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Home My WebLink About20040622Yankel Direct.pdfHECEIVED illFILED ANKEL 2fiOq JlI N 22 P'H 12: :19 SSOCIATES, INC'~9,r~c, , . f,",!n~J. I.' t ItJ . Ur'H;-11~~JUf1 29814 Lake Road Bay Village, Ohio 44140 Tekphone (440) 892.1222 Fax (440) 808.1450 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF A VISTA CORPORATION FOR THE AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC AND NATURAL GAS SERVICE TO ELECTRIC' AND NATURAL GAS CUSTOMER IN THE STATE OF IDAHO CASE NO. A VU-O4- dI. COURT REPORTER ..L. COEUR SILVER VALLEY DIRECT TESTIMONY OF ANTHONY J. YANKEL June 21 , 2004 PLEASE STATE YOUR NAME, ADDRESS, AND EMPLOYMENT. I am Anthony J. Yanke!. I am President of Yanke I and Associates, Inc. My address is 29814 Lake Road, Bay Village, Ohio, 44140. WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL BACKGROUND AND PROFESSIONAL EXPERIENCE? I received a Bachelor of Science Degree in Electrical Engineering from Carnegie Mellon University in 1969 and a Master of Science Degree in Chemical Engineering from the University of Idaho in 1972. From 1969 through 1972, I was employed by the Air Correction Division of Universal Oil Products as a product design engineer. My chief responsibilities were in the areas of design, start-up, and repair of new and existing product lines for coal-fired power plants. From 1973 through 1977, I was employed by the Bureau of Air Quality for the Idaho Department of Health & Welfare, Division of Environment. As Chief Engineer of the Bureau my responsibilities covered a wide range of investigative functions. From 1978 through June 1979, I was employed as the Director of the Idaho Electrical Consumers Office. In that capacity, I was responsible for all organizational and technical aspects of advocating a variety of positions before various governmental bodies that represented the interests of the consumers in the State of Idaho. From July 1979 through October 1980, I was a partner in the firm of Yankel, Eddy, and Associates. Since that time, I have been in business for myself. I am a registered Professional Engineer in the states of Ohio and Idaho. I have presented testimony before the Federal Energy Yankel, D I Coeur Regulatory Commission (FERC), as well as the State Public Utility Commissions of Idaho Montana, Ohio, Pennsylvania, Utah, and West Virginia. ON WHOSE BEHALF ARE YOU TESTIFYING? I am testifying on behalf of Coeur Silver Valley. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? My testimony will address the cost-of-service for Schedule 25 customers with emphasis upon directly assigning as opposed to allocating distribution plant to these customers and the rate design for Schedule 25 in order to properly reflect load factor differences within Schedule 25. Q. PLEASE SUMMARIZE YOUR CONCLUSIONS WITH RESPECT TO THE MANNER IN WHICH COSTS SHOULD BE ASSIGNED TO SCHEDULE 25 CUSTOMERS. A. After reviewing the Company s cost-or-service study, I have concluded that there are some problems with respect to the allocation/assignment of Primary related distribution plant associated with Schedule 25 customers. Basically, the Company is able to (and does properly) assign the actual costs incurred associated with distribution substations to Schedule 25. However, after identifying specific substation costs to directly assign, the Company then goes back to allocation Primary related equipment (between the substations and the customer) in a Yankel, D I Coeur manner that ignores the fact that these are customers for which specific Primary plant can be isolated and either directly assigned or simply identified as not existing at all. After correcting for only these problems (in plant accounts 364-367), the rate of return for Schedule 25 is significantly increased to the point where it is above the system average rate of return. Based upon this result, I recommend that Schedule 25 be given the average jurisdictional increase. I have reviewed the rate design for Schedule 25 in connection with the load and load factor of Schedule 25 customers. There is no question that Potlatch-Lewiston is a very special case for Schedule 25 and that rates must be designed with this customer s cost-of-service in mind. However, Coeur Silver Valley is the next largest customer and it has a significantly higher load factor than the remaining Schedule 25 customers. The difference in load factors of the various Schedule 25 customers must be better addressed than in the Company s proposed rate design. I recommend that rates be established which better reflect this difference in load factor and thus cost causation. Q. ARE YOU ADDRESSING ALL ASPECTS OF A VISTA'S CLASS COST-OF- SERVICE STUDY? A. No. Due to time constraints, I have not made a complete review of all aspects of the study, but have focused on those areas where major discrepancies exist between the way costs are addressed (allocated/assigned) and the actual costs that are incurred. For example, there are areas such as the change in allocation methodology from the last case that I am aware exists, but have not reviewed. Yankel, D I Coeur COST -OF-SERVICE STUDY Q. WHAT AREAS IN THE COMPANY'S COST-OF-SERVICE STUDY DID YOU