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Home My WebLink About20071210Reading direct.pdfREeE JlJl~J,.i~r .Qfi(~~"l pw:ATTORNEYS AT LAW ZOOI DEC l û PM 4: 09 Peter Richardson Tel: 208-938-7901 Fax: 208-938-7904 peter~ rich ardso n an dol ea 'y. co m P.O. Box 7118 Boise, 10 83707 - 515 N. 27th St. Boise, 1D 83702 Deæmber 10,2007 Ms. Jean Jewell Commission. Secretary Idaho Public Utilities Commission POBox 83720 Boise ID 83720-0074 RE: Case NoJPC-E-07 -08 Dear Ms. Jewell: Enclosed please find nine (9) copies of the DIRECT TESTIMONY OF DR. DON READING ON BEHALF OF THE INDUSTRIAL CUSTOMERS OF IDAHO POWER in the above case. An additional copy is enclosed as a reporter's copy, and a CD as required by Rule 231.05. I have also enclosed an extra copy to be serviæ-dated and returned to us for our files. Thank you. ~.Si i.y"~ JA Nina Curtis Administrative Assistant enc!. :... ~ J.,. ZOû7DfC 10 PH 4: 09 LIe lSS10i¡ BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) OF IDAHO POWER COMPANY FOR ) AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC SERVICE ) TO ELECTRIC CUSTOMERS IN THE STATE ) OF IDAHO. ) CASE NO. IPC-E-07-08 Direct Testimony of Don C. Reading, Ph.D. Ben Johnson Associates, Inc. On behalf of the Industrial Customers of Idaho Power (ICIP) ..' 1. BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION CASE NO. IPC-E-07-08IN THE MATTER OF THE APPLICATION ) OF IDAHO POWER COMPANY FOR ) AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC SERVICE ) TO ELECTRIC CUSTOMERS IN THE STATE ) OF IDAHO. ) Exhibit No. 201 Exhbit No. 202 Exhibit No. 203 Exhibit No. 204 Exhibit No. 205 Exhibit No. 206 Exhibit No. 207 Exhibit No. 208 Exhibit No. 209 Exhibit No. 210 Exhibit No. 211 Exhibit No. 212 Exhibit No. 213 Exhibit List Don C. Reading, Ph.D. Ben Johnson Associates, Inc. On behalf of the Industrial Customers of Idaho Power (ICIP) Qualifications Natual Gas Price Forecast Comparison Marginal Generation Capacity Costs Marginal Power Supply Costs Idaho Power Rate Case Power Supply Cost Base Case Comparison to Full Weighted Marginal COS Cumulative CSPP Total PURP A Resources 2002 - 2006 Base Case Comparison to PURP A Resources Base Case Comparison to Hydro Reallocation 75%/25% Base Case Comparison to Cumulative Changes Distributed Generation Report PGE Distributed Generation Promotional Materials 4 1 2 INTRODUCTION 3 4 Q.PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 5 A.My name is Don Reading and my business address is 6070 Hil Road, Boise, Idaho. I am 6 a principal with Ben Johnson Associates. 7 Q.HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR QUALIFICATIONS 8 AND BACKGROUND? 9 A.Yes. Exhibit No. 201 serves that purose. 10 Q.WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS CASE? 11 A.I have been retained by the Industrial Customers ofIdaho Power ("ICIP") to review Idaho 12 Power Company's (IPC, company) application for authority to Íncrease its rates and charges for 13 electric service. Specifically I examine the Company's rate allocations that are derived from its 14 cost of service (COS) study. I propose changes to Idaho Power's COS that wil bring cost 15 assignments closer to the Company's load profile for this capacity constrained utility. I conclude 16 that the cost of service study produces results that are counter intuitive and therefore ultimately 1 7 recommend the use of a uniform percentage allocation of any increase in rates. 18 I discuss the Company's fiing of a projected test year and show it to be a flawed 19 approach. I therefore recommend the Commission reject the use of a forecast test year. I also 20 address the company's proposal to revisit the load growth adjustment as it relates to fine tung 21 the power cost adjustment mechanism. 22 In addition to addressing issues related to test year, the Company's cost of service study 1 Reading, DI ICIP IPC-E-07-8 .. 1 and the load growth adjustment, I discuss the company's poor performance with respect to 2 distributed generation initiatives as well as the failure of time of use rates to provide any 3 meaningful benefits to either the company or its industrial customers. 4 Forecast Test Year 5 Q.DR. READING, LET'S TURN TO YOUR DISCUSSION OF THE COMPANY'S 6 PROPOSAL OF A FORECAST TEST YEAR. THE COMPANY STATES THIS IS THE 7 MOST FUNDAMENTAL POLICY DECISION IN ITS RATE FILING. DO YOU 8 AGREE? 9 A.Yes, I would ran it right up with the dramatic changes we are seeing in the Company's 10 cost of service study. In terms of this Commission's general approach to rate cases, it is one of 11 the biggest changes I have seen proposed. 12 Q.IN 2005, THE COMPANY USED A 'SPLIT TEST YEAR' WITH SIX MONTHS 13 ACTUAL DATA AND SIX MONTHS FORECASTED DATA. WH THEN IS A FULLY 14 FORECAST TEST YEAR SUCH A MAJOR DEPARTURE? 15 A.There are two major deparures from the general rate filings the Company made in 2003 16 and 2005. First, the Company's 2007 test year filed in this docket forecasts the full twelve 1 7 months of 2007 rather than using 6 months actual data and 6 months forecast data. The second 18 major departe is the forecast was 'trued up' at the end ofthe previous two cases. In this case 19 the Company recommends the revenue requirement be set purely on forecast data that will be 20 reflected in rates once the Commission's decision is made - with no true up. Any meaningful 21 differences in the Company's actual costs versus projected costs and revenue for 2008 will be 22 reflected in rates until the next general rate case. Furhermore if, as the Company intends, the 2 Reading, DI ICIP IPC-E-07-8 . 1 next general rate case is also based on a forecasted test year, then the link between rates and 2 historical costs and revenues wil be completely broken. It is true that forecasts will be updated 3 based on historical data in each successive general rate case. Nevertheless, the fact remains that 4 rates will be based on projections, not reality. With rio 'true up' mechanism proposed by the 5 Company, neither ratepayers nor the Company wil be able to recoup or correct any error between 6 actual and projected data. 7 Q.so YOU AGREE WITH THE COMPANY THAT THE FORECASTED 8 TEST YEAR is A MAJOR DEPARTURE FROM HISTORICAL PRECEDENTS OF 9 RATE MAKNG POLICIES OF THE IDAHO COMMISSION? 10 A.Yes, according to Mr. Gale, this step to a full forecasted test year is so 'bold' that the 11 Company has approached its proposal to implement a fully forecasted test year incrementally: 12 The Company believed that moving to a full forecast test year at that time was too 13 bold a step and instead chose the split year approach, which reduced regulatory 14 lag by six months yet stil provided access to the actual information prior to a final 15 order by the Commission. Additionally, Idaho Power believed that the use of a 16 split year could provide a bridge to a full forecast year in the futue. (Direct 17 Testimony, Gale, page 9.) 18 Even though the Company has used a parial forecasted 'split year' with a 'true up' in the past, in 19 this case the Comrission is being asked to make a major policy change and break with long 2 0 standing precedent. 21 22 Q.WHAT is THE ICIP'S POSITION ON THE USE OF A FORECASTED 23 TEST YEAR AS PROPOSED BY IDAHO POWER? 3 Reading, DI ICIP IPC-E-07-8 1 A.The ICIP is opposed to the forecasted test year for both theoretical and practical 2 reasons. 3 Q.COULD YOU PLEASE EXPLAIN THE THEORETICAL REASONS YOU 4 ARE OPPOSED TO A FORECASTED TEST YEAR? 5 A.One of the pilars of rate making is that ratepayers should only pay for 'known and 6 measurable' costs. Projections, by definition, are nothing more than educated guesses about 7 futue events. The stadard approach for a forecasted test year, and the one used by the 8 Company, is to make projections based on historical data and then make adjustments for 9 expected changes. For example, in this case the Horizon Wind purchase power agreement and 10 expected PURPA projects are used in the development of the Company's net power supply costs. 11 The Company states the reason for the inclusion of these costs is that they are expected to be par 12 ofIdaho Power's resource portfolio by the star of2008. (Direct Testimony, Gale, page 13.) 13 In reality, these resources mayor may not actually materialize during the year rates are in 14 effect. Therefore, they would be inaccurately reflected in the Company's resource portfolio. 15 Using a forecasted test year allows Idaho Power to enjoy rates as if these resources actually are in 16 the Company's resource stack - regardless of their actual status. I chose this example, even 17 though, along with the projected price and amount of off system purchases, the inclusion of the 18 Horizon and PURP A resources actually reduce forecasted power supply costs by nearly $51 19 milion. Although their inclusion appears to be a good deal for ratepayers, the power supply 20 costs on which the Company is asking be included in rates is also based on projected, not actul, 2 1 power supply costs from other Company resources as well as these two resotnces. 22 The price of off system purchases and the cost of producing power from the company's 4 Reading, DI ICIP IPC-E-07-8 1 gas fired units are also based on projected gas prices. For PURP A resources the company's 2 power supply costs include an estimate of the costs associated with the addition of 100 MW of 3 wind resources. As the Commission is aware, the costs of all new PURP A resources are 4 curently being disputed along with the costs associated with wind integration. This means Idaho 5 Power's proposed rates wil be set on what, at this time, is merely a guess by the Company about 6 what these costs may be. It also means that these cost estimates are sure to be wrong. 7 Q.DOES THIS MEAN, ON BEHALF OF A RATEPAYER GROUP, YOU 8 ARE ADVOCATING DISREGARDING $50 MILLION IN RATEPAYER BENEFITS? 9 A.No. As I stated above, the inclusion of the Horizon and PURPA contracts are par of an 10 overall projection of power supply costs that include a variety of assumptions. The only thing 11 that we wil know for certain is the actual power supply costs based on the resources that are 12 actully on the Company's system for 2007 after the books have been closed for that year. 13 Fundamentally, if the Commission accepts a forecasted test year as its standard for rate 14 making, it is accepting the certainty that some resources will be included in rates before they 15 become 'used and useful'. In such a circumstance ratepayers would be paying for resources that 16 are not providing power to the system. My attorney advises me that there may be a legal problem 1 7 with the use of a forecast year as well. I will let the lawyers worr about that aspect of this issue, 18 however. 19 Q.WON'T INTERVENERS AND THE COMMISSION STAFF HAVE THE 20 ABILITY TO REVIEW ALL OF THE COMPANY'S FORECASTS AND MAK 21 JUDGMENTS ABOUT THEIR REASONABLENESS? 22 A.Yes, and this leads me to my second objection about the acceptance of a forecasted test 5 Reading, DI ICIP IPC-E-07-8 ~ 1 year. 2 Q. 3 YEAR? WHAT is YOUR SECOND OBJECTION TO THE USE OF A FORECAST TEST 4 Major problems with forecast data are the controversies that swirl over the models as well 5 as the many assumptions that are used to forecast costs and revenues. The statutory time 6 constraints for prosecuting a general rate case impact the ability to thoroughly analyze models 7 and evaluate assumptions. It very diffcult for staff and interveners to critically review each of 8 the numerous forecasts that make up an overall rate fiing. Attempting to review all the forecasts 9 and assumptions imposes a real burden on limited Staff and intervenor resources and can be very 10 expensive. In fact, many of the forecasts and their underlying assumptions may well be 11 incorporated into rates without any critical analysis. Historical data on the other hand can be 12 audited and verified at a lower cost and with more accuracy. 13 Q.ARE YOUR CONCERNS SHARD BY OTHER EXPERTS ON UTILITY 14 RATEMAKNG? 15 A. 16 out: 17 18 19 20 21 22 23 24 Yes. In the respected treatise, Principles of Public Utilty Rates, Dr. Bonbright points In the first place, the commission's staff must audit the utility's books. For ratemaking puroses, only just and reasonable expenses are allowed; only used and useful propert is permitted in the rate base. In the second place, the Commission must have a basis for estimating futue revenue requirements. This estimate is one of the most difficult problems in a rate case. A commission is setting rates for the future but it has only past experience (expenses, revenues, demand conditions) to use as a guide. (James Bonbright, with Albert Danielsen and David Kamerschen, Principles of Public Utility Rates, 2nd Ed., March, 1988.) 6 Reading, DI ICIP IPC-E-07-8 ô 1 2 3 4 5 6 7 8 9 . 