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Home My WebLink About20030425Peseau Direct & Exhibits.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION POTLATCH CORPORATION Complainant Respondent CASE NO. AVU---i ~~"-;'-""::"~~':", tf)c::; () -'" 8c:: ;" l4'' :x:tr- -.,?J~ i= rt'l fT1-0 :::u ~ fT1CJ1 0 A VISTA UTILITIES CfJn .s:::- ~ 08 , DIRECT TESTIMONY DENNIS E. PESEAU ON BEHALF OF POTLATCH CORPORATION PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. My name is Delmis E. Peseau. My business address is Suite 250, 1500 Libeliy Street, S., Salem, Oregon 97302. BY WHOM AND IN WHAT CAPACITY ARE YOU EMPLOYED? I am the President of Utility Resources, Inc. ("URI"). DR1 has consulted on a number of economic, financial and engineering matters for various private and public entities for more than twenty years. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND AND WORK EXPERIENCE. My resume is attached as Exhibit No. 1. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION? Yes, many times. In addition, I have testified on the subject of avoided costs before this Commission on numerous occasions since the 1980s. FOR WHOM ARE YOU APPEARING IN THIS CASE? I am appearing on behalf of Potlatch C0l1)Oration. WHAT IS TI-IE PURPOSE OF YOUR DIRECT TESTIMONY? The ultimate purpose of my testimony is to make a recommendation to the Commission on the best method of resolving the complaint in this case. To that end I will first briefly discuss how the current impasse between Potlatch and Avista came about. I will then examine Avista s proposal to Potlatch and explain wily it is inconsistent with PURP A's requirements and this Commission 8 orders governing Direct Testimony of Dennis E. Peseau - 1 Case No. A VU-OZ- ..., PURP A purchases. Finally, I will propose a method ofresolving the controversy that is fair to bot1~ A vista and its ratepayers and to Potlatch. PLEASE DESCRIBE HOW THE DISPUTE IN THIS CASE AROSE. The Commission is well aware of most aspects of the long history between Potlatch and A vista, so I will confine my remarks to a brief summary of the relevant facts. Prior to December 31 2001 , Potlatch and Avista were parties to an Electric Service and Purchase Agreement dated January 3, 1991 ("1991 Agreement"). This lengthy and complex agreement provided for the purchase of all of Potlatch's electric energy needs for its Lewiston facilities from A vista and for the simultaneous sale to A vista of a maximum of 59 megawatts of energy from Potlatch's four cogeneration units. During the last year of the 1991 Agreement's existence , attempts to negotiate a successor agreement broke down. Potlatch's first concern was obviously with its electric supply, so on March 23 2001 , Potlatch filed a petition with this Commission seeking a determination of the terms and conditions of electric service from Avista to Potlatch's Lewiston facility. IPUC Case No. A VU-01-5. On August 17, 2001 shortly before the scheduled commencement of hearings, the parties were able to reach a settlement that provided for continued Avista service to Potlatch at Schedule 25 rates until a new special contract rate could be established in Avista s next general rate case. With its supply situation resolved, Potlatch turned its attention to the sale of its cogeneration output. On October 2 2001 , Potlatcb sent Avista a written request for a firm avoided cost quote for the purchase of its cogeneration. This request contained tIle infomlation required by applicable Commission orders. A copy is Direct Testimony of Dennis E. Peseau - 2 Case No. A VIJ-O2- attached as Exhibit 2. The request also proposed that the parties meet on October 12 2001 , to begin contract negotiations. DID THE PARTIES IN FACT MEET ON OCTOBER 12 Yes. Meetings were held on October lih, November 14 , and December lih . I did not attend these meetings, but I have reviewed the wli tten materials that A vista provided as well as the follow up correspondence between the pariies. I should mention parenthetically that Rick Sterling attended the November and December meetings on behalf of the Commission Staff DID A VISTA PROVIDE POTLATCH WITH A FIRM QUOTE FOR THE PURCHASE OF ITS COGENERATION AT THESE MEETINGS? Yes. Avista offered Potlatcb $30.95 per megawatt hour for a 5 year contract. The contract price was, however subj ect to a $1.14/mwh offset for reserves that A vista insisted were Potlatcb's responsibility, making the net price $29.811mwh. The offer was also subject to a liquidated damages provision for non delivery, which subsequent correspondence Pliced at $5.00/mwh or 20% of the price, whichever is greater. The offer is summarized in the hand out Avista distributed at the November 14tb meeting, whicb I bave attacbed as Exhibit 3. For the purpose of this testimony, I have treated the offering price as $30. because there is absolutely no authority in the Commission s orders for Avista attempt to impose liquidated damages, reserve charges or any other ancillary charges on a QF sale. HOW DID A VISTA ARRIVE AT TI-IIS PROPOSED PRICE? Dil'ec1 Testimony of Dennis E. J'eseau - 3 Case No. A VlI-O2- According to A vista, it calculated the price in accordance with the requirements of Conmlission Order No. 26576. That order was promulgated on September 4, 1996 in IPUC Case No. IPC-95-9 in order to prescribe a new methodology for avoided cost rate negotiations for Qualifying Facilities ("QF") of one megawatt or larger. DOES A VISTA'S RATE CALCULATION IN FACT COMPLY WITH THE REQUIREMENTS OF ORDER NO. 26576? In my judgment, it complies with neither the letter nor the spirit of the order, aIld it clearly does not produce the results the Commission envisioned when it signed the order. PLEASE EXPLAIN. Order No. 26576 adopted a new avoided cost methodology for large QFs that was devised primarily in the course of settlement discussions between the Idaho utilities and the Commission Staffl In essence, the new methodology attempted to produce ail objective calculation of avoided costs by requiring utilities to model QF driven changes to the utilities ' Integrated Resource Plans ("IRP"). The ultimate objective was to peg avoided cost rates to "the difference in the present value of revenue requirements (PVRR) between tile base case resource plan and a modified resource plan that includes the QF resource." Settlement Stipulation at 4. This result was to be accomplished through a complex seven-step process described as follows in the Settlement Stipulation: An IRP is prepared for the utility. The IRP should consider a range ofload forecasts for various sets of possible economic conditions. The IRP should also consider all possible resources for meeting load, both supply and demand side. In addition I A few Idaho independent power producers apparently participated in the settlement discussions to some degree, but they did not sign the resulting Settlement! Stipulation. Direct Testimony of Dennis E. l'eseau - 4 Case No. A VU-O2- .., consideration should be given to the risks and uncertainties associated with each scenario examined. The least cost combination of resources is selected to meet each scenario. The most likely scenario is identified as the base case plaIl An initial simulation analysis using a power supply and/or capacity expansion model chosen by the utility is used to calculate the PVRR of the base case resource plan over the lifetime of the proposed QF contract. The proposed QF resource is added to the base case resource plaIl during all years of the proposed contract. The required description of the QF project includes all data and infonnation needed to model the intended dispatchable or non-dispatchable operation of the project on the power supply system (see pps. 9-10 for a list of data and infolmation needed from QFs. A second simulation analysis , including the QF resource, is perfonned which results in an adjustment of the amount and/or timing of the new resources in the base case plan. The modified plan including the QF purchase is constructed to maintain resource adequacy and system reliability equivalent to that of the base case plan. The PVRR of the modified resource plan including the QF is calculated over the full ternl of the QF contract, excluding the total costs of the QF resource itself. Finally, the present value of the QF project avoided cost is calculated by subtracting