ADDRESS IN DETAIL? A. My focus was on: 1) distribution Accounts 361-367 as they relate to Schedule 25 customers; and 2) how the rates paid by Schedule 25 customers relate to individual customer load factors. Q. IS THE ALLOCATION/ASSIGNMENT OF DISTRIBUTION RELATED PLANT COSTS THE SAME FOR SCHEDULE 25 AS IT IS FOR ALL OTHER CUSTOMER CLASSES? A. No. While most distribution plant was allocated to the various rate schedules Schedule 25 customers received a mixed bag of allocated and directly assigned plant. Generally speaking, this may not be unusual except for the pattern of what plant is allocated compared to what plant is directly assigned. Direct assignment should be done wherever possible, as it is an accurate reflection of cost causation, while allocation of costs is only done as a surrogate of cost causation. A vista only has 15 customers2 in its Idaho jurisdiction that are on Schedule 25. These are Avista s largest customers in Idaho. Appropriately, Avista has directly assigned costs associated with Account 361 (Distribution Substation Structures & Improvements) and Account 362 (Substation Equipment) to Schedule 25 as can be seen on Exhibit 301. However, costs associated with 1 The main exception to this is Street and Area Lighting customers. Yankel, D I Coeur Account 364 (Poles and Towers) and Account 365 (Overhead Conductors & Devices) were then allocated to Schedule 25 customers as opposed to directly assigned. Q. WHAT IS WRONG WITH ALLOCATING ACCOUNT 364 AND 365 COSTS TO SCHEDULE 25 CUSTOMERS? A. If the costs associated with Accounts 361 and 362 could not have been directly assigned to Schedule 25 (but had to be allocated), then it may have been appropriate to allocate costs associated with Accounts 364 and 365 to Schedule 25 customers. However, the Company was able to isolate and directly assign the costs for Accounts 361 and 362 to Schedule 25, so it is only appropriate to continue to directly assign the primary lines and towers that originated at these facilities and carry electricity to these same Schedule 25 customers. This may be best understood by an illustration using the Lucky Friday Substation that serves Hecla Mining Company. Starting at the generation level, there is no way to segregate or directly assign generation plant to Hecla Mining Company, so it must be allocated. Likewise when that electricity is sent over the transmission system, there is no way to segregate or directly assign transmission plant to Hecla Mining Company, so it must be allocated. Electricity next travels through substations. The Lucky Friday Substation is entirely used to serve the Hecla Mining Company so it is not allocated, but 100% directly assigned to Schedule 25. Coming out of this substation, these particular Primary lines are 1 121 feet (0.2 Miles) long and are obviously used to serve only Hecla s Schedule 25 load and should be directly assigned, as was the plant (Accounts 361 and 362) serving those Primary lines. 2 Including Potlatch's Lewiston facility. Yankel, D I Coeur Q. WHAT DISTORTIONS RESULT WHEN POLES, TOWERS, AND OVERHEAD CONDUCTORS ARE NOT BEING DIRECTLY ASSIGNED TO SCHEDULE 25 CUSTOMERS? A. Schedule 25 customers are the largest use customers on the system. Collectively, Schedule 25 customers account for 170 611 kW of non-coincident demand out of610 300 kW listed for all customers3 or 28%. According to the Company s workpapers4 there are 3 049 circuit miles of Primary lines in Idaho. If all of the Schedule 25 non-coincident usage were used to allocate this plant, it would mean that 28% or 854 miles of Primary distribution line would be allocated to these 15 customers or about 60 miles of Primary distribution circuits per Schedule 25 customer. This would be an absurd result and is partially avoided because the Company correctly removes the Potlatch-Lewiston load when it is developing its D08 allocator for Primary related plant. It is my understanding that the Potlatch-Lewiston load is removed because the circuits behind the substation are not used to serve any customers other than Potlatch and are not even owned by A vista. However, the Company did not go far enough with its assignment of costs to the rest of the Schedule 25 customers. Instead of being assigned Primary plant, the other 14 Schedule 25 customers are allocated Primary distribution plant based upon their non-coincident peak, which is set at 49 849 kW out of a total of 489 538 kW , or 10.18% of non-directly assigned Primary distribution plant. At 10.18% of the circuit miles, this means that 310 miles of Primary lines are 3 See Exhibit 16 Schedule 2 page 31 line 20. Workpapers TLK-43 and TLK- Yankel, DI Coeur allocated to these 14 customers or 22 miles for each Schedule 25 customer. Although this is better than 60 miles of circuit per customer, it is nonetheless absurd. Q. IS IT POSSIBLE TO SEGREGATE THE PRIMARY DISTRIBUTION SYSTEM ASSOCIATED WITH ALL OF THE SCHEDULE 25 CUSTOMERS AS IT IS TO SEGREGATE THE POTLATCH RELATED EQUIPMENT? A. Data has been provided by the Company6 that lists the number of feet of primary distribution plant serving each of these Schedule 25 customers. Based upon Exhibit 301 , all of the substations that are labeled as being 