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 Q.YOU DISCUSS ABOVE THE COMPANY'S NATURA GAS FORECAST AS AN IMPORTANT INPUT TO THE POWER SUPPLY COST PROJECTION. ARN'T NATURAL GAS FORECASTS VERY SPECULATIVE AND SUBJECT TO ERROR? A. Yes. Natural gas forecasts have been notorious in recent years for being wrong. This is a good example of erroneous costs being rolled into rates. The assumed gas prices have a significant impact on the power supply cost estimate that rolls directly into rates. Q. ON WHAT DO YOU BASE YOUR FINDING THAT NATURAL GAS PRICE FORECASTS HAVE BEEN NOTORIOUSLY WRONG? A. An ilustration of how dramatically wrong natural gas forecasts have been recently is ilustrated by the region's experience with the Northwest Power and Conservation Council's periodic natual gas forecasts for the region. The Power Council's forecast for gas prices for 2006 that was made five years ago in 2002 was $3.15 MMbtu in real 2000 dollars. When adjusted for inflation (at 1.7% anually) this would mean a price of $3.71 in 2006. The Council's just issued forecast shows the price for 2006 in 2006 dollars of $6.15 or a 66% higher than projected five years earlier. This example is not to single out the Power Council; it does a fine job of forecasting. Nearly all projections of natural gas prices made in the early 2000's missed the significant ru up in natual gas prices. I used this example to show how dramatically incorrect forecasts can be. We should avoid rollng data we know to be wrong into rates and instead use historical data for setting retail rates. Q.IS THE POWER COUNCIL'S CURNT FORECAST BEING USED BY IDAHO POWER IN THIS CASE TO PROJECT NATURAL GAS PRICES? A. No. The Company uses its own natual gas price forecast in its AURORA model rus for projecting power supply costs in this case. On the other hand, the Company is using the Council's forecast to set PURPA rates in Docket No. IPC-E-07-15. Without discussing the merits of either gas forecast, the fact is the Company has two dramatically different natual gas forecasts before the Commission in concurently open dockets. As shown on Exhibit 202, the higher of the two forecasts is being used to set rates in this docket (which determines how much 7 Reading, DI ICIP IPC-E-07-8 ~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Idaho Power's ratepayers pay), while the other (lower) forecast is being used to set PURPA rates, (which determines how much Idaho Power pays small power producers). This is sort of a 'heads I win and tails you lose' proposition in that in each case the natural gas price forecast that most benefits the Company is being proposed. Q.DO YOU HAVE AN EXAMPLE OF HOW FORECASTED DATA MAY LEAD TO RATES BEING SET THAT DO NOT MATCH THE COMPANY'S REVENUE REQUIREMENT? A. Company witness Said, on page 34 of his direct testimony, states that Idaho Power's projected revenue requirement for the 2007 test year is $681.8 milion and 'envisions' a 2008 revenue requirement that is $37.0 millon higher at $718.8 milion. This means the Company is projecting that 2008 wil exceed the 2007 projection by an increase in costs of$37.0 milion. Mr. Said testifies that the Company expects 2008 revenues to be $695.4 milion or $13.7 milion higher than the 2007 projected revenue requirement. Should Idaho Power receive its full requested rate increase beginning in 2008, it would start collecting nearly $14 milion more than the 2007 estimated revenues. Mr. Said additionally states that, given the projected revenues and projected costs, the Company expects to be short of its revenue requirement for 2008 by $23.3 milion. This projection is based on the Company's projected 2008 costs layered on top their 2007 projected costs. Should costs not materialize as rapidly as the Company expects, it would be over collecting. In response, the Company could argue that it also could be under collecting more than expected. While possibly true, the point of this example is that when costs and revenues are not based on reality, but rather are forecasts based on other forecasts, there can be significant mismatches between revenues and costs which is contrar to fair and equitable ratemaking. Q.DO YOU HAVE ANY ADDITIONAL COMMENTS ABOUT A 25 FORECASTED TEST YEAR? 26 A.Yes. A forecasted test year tends to reduce risk for the utility because it allows it to 27 obtain rate relief for expected actions rather than basing rates on actual costs and revenues. In 8 Reading, DI ICIP IPC-E-07-8 I' 1 the case ofIdaho Power, the Company also has an annual PC A, and curently has decoupled rates 2 for residential customers. Should it be allowed to set rates based on a forecasted test year the 3 Commission should recognize this lowered risk in establishing the Company's rate ofretum on 4 equity. 5 Cost of Service 6 Q.DR. READING, LETS TURN TO YOUR EXAMINATION OF IDAHO POWER'S 7 COST OF SERVICE STUDY. COULD YOU PLEASE BRIEFLY REVIEW THE 8 COMPANY'S APPROACH? 9 A.Yes. Staff witness Tatum presents four separate COS studies; (i) Base Case, (ii) Non- 10 Weighted, (iii) 3 CP/12 CP, and (iv) 3 CP/Average. The Company's preferred approach is the 3 11 CP /12 CP study because it argues it is the most effective method of allocating production plant 12 costs consistent with the costs imposed by each given customer class. (Idaho Power witness 13 Tatum Direct Testimony, pages 38, 39.) Before I discuss some specific modifications to the 14 Company's COS, I have two general observations. First Mr. Tatum states that the Base Case is 15 consistent with the "Normalized" method fied in the last general rate proceeding. That case 16 (Docket No. IPC-E-05-28) was settled and thus the cost of service study was not litigated or 1 7 approved in that docket. Therefore, when comparing the curent cost of service study with those 18 in past filings, the base of comparson should be the last general rate case that preceded the '-28' 19 docket which is the general rate case in Docket No. IPC-E-03-13. 20 Second, as indicated by Company Exhibit 57, a disproportionate share of the overall 21 10.35% increase requested by Idaho Power falls on high load factor customers under all four 22 COS scenarios presented by the Company. The range of indicated increases for all four studies 9 Reading, DI ICIP IPC-E-07-8 ~ 1 presented for residential customers is from -1.7% (3 CPÆnergy) to 3.6% (Non-Weighted). On 2 the other hand, the range of indicated increases for the Schedule 19 and Special Contract 3 customers is from 17.2% (Schedule 19, Base Case) to 37.2% (JR Simplot, 3 CPÆnergy). 4 Q.WHY DO YOU ASSERT THAT THE CURRNT COST OF SERVICE STUDY 5 FILED BY THE COMPANY SHOULD BE COMPARED TO THE ONE FILED IN CASE 6 NO. IPC-E-03-13 AND NOT THE MOST RECENT GENERAL RATE CASE? 7 A.As I note above, Idaho Power's last general rate case was settled. In the Settlement 8 Agreement the paries specifically agreed that the cost of service study fied in that case would 9 not be precedent setting. As observed by the Commission in its order approving the settlement: 10 The paries also agreed that the underlying cost-of-service model fied by the 11 Company in this proceeding will not constitute precedent in any subsequent 12 general rate case. The paries specifically recognize that any par's failure to 13 specifically object to the Company s cost-of-service analysis in this case will not 14 constitute a waiver in any future general rate case proceeding. (Idaho Public 15 Commission Order 30035, IPC-E-05-28, page 5.) 16 The COS fied in the last case also allocated the major share of the proposed rate increase to the 1 7 high load factor customers. A foreshadowing of the disproportionate increase for high load 18 factor customers is found in Company witness Brilz' IPC-E-05-28 Direct Testimony filed in that 19 case. 20 Q.WHAT REASONS DID MS. BRILZ GIVE FOR THE DISPROPORTIONATELY 21 HIGHER ALLOCATIONS TO HIGH LOAD FACTOR FOUND IN THE COMPANY'S 22 COST OF SERVICE STUDIES? 10 Reading, DI ICIP IPC-E-07-8 . . ." 1 A.In her pre-filed testimony she stated: 2 Since the conclusion of the Company's last general rate case it has been 3 determined that the deficit months of June, July, August, November, and 4 December used in the 2003 marginal cost analysis were primarily determined by 5 firm generation supply acquisition need rather than determination of months in 6 which a peak-hour deficiency occured. The deficit months of January, May, 7 June, July, August, September, November, and December used in the current 8 marginal cost analysis are directly tied to peak-hour deficiency months identified 9 in the 2004 IRP. 10 And, 11 The use of eight deficit months (Januar, May, June, July, August, September, 12 November, and December) in the curent marginal cost analysis results in 13 weighting factors that attribute more generation capacity cost responsibility to 14 customer classes with usage throughout most of the year. (Direct Testimony, 15 Maggie Brilz, IPC-E-05-28, page 21, 22.) 16 Extending the number of months used in the marginal cost study from 5 to 8 months 1 7 spreads the costs of generation to customer classes with high use over a greater numbers of 18 months. 19 Q.THE COMPANY HAS EXTENDED THE NUMBER OF MONTHS THAT IT is 20 APPLYING CAPACITY COSTS. WHAT HAVE BEEN THE TRENDS IN THE 21 MARGINAL COST OF CAPACITY AND ENERGY FOR IDAHO POWER SINCE THE 22 IPC-E-03-13 GENERAL RATE CASE? 11 Reading, DI ICIP IPC-E-07-8 . . ¡- 1 A.There have been dramatic shifts in the costs of capacity and energy for the Company in 2 the last 4 years since our benchmark case, IPC-E-03-13, was fied. Marginal generation capacity 3 costs have dropped by 24% from $90.71 per KW to $69.00 per KW. The monthly amounts are 4 shown in the graph on Exhibit 203 5 While capacity costs have dropped, the marginal power (energy) supply costs over the 6 same 4 year period increased dramatically by 127%, from $33.38 to $75.84 per MWh. The 7 increase has been especially large in July and August with currently estimated marginal power 8 (energy) costs of$127.75 and $111.10 per MWh respectively. The monthly marginal power 9 supply costs over the last 3 filed general rate cases are shown on Exhibit 204. 10 Q.HOW DO YOU EXPLAIN THE SIGNIFICANT DROP IN MARGINAL 11 CAPACITY COSTS COUPLED WITH THE DRAMATIC INCREASE IN MARGINAL 12 ENERGY COSTS? 13 A.It appears to be the fuction oftwo interrelated factors. Natural gas prices have increased 14 since the fiing of our benchmark general rate case in 2003 and the Company has added gas 15 peaking resources. The capacity costs of a gas peaking unit on a per KW basis are relatively 16 lower than other generating resources. The trade off for these lower capacity costs is higher fuel 1 7 costs and hence higher energy costs. The higher gas prices have also driven the cost of 18 purchasing off~system power to higher levels. 19 Q.IDAHO POWER HAS A RESOURCE STACK WITH A MIX OF DIFFERENT 20 TYPES OF RESOURCES. WHAT HAVE BEEN THE CHANGES IN THE COST OF 21 ENERGY ON A NORMALIZED BASIS OVER THE PAST 4 YEARS? 22 A.As shown in Exhibit 205 energy costs have increased from a variety of resources. For 12 Reading, DI ICIP IPC-E-07-8 .. 1 example, Idaho Power's two coal plants (Bridger and Valmy) had essentially the same output in 2 2007 and as they did in 2005, yet their energy production costs have increased by $10 milion 3 each. The two gas. fired units in the Company's resource stack have power supply costs of 4 $86.42 per MWh for Bennett Mountain and $1,049.72 per MWh for Danskin. Off-system 5 purchases have increased from $39.9 per MWh in case IPC-E-03-13 to $70.9 per MWh in the 6 curent case. Off-system sales have also increased -- but by a lesser amount from $20.9 per 7 MWh in 2003 to $48.4 per MWh. It should be emphasized again that these curent case values 8 are based on projections by the Company. 9 Q.YOU HAVE DEMONSTRATED THE INCREASES IN ENERGY COSTS OVER 10 THE PAST 4 YEARS FOR IDAHO POWER. IS THIS THE REASON HIGH LOAD 11 FACTOR CUSTOMERS ARE BEING ASSIGNED THE MAJOR SHARE OF THE 12 PROPOSED RATE INCREASE IN THIS CASE? 13 A.Yes. The paradoxical aspect of this increase in energy costs relative to capacity costs is 14 caused by the fact that Idaho Power has changed from an energy constrained utility to a capacity 15 constrained utility over the past 15 years. This shift has been driven primarily by the growth in 16 residential and small commercial customers over the past dozen years. This is the reason the 1 7 Utility has constructed 260 MW s of gas peaking units as its most recent resource additions. 18 These higher energy costs are reflected in the Company's cost of service studies which indicate 19 that high load factor customers should suffer higher energy costs. 20 Q.DOES IT MAKE SENSE FOR HIGH LOAD FACTOR CUSTOMERS TO BE 21 ASSIGNED DISPROPORTIONATE INCREASES IN THEIR ENERGY RATES BY A 22 UTILITY, LIKE IDAHO POWER, THAT IS NOW CAPACITY CONSTRANED? 13 Reading, DI ICIP IPC-E-07-8 .- 1 A.No. For a capacity constrained utility, higher priqe signals should be sent to those 2 customer classes that have the poorest (low) load factors. Idaho Power's cost of service studies 3 do just the opposite by charging a disproportionate share to customers with high load factors. 4 Q.AS YOU POINTED OUT ABOVE, THE RESIDENTIAL, AND TO A LESSER 5 EXTENT THE SMALL COMMERCIAL CUSTOMER, CLASSES ARE RECEIVING 6 THE LOWEST PERCENTAGE INCREASES WHILE THE HIGH LOAD FACTOR 7 CUSTOMERS ARE RECEIVING THE HIGHEST. WHAT DOES THIS SAY ABOUT 8 PRICE SIGNALS TO CUSTOMERS? 9 A.The results of the Company's COS allocate more ¡costs to energy rather than capacity 10 which are reflected in the Company's proposed rates. The indicated rate increase for Schedule 11 19 customers is 3.3 times higher than for the residential dlass. The indicated rate increase for 12 special contract customers is 4.4 times higher than for residential customers. Yet the Company 13 has been adding peaking resources to meet the increasing demand during peak periods that is 14 being driven largely by residential customer growth. From an economist's standpoint this result 15 is counterintuitive. 16 Q.DO YOU HAVE ANY RECOMMENDATIONS THAT WOULD HELP REMEDY 17 THE PARADOXICAL RESULTS OF THE COMPANY'S COST OF SERVICE 18 STUDIES? 19 A.Yes. Should the Commission elect to spread rates among customer classes using any 2 0 method other thana uniform percentage increase across the board, then I have three 21 recommended changes to the company's methodology. The cost of service results described 22 below are based on changes to the Company's Base Case. I am using the Base Case because it is 14 Reading, DI ICIP IPC-E-07-8 ." 1 the one that is most similar to the methodology accepted by the Commission in the last litigated 2 case IPC-E-03-13 and the one that I believe best represents an equitable spread for rates. 3 Q.WHAT ARE THE THREE CHANGES YOU RECOMMEND BE MADETO THE 4 COMPANY'S COST OF SERVICE STUDY? 5 A.The three changes are: 6 First, I adjust the weightings for customer classes to reflect full marginal cost rather than 7 the average of marginal and embedded weightings used by the Company. This change more 8 accurately reflects the costs that are being incurred by the; Company. Marginal costs best 9 represent the costs of additional capacity and energy of needed additional resources. 