the PVRR of the modified plan, with costs of the QF set to zero, from the PVRR of the base case plaIl. Rates for capacity and energy from the QF project can now be developed for which, on a present value basis, the expected payments to the QF are equal to the project's avoided cost over the life of the contract. DID A VISTA FOLLOW TI-IIS PROCEDURE IN CALCULATING THE PRICE IT OFFERED TO POTLATCH? While I have no doubt that A vista probably has workpapers, complete with multiple runs of the propri etary ProsYI11 model, to prove that it actually followed this seven Direct Testimony of Dennis E. reseal! - 5 Case No. A VU-O2- ..., step procedure, the simple fact is that the whole exercise was, is, and continues to be nonsensical for the purpose of colTectly computing avoided costs. WHY DO YOU CHARACTERIZE A VISTA'S MODELING EFFORTS AS NONSENSICAL? Avista s interpretation of the process devised in Order No. 26576 is nonsensical because, regardless of the inputs or the nature of the QF resource being modeled, the answer is always the same-the supposedly modeled avoided costs are always equal to forward market prices at the time the model is nll1 . In short, the Prosym modeling exercise is irrelevant. You can get the same answer by just consulting a single input-market prices. The reason that maI'ket prices always equal avoided costs is that Avista s model does not allow actual or planned resources to be deferred by the avoided cost resource. Ifit can t defer resources, the model CaIl t simulate the Surrogate Avoidable Resource found prudent in GNR - E-02-1. This is a fatal flaw in the modeling process. IS THAT BECAUSE A VISTA HAS SURPLUS RESOURCES AND HAS NO NEED FOR POTLATCH'S POWER? No. On November 14, 2001 , the same day that Avista presented its offer to Potlatch A vista also filed its response to Commission Order No. 28884. That order required Avista to submit a revised load/resource balance sheet to reflect changes to Avista IRP. I have attached a copy of Avista s filing as Exhibit 4. This exhibit shows that even with Coyote Springs II coming on line in 2002 (which did not in fact occur), A vista has an annual average energy deficit in every single year. Even if all resources culTently under construction come on line as scheduled, Exhibit 4 projects Direct Testimony of Dennis E. Peseau - Case No. A VU-O2- an average energy deficit of 108 megawatts in 2004 and constantly rising deficits every year thereafter. In reviewing the evidence at the time, the Commission Staff concluded that it "confirms an immediate need for new generation resources and demonstrates additional needs in the not too distant fhture." Order No. 28884 at 2. Paradoxically, the fact that Avista needs precisely the type of base load resource that Potlatch can provide has no effect whatever on Avista s calculation of avoided costs. In fact, A vista s resource deficiency could grow much larger aIld still have no effect on Avista s calculated value of the Potlatch resource. HOW DO YOU KNOW THAT? Avista admits as much. In Staff Data Request No., Staff asked Avista to show the avoided cost rate with aIld without the Coyote Springs II generating station included in the base case. A vista responded as follows: Two nlllS were perfOlmed in AURORA for Request 3. The first run with CSII in the Company s resource portfolio aIld developed market prices in this case. The second was done without CSII. Refer to the workbook entitled "Request 3" in the file "February Offer Analysis-AURORA.xls" (provided in electronic format on an attached diskette in answer to Staff Production Requests 2 and 3) to see that the market prices of power during the January 2003 through December 2008 (taken :limn the AREA PRICE table of the AURORA run of Request 2) are identical in both altematives, and therefore that the avoided cost rate calculated in this manner is the same as the E-95-9 Rate, at $34.05/MWH for March 2003 through February 2008. (Emphasis added). This result is not only counter-intuitive, it is also inconsistent with the clear language of the Commission s order. In Order No. 26576 , the Commission stated that , " the value of power from the QF is dictated by the type amount, timing and cost of the resources in the IRP which would be displaced or deferred." Order No. 26576 at 2. Thus, if a QF purchase could displace or defer the Direct Testimony of Dennis E. J'eseau - 7 Case No. A VU-O2- I 5 I 8 I 9 cost of Coyote Springs II, the avoided cost should be largely driven by the cost of that displaced or deferred resource. This was a maj or purpose of GNR - E-02-l. But using Avista s methodology, the cost of that displacement or defenal is ilTelevant because avoided cost always equals projected market prices. DO YOU THINK THIS WAS THE COMMISSION'S INTENDED RESULT WHEN IT SIGNED ORDER NO. 26576? I am confident it was not. In the first place, Avista s results are clearly at odds with the Commission language I just quoted. Fmihernlore, if the COlmnission had intended that avoided costs would always equal estimated market prices, it presumably would have said so in a straightforward and direct manner. There would have been no need for the elaborate process it in fact endorsed. Finally, the settlement itself states that the cost ofmaI-ket resources should only "be one component in detennining utilities avoided costs " and then only to the extent utilities are actually relying on them. Settlement Stipulation at 4- THEN HOW DID THINGS COME TO THIS PASS THAT AVISTA CAN CLAIM TI-IAT ITS AVOIDED COSTS ALWAYS EQUAL PROJECTED MARKET PRICES? The evidence will support either of two alternative explanations. The first is that this is the unfortunate and unintended consequence of a Commission decision that the utility has followed in good faith. The more cynical view is that the Commission order left A vista an oppOJiunity it has exploited to subvert the Commission s intent. I-lOW DID YOU ARRIVE AT THESE ALTERNATIVES? Direct Testimony of Dennis E. Peseau - 8 C:lse No. A VU-O2- In Order 26576 the Commission was forced to decide one critical issue the parties could not resolve in the Stipulated Settlement. The utilities wanted the maximum contract tenn shortened from 20 years to five years, arguing that they did not intend to constmct or acquire new long tel1ll generating resources. See Order No. 26576 at 5. Staff and the QF developers continued to support 20 year contracts. Ultimately the Commission adopted the utilities' arguments and shortened the maIldatory contract length to five years. Order No. 26576 at 6- This finding effectively opened the door to unzipping all the painstaking work that went into the Stipulated Settlement. In Avista s case, it simply assumed for avoided cost purposes, that: (1) market prices can be reasonably forecast for five years, (2) all short tenn resource needs of 5 years or less will be met by market purchases and (3) existing high cost resources will be displaced by market purchases rather than the avoided cost resource, aIld Voila!" Avoided costs automatically equal projected market prices no matter what happens to all the other variables in the avoided cost model. YOUR ANSWER EMPHASIZES THE FACT THAT A VISTA MADE T1-IIS ASSUMPTION "FOR AVOIDED COST PURPOSES." WHY? I can t say whether Avista really believed in 1996 that the market would provide all future resource needs. In any case, those utilities that believed in total reliance on the market as a prudent resource acquisition strategy were disabused of that notion by the events of 2000-2001. By early 2001 Avista had clearly abandoned any market reliance strategy and begun the construction of Coyote Springs II, Boulder Park, and a number of other smaller generating projects. But for avoided cost purposes, Avista Direct Testimony of Dennis E. Peseau - 9 Case No. A VlJ-O2- made no such change in plarming even though its IRP, which is supposed to drive avoided cost calculations, clearly recognizes the need for, and construction of, new resources. WHY IS THIS OBJECTIONABLE? In the first place, it violates the express terms of the Stipulated Settlement that Avista signed in 1996. That settlement authorized the utilities to select their own variables in their avoided cost calculations as long as those "values and assumptions fall within a reasonable range." Stipulated Settlement at 5. But the settlement fmiher