100% assigned to a Schedule 25 customer can easily be reviewed for direct assignment of Primary distribution plant. For those substations with less than 100% assignment of substation costs, the direct assignment of Primary related plant is still quite feasible. F or example, if there is I-mile of primary distribution plant between the substation and a Schedule 25 customer and there are some other customers served off of this same I-mile stretch, then simply assigning all of the I-mile of plant to the Schedule 25 customer would be a cons~rvative estimate of the cost responsibility of the Schedule 25 customer. Q. BASED UPON THE DATA PROVIDED BY THE COMPANY, WHAT TREATMENT DO YOU RECOMMEND FOR THESE COSTS IN THIS CASE? A. There is no question that allocating 60 or even 22 miles of Primary plant to each Schedule 25 customer is inappropriate. According to the Company, there is a total of only 20. 5 See Exhibit 16 Schedule 2 page 31 line 32. 6 Response to Coeur Silver Valley Request 8. Yankel, D I Coeur miles of Overhead Primary distribution plant and 0.96 miles of Underground Primary distribution plant used to serve all 15 of the Schedule 25 customers. As opposed to being directly assigned plant that is actually used, allocation results in approximately 15 times more 7 Overhead plant and 85 times more Underground plant being associated with these customers than is used by Schedule 25 customers. All Schedule 25 customers must be treated as Potlatch is treated and have Primary distribution plant directly assigned as opposed to allocated. I recommend using the ratio of the 20 miles of Overhead Primary lines dedicated to Schedule 25 customers divided by the 3 049 miles of Overhead Primary distribution plant in Idaho (0.66%) to allocate/assign Account 364 and 365 to Schedule 25. I recommend using the ratio of the 0.96 miles of Underground Primary lines dedicated to Schedule 25 divided by the 808 miles of Underground Primary distribution plant in Idaho (0.12%) to allocate/assign Account 366 and 367 to Schedule 25. Q. WHAT IMPACT DOES DIRECTLY ASSIGNING THE COSTS OF THESE FOUR ACCOUNTS HAVE UPON THE RATE OF RETURN FOR SCHEDULE 25? A. Exhibit 302 is a summary sheet from a cost of service run made where the costs for these four distribution accounts were directly assigned to Schedule 25. Contrary to the Company s filed rate of return for Schedule 25 that was only 25% of the jurisdictional average the rate of return for Schedule 25 (when using direct assignment) turns out to be 1.03 greater than the jurisdictional average. 7 10.180/0/0.66% = 15.48 10.18% / 0.12% = 84. Yankel, DI Coeur Q. ARE THERE CONCERNS RAISED BY THE COMPANY REGARDING THE DIRECT ASSIGNMENT OF THESE COSTS? A. Yes. First, the Company is concerned that using the relative length of primary distribution does not capture the relative cost of the primary trunk lines necessary to meet the capacity needs for extra large industrial customers. Although there may be some differences in cost of serving different capacity loads, those costs should be contained within a relatively narrow range for the Company s 13 , and 34 kv lines-not in the range of 15-85 times greater as is suggested by the Company s choice of allocation factors compared to direct assignment. Additionally, the age of the Primary lines serving Schedule 25 customers would suggest that they would be relatively cheaper than the cost of lines being installed today and may be cheaper than the average cost of Primary lines. Basically, the argument should not be accepted that the costs of these facilities are higher until actual cost data is provided which demonstrates this to be the case. Second, the Company contends that the estimates it used for the circuit mileage associated with individual customers may be slightly inaccurate. Be that as it may. I assume the Company did an acceptable job of measuring, but the potential for error always exists. In order to alleviate any concerns in this regard, I conducted another cost of service run using 1.5 times the amount of Primary lines that the Company measured. I assume that the Company s accuracy is well within this factor of 1.5. Exhibit 303 contains a summary of the results assuming that 30 miles of Overhead and 1.5 miles of Underground Primary distribution should be directly assigned to Schedule 25. The resulting rate of return was still above the jurisdictional average rate of return. Yankel, DI Coeur . 16 RATE DESIGN Q. THE PRESENT RATE DESIGN FOR SCHEDULE 25 FEATURES A FLAT ENERGY CHARGE AND A DEMAND CHARGE (ABOVE THE MINIMUM) THAT IS FLAT. DOES THIS RATE DESIGN ADEQUATELY REFLECT COSTS FOR SCHEDULE 25 CUSTOMERS? A. Although there are often good reasons for using rate structures that are flat, this does not insure that the resulting charges will be reflective of cost causation. The Company readily recognizes this phenomenon in this case where it proposes a declining block rate structure for both Schedule 21 and Schedule 25 customers. As stated in Mr. Hirschkom s direct testimony at page 22: Generally, larger use customers under the Schedule are less costly to serve than smaller use customers on a cost per kWh basis, as some fixed costs are spread over a larger base of