10 My second modification changes the allocation ot'PURPApower delivered to the 11 Company to reflect the same demand/energy split as are assigned to Idaho Power's own 12 generating resources. There are now sufficient PURP A resources on Idaho Power's system that, 13 as a group, can now be counted on to supply capacity to the Company. In addition, because the 14 predominance of canal drop on PURPA resources on Idabo Power's system, QF output is highest 15 and most reliable in the sumer when the Company neeqs the capacity the most. 16 My final change reallocates the Company's hydro resources between demand/energy to 17 75% capacity and 25% energy rather than the system average split that is used by Idaho Power. 18 This reallocation is more in line with standard cost allocations and are, in fact, identical 19 allocations used by PacifiCorp in its curent rate case before the Commission. 20 I individually outline the results of these three modifications to the Company's approach 21 below and then present all three in combination with one ¡another. 15 Reading, DI ICIP IPC-E-07-8 .- 1 Q.DR. READING, LET'S TURN TO YOUR FIRST MODIFICATION TO THE 2 COST OF SERVICE STUDY PRESENTED BY THE COMPANY. FROM AN 3 ECONOMIC STANDPOINT, WHY DOES THE FULL MARGINAL COST 4 WEIGHTING BETTER REFLECT THE COMPANY'S COSTS THAN ACTUAL 5 VALUES? 6 A.As explained above, one of the problems with the class cost allocations that result 7 from the Company's cost of service studies is that cost allocations are not reflected in the 8 customer classes that drive costs on Idaho Power's system. My Exhibits 203 and 204 depicting 9 the marginal costs of capacity and energy indicate the dramatic differences in costs over the 10 different months of the year. Full marginal cost weightings reflect more fully these differences 11 among customer classes and thus better reflect the costs each customer class is placing on the 12 system. 13 Q.WHAT ARE THE RESULTS OF THIS MODIFICATION TO THE COMPANY'S 14 BASE CASE? 115 A.It should be noted before I discuss the results of these cost of service modifications that 16 all values assume the Company receives its full proposed overall increase of 10.35%. A different 1 7 overall rate increase will change the percentage change for each customer class in ratio with that 18 difference. 19 As shown in Exhibit 206, weighting customer classes at full marginal cost, in general, 20 lowers the percent increase to high load factor customers (Schedule 19, Special Contract). Cost 21 allocations to the irrigation class are increased while residential customers would receive a rate 22 decrease. The other classes remain about the same. This result tends to move the cost of service 16 Reading, DI ICIP IPC-E-07-8 " 1 away from high load factor customers but it does not send the correct price signal to residential 2 customers who are a major cause of increasing the Company's need for capacity. 3 Q.YOUR SECOND RECOMMENDATION ADDRESSES THE ALLOCATION OF 4 PURPA GENERATION BETWEEN CAPACITY AND ENERGY. WHAT IS YOUR 5 RECOMMENDED CHANGE FROM THE COMPANY'S BASE METHOD? 6 A.Curently the Company allocates nearly 100% of PURP A purchases to energy, even 7 though these resources contribute to meeting system peak. These resources should be allocated 8 to reflect the fact that they do contribute to meeting the system peak. Therefore I recommend 9 they be allocated on the same basis as the Company's other resources which is 41.47% to 10 demand and 58.53% to energy. That helps to move some of the cost responsibility for PURPA 11 resources to those customers that are causing the Company to add resources and who are 12 enjoying the benefits of the capacity contribution PURPA resources make to the system. 13 Q.IS YOUR RECOMMENDATION A DEPARTURE FROM THE 14 METHODOLOGY THIS COMMISSION HAS USED TO ALLOCATE PURP A 15 RESOURCES BETWEEN CAPACITY AND ENERGY IN THE PAST? 16 A.Yes, almost thirteen years ago, in case IPC-E-94-5 the Commission said, 17 IPCo's class cost-of-service study classified the costs associated with 18 cogeneration and small power production (CSPP) based on the type of payment 19 made to developers. Thus, capacity payments are classified as capacity related 20 costs and energy payments are classified as energy related costs. Tr. p. 2877-78. 21 Because IPCo canot call upon the capacity provided by CSPP when needed nor 22 rely upon any given amount of capacity to be available at any point in time, the 17 Reading, DI ICIP IPC-E-07-8 1 2 3 4 And, 5 6 7 8 9 10 11 12 13 Q. capacity value for CSPP is small. Accordingly, the methodology used by IPCo to classify CSPP related costs to demand and energy results in the classification of approximately 92% of the costs as energy related. Tr. p. 2878-79. We find: The CSPP purchases primarily have value to IPCo as energy resources and not capacity resources. Accordingly, IPCo's classification of its CSPP related costs is appropriate. We also find that conservation resources provide both demand and energy benefits and should be classified accordingly. The easiest method to classify conservation program expenses is in the same maier in which generation resources are classified, i.e., on the basis of the system load factor. (Idaho Public Utilities Commission Order 25880, IPC-E-94-5, page 29.) WHY is IT NOW APPROPRIATE FOR THE COMMISSION TO CHAGE THE 14 CAPACITYIENERGY ALLOCATION FOR PURPA RESOURCES IN LIGHT OF THE 15 COMMISSION'S FINDINGS YOU JUST CITED? 16 A.There are two reasons why it now makes sense to change the classification of PURP A 17 resources in the Company's COS. First, the COS should assign costs that match the resources 18 needed by the Company. Idaho Power's load profie has changed significantly since the last time 19 this issue was addressed. When the Commission last visited this issue, Idaho Power was an 2 0 energy constrained utility. It is now a capacity constrained utility. As pointed out above, the 21 Company is now building peaking resources. Since the load profile of the Company has 22 changed, it is appropriate that allocations within the COS also change to better match Idaho 18 Reading, DI ICIP IPC-E-07-8 .' 1 Power's new load profile. The cost of service studies set the base for rates among customer 2 classes and drive the price signals that are sent to ratepayers. They should therefore match the 3 resource demands ofthe Company. 4 Second, the PURP A resource mix has grown in both KW and the number of QF units that 5 are on line. In addition, they are significantly diverse and large enough that their capacity can be 6 relied on. One of the advantages of CSPP resources is, as a collective group, it is a reliable 7 resource. It is true CSPP is not dispatched by the Company as one of their own resources. 8 However, in a collective sense they are reliable. If one of the Company's resources goes down 9 Idaho Power loses all of the output of that given resource. There are nearly 100 PURP A units on 10 Idaho Power;s system; if anyone, or even several, of these PURP A resources becomes 11 unavailable, the others wil stil be providing power to the system. I prepared Exhibit 207 to 12 show the PURP A cumulative KW and the number of units on Idaho Power's system. 13 As can be seen from Exhbit 207, PURP A resources together provide Idaho Power with a 14 resource that contributes capacity to the system. Because it contributes capacity, it is rational to 15 assign a percentage of its output to capacity. 16 Q.HOW DO PURP A RESOURCES SUPPLY CAPACITY VALUE TO IDAHO 17 POWER OVER THE COURSE OF THE YEAR? 18 A.As shown in my Exhbit 208, PURP A resource output is consistently much higher during 19 the sumer months when the Company is most in need of additional power and when system 20 peaks are occurng. With large number of diverse PURP A projects on line, Idaho Power can 21 rely on PURP A resources to help meet its sumer peaks. (Response to ICIP Fourh Production 22 Request, No.9, 10.) 19 Reading, DI ICIP IPC-E-07-8 .' 1 Q.WHAT ARE THE IMPACTS ON COST OF SERVICE IF PURPA RESOURCES 2 ARE ALLOCATED IN THE SAME MANNER AS OTHER COMPANY RESOURCES? 3 A.I prepared Exhibit No. 209 to show the changes to the Company's Base Case caused by 4 the reassignment of PURP A to match the method the Company uses to assign its other resources 5 for capacity and energy. This change has about the same impact as weighting at full marginal 6 cost described above with the high load factor customers receiving lower increases. The major 7 difference is that the residential class would now receive a slightly larger increase as opposed to a 8 decrease. 9 Q.PLEASE EXPLAIN THE THIRD MODIFICATION YOU ARE 10 RECOMMENDING BE MADE TO THE COST OF SERVICE STUDY PRESENTED BY 11 THE COMPANY? 12 A. 13 14 15 16 1 '1 18 19 20 21 22 23 24 25 On pages 4 and 5 of his testimony, Company witness Tatum states, Demand related costs are investments in generation, transmission, and a portion of the distribution plant and the associated operation and maintenance expenses necessar to accommodate the maximum demand imposed on the Company's system. Energy related costs are generally the variable costs associated with the operation of the generating plants, such as fueL. However, due to the hydro production capability of the Company, a portion of the hydro and thermal generating plant investment has historically been classified as energy-related. (Pages 4 - 5.) He goes on to say, Q. What did you use as your primar guide in classifying costs as customer-, demand-, or energy related? A. I used the Electric Utility Cost Allocation Manual published by the National Association of Regulatory Utilty Commissioners (NARUC) as my primar guide 20 Reading, DI ICIP IPC-E-07-8 ." 1 to the classification of customer-, demand-, and energy-related costs. (Page 5.) 2 According to the NARUC Cost Allocation Manual relied upon by Mr. Tatum, hydro facilties are 3 usually treated as capacity. Mr. Tatu is correct that 'traditionally' the Company has treated, 4 and the Commission has accepted, the allocation of Company's hydro resources to energy. As 5 explained above, when the Company was energy (as opposed to capacity) constrained, this made 6 sense. As noted above, Idaho Power is now capacity constrained and not energy constrained. 7 Furthermore, it is adding additional resources which reduce its reliance on hydro resources. It 8 therefore now makes sense to allocate its hydro resources more to capacity rather than to energy. 9 Q.WHAT is YOUR RECOMMENDATION REGARDING THE ASSIGNMENT OF 10 HYDRO RESOURCES BETWEEN ENERGY AND CAPACITY? 11 A.A reasonable method for allocating Idaho Power's hydro resources between capacity and 12 energy is to assign 75% to capacity and 25% to energy. This is the same allocation used by 13 PacifiCorp in that company's cost of service in its curent rate case that is pending before this 14 Commission. PacifiCorp's witness testified that, "Production and transmission plant and non- 15 fuel related expenses are classified as 75 percent demand related and 25 percent energy related" 16 (PAC-E-07-05, Rocky Mountain Power, Mark E. Tucker, Di-4). It is my understading this 17 capacity/energy split was established in the Multi-State Process used by the various state 18 commissions that regulate PacifiCorp. 19 Q.ARE THERE OTHER WAYS TO ALLOCATE HYDROELECTRIC 20 RESOURCES? 21 A.Yes. There are a variety of ways hydro facilities can be allocated. They range from 22 100% to demand related to some mixture between demand and energy. This allocation of75% 21 Reading, DI ICIP IPC-E-07-8 .. 1 to capacity and 25% to energy is reasonable for hydro plants. The NARUC Cost Allocation 2 Manual states, "Most hydro capacity today is being used for peaking purposes, and its costs 3 therefore are properly classified as demand-related." (Electric Utility Cost Allocation Manual, 4 NARUC, 1967, footnote page 33.) Whle the Company has numerous ru-of-river facilities, its 5 major hydro complex is Hells Canyon which is used for peaking. 6 Q.WHAT is THE RESULT OF YOUR RECOMMENDATION THAT 7 HYRO RESOURCES BE ASSIGNED 75% TO CAPACITY AND 25% TO ENERGY? 8 A.Exhbit 210 displays the results of allocating the Company's hydro resources 75% to 9 capacity and 25% to energy. This modification produces approximately the same result as 10 reclassifying PURPA projects at the system average between capacity and energy. With this 11 change, the revenue requirement for high load factor customers is lowered and the residential 12 class would experience a slightly higher increase. In addition, as was true with the other two 13 recommended changes, the irrgation class receives a higher percent increase. 14 Q.YOU HAVE INDICATED WHAT THE RESULTS ARE FOR EACH OF 15 YOUR THREE RECOMMENDED CHANGES INDEPENDENTLY. WHAT is THE 16 CUMULATIVE IMPACT IF ALL THREE AR IMPLEMENTED? 17 A.These results are shown in Exhibit 211. When the three modifications are made 18 simultaneously, the high load factor customers' revenue requirement increases are lowered into 19 single digit percentage. The percentage increase for irrigation class is increased to 72%. The 20 residential class shows a decrease of 2.2%. 21 Q.YOU HAVE DESCRIBED THREE CHANGES TO THE COMPANY'S 22 COST OF SERVICE METHODS. ARE YOU ADVOCATING THAT THESE CHANGES 22 Reading, DI ICIP IPC-E-07-8 .' 1 BE IMPLEMENTED BY THE COMMISSION? 