provided that utilities "will be required to analyze their own resources on an equal footing with QF resources.!d. Thus, market plices are an acceptable component of the avoided cost detenllination only if they are in fact the resource of choice for the utility. Id. It is obvious that when A vista made the decision to construct Coyote Springs II and Boulder Park it abaIldoned market purchases as the resource of choice. It is equally obvious that Avista did not analyze those resources in anything like the manner in which it is evaluating Potlatch's cogeneration. There is clearly nothing equal" or fair about a situation in which A vista is constructing plants that will surely come in at an all-in cost roughly 50% to 100% higher than Avista s offer to Potlatch. Moreover, this situation is a violation of both the letter and spirit ofPURP A. The whole point of PURr A is to insure that QFs receive payments equivalent to the cost that their generation avoids. If a utility is constructing base load plants, as A vista is, then the avoided cost shou 1d bear a strong relationship to the cost ofthose Direct Testimony of Dennis E. Peseau - 10 Case No. A VIJ-02- ')..., plants. Again, the Commission s adoption of the SAR avoided costs in GNR-02- underscores this point. HOW DO YOU PROPOSE THAT THE COMMISSION RECTIFY THIS SITUATION? First, I recommend that the Commission abaIldon or revoke Order No. 26576. It was promulgated at a time when the utility world looked much different than it does now and, at least as administered by A vista, it obviously does not produce an accurate calculation of avoided costs. At the very least, I recommend that the Commission adopt a 20 year contract limitation for large QFs for the SaIl1e reasons that persuaded it to adopt a maximum contract length of 20 years for QFs of less than 10 megawatts. Second, the Commission should malce it clear that avoided costs cmmot be equated to market Plices, except possibly for very ShOli term needs one or two years in the future. WI-IY IS AN EXPLICIT RESTRICTION ON THE USE OF MARKET PRICES NECESSARY? In the first place, market prices are meaningful only if the market is liquid transparent and unconstrained. With the collapse of Emon, and the near death experience of DYl1ergy and a host of others, westem power markets are arguably too thinly traded to meet these criteria, particularly over the longer term such as five years. Even if you can detemline the most recent price for a 5 year, 50 megawatt contract there is no assurance that another contract could be executed at the same pnce. Direct Testimony of Dennis E. Peseau - 11 Case No. A VlJ-02- Perhaps more impOliant, if one uses market prices as a sunogate for avoided costs, then those prices should be adjusted upward to reflect market risks. As we have allleal1led from recent experience, the risks of going long or short in the market are not symmetrical. If I buy $50 WOlih of power the most I can lose on the transaction is $50, even if the market price goes to zero. But if! go short and depend on the market to meet my future needs, there is no limit to the price I could be required to pay, as Avista found out when it was forced to pay in excess of $300/mwh in 2000-2001. Any utility that plans on meeting its needs by market purchases must take this risk into account, and so should aI1Y avoided cost calculation that uses market prices. Unfortunately, there is no reliable way to quantify the present value of this risk in the Prosym model, and utilities that have resOlied to using financial derivatives to attempt to limit market risk have generally met with disastrous results. That is in fact why A vista is constmcting generating plants that exceed the supposedly efficient market-clearing price detennined by the model. HOW THEN DO YOU PROPOSE THE COMMISSION DETERMINE TI-IE PRICE FOR POTLATCH'S COGENERATION? One possibility is that the Commission could modify the Prosym model in an attempt to determine Avista s true avoided costs. But as I riointed out earlier, the fact that the model is proprietary and therefore unavailable for detailed analysis, means that one has to make educated assumptions about the nature ofthe required modifications. Moreover, I cannot say with assurance that the necessary changes Direct Testimony of Dennis E. Peseau - 12 Case No. A VII-02- can, as a practical matter, be accomplished without violating the integrity or functionality of the model. CAN YOU LIST SOME OF THE CHANGES THAT WOULD BE REQUIRED TO ENABLE THE MODEL TO DETERMINE A VISTA'S TRUE AVOIDED COSTS? Obviously the first adjustment would be to eliminate the market supply cost curve from the model. This would probably require the substitution of some other type of historical market data to capture the cost of opportunity sales and purchases, but it is not immediately apparent to me how this consideration could be included without turning the model back into a market driven exercise. In addition, we would have to estimate variable operating and maintenance costs for Coyote Springs II aIld Boulder Park with little or no 'actual operating data to go on. This is necessary because, with market pricing eliminated, both of these resources would be key drivers of the dispatch simulation and avoided cost calculation. Enviromllental costs associated with the operation of one of the Company s peakers would also have to be added probably in the form of external calculations. Most important, because the model is essentially an energy only calculation we would have to add a credit or adder to reflect the value of capacity and the risks posed by the lack of sufficient capacity, and this calculation would probably have to be devised outside the model and then somehow reinserted into the modeling process. Without this adjustment, the model will always underestimate the true avoided costs. Finally, I suspect that if r had access to the model itself I would find that additional changes are necessary, and that the changes I have proposed necessitate still more adjustments to preserve the model's functionality, Direct Testimony of Dennis E. l'eseau - 13 Case No. A VlI-()2- ARE YOU IN FACT RECOMMENDING THAT THE COMMISSION USE THE MODEL ADJUSTED IN THE FASHION YOU HAVE SUGGESTED? I cannot even assure the Commission it is physically possible to correct the model in the mamler I have suggested. The Prosym model was designed to value a resource acquisition only in comparison to market prices. Once we decide, as A vista quite sensibly has , that market purchases are not a reasonable substitute for physical generating resources, the model must be completely rebuilt in order to furnish aI1Y sOli of intelligible information about a given resource s value. Moreover, the most cmcial components of this rebuilding process (e.g, Coyote Springs ' variable costs and the appropriate capacity credit) would have to be developed outside the model so in the end the results would hinge on the results of a debate about the appropriate value of these elements. Under these circumstances, I do not believe that the required effort is even remotely worth the dubious results that might be achieved by altering the model to fit Avista s cunent situation. IS THERE AN ALTERNATIVE METHOD THE COMMISSION COULD USE TO CALCULATE A VISTA'S AVOIDED COSTS? Yes. This case presents a unique opportunity to detennine A vista s avoided cost with great accuracy. When A vista first began construction of Coyote Springs it planned on receiving approximately 280 megawatts of capacity and energy from that plant. UnfOJiunately, Avista s financial condition was then devastated by the huge purchase power costs it incurred in 2000 and 2001 , so it was forced to sell half of Coyote Springs to bolster its balance sheet and curb cash expenditures. This leaves Avista 140 megawatts short ofthe resource needs it identified as prudent and for Direct Testimony of Dennis E. J)eseau - 14 Case No. A VlJ-02- which it was, and presumably still is, willing to "purchase" at Coyote Springs' all- cost per mwh. IfPotlatcb provides a portion of this 140 megawatts at a price equivalent to Coyote Springs ' cost , both Avista and its ratepayers would be indifferent to the result and PURP A's requirements would be satisfied. DO YOU KNOW WHAT THE COST OF COYOTE SPRINGS' GENERATION WILL BE? I know what the preliminary cost estimates