usage. Therefore~ a lower incremental/average rate for service to larger use customers under a Schedule generally is supportable on a cost of service basis... Based upon the above, A vista is proposing the introduction of a declining block energy charge for Schedule 25 customers. Q. HOW DOES THE SIZE (USAGE) AND LOAD FACTOR VARY WITHIN SCHEDULE 25? A. Potlatch-Lewiston is a new addition to Schedule 25 and is approximately three times larger than the rest of Schedule 25 put together. Its load factor is also significantly higher than other customers on this schedule. It appears that the addition of a customer as large as Potlatch- Yankel, D I Coeur Lewiston to the Schedule 25 customer group is why a separate designation was made for this customer in the Company s cost-of-service study as well as why the Company is proposing a declining block energy rate structure for Schedule 25. After Potlatch- Lewiston, Coeur Silver Valley is the largest of the remaining 14 customers on Schedule 25. Exhibit 304 page 1 is a listing of test year monthly energy and billing demand for each Schedule 25 customer . As can be seen from that exhibit, Coeur Silver Valley s energy consumption is about 1.5 times that of the closest Schedule 25 customers, while its billing demand is the third highest of all Schedule 25 customers. The smallest Schedule 25 customer is J. D. Lumber Co. with energy consumptions about 20% that ofCoeur Silver Valley and about 1 % the size of Potlatch Lewiston. Additionally, Coeur Silver Valley is not only the largest Schedule 25 customer (excluding the new Potlatch-Lewiston load), but it also has the highest load factor of the group. Exhibit 304 page 2 lists the annual consumption as well as annual billing demands for each of these customers in order to calculate an average monthly load factorlO for each customer. As can be seen from that exhibit, Coeur Silver Valley has the highest average load factor of 71 %, while D. Lumber has the lowest at 33%. As a group (excluding Potlatch Lewiston) the average load factor for Schedule 25 is only 53%. Q. WHAT IMPLICATION DOES THIS DIFFERENCE IN LOAD FACTOR HAVE ON COST OF SERVICE AND RATE DESIGN? 9 Data provided as a workpaper in response to Staff Request 29. 10 (annual energy) (total billing demands) (730 hIs. per month) Yankel, DI Coeur A. All things being equal, higher load factor customers are generally much cheaper to serve than lower load factor customers. The fact that the Coeur Silver Valley load has an average load factor that is over 2 times the worst average load factor on the rate schedule in which it finds itself means that there are large differences in meeting demand obligations between Coeur Silver Valley and the other Schedule 25 customers. If Coeur Silver Valley is going to pay rates that are reflective of its cost causation, then the design of the rates within Schedule 25 must be such that higher load factor customers on the rate schedule are rewarded with lower rates. Q. DOES THE PRESENT SCHEDULE 25 RATE FULLY REFLECT THE DIFFERENCE IN DEMAND RELATED COSTS FOR MEMBERS OF THIS RATE SCHEDULE? A. Although there is some recognition in the existing rate schedule of the impacts of load factor, that recognition is minimal. Present rates have a minimum charge of $7 500 for the first 000 kW of demand and a $2.25 per kW charge for usage over 3 000 kV A. Assuming more than the minimum, at a 71 % load factor, this translates into 0.434 cents per kWhll, which amounts to a 15% addition to the energy charge of2.874 cents per kWh. At the Schedule 25 average load factor of 53% the demand charge translates into 0.582 cents per kWh, which is only a 20% addition over the energy cost. The effective rate for usage over 3 000 kV A per month is: L. F.Mills / kWh 33. 34. 71% 53% Yanke1, DI Coeur Although there is a 4.5% difference in the rates paid between these two load factors, this differential is not a strong price signal to reflect the difference in cost causation between the two different load factors. I will use the ratio of the demand charge to the energy charge as a gauge of the relative dependence placed upon the demand component compared to the energy component of the rate. In this particular case with a demand charge of $2.25 per kW and an energy charge of2.874 cents per kWh the ratio would be 78 (2.25 10.02874 = 78.3). Q. HAS THE COMPANY FILED DATA THAT WOULD SUGGEST A SIGNIFICANTLY DIFFERENT LEVEL OF DEMAND CHARGES FOR SCHEDULE 25? A. Yes. On Exhibit 16, Schedule 2, page 3, line 6 the Company calculated the demand related costs for serving Schedule 25 customers at current level of Return as $7.02 per kW per month. Although I do not agree that this calculation should be taken literally as the basis for setting demand charges, the fact that present demand charges for Schedule 25 are approximately 1/3rd of this level suggests that the demand charges may be too low. Q. DOES THE COMPANY'S PROPOSED SCHEDULE 25 RATE FULLY REFLECT THE DIFFERENCE IN COST CAUSA nON FOR MEMBERS OF THIS RATE SCHEDULE? A. No. The Company s proposed Schedule 25 rates do little to help the load factor diversity that I am addressing. I assume (but do not know) that the new declining block energy 11 $2.25/730 hrs / 0.71 = $0.00434 Yankel, D I Coeur rate appropriately sets a revenue requirement for the Potlatch- Lewiston load that matches its cost-of-service. However, it does little to address the load factor differentials for the rest of the Schedule 25 customers. The proposed rates have a $2.75 per kW charge for usage over 3 000 kV A. At Coeur Silver Valley s average load factor of71% this translates into 0.531 cents per kWh while at a 53% load factor it translates into 0.711 cents per kWh. With the proposed tail block energy rate of 3.420 cents per kWh, the effective rate for usage over 3 000 kV A per month is: L. F.Mills / kWh 39. 