . . . . (1 ) n ~ :: s I fi j t t 1 ... . . . CERTIFICA TE OF SERVICE HEREBY CERTIFY THAT I HAVE THIS 16TH DAY OF MAY 2005 SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE NO. IPC-05-, BY MAILING A COpy THEREOF POSTAGE PREPAID, TO THE FOLLOWING: BARTON L KLINE MONICA MOEN IDAHO POWER COMPANY PO BOX 70 BOISE ID 83707-0070 GREGORY W SAID IDAHO POWER COMPANY PO BOX 70 BOISE ID 83707-0070 SECRE Y ' , CERTIFICATE OF SERVICE