were, but I suspect they will tUl11 out to be lower than actual because of construction problems at the site. Unfortunately, I am not at liberty to divulge even the preliminaI'y estimated costs because they were furnished as confidential material in another proceeding. Under these circumstances the only way to immediately use Coyote Springs' actual costs would be to set an intelim avoided cost rate for Potlatch and then adjust it retroactively to Coyote Springs ' costs when the plant comes on line. SHOULD THE COMMISSION IMMEDIATELY UNDERTAK,EAN INDEPENDENT INVESTIGATION OF COYOTE SPRINGS' COST IN ORDER TO DETERMINE A VISTA'S AVOIDED COST? Fortunately, I don t believe that is necessary. The Commission has just recently completed a thorough reexamination of the cost of constructing and operating a natural gas generating facility in connection with its determination of avoided costs for projects of 10 megawatts or 1ess. J believe the Commission could with complete confidence use the costs detel111ined in that case as the basis for an avoided cost determination in this proceeding. Direct Testimony of Dennis E. Peseau - 15 Case No. A Vll-02- YOU STATED THAT THE PRICES PUBLISHED IN CASE NO. GNR-02- COULD BE USED AS "THE BASIS" FOR AVOIDED COSTS IN THIS CASE. DO YOU HAVE ANY REASON TO BELIEVE THE COMMISSION WOULD AGREE TO THIS RECOMMENDATION? Yes. Approximately three weeks ago , on March 28 , 2003 , the Commission issued Order No. 29216 in Case No. GNR-03-1. In that case the Independent Energy Producers of Idaho filed a petition requesting that the Commission increase from 10 MW to 30 MW the size at which a qualifying cogeneration or small power production facility is entitled to published avoided cost rates. The Commission rejected the proposal that larger QFs should be entitled to published rates as a matter of right, but went on to say: The Commission notes that QFs greater than 10 MW are not precluded from contacting an electric utility and individually negotiating a power purchase agreement. That has long been the contract procedure for large QFs. The starting point for such negotiations under the approved methodology is the established posted rate.Should a utility fail to negotiate in good faith with a qualified QF, a complaint can be filed with this Commission. Order No. 29216 at 3. I recommend that the Commission follow exactly that procedure in this case. WI-IAT ARE THE CURRENT POSTED RATES FOR A VISTA? As I stated earlier, the rate for a 5 year contract term, which seems to be acceptable to both parties, is $43.3/mwh. A full copy of A vista s posted SAR rates is attached as Exhibit 5. IF THESE RATES ARE TI-IE "STARTING POINT" FOR NEGOTIATIONS SHOULD THEY BE ADJUSTED IN SOME FASHION? Direct Testimony of Dennis E. Peseau - J Case No. A VU-02- Yes. There are at least four factors that argue for an upward adjustment to the posted rates for Potlatch. First, there is the matter of sheer size. Potlatch's cogeneration facility is capable of providing 80 megawatts of capacity and energy on a near continuous basis. A purchase of this magnitude provides obvious economies of scale as compared to the purchase of similar quaIltities of energy from a number of producers. Second, Potlatch's plant has a demonstrated history of safe, reliable and efficient generation and delivery of power to A vista. Most other proposed QFs will be new facilities that are subject to all the inherent uncertainties and risks associated with an untried aIld untested staIiup. Moreover, the interconnection facilities between A vista and Potlatch, including the necessary metering equipment and related items, are already in place and the parties already have 10 years of cooperative operating expelience in the simultaneous sale and purchase of power. All of these factors tend to decrease A vista s costs. Third, as a true cogenerator, Potlatch offers A vista a unique and valuable measure of risk protection that no other resource, including A vista s own plants, can provide. A bydroelectric facility can be washed out by floods, a wind generator can be disabled by storms, and a utility steam generator can be unusable for extended periods as a result of catastrophic accidents. In each case, the utility purchasing the lost plant's output may be forced to scramble for replacement power supplies at inconvenient times. But Potlatch's cogeneration is an integral part of its mill operations, and it is difficult to imagine that all four of Potlatch's cogeneration units would be completely off line unless the mill was also shut clown. In that event Direct Testimony of Dennis E. l)cseau - 17 Case No. A VlT-02- A vista would not be faced with a sudden need to find replacement resources because the loss of the Potlatch mill load would exceed the disabled generating capacity. Avista might then find itself with some extra energy available for sale but it would not face the lisks associated with replacing lost resources. Fomih, and most important, Potlatch is entitled to an addition to the posted cost rates to reflect the fact that Potlatch's cogeneration provides Avista with very significant savings in capital expenditures on transmission. It is common knowledge that, without Potlatch's cogeneration, Avista would have to upgrade its transmission system in order to provide reliable service to the Lewiston/Clarkston valley. Avista s avoided investment in transmission does not fit within the nonnal avoided cost calculation, but this is a unique situation. Given the magnitude of Avista avoided transmission costs, it would be both unrealistic and inequitable to omit these costs from Potlatch's rates. HAVE YOU QUANITIFIED THE ADDED VALUE TO POSTED AVOIDED COST RATES FOR THE FACTORS YOU HAVE JUST DICUSSED? , not precisely. If we are successful in discovery requests , I may be in a position to more fonnally address this in rebuttal or at the hearings. CAN YOU OFFER AN ESTIMATE OF TI-IIS ADDED VALUE? Yes, I estimate that the additional savings from avoiding the line losses of an extel11al resource such as Coyote Springs II, and avoidance of major internal- transmission expenditures to replace the system stability provided by Potlatch generation to be roughly equivalent to a 10% increase in the avoided cost rates. conclude therefore that a rate of 47.6 mills/kwh to Potlatch is fair and reasonable. Direct Testimony of Dennis E. Peseau - 18 C:lse No. A Vll-02- In the alternative, Potlatch would agree to an interim rate of$47.60/mwh lU1til Coyote Springs is brought on line. At that point, the Commission would calculate Coyote Springs ' all-in costs and adjust Potlatch's rates to those costs. Potlatch would take the risk that Coyote Springs might come in lower than Potlatch' rate. This proposal has the benefit of matching Potlatch's rate to the exact plaIlt that Potlatch is deferring and it holds the ratepayers completely harmless. ARE THERE ANY OTHER RELEV ANT FACTORS THAT THE COMMISSION SHOULD CONSIDER IN THIS CASE? Yes. Since the expiration of the prior A vista/Potlatch contract on December 31 2001 , the lack of a power sales contract has forced Potlatch to generate into its own load. By any measure, this is an undeserved windfall for Avista because Avista effectively gets the benefit of Potlatch's generation without paying for it. But this is a dangerous game for Avista s ratepayers. Someday market prices will spike up to a sufficiently high level to entice Potlatch to sell its generation to a third pmiy. At that point, Avista will have to buy replacement power in the same high Pliced market. Ninety percent of the cost of that replacement power will flow straight through Avista s PCA, resulting in a direct and immediate rate increase for Idaho ratepayers. A vista itself will absorb only ten percent of that cost. Given the windfall it is receiving from the free use of Potlatch's power in the interim , this is a small risk for Avista to run. But the stakes for the ratepayers are far higher and the potential for loss much more severe. WOULD YOU PLEASE SUMMARIZE YOUR FINDINGS AND RECOMMENDA TJ ONS? Direct Testimony of Dennis E. Peseau - J Case No. A VU-02- .., I recommend that the Conmlission adopt as a point of departure the "SAR" avoided cost concept it established in the recent Case No. GNR-02-l and increase those avoided cost rates for Potlatch for reasons I explained earlier in