41.31 71% 53% Once again, the difference in the rates between these two load factors (4.6%) is not significant enough to reflect the difference in cost causation. In this case the proposed ratio of the demand to energy rate is 80 (2.75 /0.03420 = 80.4) or not much of a change. Q. IS THERE ANOTHER UTILITY TO WInCH THE COMMISSION COULD TURN THAT PLACES MORE EMPHASIS UPON DEMAND RELATED CHARGES? A. Yes. This Commission recently concluded a major rate case with Idaho Power. Idaho Power s Schedule 19 serves customers in a similar size range to that of A vista's Schedule 25. It is interesting to note, that the present energy rates for Idaho Power s Schedule 19 have been set at 2.8486 cents per kWh, which is almost the same as Avista's present energy rate of 8740 cents per kWh for its Schedule 25 customers. In contrast to the closeness of these energy rates, Idaho Power s demand charge for Schedule 19 is $3.21 / k W, while A vista's demand charge for Schedule 25 is $2.25 / kW (for usage greater than 3 000 kW). The ratio of the Yankel, DI Coeur demand to energy rate for Idaho Power s Schedule 19 is now set at 113 (3.21 / .028486 = 112.7). Additionally, Idaho Power s Schedule 19 has a "Basic Load Capacity" rate that increases the demand charge and thus this ratio even higher. Idaho Power s rates for Schedule 24 (Irrigation Pumping) now has a demand charge of $4.00 per kW and an energy charge of 3.244 cents per kWh. The ratio of demand to energy charges in this case is 123 (4.00/ .03244 = 123.3). In spite of the fact that it is important to keep this ratio for Irrigation customers as low as possible because Irrigators have effectively no discretion regarding their demand levels, this ratio is significantly above the 78 calculated for Avista's Schedule 25. Q. HOW CAN THIS PROBLEM BE CORRECTED? A. There are two ways to correct this problem of not assigning enough costs to low load factor customers. The first way is to increase the demand charge and lower the energy charge ( s). The second method is to develop a declining block energy rate that is load factor dependent, i. the first so many kWh per kW are priced at one rate while usage above that level is priced at a lower rate. I do not have a preference as to which method the Commission should adopt. I do recommend that whatever method the Commission uses, it should target a ratio of demand to energy charges of at least 120 for Schedule 25. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? A. Yes. Yankel, DI Coeur A V I S T A U T I L I T I E S Su b s t a t i o n s Di s t r i b u t i o n S u b s t a t i o n D i r e c t A s s i g n m e n t Id a h o J u r i s d i c t i o n E l e c t r i c C o s t S t u d y Tw e l v e M o n t h s E n d e d D e c e m b e r 3 1 , 2 0 0 2 ID A H O 12 / 3 1 / 2 0 0 2 12 / 3 1 / 2 0 0 2 SC H E D U L E 2 5 AC C O U N T 3 6 1 AC C O U N T 3 6 2 SU B S T A T I O N AC C O U N T 3 6 1 AC C O U N T 3 6 2 PE R C E N T A G E DI R E C T A S S I G N DI R E C T A S S I G N AP P L E W A Y 1 1 5 68 , 75 5 85 2 02 0 11 % 56 3 72 2 CA L A D A Y 1 3 02 9 30 9 10 0 % 02 9 30 9 CO E U R D ' AL E N E 1 5 T H S T 1 1 5 N E W 89 , 25 7 94 5 , 21 1 57 0 80 8 Co e u r S h a f t S u b 79 8 22 , 47 2 10 0 % 79 8 22 , 4 7 2 Di a m o n d M a t c h 6 0 1, 4 8 1 13 6 28 6 10 0 % 48 1 13 6 28 6 KA M I A H 1 1 5 39 , 91 2 26 6 , 30 0 18 % 18 4 93 4 KO O S K I A 1 1 5 24 4 45 9 90 9 28 % 1 , 4 6 8 12 8 , 77 5 LU C K Y F R I D A Y 1 1 5 65 1 87 2 10 0 % 65 1 87 2 Mo s c o w C i t y 91 8 74 2 , 97 4 15 % 13 , 03 8 11 1 , 4 4 6 NO R T H M O S C O W 1 1 5 27 5 16 7 17 7 33 % 39 1 16 8 OS B U R N 1 1 5 77 3 15 8 36 2 50 % 88 7 18 1 Pr a i r i e B P A 63 , 44 0 53 7 52 8 14 % 88 2 25 4 Pr i e s t R i v e r 98 6 56 7 , 4 2 2 57 % 25 2 32 3 , 4 3 1 ST . M A R I E S 1 1 5 78 , 49 3 47 3 , 62 4 20 % 69 9 72 5 SO U T H L E W I S T O N 1 1 5 57 2 82 6 54 7 10 % 35 7 65 5 25 0 33 9 , 03 8 1, 4 3 3 28 8 SC H E D U L E 2 5 P CL E A R W A T E R 1 1 5 21 4 84 8 , 03 9 10 0 % 21 4 84 8 03 9 92 1 25 3 To t a l E n d i n g B a l a n c e 1 2 / 0 2 o f A c c o u n t s Le s s : D i r e c t l y A s s i g n e d P l a n t As s i g n m e n t D e m a n d N C P - Ac c o u n t 3 6 1 70 4 87 2 16 7 46 4 53 7 , 4 0 8 To t a l 10 4 16 9 35 4 54 1 74 9 , 62 8 Ac c o u n t 3 6 2 39 9 29 7 18 7 07 7 20 , 21 2 22 0 Mi s c A s s i g n I D 2" . ;:: ; . : (., . ) tl k 6 / 2 1 / 2 0 0 4 Exhibit 302 Sumcost AVISTA UTIUTlES Idaho Jurisdiction Page 1 of 1 $c€nario: Company Base Case Cost of Service Basic Summary Electric Utility 06-11-04 Direct Assign Primary Plant For The Twelve Months Ended December 31 , 