2 A.If the Commission chooses to use a cost of service study to allocate rates among customer 3 classes, I would recommend using the Company's Base Case as modified by my three 4 recommended changes described above. I am concerned, however, by the fact that even with my 5 changes, the cost of service studies are stil not sending the correct price signals to customer 6 classes. With my changes, the revenue requirement for the high load factor customers is lowered 7 appropriately. However, even with my changes, the residential class is not seeing the appropriate 8 cost causation price signaL. This is so, even though we know new residential load is a major 9 cause ofthe Company's need for new generation plant. The results of my three changes also 10 increase the revenue requirement for the irrigation class by over $20 milion. The irrigation class 11 has the misfortune of having their need for power during sumer peak which is when the 12 Company's system needs are growing the fastest. Unlike the residential class, the Irrigation class 13 is not growing. Yet due to increasing residential and commercial demand in the sumer, the 14 irrigation class' allocations increase their share of Company costs. 15 Q.YOU SAID "IF" THE COMMISSION CHOOSES TO USE A COST OF SERVICE 16 TO ALLOCATERATES AMONG CUSTOMER CLASSES. DOES THAT MEAN, EVEN 17 GIVEN YOUR RECOMMENDED CHANGES, THAT YOU AR NOT 18 RECOMMENDING THE USE OF A COST OF SERVICE STUDY FOR RATE 19 ALLOCATION IN THIS CASE? 20 A.Even with my modifications, the fudamental problems in the allocation of costs among 21 Idaho Power's customer classes are not solved. These fundamental problems that are occuring 22 within the cost of service studies presented by the company create perverse results. 23 Reading, DI ICIP IPC-E-07-8 . . " 1 Q.WHAT PERVERSE RESULTS ARE YOU REFERRNG TO? 2 A.It does not make sense that a stagnant (or even shrnking) class like the irrigators are 3 being saddled with the responsibility to cover the costs of new plant used to serve the burgeoning 4 residential and commercial classes. It makes even less sense for another class, like the industrial 5 class, whose load has also been static over the last decade and whose load is prett much flat 6 year-round to now suddenly be tageted for disproportionate increases in order to pay for new 7 plant used to serve the residential and commercial classes. Finally, it certainly defies logic for 8 these cost of service studies to indicate that, even in the face of an overall ten percent increase, 9 that the residential rates should actually decrease. From an economic standpoint, the cost of 10 service studies, even when corrected as best I can, result in perverse outcomes. 11 Q.IN LIGHT OF THE PERVERSE RESULTS YOU IDENTIFY, WHAT DO YOU 12 RECOMMEND THIS COMMISSION DO? 13 A.For this case, the most equitable solution is an equal percentage increase for all customer 14 classes. While not solving the problem, it would buy us time, without causing undue damage, to 15 find a solution. I recommend the paries investigate new cost of service approaches that produce 16 results more in line with what we all know is driving the Company's resource acquisition 1 7 strategy and hence higher costs. Unless an alternative approach is found, it appears the 18 methodology that has been used in the past will continue to produce counter-intuitive results and 19 yield perverse price signals. That is simply an unacceptable result. 20 Load Growth Adjustment 21 Q.COMPANY WITNESS SAID ADVOCATES SETTING THE LOAD 22 GROWTH ADJUSTMENT AT $29.16 PER MWH. DO YOU CONCUR WITH THIS 24 Reading, DI ICIP IPC-E-07-8 .. 1 VALUE? 2 A.No. The load growth adjustment was litigated just one year ago in signal issue Docket 3 No. IPC-E-06-08. In that case, the Commission clearly states the load growth adjustment should 4 be based on the Company's estimate of marginal cost found in its marginal cost studies, 5 We continue to find it reasonable to use a marginal cost based number to establish 6 the expense adjustment rate for the load growth component of the PCA formula 7 for annual true-ups. We adopt the $29.41 MWh adjustment factor proposed by 8 Staff in the Company's IPC- 03-13 rate case. We find this number to be derived 9 from the $27.01 MWh marginal generation cost in the Company's 2003 Marginal 10 Cost Analysis study, adjusted for 8.9% line losses. (Idaho Public Utilities 11 Commission, Order No. 30215, IPC-E-06-08, p. 11.) 12 The Company is again attempting, as it did in IPC-E-06-08, to redefine what the Commission 13 originally understood and meant when it established the PCA. In the IPC-E-06-08 case I 14 testified: 15 I agree with the Idaho Commission's decision in the original PCA case to set the 16 load growth adjustment based on the marginal costs of servng new load. The 17 Company's arguments presented in this docket simply rehash an issue settled by 18 the Commission some time ago, when it established the PCA. The underlying 19 reasons for setting the load growth adjustment based on the marginal costs of 20 serving new load remain sound and compellng. 2 1 The past 12 months have not changed my mind. I consider the Company's attempts to use its 22 definition of 'incremental' costs and a substitute for marginal cost as a rehash of a rehash. A 25 Reading, DI ICIP IPC-E-07-8 ," 1 review of the fiings and Order in case IPC-E-06-08 fully explains the load growth adjustment 2 and the Commission's rationale for its decision. Since that case was litigated just one year ago 3 these issues need not be revisited here. 4 Q.WHAT LOAD GROWTH VALUE AR YOU PROPOSING FOR USE IN 5 THE COMING PCA? 6 A.As shown in Exhibit Nos. 203 and 204, the Company's marginal cost studies show that 7 the marginal cost of energy has increased from $39.9 per MWh in Case No. IPC-E-03-13 to 8 $70.9 per MWh in the curent case. Mr. Said indicates a five year average value of $71.58 per 9 MWh (including lìne losses) for the Company's marginal cost, with a single test year value of 10 $67.74 per MWh. Either one of these values would fit the Commission's definition of marginal 11 cost and could be used for the load growth adjustment in the PCA. These values fit what the 12 Company itself defines as marginal cost and is driven, as discussed above, by the Company's 13 choice of new generation units to meet its growing loads. 14 Distributed Generation 15 Q.DO YOU HAVE ANY COMMENTS ON IDAHO POWER'S PROGRESS IN THE 16 ARA OF DISTRIBUTED GENERATION? 17 A.I think this is an important area that Idaho Power has been neglecting in its resource 18 planing - especially in meeting peak demand. As the Commission knows, Idaho Power now 19 relies on expensive natural gas fired peak plants to meet sumer and, at times, winter peaks. 2 0 The industrial customers opposed the constrction of those plants because of the availabilty of 21 less expensive alternatives such as the "Virtual Peaking Program" that had been successfully 22 offered by PGE in Portland, Oregon. 26 Reading, DI ICIP IPC-E-07-8 .' 1 Q.WHAT WAS YOUR RECOMMENDATION IN IDAHO POWER'S 2 PROCEEDING TO OBTAIN A CERTIFICATE OF CONVENIENCE AND NECESSITY 3 TO CONSTRUCt THE EV ANDER ANDREWS NATURA GAS PEAKING PLANT? 4 A.I testified in Case No. IPC-E-06-09 that Portland General Electric (PGE) had established 5 a Dispatachable Stadby Generation (DSG) program through which it acquired a significant 6 virtual peaking plant at a low cost. In exchange for the right to dispatch its customers' 7 emergency back up generators durng time of system peak, PGE provides the fuel and 8 maintenance for those generators. I reported that in 2006, PGE successfully dispatched 26.5 9 megawatts of customer owned generation to help meet system peak. 10 Q.WHAT IS THE COST OF SUCH A SYSTEM? 11 A.I testified that the cost of using customer owned back up generation to meet system peak 12 was approximately one-half of what then curent estimates of cost of the construction of a simple 13 cycle combustion turbine. 14 Q.WHAT WAS YOUR RECOMMENDATION TO THE COMMISSION IN LIGHT 15 OF YOUR FINDINGS ABOUT PGE'S DISPATCHABLE STANDBY GENERATION? 16 A.I recommended that no certificate of convenience and necessity for Evander Andrews be 1 7 issued pending an investigation into the size of this potential resource that is available for Idaho 18 Power's use. 19 Q.WHAT WAS THIS COMMISSION'S ORDER IN RESPONSE TO YOUR 20 TESTIMONY? 21 A.Although the Commission granted Idaho Power a certificate of convenience and necessity 22 to construct the Evander Andrews plant, it did order Idaho Power to: 27 Reading, DI ICIP IPC-E-07-8 .' 1 (I)nvestigate and submit a report for the implementation of a "virtual peaking 2 plant" program based upon the use of existing emergency generator resources in 3 the Company's service territory. This report shall be filed no later than June 1, 4 2007. (Order No. 30201 at p. 12.) 5 The Commission also indicated it was "paricularly interested" in the virtual peaking 6 program. 7 Q.HOW DO YOU INTERPRET THE COMMISSION'S DIRECTIVE TO IDAHO 8 POWER? 9 A.I think the Order speaks for itself. Idaho Power was directed to file a report on how it 10 plans to implement a virtual peaking plant program. 11 Q.DID IDAHO POWER COMPLY WITH THE COMMISSION'S DIRECTIVE? 12 A.I do not believe they fully complied with the Commission's Order. 13 Q.WHY NOT? 14 A.To be fair, the Company did file a report on June 1,2007, the day of the fiing deadline. I 15 would hope a Company trying to get such a program off the ground would be more enthusiastic 16 about meeting the Commission's Order rather than just complying with the minimum 17 requirement of fiing a report on the due date. 18 Q.WHAT WAS IN THE REPORT? 19 A.I have attached the entire three page report as Exhibit No. 212. The report concludes: 20 The Company plans to conduct the interconnection cost estimate analyses over the 21 next three months. Once detailed interconnection cost information is available, 22 the Company wil update its financial analysis to determine if a "virtual peaker" 28 Reading, DI ICIP IPC-E-07-8 ,0 1 program is economically viable and submit a detailed report of its findings to the 2 Commission. 3 Q.HAVE ANY ADDITIONAL VIABILITY REPORTS BEEN FILED WITH THE 4 COMMISSION SINCE JUNE I? 5 A.Not that I am aware. 6 Q.WHY DO YOU CONCLUDE THAT THE COMPANY DID NOT FULLY 7 COMPLY WITH THE COMMISSION'S ORDER WITH RESPECT TO A VIRTUAL 8 PEAKER PROGRAM? 9 A.Because the Order required Idaho Power to investigate and submit a report for the 10 implementation ofa virtual peaker program. The June 1,2007, report states that Idaho Power 11 has yet to determine if a peaker program is economically viable. In other words, the report 12 simply stated that the investigation the Commission wanted completed by June first was just 13 getting stared. For example, the report observes that "Idaho Power hopes to identify four to six 14 customers who are' willng to work with company personnel..." -- hardly a bold statement ofa 15 utilty looking for lower cost solutions to its power supply problems. 16 Q.DO YOU KNOW THE CURRNT STATUS OF PGE'S DISPATACHABLE 17 STANDBY GENERATION PROGRAM? 18 A.Since I last testified in 2006 that PGE had 25.5 MW ofDSG on line, that utility has added 19 an added an additional 18 MW for a curent total of 43 MW on line. It also curently has 17 20 more under active development and plans to add an additional 80 MW. In other words, in the 21 time it took Idaho Power to file a report in which it states it "hopes to identify 4 to 6 customers to 22 work with", PGE added 18 megawatts to its system and is actively developing 17 more. 29 Reading, DI ICIP IPC-E-07-8 .- 1 Attached as Exhbit 213 are materials PGE is using to promote and explain its virtual peaking 2 program for its customers. It has signed up universities, water treatment plants, milita 3 facilities, correctional facilities, data centers, lumber mils, bank operations, and semi conductor 4 plants - to just name a few. It has connected facilities as small as 0.4 MW and as large as 2.8 5 MW. 6 Q.WHAT DO YOU CONCLUDE FROM YOUR UNDERSTANDING OF THE PGE 7 PROGRAM AND IDAHO POWER'S RESPONSE TO THE COMMISSION'S 8 DIRECTIVE IN THE EVANDER ANDREWS PROCEEDING? 9 A.Given the obvious success of the PGE program, it would be reasonable for Idaho Power 10 to use what that company has leared rather than building a virtual peaking program from the 11 ground up - as it appears to be doing. It is diffcult to know from the Report filed on June 1, 12 2007, exactly what the Company has been doing. I have to conclude that Idaho Power mmt be 13 more interested in building expensive new plant to meet its future peak loads rather than 14 aggressively looking at alternative resources such as virtual peaking resources. 15 Q.DOES THE ICIP OFFER ANY OTHER RESOURCE SOLUTIONS THAT IDAHO 16 POWER COULD TAKE ADVANTAGE OF? 17 A.Yes. Strug across southern Idaho is a series of large natural gas consuming food 18 processing plants that are ideal for siting what are called combined heat and power plants. These 19 systems, also known as cogeneration plants are an efficient and cost effective method of 20 generating electricity. The ICIP's members are more than happy to work with Idaho Power to 21 develop the full potential of these resources to help meet Idaho Power's growing system load. 22 However, it is my experience that Idao Power is unwiling to assume fuel cost risk escalations 30 Reading, DI ICIP IPC-E-07-8 " 1 when exploring such options. That is short sighted because the ratepayers are already assuming 2 all ofthe fuel price risk when Idaho Power builds new gas fired peakers. 3 Time of Use Rates: 4 Q.CAN YOU OFFER A REPORT ON THE SUCCESS, OR LACK THEREOF, OF 5 THE MANDATORY TIME OF USE RATE SCHEDULE IMPOSED ON THE 6 INDUSTRIAL CUSTOMERS? 7 A.Yes. Idaho Power was allowed to impose mandatory time of use rates on the Schedule 19 8 customers by this Commission in IPC-E-03-13 in Order No. 29505. The Industrial Customers 9 opposed mandatory time of use rates at that time and they stil oppose mandatory time of use 10 rates. 