my testimony. The five- year SAR posted rate beginning in 2004 is approximately $43.30/mwh. With the additions I have proposed, Potlatch's rates would become $47.60/mwh. Altematively, I recommend that the Commission adopt the $47.60 rate as an interim rate until Coyote Springs ' costs can be determined , at which point Potlatch's rate would be adjusted to equal Coyote Springs' costs. DOES THIS CONCLUDE YOUR TESTIMONY? Yes. Direct Testimony of Dennis E. ))eseau - 20 Case No. A VlJ-02- CERTIFICATE OF SERVICE I HEREBY CERTIFY that on the 25th day of Aplil, 2003 , I caused to be served a true and COlTect copy of the foregoing by the method indicated below, and addressed to the following: Jean Jewell Idaho Public Utilities Commission 472 W. Washington Street O. Box 83720 Boise, ID 83720-0074 - US. Mail - Fax -L By Hand Scott D. Woodbury Idaho Public Utilities Commission 472 W. Washington O. Box 83720 Boise, ID 83720-0074 - US. Mail - Fax -L By Hand David J. Meyer Senior Vice President and General Counsel A vista Corporation 1411 E. Mission Ave. Spokane, W A 99220 -L U.S. Mail - Fax - By Hand R. Blair Strong Paine, Hamblen, Coffin, Brooke & Miller LLP 717 West Sprague Avenue, Suite 1200 Spokane, WA 99201-3505 -L US. Mail -L Fax - By I-land l;,y4' j/ffTina Smith ,.....--'--- Direct Testimony of Dennis KI)eseall - 21 Case No. A VU-02- DENNIS E. PESEAU President Utility Resources , Inc. EDUCATION Claremont Gmduate School Ph.D. Economics , 1977 A. Economics , 1971 California State University (Chico)A. Economics, 1969 II\JOUSTRY AI\lD GOVERNMEhJT EXPERIENCE Zinder Companies , Inc.Senior Vice Pmsident Oregon Public Utility Commissioner Senior Economist Southern California Edison Company Economist Dr, Peseau has consulted on numerous technical, legal and administrative economic, engineering and 'financial topics fol- over fifteen years, I-Ie currentlyheads a firm which is engaged entirely in technical, mathematical ane! computermodeling of la'-ge scale economic problem solving for litigated, disputed or otherwise contentious issues. Members of the firm are involved almostconstantly in the development and presentation of economic issues in a mannerwhich can be understood by pei"solls not expert in these areas. Dr. F)eseau has personally testified in various administrative ane! civilproceedin~,s on more than one hundred occasions. Exhibit 1 C:Ise No. A \111-11-02-01:1 nired Testinwny of Hennis E. I'eseau DENNIS E. PESEAU Page 2 TESTIFIED OR PREPARED STUDIES BEFORE STATE AND FEDERAL AGENCIES IN: Alaska California Colorado Idaho Maryland Minnesota Montana Nevada New York Oregon Virginia Washington Washington , D. SELECTED CONSULTING EXPERIENCE - Anti-Trust, Economic Evaluation and Other Civil Suits Western Cities Broadcasting, Inc. vs. Eldorado Communications. District Court Jefferson County, State of Colorado. Schmidt-Tiago vs. State of Colorado. Conducted extensive econometric and statistical analysis and direct testimony to rebut liability and damage claims by plaintiffs in bid rigging anti-trust case. Asphalt Paving vs. State of Colorado. Conducted extensive econometric and statistical analysis and direct testimony to rebut liability and damage claims by plaintiffs in bid rigging anti-trust case. Peter Kiewit Construction vs. State of Colorado. Conducted extensiveeconometric and statistical analysis to rebut liability and damage claims by plaintiffs in bid rigging anti-trust case. State of Ol"8gon VB. Santiam Canyon Lumber Companies. Develop modelingmethods for plainti'ffs to estimate damages from alleged bid-rigging practices. UNOCAL vs. Pacific Gas & Electric, U. S. District Court. Central District ofCalifornia. Develop modeling methods to estimate damages in complaint for violation of federal antitrust law; bl"8ach of contract. Oregonian Paper Dealers vs. Oregonian Newspaper. Develop modelingmethods for plaintiffs to estimate damages from alleged price setting to dealer groups. DENNIS E. PESEAU Page 3 PPC vs. Johnson , before Judge Panner, Federal Court Case in Oregon. Prefiled testimony ordered by Judge Panner on various federal Northwest PowerPlanning Act issues. Colorado Interstate Gas Companies vs. Martin Exploration Management Corp. District Court of the County of EI Paso. Damage calculations in gas contract price case. Lifetime earnings analysis and job interview appraisal forwrongful terminationdiscrimination suit. Analysis regarding appropriate settlement levels in take-or-pay suit. ~ Power Economics Conducted reserve and reliability studies for the Northwest Power PlanningCouncil. Developed an optimal capacity expansion model for electric power systems to analyze reliability, reserve margins , hydro dispatch and costs of system growth. Developed procedure to value electric energy from cogeneration projects and economic trade-offs of electric and process pressure steam. Testified before Bonneville Power Administration in 1982, 1983 , and 1985 ratecases Cogeneration and Avoided Cost Estimation Developed , sponsored utility system models of groups of prospective CSPPs to estimate avoided costs in Alaska , Oregon , Idaho , California, WashingtonVirginia, Maryland and District of Columbia. Conducted economic and financial feasibility studies and developed models for same for several prospective CSPPs. Testified on avoided costs , contractterms , costclassificalion and seasonal mtes for CSPPs in seveml jurisdictions. Wrote discussion papers on the value ofgeothermal development in the Pacific Northwestfor U.S. Secretary of Energyand Administrator of Bonneville Power Administmtion. DENNIS E. PESEAU Page 4 - Rates , Rate of Return and Regulation Co-developed rate and marginal cost estimation models and assessed ratespread implications for several major U.S. electric utilities. Testified in PURPA and general rate cases on these matters. Developed a series of energy and revenue forecasting computer models forSouthern California Edison Company. Developed cost of capita I and economic feasibility testimony in support of an incentive rate of return for a major natural gas pipeline. Developed a model based on capital asset pricing for use in cost of capital testimony for major U.S. utilities. Testified recently in over twenty cases. Conducted a capital structure study for Pacific Northwest Bell TelephoneCompany. - Finance Developed a rate of return , cost of capital and capital structure study andsponsored testimony on these subjects in several regulatory jurisdictions. Conducted a study assessing the financial impact on ratepayers , utilitycompanies and a municipality of dual jurisdiction as proposed in a largeNorthwest city. Assisted the Arthur D. Little team to analyze the demand forecasting and 'financial modeling of Poliland General Electl"ic Company. PUBLICATIONS Size, Growth and Profits, and Executive ComRensation in the Large Corporation (with D. Smyth and W. Boyes). (London , The Macmillan Press, ane! New YorkHolmes ane! Meier, 1975). On the Relationship Between Executives ' Compensation , Sales, and ProfitsAtlantic Economic Journal , \/01. \/11 , No., July 1979. DENNIS E. PESEAU Page 5 A Comment on the Use of CAPM in Public Utility Rate Cases FinancialManaqement Journal , Vol. 7 , No., Autumn 1978. The Measurement of Firrn Size: Theory and Evidence for the United States andthe United Kingdom" (with D. Smyth and W. Boyes), Review of Economics andStatistics, Vol. LVI , No., February 1975. On Optimization in Models of Urban Land Use Densities " (with W. Boyes),Journal of Reqional Science , Vol. 13 , No., 1973. PAPERS AND CONFERENCE PRESENTATIONS Guest lecturer, Executive Seminar , " Regulated Utility Cost of Equity and the Capital Asset Pricing Model," Colgate Darden Graduate School of Business University of Virginia , 1979. Shorter Term Stability and Predictability of Parameters of Capital Asset Pricing with Implications for Regulated Utilities " presented to the Western EconomicAssociation Conference , Las Vegas , 1979. Rate Base Valuation as a Determinant of Risk in the Electric Utility Industry, presented to the Financial Management Association , Seattle , 1977. Resource Allocation and Rate of Return Regulation in Electric PowerGeneration: Capital Surplus or Shortage?", presented to the Western EconomicAssociation Conference , San Diego , 1975. Resource Allocation in an Industry Regulated by Rate of Return," read to theUCLA Graduate School Seminar on the Economics of Regulation, 1975. 