2002 Coeur Silver Valiley Data Request 8 (b)(c) (d) (e)(I) (g) (h)(i)(k)(I)(m) Residential General Large Gen Extra Large Potlatch Pumping Street & System Service Service Service Gen Service Ex Lg Gen Svc Service Area Lights Description Total Sch 1 Sch 11-Sch 21-Sch 25 Sch 25P Sch 31-Sch 41-49 Plant In Service Production Plant 300 269 000 103 855 863 871 210 089,462 322 636 527 729 560 417 041 683 Transmission Plant 109 001 000 345 154 575 673 320 080 300 710 407 393 663 998 387 992 Distribution Plant 257 643 000 130 693 683 450789 258 291 277 067 125 817 300 802 536 552 Intangible Plant 353 000 905 049 085 807 159,794 810 O9fi 138 084 170,709 83,462 General Plant 524 000 936 429 095 165 117 540 1,799 957 636 235 539 983 398 691 Total Plant In Service 714 790 000 295 736 177 078 645 166 945 510,466 110 835 257 235 908 448 380 Accum Depreciation Production Plant (91 465 000)(31 590 537)(7,260 043)(19 529 251)629 804)(22746 584)390 227)(318 554) Transmission Plant (36 394 000)(12,469 056)863 304)786 268)439 272)150968)(555 587)(129 546) Distribution Plant (75 640 000)(38 096 555)817 412)(19 619 574)(623 848)(546 491)527 105)409 017) Intangible Plant 893 000)(903 489)(197 382)(337 595)(113219)(295 660)(28 213)(17 443) General Plant (16 434 000)520,460)(1,842 622)(2.752 592)(809 892)086 077)(242 966)(179 391) T ota! Accumulated Depreciation (221 826 000)(91 580 096)(21 980 763)(50 025 279)(13 616 034)(34 825 780)(3,744 097)053951) Net Plant 492 964 000 204 156 081 097 882 116,919 8B8 894,432 009477 8,491 811 394 429 Accumulated Deferred FIT (61 593 000)(25 474 097)130 524)(14 427 654)735 958)509603)056485)258 680) Miscellaneous Rate Base 836 000 756 005 656 928 003 272 904 756 352 195 136 172 671 Total Rate Base 440 207 000 181 437989 624 286 104 495 506 063 230 68,852 070 571 499 162,420 Revenue From Retail Rates 146 248 000 648 000 212 000 804 000 10,475 000 696 000 549 000 864 000 Other Operating Revenues 677 000 598479 755 180 669 859 988 040 226 957 332 976 105 510 Total Revenues 167 925 000 246,479 967 180 39,473 859 463 040 922 957 881 976 969 510 Operating Expenses Production Expenses 522 000 179 034 239677 17,023 454 518 503 060 876 215 561 21M 895 Transmission Expenses 5,485 000 879 232 431 533 173,481 518 338 379 158 83,733 524 Distribution Expenses 495 000 031 498 929 068 864 770 479 378 155 495 379 313 Customer Accounting Expenses 296 000 174 073 712 481 196 952 870 200 053 370 Customer Infonnation Expenses 480 000 589 887 129 334 283 641 124 152 326 637 592 4,756 Sales Expenses 421 000 134 538 672 568 311 115,486 659 767 Admin & General Expenses 888 000 940 189 968 234 189 852 917 915 378 876 271 669 221 265 T olal O&M Expenses 115 587 000 928 450 441 000 823,718 242 568 24,424 611 805,762 920 891 Taxes Other Than Income Taxes 438 000 127 197 765 287 813 904 399 604 013 140 132 467 186 399 Other Income Related Items Depreciation Expense Production Plant Depreciation 933 000 2,759 593 634 649 690,789 747 420 953 357 120 107 085 Transmission Plant Depreciation 532 000 867,496 199 206 541,706 239 277 636 650 653 013 Distribution Plant Depreciation 670 000 820 382 728,701 499445 523 654 114 625 408 670 General Plant Depreciation 892 000 017 867 436 381 651 886 191 804 494 038 541 42,485 Amortization Expense 367 000 134 172 004 216 225 910 5,401 073 Total Depreciation Expense 394 000 599 510 029 941 4,461 041 262 248 216 609 336 327 488 324 Income Tax 3,794 000 556 006 732 442 451 461 241 304 660 861 040 886 Total Operating Expenses 147 213 000 211 163 968 670 550 124 145 725 315 221 368 596 653 501 Netlncome 20,712 000 035 315 998 509 923,736 317316 607 736 513379 316 009 Rate 01 Return 71%67%17%58%87%524%78%4.41% Retum Ratio 1.61 1.11 Interest Expense 250 000 346 345 -006 765 806 907 244 938 167 270 348 297 329 479 Exhibit 16, Schedule 2 T. Knox Avista Corporation Page 1 of 59 As s i g n AV I S T A U T I L I T I E S El e c t r i c U t i l i t y Id a h o J u r i s d i c t i o n Sc e n a r i o : C o m p a n y B a s e C a s e Co s t o f S e r v i c e C a l c u l a t i o n Dir e c t A s s i g n P r i m a r y P l a n t Fo r t h e Y e a r E n d e d D e c e m b e r 3 1 J 2 0 0 2 Fu n c t i o n a l i z a t i o n a n d C l a s s i f i c a t i o n Co e u r S i l v e r V a l l e y D a t a R e q u e s t 8 (k ) (I ) (m ) (n ) (0 ) (p ) (q ) (r ) (s ) (t ) (u ) (v ) (w ) (x ) (y ) No t e s Fu n c t i o n a l Cl a s s Pr o f o r m a Fu n c t i o n a l Re s i d e n t i a l Ge n e r a ! La r g e G e n Ex t r a L a r g e Po t l a t c h Pu m p i n g St r e e t & Ac c o u n t D e s c r i p t i o n Al l o c a t i o n A l l o c a t o r To t a l s To t a l s Se r v i c e Se r v i c e Se r v i c e Ge n S e r v i c e : : x L g G e n SV ( Se r v i c e Ar e a L i g h t s Sc h 1 Sc h 1 1 - Sc h 2 1 - Sc h 2 5 Sc h 2 5 P Sc h 3 1 - Sc h 4 1 - 4 9 Ra t e o f R e t u r n 4. 7 1 % 4. 7 1 % 68 % 18 % 60 % 4. 7 4 % 24 % 79 % 4.4 2 % :: r ._ - - , . _ _ . _ . . _ _ . . _ _ A . ~ AV I S T A U ' Sc h e d u l e 2b ," , w .l o m e r s Te s t Y e a r B i l l i n g D a t a S u m m a r y Id a h o 1 2 M o n t h s E n d e d D e c s m b e r 3 1 , 2 0 0 2 kll o w l t 1 h o o r s Cu s t o m e r N a m e Ac c t N o , Ja n u a r y Fe b r u a r y Ma r c h Ap r i l Ma y Ju n e Ju t y Au g u s t Se p t e m b e r Oc t o b e r No v e m b e r De c e m b e r An n u a l T o l a ! Co e u r S i l v e r V a H e y I n c 50 0 0 0 1 97 8 , 18 8 04 3 , 41 5 1 O O , 3( ) . 