11 Q.WHAT IS THE BASIS OF THE OBJECTION OF THE INDUSTRIAL 12 CUSTOMERS TO MANDATORY TIME OF USE RATE? 13 A.We did not support time of use rates because of the belief that the Schedule 19 class 14 would not be able to adjust its load usage pattern to maximize the potential savings of moving 15 load to off peak times. Experience has borne that out. Whenever I discuss this issue with the 16 members ofthe ICIP, I am reminded of the uselessness ofthis rate product. It is exceedingly 1 7 complex and industrial users are simply not responding to the "price signals" being sent by the 18 time of use rates. Potato processors are not able to shift refrigeration load to cooler times of the 19 day. Large office buildings are not able to ru graveyard shifts and maintain employee morale. 2 0 Meat packers and other food processors are at the mercy of when their product is available for 21 processing. 31 Reading, DI ICIP IPC-E-07-8 ~ . . 1 Q.is THE OPPOSITION TO TIME OF USE RATES UNIVERSAL AMONG THE 2 INDUSTRIAL CUSTOMERS? 3 A.Within the Industrial Customers of Idaho Power, opposition is prett much universaL. 4 That is not to say, however, that there may be an industrial customer who may be able to take 5 advantage of time of use rates. That said, the classes that are best suited to being able to respond 6 to time of use rates are the residential class, the irrgation class and, I think to a lesser extent, the 7 commercial class. 8 Q.WHAT DO YOU RECOMMEND WITH RESPECT TO MANDATORY TIME OF 9 USE RATES FOR THE INDUSTRIAL CLASS? 10 A.I recommend they be offered only as a voluntar optional rate. Certainly if there are 11 industrial customers who can take advantage of time of use rates they should be encouraged to do 12 so. However, experience has shown that time of use rates are not very effective with the vast 13 majority of industrial customers. 14 Q.DOES THIS END YOU TESTIMONY AS OF DECEMBER 7, 2007? A. Yes. 32 Reading, DI ICIP IPC-E-07-8 CERTIFICATE OF SERVICE I HEREBY CERTIFY that on the 10th day of December, 2007 a true and correct copy of the within and foregoing DIRECT TESTIMONY OF DON C. READING, Ph.D. was fied with the Idao Public Utilities Commission and parties as indicated below: Ms. Jean Jewell Commission Secreta Idao Public Utilities Commssion POBox 83720 Boise ID 83720-0074 Baron L. Kline Lisa D. Nordstrom Idaho Power Company 1221 W. Idaho St. (83702) POBox 70 Boise, ID 83707-0070 Email: bklinerfidahopower.com lnordstromrfidahopower .com JohnE. Gale Vice President, Regulatory Affairs Idaho Power Company 1221 W. Idaho St. (83702) PO Box 70 Boise, ID 83707-0070 Email: rgalerfidahopower.com Weldon Stutzman Donovan Walker Deputy Attorney Generals Idaho Public Utilities Commission 472 W. Washington (83702) PO Box 83720 Boise, ID 83720-0074 Email: weldon.stutzmanrfpuc.idaho.gov donovan. walkerrfpuc.idaho. gov Eric L. Olsen Racine, Olson, Nye, Budge & Bailey, Chtd. 201 E. Center PO Box 1391 Pocatello, ID 83204-1391 Email: elorfracinelaw.net Certificate of Service - 1 2L Hand Delivery _ U.S. Mail, postage pre-paid Facsimile Electronic Mail 2L Hand Delivery _ U.S. Mail, postage pre-paid Facsimile lL Electronic Mail 2L Hand Delivery _U.S. Mail, postage pre-paid Facsimile lL Electronic Mail 2L Hand Delivery _U.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery LU.S. Mail, postage pre-paid Facsimile lL Electronic Mail " . Anthony Yanel 29814 Lake Road. Bay Bilage, OH 44140 Email: tony~yanei.net Michael Kurz, Esq. Kur J. Boehm, Esq. Boehm, Kurtz & Lowr 36 E. Seventh Street, Suite 1510 Cincinnati, OH 45202 Email: mkurz~BKLlawfirm.com kboehm~BKLiawfrm.com Conley E. Ward Michael C. Creamer Givens Pursley LLP 601 W. Banock Street PO Box 2720 Boise, ID 83701-2720 Email: cew~givenspursley.com Dennis E. Peseau, Ph.D. Utility Resources, Inc. 1500 Liberty Street, Suite 250 Salem, OR 97302 Email: dpeseau~excite.coÌn LotH. Cooke Acting Assistant General Counsel United States Departent of Energy 1000 Independence Ave., SW Washington, DC 20585 Email: lot.cooke~hq.doe.gov Dale Swan Exeter Associates, Inc. 5565 Sterrett Place, Suite 310 Columbia, MD 21044 Email: dswan~exeterassociates.com ELECTRONIC COPIES ONLY: Dennis Goins Email: dgoinspmg~cox.net Arhur Perry Bruder Email: Arhur.bruder~hq.doe.gov Certificate of Service. DI - Don Reading Case No. IPC-E-07-08 _ Hand Delivery lLU.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery lLU.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery lLU.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery lLU.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery lLU.S. Mail, postage pre-paid Facsimile lL Electronic Mail _ Hand Delivery lLD.S. Mail, postage pre-paid Facsimile lL Electronic Mail ~~ltCw~~ Nina M. Curtis 2 EXHIBIT NO. 201 Reading, DI Industrial Customers of Idaho Power Presentpo~j¡if:/l Educatif:/l Don C. Reading Don C. Reading Vice President and Consulti Economist 'B.S., Economics C Utah State University ¡M.S., Economics C University of Oregon 'Ph.D., Economics C Utah State University Honors and awards Omicron Delta Epsilon, NSF Fellowship Profession~ and busines~ history Firr exprience ¡Ben Johnson Associates, Inc.: :i 989 Vice President 11986 ---- Consultig Economist ,Idaho Public Utities Commssion: 1981-86 Economist/Director of Policy and Admistration Teachig: 1980-81 Associate Professor, University of Hawai-Hio ,1970-80 Associate and Assistant Professor, Idaho State University :1968-70 Assistant Professor, MiddleTennessee State University pro Readig provides expert testiony concerning economic and regulatory issues. lHe has testified on more than 35 occasions before utity regulatory commssions in Alaska, Calfornia, Colorado, the District of Columbia, Hawai, Idaho, Nevada, North Dakota, Texas, Utah, Wyomig, and Washigton. Dr. Reading has more than 30 years experience in the field of economics. He has participated in the development of indices reflecting economic trends, GNP growth tates, forei exchange markets, the money supply, stock market levels, and inflation. He has analyzed such public policy issues as the minium wage, federal 'spendig and taxation, and import/ export balances. Dr. Reading is one of four economists providig yearly forecasts of statewide personal income to the State of Idaho for puroses of establishig state personal income tax rates. ,In the field of telecommunications, Dr. Reading has provided expert testiony on the issues of margial cost, price elasticity, and measured service. Dr. Readig prepared a state-specific study of the price elasticity of demand for local telephone .service in Idaho and recently conducted research for, and diected the preparation of, a report to the Idaho legislatue regardig the status of telecommunications ,competition in that state. EXHIBIT NO. 201 Reading, DI Industral Customers ofIdaho Power Page 1 of3 Don C. Reading Dr. Readig's areas of expertise in the field of electric power include demand forecastig, long-range plannig, price elastiCity, margial and average cost pricing, production-simulation modelig, and econometric modelig. Among his recent .cases was an electrc rate design analysis for the Industral Customers of Idaho .Power. Dr. Readig is currently a consultant to the Idaho Legislatue=s Commttee on Electrc Restrctug. Since 1999 Dr. Readig has been affiated with the Cliate Impact Group (CIG) at the University of Washigton. His work with the CIG has involved an analysis of the impact of Global Warg on the hydo facities on the Snake River. It also includes an investiation into water markets in the Northwest and Florida. In addition he has analyzed the economics of snowrakig for ski area's impacted byGlobal Warg. Among Dr. Readig's recent projects are a FERC hydropower relicensing study (for the Skokomish Indian Tribe) and an analysis of Northern States Power's North bakota rate desig proposals affectig large industral customers (for JR. Simplot Company). Dr. Readig has also performed analysis for the Idaho Governor's Office of the impact on the Northwest Power Grid of various plans to increase salon runs in the Columbia River Basin. br. Readig has prepared econometric forecasts for the Southeast Idaho Council of Governents and the Revenue Projection Committee of the Idaho State Legislatue. He has also been a member of several Nortwest Power Plannig Counci Statistical Advisory Committees and was vice chaian of the Governor's Economic Research Council in Idaho While at Idaho State University, Dr. Readig performed demographic studies using a cohort/survval model and several economic impact studies using input/ output analysis. He has also provided expert testiony in cases concerning loss of income resultig from wrongfu death, injury, or employment discriation. He is currently a adjunct professor of economics at Boise State University (Idaho economic history, urban/regional economics and labor economic.) Dr. Readig has recently completed a public interest water rihts transfer case. He has also just completed an economic impact analysis of the 2001 salmon season in Idaho. EXHIBIT NO. 201 Reading, DI Industrial Customers of Idaho Power Page 2 of3 Don C. Reading Publications ,"Energiing Idaho", Idaho Issues Onlie, Boise State University, Fall 2006. "\. boisestate.edu/history / issuesonlie/ fal006 _issues / index.h tm The Economic Impact of the 2001 Salmon Season In Idaho, Idaho Fish and ~Vildlfe Foundation, Apri 2003. The Economic Impact of a Restored Salmon Fishery in Idaho, Idaho Fish and Wildlfe Foundation, Apri, 1999. ifhe Economic Impact of Steelhead Fishing and the Retu of Salon Fishig in Idaho, Idaho Fish and Wildlfe Foundation, September, 1997. ACost Savigs from Nuclear Resources Reform: An Econometrc Modelcg (with E. Ray Canterbery and Ben Johnson) Southern Elvnomù)ournal, Spring 1996. A Visitor Analysis for a Birds of Prey Public Attaction, Peregrine Fund, Inc., November, 1988. Investigation of a Capitalation Rate for Idaho Hydroelectrc Projects, Idaho State Tax Commission, June, 1988. "Post-PURPA Views," InProceeclgs of the NARUC Biennial Regulatory Conference, 1983. ~n Input-Output Analysis of the Impact from Proposed Mig in the Challs Area !(with R. Davies). Public Policy Research Center, Idaho State University, Februar 1980. PhoJphate and Southeast: A Sodo El"Onomù'Analysis (with). Eyre, et al). Government Research Institute of Idåho State University and the Southeast Idaho Council of Governments, August 1975. 'Estimating General Fund Revenues of the State of Idaho (with S. Ghazanfar and D, Holley) Center for Business and Economic Research, Boise State University, June 1975, "A Note on the Distrbution of Federal Expenditues: An Interstate Comparson, 1933-1939 and 1961-1965." In TheAmerù-an E"Onomist, VoL. XVIII, No.2 (Fal 1974), pp. 125-128. "Newpeal Activity and the States, 1933-1939." In Journal ofEconomù'History, VoL. XXIII, December 1973, pp. 792-810. EXHIBIT NO. 201 Reading, DI Industrial Customers of Idaho Power Page 3 of3 EXHIBIT NO. 202 Reading, 01 Industrial Customers of Idaho Power Power Council Foreca (IPC-E-07-15), IPCo AURORA Rate Cas Forecast (IPC-E-07-oS $10.00 $9.50 $9.00 $8.50 = $8.00a: I $7.50'h $7.00 $6.50 $6.00 $5.50 $5.00 - \ - - -- ---- '\i_l_~~_~ ---~ ~ A 0 ~ ~ ~ A 0 ~ ~ ~ A~~ ~' ~'. ~ ~~ ~- ~\ ~~ ~ ~. ~. ~\~~~~~~~~~~~~ -+ Par Concil 20 nominal; IPC-E-07-15 .. IPCo Sumas; IPC-E-Q- 08 The IPCo Sumas; IPC-E-07-08 forecast (top line) is being used to set rates in the general rate case. The Power Council 2006 nominal; forecast (bottom line) is being used to set rates in Idaho Power avoided cost rate setting proceeding. Reading, DI Industrial Customers of Idaho Power EXHIBIT NO. 202 EXHIBIT NO. 203 Reading, DI Industrial Customers of Idaho Power Marginal Generation Capacity Costs Dec. Nov. October Sept August July June May April March Feb. January 0 5 10 15 20 25 Dollars per KW 1_IPC-E-03-13 _IPC-E-05-28 _IPC-E-07-08 i Reading, DI Industrial Customers of Idaho Power EXHIBIT NO. 203 EXHIBIT NO. 204 Reading, DI Industrial Customers of Idaho Power December November October September August July June May April March February January Marginal Power Supply Costs .-r o 100 14020406080 Dollars per MWh IIIPC-E-03-13 IIIPC-E-05-28 IIIPC-E-07-08 120 EXHIBIT NO. 204 Reading, DI Industrial Customers of Idaho Power EXHIBIT NO. 205 Reading, DI Industrial Customers of Idaho Power IDAHO POWER RATE CASE POWER SUPPLY COST IPC-E-07 -08 2007 After PURPA& Horizon Annual Hydroelecc Generation (mwh)8,748,179.7 Bridger Energy (mwh) Cost ($ x 1000) 5,052,875.3 $73,318.8 Boardman Energy (mwh) Cost ($ x 1000) 422,213.2 $5,874.6 Valmy Enegy (mwh) Cost ($ x 1000) 1,826,704.5 $40,291.4 Danskin Energy (mwh) Cost ($ x 1000) Fixed Capacity Charge - Gas Transporton ($ x 1000) Total Cost 2,970.9 $292.1 $2,826.5 $3,118.6 Bennett Mountain Energy (mwh) Cost ($ x 1000) Fixed Capacit Charge - Gas Transportn ($ x 1000) Total Cost 45,890.0 $3,967.3 $3,967.3 Purchase Power (Excluding CSPP) Market Energy (mwh) Contct Energy (mwh) Totl Energy Exci: CSPP (mwh) Market Cost ($ x 1000) Contrct Cost ($ x 1000) Total Cost Excl. CSPP ($ x 1000) PurchBse mills pe kWh Total Surplus Sale , Energy (mwh) Revenue Including Transmission Cost ($ x 1000) Transmission Costs ($ x 1000) Revenue Excluding Transmission Cpsts ($ x 1000) Stdfls nJils .per include TÆns 401,368.2 406,84.9 808,212.1 $37,984.5 $19,299.4 $57,283.9 7(JJ:¡ 2,950,604.2 $145,834.2 $2,950.6 $142,883.6 48A Net :''4'1 Power Supply Costs ($ x 1000)$40,971.0 ~ 2007 Pricemilslk 14.51 13.91 22.06 1,049.72 86.45 94.64 47.44 70.88 49.43 1.00 48.43 Reading, DI Industrial Customers of Idaho Power IPC-E-07-08EXHIBIT NO. 205 EXHIBIT NO. 206 Reading, DI Industrial Customers of Idaho Power .,. IA B C I lD l I' lE I I IF I I G HI ti (J ) IK \ IL L 1M ) (N l GE S A V I G E M S R I AR I L G P O I I R T I O U/ l T E R O MU I P A l TR A F I C SC SC SC TO T A L RE S I D N T I A l I G E N S R V I l ' y i s e C O N Y LI G H T i N I P R Y r s e C l GE N s e E ST L I T CO N T R O L 00 JR S I O T MI R O N (Ù 17 1i " P ' 19 - $ ) /1 5 l& - P ' m- S l (4 0 ) 14 H (4 2 ) BA S E C A S E A S f u n B Y I O P O RE V E N U E D E F I C I E N C Y $6 3 , 9 4 5 2 5 8 $3 3 3 , 2 8 3 $2 . 3 6 4 3 8 5 $1 6 5 6 . 3 7 5 $1 1 5 3 8 5 1 9 ($ 1 l l ì , l I 1 $1 1 , 3 1 0 9 2 8 $3 0 . 1 6 8 2 4 7 $1 2 6 8 8 $1 0 1 . 3 4 8 $2 9 5 4 1 $1 1 6 0 . 3 7 9 $1 . 