4/03 Before the PSC of Nevada Docket No. 02-11021On behalf of Southern Nevada Water Authority 7/02 Before the Idaho pue Case No. GNR-02-On behalf of Idaho Power Company 5/02 Before the PSC of Nevada Docket No. 02-4037On behalf of Southern Nevada Water Authority 2/02 Before the PSC of Nevada Docket No. 01-11029On behalf of Southern Nevada Water Authority 1/02 Before the PSG of Nevada Docket No. 01-100012/02 On behalf of Southern Nevada Docket No. 01-10002Water Authority 4/01 Before the Idaho PSG Case No. AVU-O1-On behalf of Potlatch Corp. 1/01 Before the PSG of Nevada Docket No. 00-10014On behalf of Southern Nevada Docket No. 00-10015 W ate,- Authority 9/00 Before the PSG of Nevada Docket No. 00-6063On behalf of Southern Nevada W atel- Authority 6/00 Before the ,PUG of Oregon Docket hlo. UM-967On behalf of Industria! Customers of Northwest Utilities 12/99 Before the Iclaho PSG Case 1\10. A VU-99-On behalf of Potlatch Corp. 8/99 Before the PSC of Nevada Docket 1\10. 99-4005On behalf of Southern Nevada Water Authority 5/99 Before the Idaho pue Case 1\10. IPC-99-On behalf of Industrial Customers 4/99 9/98 8/98 5/98 of Idaho Power Before the Idaho pue On behalf of Potlatch Corp. Before the Nevada PSC On behalf of Southern Nevada Water Authority Before the PSC of Nevada On behalf of Southern Nevada Water Authority Before the Idaho pue On behalf of Industrial Customers of Northwest Utilities Case No. WWP-98- Docket No. 98-7023 Docket No. 97-7030 Case No. IPC-97- October 2 2001 Potl~ch Mr. Douglas Young A vista Utilities 1411 East Mission Spokane, Washington 99220 Potlatch Corporation Idaho Pulp and Paperboard Division 803 Mill Road O, Box 1126 Lewiston, Idaho 83501-1126 Telephone (208) 799-1561 Subject: Avoided Cost Calculation Dear l\1r. Young: Potlatch Corporation is in the process of detemlining the most beneficial way to sell the output from its generation facilities at the expiration of the CUITent contract betweenPotlatcJl and Avistaat the end of this year. One option is to sell Potlatch's generation to Avista UtilHies (Avista) atavoided cost. Therefore, we are requesting that A vista provide us with the avoided cost amountfor Potlatch's generation - the amount Avista will pay to avoid generating power or purchasingpower at market if it could instead obtain such power from Potlatch's facilities. It is oui 11llderstanding that the avoided cost methodology for projects larger 11lan one megawatthas been developed and is approved by the Idaho Public Utilities Commission (IPUC). Werequest 11mt A vista pelform all calculations, and fulfilJ all requirements, as described in 111eapproved calculation mefuodology. "It is also our understanding that the calculation meOlodologythat A vista is required to Use is described in Case No. IPC- 95-9. If this is not yourunderstandiIlg, please advise as to the metilodology Avista intends to use for calculatiIlg tileavoided cost and A vista s rationale for using an alternative metilOdology. The IPUC staff contends that, under the approved metllOclology, the utility is obligated to respondto a request for an avoided cost caJculation within 30 days. We would greatly appreciate an earlierresponse if possible. IPUC staffrecommeJJds a meeting between the developer (Potlatch) and Utility (Avista) to discuss details of the project and detaib of tl1e avoided cost calculation. It: is Potlatch 'sdesire to conductOtis meeting at your earliest convenience. Potlatch suggests J 0:00 a.m. October 12, 2001, inSpokane, Washington, as a potentia! date and time lor this ilJitial meeting. Per the approved cost calculatiOJl methodology we are providing jJJe foJlowiJlg information. The Developer is: Potlatch Corporation 60) West H.jversidt~ Ave. Suite 11 00 Spokane, WA 992lJJ roof of OF StatLl~,: Potbtch ha:; four (4) separate Qualified Filcilitie~~ QFID-J42-000 - A cogeneraUon lilciJity rated I 1 lltH kVA (iD 8 PFQH:3-J44-()/J0 - A cogeneration filcility rated J2 50n 1-:\1 A (q) 8 J'PQFID-JilJ-OOO - A cogeneratioll :facility rated 41 600 kVA (11) (J.8:; j)FOF92-((I-OOO - A cogeneraj.ion lilcili1,V ntteel (;6 91(, I\\lA 1(li O.~1'F ii, Exhibit 2 Case Nti. A Vll-()2-1H~ Direct Testimony of Dennis E. Pesenu ' ' Mr. Douglas Young October 2 2001 Page 2 Project location: Potlatch Corporation 803 Mill Road O. Box 1126 Lewiston, ID 83501 4. Project size, including ambient conditions for this rating: The project generating size based upon available steam to the four turbine generators is a maximum of 85 MW under alJ ambient conditions. Capacity factor and proposed time shape ofproduction: Potlatch will provide proposed capacity levels after our initial meeting. Fuel source and mode and route of delivery: A combination of wood waste, black liquor, and natural gas are used in variouscombinations to supply steam to power and recovery boilers. Wood waste is a by- product of on-site process production and is also delivered by truck. Black liquor is a by- product of the pulp-making process. Natural gas is delivered from various sources via a natural gas pipeline and then through Avista s distribution line. Whether fuel supply is firm or non-rum and whether there are any constraints affectingits availability or dependability: Wood waste and black liquor are dependent on process plant production. Natural gas is dependent on the availability of supply and appropriate transportation capability. The reliability of the plant generation is anticipated to be the san1e as historicalIydemonstrated. Proposed contract tenD (fmal term - length and tin1ing - to be subject to negotiations): The term is negotiable, but no less than five yem' On-line mOllth and year: This is an existulg facility that has sold part of its generation output to A vista under contract for nearly the past 10 years. This contract expires at 12:00 a., January 12002, making the above-referenced output available at that time. 10. Maintenance schedule: Maintenance schedule is determined by plant process maintenance. Historically, this has been scheduled in advance with Avista, and Potlatch proposes to use similar proceduresill the future. No difference is anticipated from what has been historically demonstrated. J 1. Other factor:; affecting operations: Operations are expected to remain the same as historicalJy demonstmted. J 2. Wheeling utility or utilities between point of interconnection and point of delivery: None. , - Mr. Douglas Young October 2, 2001 13. Expected delivery per months during heavy and light load hours: Delivery of energy is expected to be relatively constant over a 24-hour period, ashistorically demonstrated. 14. Guaranteed minimum capacity: The minimum capacity scenarios are described in item #5. Thank you for your anticipated prompt response to this request. Sincerely, POTLA TCH CORPORA nON Howard Ray EngineeringlProcess Control Manager Randy Lobb - IPUC Conley Ward, Esq. Page 3 ,.: ... Power Sale Key Assumptions Sale to A VA Ib January 2002 through December 2006 term GI 50 MVV flat II Potlatch carries reserves for sale fjl 7% (3.5% spin/3.5% non-spin) t' may require 2% spinning reserve requirement (will check with transmission group) ." where A V A carries reserves , value is less II financially-firm Ci Le., in hours where there is no generation , Potlatch will compensate theCompany at its cost of replacement power, including transmission to AVA's system lib if Potlatch will not guarantee deliveries , vaiue is substantially less Sale to J\I/arkel '" same terms as above iii requires purchase of J-\ \f A transmission, including losses, and reservesWI! approximately $3,1 .\ /iV/VVh , including EI. load 'following chE1.r~le '" price o'r losses increasE' EI.S -marlcet increaser:;t, translTli~siDn to other systerns not qUElntifiEJdIIJ wm iowa!" va.luE~ to Potlatch Exhibif 3 Ca!;c Nil. A Vll-02- Direct Tc!;timony of Dcnni, E. Pcscau Pr i c e F o r e c a s t s As s u m p t i o n s 10 / 1 2 / 2 0 0 1 F o r w a r d C u r v e s Ra t h d r u m Ra t h d r u m Mi d - C E l e c t r i c i t y Na t u r a l Mi d - C E l e c t r i c i t y Na t u r a l ' Mo n t h HL H LL H Fl a t Ga s Mo n t h HL H LL H Fl a t Ga s ($ / M W h ) ($ / M W h ) ($ / M W h ) ($ / d t h ) ($ / M W h ) ($ / M W h ) ($ / M W h ) ($ / d t h ) Ja n - 35 . 28 . 32 . 01 0 Ja n - 39 . 31 . 35 . 60 7 Fe b - 33 . 27 , 30 . 