4 08 O 75 1 , 24 2 75 4 , 07 2 67 ~ 60 6 OO B , 14 5 16 8 , 52 4 85 3 , 60 0 4 73 3 , 24 5 3,4 9 5 , 18 9 ~e , o 1 U 1 6 He c i 8 M i n i n g C o m p a n y 50 0 0 2 3 53 0 , 8. 2 7 57 1 , 57 1 57 7 , 11 0 89 3 , 69 0 72 3 85 8 78 8 00 3 79 1 43 0 MO , 5C 2 87 7 , 02 4 ~1 , 99 7 90 3 29 9 2 , 90 4 1, 1 0 . 4 33 , 10 0 , 21 3 Po ~ a t c h C o r p o r a t l o n . S I . M a r l e s 50 0 0 2 6 04 0 , 00 0 ~0 , 00 6 57 5 , 48 8 75 2 , 40 6 73 9 , 48 5 61 0 , 59 9 , 8a 2 61 / ! , 77 8 00 0 , 63 2 43 6 , 01 9 62 2 , 14 1 48 3 , 6g e 31 , 09 7 91 3 Un i v e r s i t y o f l d a h c . W e s t C a m p J ! 50 0 0 2 7 70 8 , 36 2 57 6 , 23 8 50 3 , 29 2 60 5 , 49 5 39 7 37 7 24 6 , 03 4 22 6 , 97 4 40 5 , 62 4 41 7 , 83 9 44 3 58 4 , 76 1 45 3 , 65 0 29 , 81 1 , 30 9 Co e u r 0 A J e n e R e s o r t 70 0 0 0 1 98 3 , 80 2 95 0 4 , 6 7 8 82 M 8 7 89 5 , 5 3 3 77 9 , 59 5 83 9 , 11 4 eo e , .( U 05 9 , 3. 2 1 99 5 , ~ 1 6 US , 81 0 Be 2 , M5 , 83 4 10 , MO , 49 2 Blo u n l l n d u s t r l e s 1 0 0 0 0 0 1 57 3 , 42 9 71 6 53 7 , 88 1 70 1 , 67 2 , 70 3 74 M 6 6 81 1 , 37 6 11 1 , 11 0 12 4 37 7 97 9 , 09 9 02 0 , 92 8 96 2 , 21 8 12 e Un i v e r s i t y o f I d a h o . E a s t C a m p u s 12 3 5 1 8 8 48 . 3 , 72 0 86 4 , 57 5 53 8 , 92 3 70 7 65 0 6.9 6 , 11 4 82 5 , 09 - 4 17 6 , . 4 2 4 01 1 , 31 6 97 3 , 30 9 96 9 , 11 4 99 0 4 27 5 2,8 3 2 67 4 33 , 25 1 , 38 8 Po ~ a t c h C o r p o r a t i o n . P o s t F a l l s 2 3 O O O O . c 06 9 , 16 1 26 1 , 15 2 1 , 1 62 , 5 8 0 26 3 , 78 7 17 8 . 4 6 0 1.2 Q 7 , 45 1 15 4 , 21 0 , 2& 4 19 5 62 4 10 1 , 0.4 8 25 8 , 22 3 55 0 , 55 4 13 , 15 5 3 , 15 0 CI B B r w a t e r F o r e s l l n d u s t 24 0 0 0 0 1 13 0 , 17 2 25 8 , 73 5 19 3 , 47 5 1 , 2 3 6 , 77 ~ 28 8 54 4 26 9 , 60 0 25 9 , 18 5 34 S , 28 1 32 1 , 54 2 21 6 , 63 6 34 7 15 5 7 26 7 , 17 1 . 15 , 13 3 , B3 2 Th ~ Riv e r s T I m b e r , l n o 37 0 0 1 4 3 5 9 20 0 , 64 0 33 2 , 41 8 30 0 , 00 4 ~2 , 7 2 2 30 2 , 50 0 32 1 , 85 8 17 4 20 0 1, 1 5 9 , 88 3 22 0 21 7 , 93 0 38 3 , 00 7 30 - 4 , 08 9 1M 2 O , 77 5 Tr l . Pr o C e d a r P r o d u c t s 45 0 0 1 0 0 4 1 12 7 70 0 12 7 74 2 r0 4 , :w 3 02 3 , 80 4 85 5 , 75 0 74 5 , 58 0 , 0 5 8 61 3 , 24 2 66 - 4 , 37 4 78 0 , 39 6 92 3 , 77 2 85 9 , 62 4 10 , 31 6 3S - 4 St i m s o n L u m b e r C o m p a t 1 y - P r i e s t R i v e r 45 0 0 4 9 3 9 : 3 11 3 , 67 8 00 5 , 55 6 0. 4 3 85 2 93 6 , 54 2 0. 4 0 93 6 87 7 , 77 9 ~5 , 35 S 96 3 , e o o 11 0 0 , 13 9 00 9 , 39 6 93 0 , 8O e 99 0 4 , 62 0 59 8 , 5 8 0 J 0 L u m b e r C o 1\9 0 0 1 9 8 9 2 71 2 , 50 0 83 8 , 50 0 74 5 , 50 0 67 5 , 00 0 T7 2 , YX J 60 7 , 50 0 68 9 , 00 0 67 2 , 00 0 M3 , 0 0 0 6- 4 9 , 50 0 65 6 , 50 0 OO O 96 9 , &0 0 St i m s o n L u m b e r C o m p a n y . C D A 6~ 7 6 53 e , 91 1 68 3 , 22 1 M5 , 70 0 76 5 46 4 71 6 , 74 7 ss a , 38 2 15 5 , 31 4 1,2 5 5 , 21 8 1 , 01 1 90 , 0 6 2 58 0 , 15 2 83 5 , 68 9 58 5 , 91 7 19 , 03 0 , !3 5 24 , 19 0 , 00 0 28 , 09 9 , 54 3 23 , 82 5 , 96 0 25 , 23 4 , 79 0 25 , 91 3 , 11 8 9 39 7 92 9 23 , 58 5 , 14 1 25 , 37 5 , 43 4 25 , 7B B , 60 6 24 , 6 8 8 , 1 4 . 4 28 , 45 6 , 81 7 24 , 34 . 4 , 90 4 0 29 9 , 00 3 , 2 0 3 Re v e l ' l l J e R u n S d 1 e d u l e 2 5 k \ ' V h s 22 , 3& 4 , 80 2 24 , 1 e 5 , 22 , 03 6 , 00 8 23 , 62 3 , 24 8 10 0 , 43 3 22 , 91 2 , 65 0 22 , 09 0 , 78 5 23 , 7~ , e.s . 4 23 , 12 9 , 24 1 1 00 9 , 41 1 22 , 40 2 , 32 0 27 9 , 31 5 , 14 3 Di f f e r e n c e E x d u d l n g n e w C u s t o m e r s Po ~ a t c h C o r p o r a t i o n - L e w l s t o n 2 5 0 0 0 0 9 54 2 , 28 0 25 , 01 3 , 43 0 20 7 , 34 0 29 , 87 2 , 23 0 29 , 91 2 , 56 0 31 , 65 1 , 66 0 26 , 70 7 33 0 33 , 91 7 , 09 0 29 , 30 5 89 0 27 , 36 9 83 0 26 , 52 1 , 82 0 59 9 , 16 0 3- 4 7 , 72 0 , a2 Q Pr o F o r m a P u r c h a s e / S a l e G e n e r a t i o n 20 0 2 s e H Q e n 43 , 75 5 , 00 0 36 , fi9 9 , OO O 4.4 , &4 1 , 00 0 43 , 07 2 , 00 0 78 0 00 0 41 , 70 3 , 00 0 49 , 50 9 , 00 0 B5 9 00 0 43 , 99 5 , 00 0 48 , 55 9 , 00 0 43 , 8 6 7 , 00 0 46 , 82 6 , 00 0 52 2 , 36 5 , 00 0 Pr o F o r m a T o U U S c h e d u l e 2 5 P 71 , 39 7 26 0 62 , 01 2 , 43 0 73 , 84 8 , 34 0 72 , 94 4 , 23 0 69 2 , 58 0 73 , 35 4 , 66 0 76 , 21 6 , 33 0 75 , 77 8 , 09 0 30 0 , 89 0 75 , 92 8 83 0 72 , 1 B B , B:2 0 75 , 42 5 , 16 0 87 0 , 08 5 , &2 0 kl l o v o a a m p e r u Cu s t o m e r N a m e Ac c t N o . Ja l ' l l J a r y Fe b r u a r y Me r c h Ap r l l Ma y Ju n e Ju l y Au g u s t Se p t e m b e r 0c 1 o b e r No v e m b e r ~b e r An n u a l T o l a ! Co e u r S i l v e r V a l l e y I n c 5 0 0 0 0 1 54 6 00 3 65 4 96 4 64 6 52 7 88 1 68 9 88 5 85 7 7- 4 6 11 2 1 88 , 85 9 Ha d a M i n i n g Co m p B l 1 Y 50 0 0 2 3 15 2 20 1 26 0 01 1 2 0 37 1 47 4 37 3 59 2 55 8 38 6 83 6 67 8 89 , 10 1 Po t l a t c h C o r p o r a t I o n . 5 1 . M a r i e s 50 0 0 2 6 39 6 78 1 93 5 76 5 70 0 70 6 39 5 58 9 72 5 37 9 8.3 8 91 . 