1 6 7 5 9 7 $4 . 2 8 1 0 1 0 'E R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % 0. 1 1 % 15 . 3 7 % 12 . 9 7 % 9. 1 4 % 19 l ! j i j 17 . 1 7 % 42 . 6 4 % 1. 4 4 % 4.9 3 % 15 . 6 7 % 21 . 5 5 % 25 . 0 7 % 22 . 9 7 % RE T U R N A T C L A I M E D R O R $1 6 1 . 1 7 5 . 4 5 . 7 $7 0 . 8 5 , . 3 7 3 $3 . 7 6 7 . 2 0 5 $3 6 1 1 7 4 5 $3 3 . 1 6 1 . 0 9 1 $7 8 , 2 1 0 $1 8 . 1 0 4 . 7 1 9 $2 3 . 6 6 2 1 7 5 $2 0 8 , 6 8 9 $2 4 9 4 5 3 $4 8 . 6 8 1 $1 3 6 9 2 7 0 $1 4 2 4 2 9 4 $4 . 6 3 8 5 5 3 EA R N I N G S D E F I C I E N C Y $3 8 . 9 4 3 5 1 9 $2 0 2 . 9 7 4 $1 , 4 3 9 , 9 4 2 $1 0 0 8 7 5 4 $7 0 2 7 . 1 1 3 ($ I O I . ! I : : I 1 $6 , 8 8 8 . 5 0 7 $1 8 . 3 7 2 8 6 6 $7 , 7 2 7 . $ 6 1 . 7 2 2 $1 7 9 9 1 $7 0 6 6 8 6 $7 1 1 . 0 8 2 $2 , 6 0 7 1 9 2 RE V E N U E D E F I C I E N C Y $6 3 9 4 5 2 5 2 ($ t ~ j i M ' ï $2 3 5 3 5 4 8 $1 5 4 8 4 3 4 $1 0 9 6 1 3 5 1 1$ 1 1 # 4 3 1 1 ' $9 7 6 6 5 3 1 $4 1 . 6 7 8 1 4 1 $6 8 8 7 $7 1 6 1 3 $2 1 , 9 4 4 $7 4 0 2 2 8 $9 7 4 , 5 3 2 $3 7 2 6 9 8 7 'E R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % 23 2 % 15 . 3 0 % 12 . 1 2 % 8. 6 8 % 20 . 4 ~ % 14 . 8 3 % 58 . 9 1 % 0. 7 8 % 3. 4 8 % 11 . 6 4 % 13 . 7 5 % 20 . 9 2 % 20 . 0 0 % RE T U R N A T C L A I M E D R O R $1 6 1 , 1 7 5 4 5 7 $6 9 . 7 0 9 4 8 6 $3 7 6 9 4 4 4 $3 5 9 2 7 1 1 $3 3 . 0 5 9 3 1 6 $7 6 4 4 2 $1 7 , 8 9 3 . 5 0 1 $2 5 3 9 5 5 7 1 $2 0 8 3 3 7 $2 4 5 0 2 1 $4 7 5 6 6 $1 . 3 0 5 4 4 6 $1 3 9 5 4 5 9 $4 5 6 2 9 0 3 EA R N I N G S D E F I C I E N C Y $3 8 , 9 4 3 5 1 5 ($ 4 1 5 2 0 l í l $1 , 4 3 3 . 3 4 2 $9 4 3 0 1 7 $6 . 6 7 5 6 1 0 \$ i 1 ' ï . l l l ì ) $5 9 4 7 . 9 4 8 $2 5 3 8 2 . 5 4 6 $4 1 9 5 $4 3 6 1 3 $1 3 3 6 4 $4 5 0 . 8 0 9 $5 9 3 5 0 3 $2 2 6 9 . 7 8 5 BA S E C A S E : F U l l W Ð T E D 1 I l . C O T Ex h i b i t 2 0 6 Re a d i n g , D I In d u s t r i a l C u s t o m e r s of I d a h o P o w e r IP C - E - 0 7 - 0 8 EXHIBIT NO. 207 Reading, 01 Industrial Customers of Idaho Power Idaho Power Cum ulative CSPP KW & Numberof Units 600,000 500,000 Yo lJ0 400,000 CI~..300,000II :s E 200,000:s0 100,000 1_-,--ll._._------ - --- --~.---- ,,R -------c--------.-------.-- 120 .'100 Co lJ800 CI~ 60 ..II :s 40 E :s020o 0 19~ 1 1983 1985 1987 1990 1992 1994 2000 2003 2005 _ Cum ulative KW _...._. Cum ulative units Exhibit 207 Reading, DI Industrial Customers of Idaho Power IPC-E-07-08 EXHIBIT NO. 208 Reading, DI Industrial Customers of Idaho Power Id a h o P o w e r P U R P A R e s o u r c e s ; 2 0 0 2 - 2 0 0 DeNoOc Se p Au g Ju l Ju n Ma y Ap r Ma r Fe b Ja n o 2 5 , 0 0 5 0 , 0 0 7 5 , 0 0 1 0 0 , 0 0 1 2 5 , 0 0 1 5 0 , 0 0 1 7 5 , 0 0 MV , . 2 0 . 2 0 0 2 0 0 5 I í I P E - 0 7 - 0 1 Ex h i b i t 2 0 8 Re a d i n g , D I In d u s t r i a l C u s t o m e r s of I d a h o P o w e r IP C - E - 0 7 - 0 8 EXHIBIT NO. 209 Reading, DI Industrial Customers of Idaho Power (A BI I IC ) I ~0 ) ' I lE i I IF I I (O l I (H ) (I IJ ) KI Ll IM I IN I I I G E N S R V I G E N S R V I AR E A I L G P O W E R I I R R I G A T I O N UN M E T E R E O MU N I C I P A L TR A F F I C SC SC . SC TO T A L RE S I D E N T I A L I G E N S R V I P R I M A R Y I S E C O N D A R Y I L I G H T I N I P R I M R Y I S E C O N D A R Y GE N S e R V I C E ST L I G H T CO N T R O L DO E l I N L JR S I M P L O T MI C R O N 1 I7 (9 - T 1 (9 - P I 9- S 1 (1 9 - P L .1 2 4 - S ) 14 m (4 1 1 14 2 1 RE V E N U E D E F I C I E N C Y PE R C E N T C H A N G E ' R E Q U I R E D RE T U R N A T C L A I M E D R O R EA R N I N G S D E F I C I E N C Y $6 3 , 9 4 5 , 2 5 8 10 . 3 5 % $1 1 l 1 , 1 7 5 , 4 5 7 $3 8 , 9 4 3 , 5 1 9 $3 3 3 , 2 8 3 0.1 1 % $7 0 , 8 5 1 , 3 7 3 $2 0 2 , 9 7 4 $2 , 3 6 4 , 3 8 5 15 . 3 7 % $3 , 7 6 7 , 2 0 5 $1 , 4 3 9 , 9 4 2 $1 , 6 5 6 , 3 7 5 12 . 9 7 % $3 , 6 1 1 , 7 4 5 $1 , 0 0 8 . 7 5 4 SA S E C A S E A S f l D B Y I D H O P O $1 1 , 5 3 8 5 1 9 ~ $ 1 1 9 0 4 1 $ 1 1 , 3 1 0 , 9 2 8 $ 3 0 , 1 6 8 . 2 4 7 9. 1 4 % - 1 9 . 2 3 1 7 . 1 7 % 4 2 . 6 4 % $3 3 , 1 6 1 , 0 9 1 $ 7 8 , 2 1 0 $ 1 8 1 0 4 , 7 1 9 $ 2 3 , 6 6 2 . 1 7 5 $7 , 0 2 7 , 1 1 3 ( $ 1 0 0 . 0 3 8 $ 6 , 8 8 8 , 5 0 7 $ 1 8 3 7 2 , 8 6 6 $1 2 , 6 8 8 1.4 4 % $2 0 8 , 6 8 9 $7 , 7 2 7 $1 0 1 , 3 4 8 4. 9 3 % $2 4 9 , 4 5 3 $6 1 , 7 2 2 $2 9 , 5 4 1 15 . 6 7 % $4 8 , 6 8 1 $1 7 , 9 9 1 $1 , 1 6 0 , 3 7 9 21 . 5 5 % $1 , 3 6 9 , 2 7 0 $7 0 6 . 6 8 6 $1 , 1 6 7 , 5 9 7 25 . 0 7 % $1 , 4 2 4 , 2 9 4 $7 1 1 , 0 8 2 $4 , 2 8 1 , 0 1 0 22 . 9 7 % $4 , 6 3 8 , 5 5 3 $2 , 6 0 7 , 1 9 2 BA H C A S E ' P U A R E S O U C E S S E T . A S O T H R R E S O C E S ( . 5 8 3 1 5 N E R G Y / . 4 1 4 7 D e M A N O l RE V E N U E D E F I C I E N C Y 63 , 9 4 5 , 2 5 8 32 2 0 0 4 8 2,4 6 9 1 4 2 14 8 1 , 9 2 4 10 , 7 5 4 , 5 0 3 1. 2 1 1 1 5 0 1 9, 0 0 7 , 1 9 2 32 , 5 0 5 9 6 5 12 6 , 1 4 6 16 , 0 5 3 19 , 5 8 0 84 5 ; 8 7 9 79 2 , 3 0 7 31 0 2 , 0 7 1 PE R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % 1. 0 9 % 16 . 0 5 % 11 . 6 0 % 8. 5 2 % -2 2 . 6 8 % 13 . 6 7 % 45 . 9 4 % -2 . 9 7 % -0 . 7 8 % 10 . 3 9 % 15 . 7 1 % 17 . 0 1 % 16 . 6 4 % RE T U R N A T C L A I M E D R O R 16 1 , 1 7 5 , 4 5 7 70 , 8 5 1 3 7 3 3,7 6 7 2 0 5 3, 6 1 1 7 4 5 33 1 6 1 , 0 9 1 78 , 2 1 0 18 1 0 4 , 7 1 9 23 6 6 2 , 1 7 5 20 6 , 8 8 9 24 9 , 4 5 3 48 6 8 1 1, 3 6 9 2 7 0 1, 4 2 4 , 2 9 4 46 3 8 , 5 5 3 EA R N I N G S D E F I C I E N C Y 38 , 9 4 3 , 5 1 9 19 6 1 , 0 5 3 1, 5 0 3 7 4 0 90 2 , 5 1 2 6, 5 4 9 , 6 3 6 (1 2 8 5 9 ) 5, 4 8 5 , 5 0 1 19 7 9 6 . 5 8 8 (1 5 , 9 2 3 ) 19 7 7 7 11 9 2 5 51 5 , 1 5 2 48 2 , 5 2 6 1,8 8 9 , 2 0 3 Ex h i b i t 2 0 9 Re a d i n g , D I In d u s t r i a l C u s t o m e r s of I d a h o P o w e r IP C - E - 0 7 - 0 8 EXHIBIT NO. 21 0 Reading, DI Industrial Customers of Idaho Power A 8 C D E F G H I J K L M N GE N S R V GE N S R V AR E A LG P O W i ; R IR R I G A T I O N UN M E T E R E D MU N I C I P A L TR A F F I C ,'S C SC SC TO T A L RÈ S I D E N T I A L GE N S R V PR I M A R Y ' SE C O N D A R Y LI G H T I N G PR I M A R Y SE C O N D A R Y G E N S E R V I C E ST L I G H T CO N T R O L DO E / 1 N L JR S I M P L O T MI C R O N (1 7 9- n 9. P 9- S (H i . P ) 24 - S (4 0 (4 1 ) 42 RE V E N U E D E F I C I E N C Y PE R C E N T C H A N G E R E Q U I R E D RE T U R N A T C L A I M E D R O R EA R N I N G S D E F I C I E N C Y $6 3 , 9 4 5 , 2 5 6 10 . 3 5 % $1 6 1 , 1 7 5 , 4 5 7 $3 6 , 9 4 3 , 5 1 9 $3 3 3 , 2 6 3 -- $7 0 , 6 5 1 , 3 7 3 $2 0 2 , 9 7 4 $2 , 3 6 4 , 3 6 5 15 . 3 7 % $3 , 7 6 7 , 2 0 5 $1 , 4 3 9 , 9 4 2 $1 , 6 5 6 , 3 7 5 12 . 9 7 % $3 , 6 1 1 , 7 4 5 $1 , 0 0 6 . 7 5 4 BA . C A s e A S F l E D B Y I Ð P O $1 1 , 5 3 6 , 5 1 9 $ 1 7 9 . Q 4 1 $ 1 1 , 3 1 0 , 9 2 6 $ 3 0 , 1 6 6 , 2 4 7 9. 1 4 % . 1 9 2 3 % 1 7 . 1 7 % 4 2 . 6 4 % $3 3 , 1 6 1 0 9 1 $ 7 6 , 2 1 0 $ 1 6 , 1 0 4 , 7 1 9 $ 2 3 , 6 6 2 , 1 7 5 $7 , 0 2 7 , 1 1 3 $ 1 0 9 . 0 3 1 $ 6 , 6 6 6 , 5 0 7 $ 1 6 3 7 2 , 6 6 6 $1 2 , 6 6 8 1.4 4 % $2 0 8 , 6 8 9 $7 , 7 2 7 $1 0 1 , 3 4 8 4. 9 3 % $2 4 9 , 4 5 3 $6 1 , 7 2 2 $2 9 , 5 4 1 15 . 6 7 % $4 8 , 6 6 1 $1 7 , 9 9 1 $1 , 1 6 0 , 3 7 9 21 . 5 5 % $1 , 3 6 9 , 2 7 0 $7 0 6 , 6 6 6 $1 , 1 6 7 , 5 9 7 25 . 0 7 % $1 , 4 2 4 , 2 9 4 $7 1 1 , 0 6 2 $4 , 2 6 1 , 0 1 0 22 . 9 7 % $4 , 6 3 8 , 5 5 3 $2 , 6 0 7 , 1 9 2 BA S E C A S E : H Y D R O 8 £ T A T . 2 6 E N E I ' G Y I . 7 & D E A N D RE V E N U E D E F I C I E N C Y 63 , 9 4 5 , 2 5 6 2, 2 5 5 , 0 0 6 1 2, 4 3 4 , 1 2 2 1, 5 4 0 , 2 4 3 11 0 1 6 , 5 9 8 12 0 4 1 9 \ 1 97 7 7 3 2 6 31 , 7 2 4 , 4 6 9 1 13 , 1 6 4 \ 1 23 , 1 9 4 1 22 , 9 1 0 95 1 , 0 1 6 91 7 , 7 6 6 3, 9 6 , 1 6 9 PE R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % 0. 7 7 % 1 15 . 8 3 % 12 . 0 6 % 6. 7 3 % 1 .2 1 5 2 % 14 . 6 4 % 44 . 6 4 % 1 .1 . 4 9 % 1 1.1 3 % 1 12 . 1 5 % 17 . 6 6 % 19 . 7 0 % 16 . 7 6 % RE T U R N A T C L A I M E D R O R 16 1 , 1 7 5 , 4 5 7 71 , 1 6 7 1 3 1 1 37 7 8 6 6 3 3, 5 9 2 , 6 6 3 33 , 0 7 5 , 3 3 4 1 74 , 6 9 7 17 , 6 5 2 , 7 3 4 23 , 9 1 7 , 6 7 6 T 20 4 4 4 1 I 23 6 , 6 1 2 I 47 , 5 9 2 1, 3 3 4 8 7 0 1,3 6 3 , 2 4 4 4, 5 0 9 , 5 9 9 EA R N I N G S D E F I C I E N C Y 36 , 9 4 3 , 5 1 9 1,3 7 3 , 3 2 9 1 1,4 6 2 , 4 1 3 93 6 0 2 8 6,7 0 9 , 2 5 6 1 (1 2 2 0 5 6 \ 1 59 5 4 , 5 2 4 19 , 3 2 0 , 6 2 7 I 8,0 1 7 1 14 , 1 2 5 I 13 , 9 5 3 57 9 , 1 8 1 55 6 , 9 3 2 2, 1 2 9 , 2 2 6 Ex h i b i t 2 1 0 Re a d i n g , D I In d u s t r i a l C u s t o m e r s of I d a h o P o w e r IP C - E - 0 7 - 0 8 EXHIBIT NO. 211 Reading, DI Industrial Customers of Idaho Power (A I IB I 1 (C l I ID l 1 (E l 1 (F l I IG ) I (H I II (J ) (K l (L l (M IN I I I G E N S R V I GE N S R V I AR E A 1 L G P O R I I R R I G A T I O N VN M E T E R E O MU N I C I P A L TR A F F I C SC SC SC TO T A L RE S I O E N ' I A L I G E N S R V 1 P R I M A R Y 1 S E C O N O A R Y 1 LI G H T I N G I PR I M R Y I S E C O N D A R Y GE N S E R V I C E ST L I G H T CO N T R O L DO E / I N L JR S I M P L O T MI C R O N (1 ; IT ' (1 i . P ) 19 - 5 ) . (1 5 ' í1 9 - P ' /2 4 . S I (4 0 1 14 1 ) (4 2 ) PO "- , ~ . _ . . . . . . i ", , , n 1 : . . . . I 4:' " " ' R n " 1 7 Q I 'l 1 1 R 7 5 9 7 1 $4 . 2 8 1 . 0 1 0 I RE V E N U E D E F I C I E N C Y PE R C E N T C H A N G E R E Q U I R E D RE T U R N A T C L A I M E D R O R EA R N I N G S D E F I C I E N C Y $6 3 , 9 4 5 , 2 5 8 10 . 3 5 % $1 6 1 , 1 7 5 , 4 5 7 $3 8 , 9 4 3 , 5 1 9 $3 3 3 , 2 8 3 0.1 1 % S7 õ , $2 0 2 , 9 7 4 $2 , 3 6 4 , 3 8 5 15 . 3 7 % $3 , 7 6 7 , 2 0 5 $1 , 4 3 9 , 9 4 2 $1 , 6 5 6 , 3 7 5 12 . 9 7 % $3 , 6 1 1 , 7 4 5 $1 , O O i i , 7 5 4 BA S E C A S E A S F l t E D B Y I D P O $1 1 , 5 3 8 , 5 1 9 - 9.1 4 % $3 3 , 1 6 1 , 0 9 1 $7 , 0 2 7 , 1 1 3 \ i OJ ! \. . . . ! . , _ . . . AS F l t E D B Y I D P O 'i S r ~ , l ) l l $ 1 1 , 3 1 0 , 9 2 8 $ 3 Ó , 1 6 8 2 4 7 $ 1 2 , 6 8 8 $ 1 0 1 , 3 4 8 $ 2 9 , 5 4 1 $ 1 , 1 6 0 , 3 7 9 $ 1 , 1 6 7 , 5 9 7 $ 4 , 2 8 1 , 0 1 0 .1 9 . 2 3 % 1 7 . 1 7 % 4 2 . 6 4 % 1 . 4 4 % 4 . 9 3 % 1 5 . 6 7 % 2 1 . 5 5 % 2 5 . 0 7 % 2 2 . 9 7 % 57 8 , 2 1 0 $ 1 8 1 0 4 , 7 1 9 $ 2 3 , 6 6 2 , 1 7 5 $ 2 0 8 , 6 8 9 $ 2 4 9 , 4 5 3 $ 4 8 , 6 8 1 $ 1 , 3 6 9 , 2 7 0 $ 1 , 4 2 4 , 2 9 4 $ 4 , 6 3 8 , 5 5 3 :¡ l Q ~ t Q ; 1 - $ 6 , 8 8 8 , 5 0 7 $ 1 8 , 3 7 2 , 8 6 $ 7 , 7 2 7 $ 6 1 7 2 2 $ 1 7 , 9 9 1 $ 7 0 6 , 6 8 6 $ 7 1 1 0 8 2 $ 2 , 6 0 7 , 1 9 2 i BA S E C A S E ; - f U L L W E I G H T E D M A R G l . C 0 6 T RE V E N U E D E F I C I E N C Y $6 3 , 9 4 5 , 2 5 2 ($ ( 8 1 7 , 6 5 5 ¡ $2 , 3 5 3 , 5 4 8 $1 , 5 4 8 , 4 3 4 $1 0 , 9 6 1 , 3 5 1 1$ I O O A 3 I j $9 , 7 6 6 , 5 3 1 $4 1 6 7 8 , 1 4 1 $6 , 8 8 7 $7 1 , 6 1 3 $2 1 , 9 4 4 $7 4 0 2 2 8 $9 7 4 , 5 3 2 $3 7 2 6 , 9 8 7 PE R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % 23 2 , 15 . 3 0 % 12 . 1 2 % 8.6 8 % .2 0 4 5 % 14 . 8 3 % 58 . 9 1 % 0.7 8 % 3. 4 8 % 11 . 6 4 % 13 . 7 5 % 20 . 9 2 % 20 . 0 0 % RE T U R N A T C L A I M E D R O R $1 6 1 , 1 7 5 4 5 7 $6 9 , 7 0 9 , 4 8 6 $3 , 7 6 9 , 4 4 4 $3 , 5 9 2 , 7 1 1 $3 3 , 0 5 9 , 3 1 6 $7 6 , 4 4 2 $1 7 , 8 9 3 , 5 0 1 $2 5 , 3 9 5 , 5 7 1 $2 0 8 , 3 3 7 $2 4 5 , 0 2 1 $4 7 , 5 6 6 $1 , 3 0 5 , 4 4 6 $1 , 3 9 5 , 5 9 $4 , 5 6 2 9 0 3 EA R N I N G S D E F I C I E N C Y $3 8 , 9 4 3 5 1 5 ($ 4 . ßio o n $1 , 4 3 3 , 3 4 2 $9 4 3 , 0 1 7 $6 , 6 7 5 , 6 1 0 -( : $ 1 1 5 9 7 9 ) $5 , 9 4 7 , 9 4 8 $2 5 3 8 2 , 5 4 6 $4 , 1 9 5 $4 3 , 6 1 3 $1 3 , 3 6 4 $4 5 0 , 8 0 9 $5 9 3 , 5 0 3 $2 , 2 6 9 , 7 8 5 BA e e ~ ~ ~ ; F U L L W E I G H T E D M A R G I A L C O S T P L U S P U R P A R i : l 5 ~ i : l ) l ) ' , . . " v , n o n n . . RE V E N U E D E F I C I E N C Y $6 3 , 9 4 5 , 2 5 2 ( S f , 5 4 5 , 0 1 8 " $ 2 , 4 9 0 , 8 8 9 $ 1 , 2 4 4 , 0 2 5 $ 9 , 2 5 6 , 0 4 5 ( ~ ~ J ; 1 4 ) $ 7 , 2 2 4 , 0 9 0 $ 4 7 , 2 6 1 , 1 3 9 - PE R C E N T C H A N G E R E Q U I R E D 10 . 3 5 % ,1 . 2 : ¥ % 16 . 1 9 % 9.7 4 % 7. 3 3 % 24 3 0 % 10 . 9 7 % 66 . 8 0 % RE T U R N A T C L A I M E D R O R $1 6 1 , 1 7 5 , 4 5 7 $6 9 , 7 0 9 , 4 8 6 $3 , 7 6 9 4 4 4 $3 , 5 8 3 , 5 9 6 $3 2 , 9 8 2 , 6 7 1 $7 6 , 4 4 2 $1 7 , 8 9 3 5 0 1 $2 5 3 9 5 , 5 7 1 EA R N I N G S D E F I C I E N C Y $3 8 , 9 4 3 , 5 1 5 ($ 3 , 9 6 . 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'L ~ ~\.\ ~:'. .~\. - \ ~; .'~.'i 2.: L: !:i An IDACORP copay U\l~\-,C¿~ù',\b. . June 1,2007 =tlc .-F -06- o? Ms. Jean D. Jewell, Secreta Idao Public Utiities Commission 472 West Washington Str P. O. Box 83720 Boise, ID 83720-0074 RE: Vir Peaer Progr Case No. IPC-E-06-09 Dea Ms. Jewell: Enclosed please fid eight copies of Idao Power's Vir Peakg Progr sttu report. Ths report is filed ii compliance with the Idao Public Utilities COmmSsiOIl Order No. 30201. The Company prevewed the inormation included in ths. rert with Commssion Sta and the Indusal CUomer ofIdao Power on May 15th, 2Ó07. As staed íiiths rert the Compay will submit a detåed rert of its findis to the Coniissionaler the completon of its ~'Engieeg Analysis Pilot Progr" and updated fiancial analysis. If you have any questons regarin ths filing, pleae do not hesitate to contact me. If CW:cw cc: Ric Gae Maggie Brilz Pricing & Regulatory Services Voice: 208-388-5612 Fax: 208-38~9 cwaites(qidahopower .com Exhibit 212 Reading, DI Industral Customers of Idaho power IPC-E-07-08 P.O. Box 70 (83707) 1221 W. Idaho St. Boise, 10 83702 1l....~..POCl An lDACORP comøanv ::'.~L~ J .;" ,~ .' (... ~ ¡p l ï ; ¡ C." t.~.";; " .. J . \ ;,_: . ...~'.:I.:¡SS¡,..1 l " ~ I ;': . :'. .'bl ; ~ ~_i ; ; :.4 ,_,' ~c.