99 7 Fe b - 37 . 30 . 34 . 3. 4 9 3 Ma r - 30 . 24 . 27 . 4 2 93 7 Ma r - 33 . 26 . 30 . 4 7 36 1 Ap r - 28 . 22 . 4 0 25 . 82 9 Ap r - 31 . 24 . 28 . 4 3 19 1 Ma y - 25 , 20 . 22 . 85 4 Ma y - 27 . 22 . 25 . 19 1 Ju n - 0 2 29 . 23 . 4 0 26 . 89 8 Ju n - 0 6 32 . 26 . 29 . 22 3 Ju l - 40 . 32 . 36 . 93 6 Ju l - 44 . 4 4 35 . 40 . 27 3 P. u g - 48 . 38 . 4 0 43 . 97 2 Au g - 53 , 42 . 48 . 30 7 Se p - 43 . 34 . 39 . 96 7 Se p - 48 . 38 . 44 . 32 0 Oc t - 34 . 27 . 31 . 99 1 Oc t - 38 . 30 . 35 . 27 7 No v - 36 . 28 . 32 . 17 6 No v - 06 ' 40 . 32 . 36 . 3. 4 4 2 De c - 36 . 28 . 32 . 38 1 De e - 40 . 32 . 36 . 60 7 Av e r a g e 34 , 27 . 31 . 99 6 Av e r a g e 38 . 31 . 35 . 4 8 35 8 Tr a n s m i s s i o n Re s e r v e s $1 . 4 0 / k W - m o n t h , 3 % l o s s e s - $1 . 9S / M W h 5% / 3 . 5% / 2 . 0% s p i n / s u p p l e m e n t a l / l o a d f o f l o w i n g ~ $ 8 . 94 / k W - m o n t h - $ 1 . 14 / M W h Ba s e C a s e Po t l a t c h s e l l s o f f s y s t e m , p u r c h a s i n g l o s s e s , r e s e r v e s , a n d t r a n s m i s s i o n Av i s t a s e r v e s e n t i r e f o a d a t S c h e d u l e 2 5 r a t e s Fl a t S a f e C a s e Po t l a t c h s e l l s 5 0 M W ( f l a t , y e a r - a r o u n d , w i t h l i q u i d a t e d d a m a g e s ) a s P U R P A t o A V A Av i s t a s e r v e s e n t i r e l o a d a t S c h e d u l e 2 5 r a t e s $6 7 . 8 m i l l i o n p o r t f o l i o b e n e f i t & 2 18 9 , 54 0 M W h = $ 3 0 . 95 / M W h n e t v a l u e o f p o w e r 11 - 13 - 20 0 1 C a s e A s s u m p t i o n s . xf s c g k PR OSYMTM Market Simulation Engine ' - ~....'I"ere' . . ni'*~'M se,,;-0.1'0" "'" ,. ~1'7""'.L,,1,~.Ji".J\:,,--, so twa Business Solutions for Energy Supply Cha i n Management Electric markets worldwide are rapidly transforming from regulated industries to environments characterized by aggressive competition and customer choice. Wholesale energy is now sold, traded, and purchased as an unbundled commodity. Forecasting market-clearing prices, acquiring and scheduling supply resources in ' response to these prices, and developing a fundamental in-depth understanding of the market dynamics, are mission-critical tasks for any entity actively involved in the wholesale energy market. Henwood Energy Services, lnc, (Henwood) has developed a sUite of Business Solutions for energy supply chain management. Henwood's PROSYMTM product provides Price Forecasting, Generation Evaluation Generation Operations, Risk Analysis, and Portfolio Optimization functions. Product Description PROSYM performs a detailed fundamental simulation of the electric wholesale market on an hour-to-hour basis. Electric production is modeled at the generation unit level wIllie system loads and transmission constraints are modeled on an hourly basis, PROSYM computes market clearing prices and generation production for user-defined transmission zone(s). PROSYM reflects the specific market rules feir any regionthat is being modeled - whether it is the United Kingdom Australia Singapore, Alberta California anywhere else in the world. As a result of its extensive abilityto incorporate specific regional rules , PROSYM has up to an 80 percent market: share in deregulated markets worldwide. BenefitS ' PROSYl\1.:is: modelirig:S'Y:~solutioniii' ~~~~~ 10 mod1.l1~~X Henw6&L~# issues, Load & Generation Vs Market Clearing Price ,t:I. IIUIII :: :~~:~:~ :~r:::::::r::~::::~r:~ :: ::~::r::~::~y:~:~ :l~:~:~I ::~i '25 ~9 '13 nOliI' !17 121 1~5 -),...1 -),.",jC;.......H"..-MC)' 4/1912001. 11:45/1M Prollym.pG5 Detailed market simulations from one day to twenty years Advanced hourly commitnient ,and dispatch optimization Cost, bid, emission, or price-based dispatching capability Direct modeling of stochastic drivers and their correlations: forced outages energy market and reserve market prices, emission prices, fuel prices hydro energy and load Generating asset profit maximization in competitive markets Zonal market-clearing prices and congestion charges computed on an hourly basis Bid-based IID.rket simulations based on region-specific pool rules Zonal constraints such as minimum generation and muJtiple operating reserve criteria are enforced Detailed representation performance, cost, and constraint characteristics of physical and financial supply resources Direct modeling of significant chronological constraints such as ramp rates and minimum up and down times Fu el con tract andpipeline constraint optimization Direct modeling of start- up costs and lllel burn as a function of off-time 11/ Busines& ApplicatioI1S PROSYM perform~ detailed simulations of energy markets worldwide. It is used for forecasting wholesale electric prices, evaluating generation assets, energy transactions, and short-term unit commitment and dispatch decisions. PROSYM, in tandem with its supplemental modules, provides regional simulation capabilities unparalleled in the industry. These applications ' are critical a company IS: II Evaluating its competitive position and identifying attractive market opportunities II Considering the acquisition Dr divestiture of an electric generation asset and need to detennine the value of the asset under competitive market conditions Financing a major electric generation' investment in a competitive power market Performing stranded cost recovery evaluation Developing forward-price curves or generation operating budgets Forecasting energy, capacity and ancillary service prices Performing transaction evaluation, and transmission congestion analysis Evaluating regional emission impacts of generating facility additions 271.0 G:ltew3Y O~b Drive Suite 300N S"cramento,CA 95833 TeJ: (916) 569-0985 Eo::: (916) 569-0999 . j\tlmta .. Australia " London ,J..411912001,11:45AM Table" Potlatch Analysis Forward Curve Summary Average 2002 2003 Mid-NYIv1EX Mid-NYMEX Mid-NYMEXMonthHLHLLHFlatGasHLHLLHFlatGasHLI-!LLH Flat GasJan38.30.35,477 35.28.32.010 38.30.35.3.501Feb36.29.33.387 33,27.30.997 37.29,33.406Mar32.26.29.271 30.24.27.42 937 32.26.30,296Apr30.42 24.27.121 28.22.40 25,829 30.24.28.160May27.21.24.127 25.20.22,854 27.48 21.25.170Jun31.25.42 29.161 29.23.40 26.898 32,25.29.200Jul43.46 34.39.202 40.32.36.56 936 43.35,40.226Aug52.41.47.234 48.38.40 43.972 52.42.48,252Sep47.37.43.237 43.34.39.967 47.38.43,252Oct37.48 29.34.26 227 34.27.31.53 991 37.30.34.265Nav39.31.35.372 36.28.32.39,31.36,439Dee39.31.35,3.545 36.28.32.381 39.31.36.601 2004 2005 2006 Mid-NYMEX Mid-NYMEX Mid-NYMEXMonthHLHLLI-!Flat Gas HLH LLH Flat Gas HLH LLH Flat GasJan39.35,661 39.31,35.607 39:17 31.35.607Feb37.30.34.546 37.30,34.493 37,30.34.3.493\\liar 33.26.30.47 399 33.26.30.47 361 33.26.30.36"Apr 31,24.28.234 31.24,28.43 191 31.1"1 24.28.43 19"May 27.22.25.229 27,22.25.191 27.22.25.191Jun32.26.29.261 32.26,29.223 32..26.29,223luj44.44 35.40.301 44,35.40.273 44.35.40,273Aug53,42,48.334 53.42..48.3307 53.42.48,307Sep48,38.4-4:18 328 48.38,44,320 48.38,67'44.320Oct38.30.35,326 38.30.35,277 38.30,35,277I\/ov 40,32.36.56 362 40,32.36.3.442 40.32.36.3.442Dee40,32.36.3.527 40.32,()0 36,607 40.32.36,607 Po t l a t c h . da t 10 - 19 - 20 0 ! X X X X Y - X X X YJ " l'. x x x X Y ,y J , , 1 ' -X X xx x x x X x Y . x x x X X X X X XX X X X X X X X X X X X X X y.x x X XX X X X XX X X X X X X Y J " XX X X X X X X X X X X X X X X X X X X X X X xx x x x x XX X X X xx X X X xx X X X xx X X ! y . x x X X X X X X X X X X X X X Y . x x x x x X X X X X X X Y J " X X X X X X X X X X X X Y . x x x XX X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X X X X X xx X X X X X X X X X X X X X X XX X X X X X X xx x x x X X X X X ! X X X X X X X X x : " . 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' Q C X X X X X X X X X Y . x X X X X X X X X X X y.x x x XX X X X X X XX X X X X X X X X X X X X X X X X X X X X X ! ; ~ X X XX X X X X X XY . . x x y . x x x x x x x XX X X X X X X l ' -X Y . x x Y . x XX XX X X X X X X X XX X X X X Y . x X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X x ; e x X X ! X Y J " xx y . x X Y, x x x x XX X X X X i f . . x x x y . x x x . . xx x x x x x x X x YJ J . x x 1'. . x x x x X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X XX X X X X X XX X XX X X X X X y . x x y . x X XX X X X X X X X X X X X 24 - ST A T I o n s SE C T I O N ' ! y . x X XX y . x x x XX X X y.. x x x x XX X X X X Y J " X x y . x x x XX X X X X X X X X X X X Y . x X X X X X X X X X X X X X X X X X X X X X X X X y.x XX X y . x X X X X X y . x X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X X Po t l a t c h C o n t r a c t s y. x x Y J J C X X X X Y ~ X X xy ~ v.x x XX X X y . x X X X X X X X X X X X X X X Y . x x x x x x Xl ' . x x x Y J " y . x X X X X X X X X X X X X XX X X X X X X X X X X X X X X X XX XX XX X X X X X x xy . : x x X X X X X X X X X X X X X X X X X X X Po t 1 a t c h . L o a d St a t i o n G r o u p Sp i n S t a t u s Ca p a c i t y H 2 X Pr i c e Ca r o m i t Lo a d b i a s e r Po t l a t c h . P U R P A St a t i o n G r o u p Sp i n S t a t u s Ca p E c i t y M a x Co m m i t Lo 2 . d b i a s e r Po t l a t c h 31 . 