63 1 Un i v e r s i t y 0 1 I d a h o . W e s t C a m p u s 50 0 0 2 7 66 7 12 3 5, 0 7 6 01 3 66 8 72 7 43 6 22 2 14 1 53 7 20 1 75 8 61 , 58 9 Co e u r D A l e n e R e s o r t 70 0 0 0 1 83 2 84 3 83 0 82 2 52 1 58 3 07 1 24 0 99 8 68 1 60 5 73 9 90 4 5 Bl o u n l l n d u s l r 1 e s 1 0 0 0 0 0 1 76 4 71 1 70 8 79 6 83 7 90 1 17 8 59 9 60 5 47 9 29 1 30 1 49 , 27 0 Un i v e r s i t y 0 1 I d a h o . E a s t C a m p u s 12 3 5 1 8 8 29 6 46 5 53 9 48 0 77 5 11 2 21 7 24 6 56 2 70 2 1!! 1 53 3 71 . 09 0 Po i j a l c h C o r p o r a t i o n . P o s t F a l l s 23 0 0 0 0 4 68 9 72 7 78 8 71 6 67 7 63 6 62 5 84 2 62 4 60 7 68 8 66 4 32 , 06 3 Cle a r w a t e r F o r e s t I n d u s t 2 4 0 0 0 0 1 56 2 88 7 93 4 73 3 56 0 48 3 54 6 48 4 75 9 29 1 55 3 83 1 47 , 40 3 Th r e e R i v e r s T I m b e r , l n o 37 0 0 1 4 3 5 9 14 9 17 8 15 8 07 5 92 6 01 7 68 5 64 7 61 4 61 6 11 4 14 . 4 38 , 12 1 Trl . Pr o C e d a r P r c x J u c t s 4Y X J 1 0 0 4 1 59 6 56 5 68 9 41 6 62 7 79 1 80 9 42 0 90 4 7 77 2 96 3 19 0 4 11 2 9 St i m s o n L u m b e r C o m p a n y - P r i e s t R i v e r .. 5 0 0 4 9 3 9 3 50 9 56 8 5& 4 53 1 41 2 42 4 37 7 23 4 35 0 37 4 4. 4 5 45 9 41 , 24 7 J 0 L u m b e r C o 69 0 0 1 9 8 9 2 01 5 03 1 04 1 2 , 99 - 4 96 7 00 8 12 3 12 3 48 6 97 4 .w 9 3. 2 3 37 , 47 4 St i m s o n L u m b e r C o m p a n y . C D A 6 9 0 0 4 9 0 4 7 6 50 5 55 2 5,. ( 9 0 50 4 0 38 2 44 0 32 6 26 7 .w 8 55 2 04 J 3 9 64 , 92 5 &4 , 70 0 6S , 69 5 , 6 & 2 &4 , 26 5 63 , 07 5 62 , 81 1 64 , 2 4 2 1) . ( , 00 3 48 1 &4 , 24 3 83 , 9 9 8 63 , 37 2 77 0 , 54 7 Po ~ a l c h C o r p o r a t l o n . L e w l s t o n 25 0 0 0 0 9 65 , 75 0 52 , 75 5 53 , 12 6 52 , 21 0 60 , 80 7 92 , 51 3 77 , 14 7 87 , 33 0 47 . 6 7 7 45 , 18 0 90 , 0. 4 7 76 , 32 0 80 0 , 84 2 Pr o F o r m a P u r c h a s e / S a J e G e n e r a t l o n -6 3 . . Q Q O 00 0 57 , 00 0 00 0 00 0 15 , 00 0 26 , 00 0 13 , 00 0 62 , 0 0 0 66 , 00 0 00 0 . 34 , 00 0 50 7 , 00 0 Pr o F o r m a T o t a J S d 1 e d u l e 2 5 P 11 8 . 75 1 1 99 , 75 5 11 0 , 12 6 10 9 , 21 0 11 1 , 80 7 10 7 51 3 10 3 , 14 7 10 0 , 33 0 10 9 67 7 11 1 , 18 0 11 6 , 04 1 " . 11 0 , 3. 2 0 30 7 , 84 2 kV I ) 0 3 0 0 0 Cu s t o m e r N a m e Ac c t N o . Ja n u a r y Fe b r u a r y Ma r c h Ap r l l Me y Ju n e Ju l y Au o u s t Se p t e m b e r 0c I o b e r No v e m b i J r De c e m b e r An n u a l T o l a ! Co e u r S i l v e r V a l l e y I n c SO O O O 54 6 06 3 65 4 96 4 84 6 52 7 68 1 68 9 68 5 65 7 74 8 62 1 52 , 85 9 Ha d a M i n i n g C o m p a n y 50 0 0 2 3 15 2 20 1 26 0 42 0 37 1 47 4 37 3 59 2 55 8 38 6 63 6 87 8 63 , 10 1 Po ~ a t c h C o r p o r a t i o n - S I . M a r l e s 50 0 0 2 8 39 8 71 3 1 93 5 76 5 70 6 70 6 39 5 68 9 72 5 37 9 63 4 63 8 55 , 63 1 Un i v e r s i t y o f I d a h o . W e s t C a m p u s 50 0 0 2 7 68 7 12 3 07 6 01 3 68 8 72 7 43 8 22 2 14 1 53 7 20 1 75 8 58 9 Co e u r 0 A J e n e R e s o r t 7 0 0 0 0 1 Blo u n t I n d u s t r i e s 1 0 0 0 0 0 1 78 4 71 1 70 8 79 6 83 7 90 1 17 8 69 9 1 , 60 S 47 9 29 1 30 1 13 , 27 0 Un i v e r s i t y o f I d a h o . E a s ! C a m p u s 12 3 5 1 8 8 20 0 48 5 53 9 48 0 77 5 11 2 21 7 24 8 56 2 70 2 16 1 53 3 35 , 09 0 Po ~ a t c h C o r p o r a t i o n . P o s t F a l l s 2 3 0 0 0 0 4 Cl e a r w a t e r F o r e s l l n d u s t 2 4 0 0 0 0 1 58 2 liS 7 93 - 4 73 3 58 0 48 3 54 8 48 4 75 9 29 1 55 3 63 1 40 3 Th r e e R i v e r s T I m b e r , l n o 37 0 0 1 4 3 5 9 14 9 17 8 15 8 11 4 14 4 63 3 Tr l . Pr o C e d a r P r o d u c t s 45 0 0 1 9 0 4 1 59 6 58 5 68 9 41 6 62 7 19 0 4 10 7 St i m s o n L u m b e r C o m p a n y - P r i e s t R i v e r 45 0 0 4 9 3 9 3 50 9 58 8 58 4 53 1 41 2 42 4 37 7 23 4 35 0 37 4 44 5 45 9 24 7 ::Y J D L u m b e r C o 69 0 0 1 9 8 9 2 12 3 12 3 46 6 40 9 32 3 53 9 1-' - Sti m s o n L u m b e r C o m p a n y . C D A 69 0 0 . 4 9 4 7 6 5O S 55 2 2 , 4.9 Q 54 0 38 2 44 0 3.2 6 91 4 25 7 .w 8 55 2 28 , 92 5 17 9 25 , 12 5 23 , 73 3 22 , 98 4 22 , 79 9 85 2 23 , 8s . 4 25 , 0 9 8 21 3 23 , 74 2 22 , 96 9 26 6 1-" Po t l e t c h C o r p o r a t l o n . L e w l s t o n 2 5 0 0 0 0 9 62 , 75 0 75 5 50 , 12 6 49 , 21 0 57 , 80 7 69 , 51 3 14 7 1). ( , 33 0 +4 , 67 7 16 0 04 7 73 , 32 0 71 ) . ( , 1). ( 2 Pro F o r m a P u r c h a s e l S a l e G e n e r a t i o n 10 0 % L F 58 , 8 1 0 55 , 05 8 60 , 00 1 59 , 62 2 50 , 76 0 92 1 54 - 4 58 , 28 2 61 , 10 . 4 65 , 26 7 60 , &4 9 82 , 93 8 71 5 , 15 6 Pr o F o r m a T o t a J S d 1 e d u 1 e 2 5 P no I a d d i t i v e 11 S , 75 O 96 , 75 5 10 7 12 6 10 6 , 21 0 10 8 , 80 7 10 4 , 51 3 10 0 14 7 97 , 33 0 10 6 , 67 7 10 8 , 16 0 11 3 , 0. 4 7 10 7 , 32 0 27 1 , B4 2 74 4 67 2 74 . 4 72 0 74 4 72 0 70 4 - 4 74 . 4 72 0 74 . 4 72 0 74 . 4 76 0 Billing Determinants and Load Factor Schedule 25 (A)(B)(C) Total Monthly Average Annual Energy Billing Demands Load kWh Factor Potlatch-Lewiston 870 085 620 1 ,307 842 91% JD Lumber 989 500 37,474 33% Tri-Pro 316 394 829 37% Coeur D Alene Resort 840 492 945 68% Stimson 598 560 247 39% Potclatch Post Falls 653 150 063 58% Clearwater 133 932 47,403 44% Three Rivers 320 775 121 58% Stimson CDA 030 835 925 40% Blount 946 126 270 61% U of I West 611 309 589 66% Potlach S1. Maries 097 913 631 46% Hecla 100 213 101 51% U of I East 251 388 090 64% Coeur Silver 012 616 859 71% 299 903 203 770 547 53% From RTP 29 Sch 25 Test year billing data summary Load Factor equals (A) / (B) / 730 Exhibit 305