-c -06--6'( VIRTUAL PEAKER PROGRAM Background Over the past ten years, Idaho Power has periodically investigated the possibilty of implementing a distributed generation program as an alternative resource to help meet peak demands. In the fall of 2006, the Company onæ again began investigating the potential for a program. Shortly after, the Industrial Customers of Idaho Power and the Idaho Public Utilties Commission (IPUC) expressed an increased interest in this type of program and on December 15, 2006, the IPUC issued Order No. 30201, which directed Idaho Power to "investigate and submit a report for the implementation of a 'virtual peaking plant' program based upon the use of existing emergency generator resouræs in the Company's serviæ territory." This report is filed in compliance with Order No. 30201. As part of our research, the Company reviewed virtual peaking programs other utilities have successfully operated and focused on two designs: The Dispatchable Standby Generation program conducted by Portland General Electric Company (PGE) and Madison Gas and Electric's (MGE) Backup Generation Service. The primary difference between the two programs is in regards to the ownership of the generator: MGE owns the generator located on the customets premises whereas PGE's customers own their generator. . Also, MGE customers pay a monthly service charge based on their maximum ánnual kilowatt demand for electricity. Idaho Power chose PGE's program model to use as a basis for our program development. Program Description A dispatchable standby generation program would allow the Company to use nonresidential customers' standby generators for up to 400 hours a year to meet system peak power. demands. Customers' generators would operate in parallel with Idaho Powet's system while.also being available to back up their facilty when needed. The Company's. design wil be such that during an outage situation, the customets generator(s) wil automatically start and provide backup power to the customer for as long as needed as originally intended by the customer. During times when customers' generators can be beneficial to the Company's system, the generators wil be started remotely by the Company's dispatch ænter. Exhibit 212 Reading, DI Industral Customers of Idaho Power IPC- E-07 -08 The following are the responsibilities of the customer and the Company under the proposed program design: Customer Responsiailites: Customers wil be responsible for purchasing thegenel"ator(s) and providing the site for generator installation. In addition, customers will .grant the Company acæss to their generation suc~ that the Company can control operation of the generator(s) remotely in parallel with the Company's distribution system from the Company's dispatch center for up to 400 hours per year. Customers may operate the generator(s) at their sites as needed for emergency back-up power. Company Responsiailities: The Company wil conduct an analysis of the customer's generator project and develop a comprehensive cost estimate. The .Company wil be responsible . for providing interconnecion engineering,. facilties,. and installation and any other equipment neæssary for participation in the. program. The Company wil pay for and own all communications and metering equipment. In addition, the Company will be responsible for routine maintenanæ of the generator(s) including ovel"hauls over the term of the service agreement. The Company wil also pay for all fuel use. to operate the customets generator(s) throughout the term of the service agreement. The Comraany wil perform monthly full-load testing of the custometsgenerator(s) and control system and testing of the Company's dispatch control . and interconnecon facilities. All energy consumed by the customer while participating in the program wil be billed at standard tarif rates. The following is a partial listing of the infrastructure that would need to be in place for such a program to run: · Utility Paralleling Power System (UPPS) - The UPPS wil ensure that the customer is provided with.a continuous supply of electric power by, almost instantaneously, switching from the Company's power supply to the bàck-up generatots power supply in the event of a power failure. · Metering - For an existing generator to be retrofitted, an additional time-based meter would be required. New generators would require two time-based meters be installed. The time-based meters would ensure that wheth.er customers are drawing energy from the Company's system or from. the back-up generator, their usage is tracked and biled under the 'Standard service schedule. . Communication Node Network - For communication between the customets system and the Company's system, a frame relay based network would be installed in order to provide a secure network. · Energy Management System (EMS) - The EMS would need to be programmed to accept the data from the UPPS. Exhbit 212 Reading, DI Industrial Customers of Idaho Power IPC-E-07-08 Feasibilty Analysis In our feasibilty analysis, the Company looked at the various costs involved. in the interconnection of a back-up generator as well as the resulting operations and maintenêance costs which wiUbe covered by the Company. Both initial generator installations and existing retrofits were considered. The initial analysis indicated there is enough potential benefit associated with the program to continue pursuing its investigation. Pilot Program The feasibilty analysis concluded that Idaho Power would need to make an investment in infrastructure of approximately $1 milion in order to integrate customer-owned generators into our system. Because of the investment size and the potential complexity of the interconnection of some generators, the Company determined it was neæssary to do an in-depth analysis of the interconnection costs, targeting generators of different sizes, ages, and locations. This thorough analysis would provide more detailed costs. of interconnection and a more accurate determination of the program's potential viabilty. In order to complete the in-depth cost analysis, Idaho Power met with numerous customers, as well.as representatives of the Industrial Customers of Idaho Power, to describe the potential program and solicit pêarticipation in an "Engineering Analysis Pilot Program". Through this process, Idaho Power hopes to identify four to six customers who are wiling to work with Company personnei in the development of this initial cost estimate for their specific facilities. The Company is targeting customers whose existing generators vary in size and customers who do not currently have back-up generators but would consider installng one if a "virtual peaker" program were offèred. The Company plans to conduct the interconnection cost estimate analyses over the next three months. Onæ detailed interconnection cost information is available, the Company will update its financial analysis to determine if a "virtual peaker" program is economically viable and submit a detailed report of its finding to the Commission. Exhibit 212 Reading, DI Industral Customers of Idaho Power IPC-E-07-08 EXHIBIT NO. 213 Reading, DI Industrial Customers of Idaho Power Customer News - Dispatchable Standby Generation offers savings and reliability I PGE Page 1 of2 '~"Be..'U".'.''''.".,..,.",..U'''.'''..,.."."~J:J:!9.!!e "" C:.!!!l!!IIJ.eW.ejMCustomer News................................__.....n......n. ......~~~!::.t..~.~~.~.~J...~!.~_..CustomerNews 2008 PGE pricing adjustments The new year wil bnng slight pnce adjustments to your bil. Here is how they are shaping up: · We estimate that prices for large business customers (Schedules 83 and 89) wil increase an average of 1 to 2 percent in January, then decrease in June. · The net change for 2008 is expected to be less than 1 percent for Schedules 83 and 89; for Schedule 32 accounts, the expected net change is just over 2 percent. See çJi;¡Ji for details about these pncing adjustments. The Oregon Public Utilty Commission is in the process of reviewing these proposed changes. We anticipate their final decision by the end of December. Growing Dispatchable Standby Generation program offers reliabilty and savings When Salem Hospital decided to install standby generators in their new central energy plant this year, they signed up with the PGE Dispatchable Standby Generation program. Rather than standing idle during non-emergency times, their two 2,000 kilowatt (kW) generators wil work up to 400 hours annually, helping meet peak power demands for PGE customers. In return, PGE covers all generator maintenance . and fuel expenses, as well as monthly testing. According to Tom Bickett, director of facilties management for salem Hospital - which is in the midst of a major renovation - the DSG program benefits the hospital and the Salem community in several ways. "First, we're helping PGE meet the area's need for power during peak penods. This supports the hospital's commitment to being a valued and integral part of the communities we serve," says Bickett. "Second, we were able to increase our generating capacities from two 1,500 kW generators to two 2,000 kW generators . and connect to pnmary metering, which saves on kilowatt hour (kWh) costs. And during the 10-year DSG agreement, PGE provides for all of the maintenance and fuel expenses. This is a signifcant operating savings to the hospital, which in 'tum helps us hold the line on the cost of health care. With all the savings, pclback is less than three years, which is an outstanding return." Salem Hospital never has to worr about being without power because the generators are always available for back up in the event of a power outage. They are continuously . monitored and may be dispatched from the PGE control center if needed. The generators are synchronized and operate in parallel with PGE power so there is no service interruption to ,the hospital when the generators are operated by PGE. For DSG program participants, PGE wil: · Cover all maintenance, repair, fuel and other operation rnc:tc: http://ww.portlandfleneraL.biz/CustomerN ews/Default .i:snx Other customer news See lhe lopics below for lhe lalest energy news from PGE. · M~M-Yo!!r.leneral9rs.'!arut.l:ir keep · E.ri.RoYee.Je.a.msllelp. !i!!t .eDJlmy wa!;t,! · ¡:o.il!S_9.!J!9~JlLqll.aIity.an!! rJ1Jla,l:jIly .E!ymei:illIU;!'-Ye.5. l'P 5.lI!;talmll:ity I: ~::::=:,." ; Exhibit 213 Reading, DI Industrial Customers of Idaho Power IPC-E-07-08 Page 1 of34 o 1 1 ?/r-/?007 L,uswmer r~ews - uispatcnaoie :stanaoy Veneration otters savings and reliability I PGE . Provide alerts to facilty staff regarding critical alarms or other potential generator problems. · Improve exhaust emissions by installng oxidation catalysts. . Conduct monthly testing - fully loading the generators and eliminating expensive load bank tests. Salem Hospital is just one of more than 20 PGE customers already signed up for the growing DSG program. Collectively, these standby generators represent 40 megawatts of power. Over the next five years PGE aims to recruit eight to 10 customers annually, growing the program by an additional 80 megawatts. . "DSG represents a least-cost option for meeting peak capacity and providing necessary reserves," says Mark Osborn, distnbuted resources manager. 'We don't call on the generators every day, just on cntical winter and summer days when energy use is really high and when other resources are challenged. This program is sort of like an emergency backup generator for all PGE customers." Visit the DSG section on our Web site to learn more. If you have standby generators and want to know if you are eligible to participate in the DSG program, contact your PGE representative today. _h". -"~._-'~__"__~__'_'~"___.'_-"'_'_".""_'_'___~"_'~""___,_~_~,_. _ ._. .'_.~.._.._~._ ~._' .' _'_'_'_"'~~.__'_ "_""_~'_ ,..__"___" "'"~"_""__'.'~_~'_~_'_'__~c htt://ww.portlandgeneraL.biz/CustomerN ews/Default.aspx Page 2 of2 o 2.. 12/6/2007 rut - Large &. inaustnai Accounts: Dispatchable Standby Generation Page 1 of2 Large & Industrial Accounts,."......................a...............uu.........Dispatchable Generation FAQ P_GEti()'!te "" Susiiiess_Se_iyiç~ "" Lll9ILBusineS!L~Usl()niE!rs "" Qis.P~~ti~tile~Jlne'alioll Oispatchable Standby Generation Capture enhanced reliabilty and operational savings from your backup electric generation system. If your business requires standby electric generation to ensure vital production or service performance, you know the daily reality: constant maintenance of your backup system in the hope that it wil perform when you need it. For most of the year, however, the only thing your backup system generates is a stream of operational and maintenance expenses. From PGE's control center, a dispatcher can start any or all of the standby generators within the system. Up to 100 megawatt of power can be generated during peak hours. PGE's Dispatchable Standby Generation program puts your standby generators to work for up to 400 hours annually to meet peak power demands - and PGE picks up all your maintenance and fuel expenses. Your generator is always available to backup your facility and will operate synchronized and in parallel with PGE power so there is no service interruption. For the option of running your generators when needed, PGE will: . Upgrade switchgear and install control and communications hardware at no charge, increasing reliability and improving control of your system. . Assume all maintenance and operation costs for your system, eliminating your costs for fuel, repairs, tune-ups, oil changes, filter replacements and overhauls. . Provide additional sound attenuation, if needed, quieting the generator system. . Provide additional fuel storage, if needed, expanding your operating time during those weather-related, long-term power outages. . Test your system at least once a month under full load; frequent full-load testing ensures the generator will operate successfully during an outage and is better for the engine. A powerfl network PGE equips your standby generator with paralleling switchgear, allowing the unit to be operated in synchronization with the electric distribution system. Qualifying commercial and industrial customers (those with standby generators of 250 kilowatts and up) are networked with PGE's communications and power control system. The standby units can be PARAUNG PGE swSW' GEA ~PGE Gferatoc ~ ~,¡,ñ E-Manager . E-Manager prokks easy-to- rea d' and graphs that help analyze your ficilrt's energ use. . News to Power ...... Your Business ' "¡;I;ll! to ~ ..- e-mail neletter for the late on energy savìngs, elecricity price and more. o 3 http://ww.portlandgeneraLcom/usiness/large _industrial/dispatchable _generation.asp?bh... 12/6/2007 rue - Lê:gt: oc muUSiriai A.CCOuntS: lJispatcnaole ::tandoy Ueneration from PGE's control center. monitored and dispatched In case of an outage, the standby generator functions as ìt normally would, providing backup power to your facility for the duration of the outage. However, when power returns to the grid, your facility moves back to utilty power without additional interruption. Program participants pay standard electric rates for power used, regardless of where it's being generated. PGE pays all the fuel costs for the standby generators, even during an outage, adding to the operational savings. So how does this work? Read our FAQ, which answers common questions about how the program works, why PGE is offering the DSG program and how your business can take advantage of this savings opportunity. Unleash the full potential of your standby generator Interested? At your request, we wil provide a detailed analysis and proposal tailored to your business requirements. Please contact your PGE representative or e-mail us. You may also call Mark Osborn, DSG program manager, at 503-464-8347. If you are considering purchasing a new generator or upgrading to a larger system of backup generation, PGE provides convenient financing on request. Financing can be added to your monthly electric bil. eGE.Ho.1J~ Site Map Co.njact U~ Privacy LegalNotice fr-E§QiiQl Page 2 of2 o 4 htt://ww.portlandgeneral.com/usiness/large _ industrial/dispatchable _generation.asp?bh... 12/6/2007 rut - Large & Ind.ustrial Accounts: Uispatchable Generation F AQ Page 1 of4 /~"'/ I..et FAQ lG_Ef:()n:e ".".al!sjrieSS~Elrvic:es "'''L~a!gejllJsinE!ssJiist()niers ".". Djspl!c.!iiil:L~Gemmitio.!Large & Industrial Accounts,'~ ................................................~...~.... Dispatchable Generation FAQ Q: Why is PGE offering the Dispatchable Standby Generation (DSG) program? . The tight supply of electricity and resulting high prices have created new business opportunities for PGE customers who can simultaneously use power, while making more power available in PGE's territory. The DSG program improves a participant's bottom line by having PGE: . Cover the operating and maintenance costs of the DSG power system . Contribute to the customer's standby generator system installation PGE benefits by accssing new power resources for all its customers. By linking many generators to the electric distribution system and turning them on at peak demand hours, PGE and program participants are helping keep the price of power down and the supply up with an innovative business relationship. Q: What happens if we need power at the same time PGE is using the DSG system? . Your backup generator is always available to serve you without interruption. Your generator and PGE are synchronized and operate in parallel, automatically backing each other up. If one system fails, the other takes over - significantly increasing your reliability. The DSG system is set up so your facility's loads are automatically served first and then any excess power you generate flows into the PGE system. For example, if your building load is 1,000 kilowatts, and the generator is putting out 1,500 kilowatts, only 500 kilowatts are serving other PGE customers. Q: Wil the DSG program put more wear and tear on my company's generator? . The DSG program wil probably extend the life of your backup/emergency power system. The program operators regularly start up the generators and test them at full load. More frequent full load runs are better for the diesel engines. The tests also save the costs of load bank testing and assure your organization that the equipment will start up and function properly in a power outage. Q: Wil PGE help pay for new generators? Does PGE help if I'm installng new generators? http://ww.portlandgeneral.comlusiness/large _industrial/faq .asp ?bhcp= 1 E-Manager .. E-Mariger . proids easy-tt- rea clrt and graphs that help analyze yor faclit's energy use. II Own high voltage equipment?Ge the mos value with re~uliir m$Ìrmnce. PG's DistributiQn and High Volta 5erviw maes it easy. 05 12/6/2007 rve - Large lJ industrial Accounts: Vispatchable Generation F AQ Page 2 of4 · The generators themselves are not funded by PGE. However, whether you are building a new facility with backup power, adding generators or upgrading your switch gear, PGE helps fund the installation. PGE provides most of the cost for the latest generator control and paralleling circuit breaker technology. Many high-tech companies are already using this equipment for seamless transition from generators to the power grid. Q: Can you assure us that our emergency power system is maintained to our standards of reliabilty and quality? · Yes, your facility's staff and PGE wil jointly decide on the most qualified maintenance provider. This may be your existing provider, your own staff or a new provider that best meets your needs. Our agreement with maintenance providers will include annual performance reviews and if they are not performing at the levels we expect, we can agree to change providers. Q: Who is responsible for maintenance and repair? . This is another win-win aspect of the program for participating businesses, institutions and PGE. All regular maintenance and any repair bills are paid by PGE. The utility sees this as a reasonable cost to assure that your generator is available at all times to participate in the program, and it lowers your cost of doing business. We estimate that this may easily save $50,000 to $100,000 over a five-year period. PGE has created the DSG program with the highest standards. Should your equipment fail to function as required for your emergencylbackup use, the maintenance provider selected by you and PGE will begin diagnosing the problem within four hours of notification. If appropriate, the provider wil then repair or replace the equipment (at PGE's discretion) with comparable items as required to meet your system's needs. Q: Who pays for fuel? . PGE pays for fuel regardless of whether the fuel was used only for your needs or to serve the utilty distribution system. We do require the use of transportation grade, low-sulfur, diesel fueL. Q: Can I stil participate if I choose to buy power from an independent supplier? . Under Oregon's restructuring law, you can choose to purchase your power from an independent provide. If you make this choice, you can stil take advantage of the DSG program. You, PGE and your independent supplier would negotiate an agreement, which would provide accurate billing and properly account for the power used by your facility, even when the generators are operating. Q: Are there any regulatory or tax issues I should be aware of? o 6 htt://ww.portlandgeneral.com/usiness/large _ industrial/faq .asp?bhcp= 1 12/6/2007 nJ.t - Large &: maustriai Accounts: 1Jispatchabie Veneration FAQ Page 3 of4 . Participating in the DSG program will not affect your taxes. Because PGE wil own a portion of the system of which the generators are a part, the output of the generators will be considered PGE power. PGE wil also handle all power regulation issues related to the operation of your DSG power system. Q: Under what circumstances would my organization have to reimburse PGE for its investment? . PGE is providing a significant investment to upgrade your property. PGE is counting on your generation to maintain an effcient power system and reduce costs. If you cancel the agreement without cause or without proper notice, most of the equipment would typically remain with you and you would be responsible for reimbursing PGE for the value of that equipment. If PGE cancels the agreement, PGE wil remove any PGE equipment and leave your facility in such condition as wil enable you to operate the generators for your own backup use. Under these circumstances, no equipment reimbursement would be required. Q: Can a business cancel the DSG agreement? . In the unlikely event that PGE fails to maintain or repair the equipment as required in the agreement, you may cancel the contract before its normal expiration date. As mentioned above, the maintenance service provider is required to begin diagnosing a problem within four hours. If a problem cannot be fixed within 30 days, you would have the option to terminate the agreement. Q: What happens if the actual project cost is greater than PGE's projections because of unforeseen conditions? . In a retrofit installation or for PGE owned equipment, PGE will be responsible for all cost over-runs related to items installed under the Dispatchable Generation Agreement. With a new facilty or new generator plant, where you would have primary responsibilty, we would negotiate an appropriate cost sharing solution. Q: How is PGE handling the environmental impact of the DSG program? . PGE cares a great deal about the environment. We wil be installing oxidation catalysts on all DSG program engine- generators. These catalysts significantly reduce carbon monoxide (CO), hydrocarbons (HC) and odor from the diesel engines. Research is also underway to explore new ways to reduce nitrogen oxides (NOx) in the engines we use for the program. PGE is also doing extensive research on the use of dual fuels. This could create opportunities to burn natural gas ínstead of diesel oil in many generators, significantly reducing emissions into the air. Every generating system in the program is issued a permit by the Oregon Department of Environmental quality, assuring that the engines are operating within standards. o 7 http://ww.portlandgeneral.com/usiness/large _ industrial/faq.asp?bhcp= 1 12/6/2007 rut: - Large &, industnal Accounts: Vispatchable Generation FAQ Page 4 of4 Q: How can I learn more about PGE's Dispatchable Standby Generation program? · Please contact your PGE representative or ~-mail us. You may also call Mark Osborn, DSG program manager, at 503-464-8347. PGE.. 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Th r o u g h a p i o n e e r i n g p a r t n e r s h i p w i t h P o r t l a n d Ge n e r a l E l e c t r i c , a u n i q u e D i s p a t c h a b l e S t a n d b y G e n e r a t i o n (O S G ) p o w e r s y s t e m w a s e n g i n e e r e d t h a t " s h a r e s p o w e r " by u s i n g t h e e m e r g e n c y g e n e r a t o r s t o m e e t p e a k p o w e r re q u i r e m e n t s . A s t h e f i r s t h o s p i t a l i n O r e g o n t o sy n c h r o n i z e t h e e l e c t r i c a l g e n e r a t o r s t o t h e u t i l i t y p o w e r gr i d , n e w d e s i g n c r i t e r i a a n d t e s t i n g p r o t o c o l s g o v e r n i n g OS G s y s t e m s i n h o s p i t a l s w e r e n e e d e d . T o f a c i l i t a t e t h i s , Sp a r l i n g e n g a g e d m a n y e x p e r t s i n c l u d i n g P o r t l a n d G e n e r a l El e c t r i c , S t a t e F i r e M a r s h a l , t h e e l e c t r i c a l c o d e a u t h o r i t y , Un d e r w r i t e r s L a b o r a t o r i e s a n d t h e o w n e r t o d e v e l o p c r i t e r i a fo r a c o m p l e x c o n t r o l s y s t e m t h a t w o u l d a u t o m a t i c a l l y pr i o r i t i z e a n d i m m e d i a t e l y s w i t c h g e n e r a t o r p o w e r t o pa t i e n t s d u r i n g a n y l o s s o f h o s p i t a l p o w e r . Th i s p r o j e c t i s j u s t o n e e x a m p l e o f t h e i n c r e d i b l e v a l u e th a t t h e e n g i n e e r i n g p r o f e s s i o n d e l i v e r s t o c o m m u n i t i e s t h r o u g h re s e a r c h a n d i n n o v a t i o n . A n e w m o d e l f o r h e a l t h c a r e e m e r g e n c y po w e r s y s t e m s h a s b e e n c r e a t e d t h a t b e n e f i t s b o t h p a t i e n t s a n d th e c o m m u n i t y b y g e n e r a t i n g p e a k p o w e r d u r i n g a n e n e r g y sh o r t a g e . C\ ,.o . GR A N D A W A R D : C e n t r a l U t i l i t y P l a n t f o r P r o v i d e n c e M e d i c a l C e n t e r Pi c t u r e d , f r o m l e f t , a r e M a r k E n g d a l l , S p a r l i n g ; K a r e n W e y l a n d t , Pr o v i d e n c e M e d i c a l C e n t e r ; K i m b e r l y K r u l l , S p a r l i n g ; a n d A C E C Or e g o n P r e s i d e n t K e n W i g h t m a n . Pr o v i d e n c e g e t s g o l d f o r g o i n g g r e e n Th e S h e r w o o d G a z e t t e A u g 2 8 , 2 0 0 6 CO U R T E S Y O F / P R O V I D E N C E H E A L T H S Y S T E M Th e P r o v i d e n c e - N e w b e r g M e d i c a l C e n t e r h e a l i n g g a r d e n . Or e g o n ' s n e w e s t h o s p i t a l i s a l s o t h e na t i o n ' s g r e e n e s t . Th e u . s . G r e e n B u i l d i n g C o u n c i l h a s a n n o u n c e d th a t P r o v i d e n c e N e w b e r g M e d i c a l C e n t e r ( P N M C ) re c e i v e d G o l d L E E D ( L e a d e r s h i p i n E n e r g y a n d En v i r o n m e n t a l D e s i g n ) c e r t i f i c a t i o n , m a k i n g i t t h e "g r e e n e s t " h o s p i t a l i n t h e U n i t e d S t a t e s . Pr o v i d e n c e N e w b e r g i s t h e f i r s t h o s p i t a l i n t h e na t i o n t o e a r n t h i s d e s i g n a t i o n . 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P N M C i s t h e o n l y h o s p i t a l i n t h e n a t i o n t o pu r c h a s e 1 0 0 p e r c e n t g r e e n p o w e r . .P a r t i c i p a t i o n i n t h e D i s p a t c h a b l e S t a n d b y G e n e r a t i o n pr o g r a m t h r o u g h P o r t l a n d G e n e r a l E l e c t r i c ( P G E ) .O c c u p a n c y s e n s o r s , d a y l i g h t c o n t r o l s a n d c e n t r a l i z e d li g h t i n g c o n t r o l s y s t e m s t u r n o f f l i g h t s w h e n s p a c e s a r e un o c c u p i e d . *A I I p u b l i c s p a c e s a n d w a i t i n g a r e a s i n c l u d e u s e o f n a t u r a l li g h t t h r o u g h d e s i g n a n d f e a t u r e v i e w s o f n e a r b y h i l s i d e s an d n a t u r a l s c e n e r y . 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