9 ! A p p r o x i m a t e s S c h . 2 5 WiD Su r c h a r g e Po t l a t c h !' o t l a t c h . da t 10 - 19 - 20 G ! x x . X X X X Y J a X Y ~ XX X Y J i Y - . X X X Y . x y. x x . . 'i X X X X X X XX X X X X X X X X X X X X X X X X X X X X X X X y. x x x X X x X X Y . x x X : X X Y . x x x X X X X X X X XX X X X X X X X X X X X X X X X X X X X X X X X X X X X X X ! X X X X X X J f .. x x x Y . x x x x x x x x x x x x x x J D C X X X X X X XX X X X X Y .x x x x x x x x x x x x x Y . x x x XY . x Y . x X X Y .. . x x x x x x x X X XX X X X X X X X X X X XX X X X X X X X X X X X X X X X X X X X X X X X X X X X ! X X X Y.. Y . x y eX x x x x . . ' D C X X X X X X X X l ' , XX X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X XX X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X Av i s t a C o r p o r a t i o n Sy s t e m S t u d y CO N F I D E N T I ~ L MT I J P R O P R I E T A R Y - N O T F O R D I S T R I B U T I O N PR O S T I 1 Ch r o n o l o g i c a l p r o d u c t i o n H o d e l i n g S y s t e m NO P O T L A T C H SC ~ f ~ ~ I O 31 - ! x y . x X l ' .. x x x X X . . x x x x . v. . x x x x x x x x x . , ' C X X X X X X xx x x x x x : x x x x x x x XX X X X X X X X X X X X X Y . x x x X : X X X X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X XX X X X X X X X XX X X X Y J . x . x x x l ' -x x y . . . x y . x X X X X X X X X X X X X X X X Y . x x 2 ' . . x x x y. x x x x x x x x x x x X X X X X X X X X Y . x x X : X XX X X X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X X X X X X X X X X X XX X X X X X X X ! X X X X X X X X X X X X X X X X X X X X 1 ' . x x X X X X X X X X X X X X X X XX X X X X X X X X X X X X X X X XX X X X X X x x y . x X X X X X X X X X X X X X X X X X X X X XX X X X X X X X X xx x x x x x x x x X XX X X X X X X ST A T I O N S S E C T I O N ! X X X X X X X X X 1 O ' . x x x . . . . "X X X . . ' i X X X X X X X X X X X X X xx x y . . x x x x x x x x x x x x x X X X x x x y . . x x x x x x x x x x XX X X X X X X X X X X X X X X X X X X X X y . x X X X X X X X X X X X y . x X X XX X X X X X y.x XX X X X Po t l a t c h C o n t r a c t s ! X l ' . . x x x . . . X X X xx x x x x x x y . x x x x x x x x x x x : x x " . . x x y . x x x x x x x x x y . x X XX X X x x x x x x x y . x XX X X X x x y . x x X X X X X X X X X X X X X X X X X X X X X X X X X X y . x x X X X X X X X X X X X X X X X X X X X Po t l a t c h . L o a d St a t i o n G r o u p Sp i n S t a t u s Ca p a c i ty H a . . ' C Pr i c e Co I T I ! I I i t Lo a d b i a s e r po t l a t c h , 4R e s a l e St a t i o n G r o u p Sp i n S t a t u s . Ca p a c i t y l - f a x Co r o m ! t Lo a d b i a s e r Po t l a t c h . R e s a l e St a t i o n G r o u p Sp i n S t a t u s . C a p a c i t y ! 1 a x Pr i c e Co I T l ! l l i t Lo a d b i a s e r Po t l a t c h 31 . 9 Po t l a t c h 48 . Po t l a t c h 48 . ! A p p r o x i m a t e s S c h . 2 5 wl o Su r c h a r g e ! A p p r o x i m a t e s T r a n s c h a r g e s , i n c l u d i n g r e s e r v e s a n d l o s s e s Avista Corporation 1411 East Mission P.O. Box3727. Spokane Washington 99220,3727 Telephone 509;489-0500 . Toll Free 800-727-9170 ~1'!'iOI".'r"T_. ,nUlif' f,;;~ Corp. November 14 , 2001 Jean D. Jewell, Secretary Idaho Public Utilities Commission 472 West Washington Street Boise, ill 83702 RE:Order No. 28884 , Case No. A VU-01-, Compliance Filing Dear Ms. Jewell: On April 27, 2001, Avista Utilities filed its 2001 Integrated Resource Plan (IRP) with the Idaho Public Utilities Commission (Commission), On October 24 2001 the Commissionissued its "Acceptance of Filing with Order N.D. 28884. On July 12 , 2000 Avista prepared an update to its 1997 IRP to include known and significant changes. This updated IRP served as the basis for a Request-FoT-Proposals(RFP), which was issued on August 14, 2000. The updated 1997 ffiP and the 2000 RFPincluded significant input from both the Idaho and Washington Col1lIIrission Staffs. The2001 IRP was a more fonnaI report to support and report on the 2000 RFP activities. Atthat time, because no agreement had been reached with Potlatch, their total load was notincJuded in either the updated 1997 IRP or the 2001 IRP after January 1 2002 , when theirlO-year contract ended with A vista. Although the total load was not included, a smalJincremental load in excess of Potlatch's generation and inteITuptiblc purchases was included. A vista also believes , along with the Commission staff, tllat the IRP process provides avaluable tool to botb Avista ~md the. Cormnission by providing additional communication& between the company and other public e:ntitie&. Under Order No. 28884 the Commission required A vista to submit a revisedloadJresource balance schedulel; that would include the. addition of know)') new generating resourcel; and the load relating to Potlatch's Lewiston facility. Please find attached the loi:lclJresoLlrce~ tabulation dated November 5 2001 to meet that requirement. The. differences between the annual load/resource::: tabulation , dated January 2LI 2001 :I"Dunc1 in Appendix K of the 20m my and the CLJnent Joad/rermLlfce tabulation dated November 5 2001 are m: follo\;vs: Exhibij -'1 CfI!;e Nu. A Vtl-O2- Direct Testinwny of Dennis E. I'eseall 1. System Load- the CUITent load numbers reflect the new load forecast completed by the company in July 2001 , which had a decrease in forecasted loads due to the current economic conditions in its service territory. Then Potlatch loads were added andwere assumed to be 110 MW peak and 93 aMW annual energy. 2. PacifiCorp sale was increased 3aM'W to reflect their option to increase the summerdelivery tenn one additional month. 3. BPA- WNP #3 current numbers showed delivery and receipt of energy but the net effect of 10 aMW was the same. 4. Nichols Pumping showed a continuation of that load but only the 3ll1ount to cover A vista s share of the pumping load at Colstrip. 5. Reserves were adjusted to reflect the changes in the forecasted peak loads, 6. Hydro numbers were adjusted to reflect the numbers in the most recent Northwest Power Pool regulation studies (2001-02). Canadian Entitlement Return numberswere changed to match the information from BP A. Contract Hydro numbers startingin 2005 were increased to reflect the proposed Priest Rapids and Wanapum contract extensions. 7. Small Power energy figure was increased 1 MW to reflect updated information, 8, Northeast and Rathdrum CT's peak capability was reduced to better match historical operating capabilities and the energy reflects the average of monthly generation required to meet load. 9. Kettle Falls CT and Boulder Parle generation was added. 10. BPA Residential Exchange shows no peak or energy due to the fact that the company has decided to receive cash payments in lieu of power. 11. Kettle Falls energy was decreased 3 aM'W to reflect actual operating characteristics. 12, Colstrip energy was decreasedl aM'W to reflect actual operating characteristics, andthe energy in year 2002 was further reduced to account for increased maintenance outages for that year. 13. Coyote Springs n generation for 50% of the plant output was added. Any questions on this compliance filing should be directed to: Douglas Young . Contracts and Resource Administrator A vista Utilities O. Box 3727 Spokane, W A 99220 Phone: (509) 495-4521 Sincerely, ~??! Vice President, Power Supply n. . . . - -- - - - , . ' - - - ' . 11 - 05 - 20 0 1 AV I S T A C O R P . Re q u I r e m e n t s e n d R e s o u r c e s li g u r e s i n M W ( c r i t i c a l w a t e r ) 20 0 2 20 0 3 20 0 4 20 0 5 20 0 6 20 0 7 20 0 8 20 0 9 20 1 0 20 1 1 Un e N o . R E Q U I R E / I ' I E I H S Av g Av g Av g Av g Av g Av g Av g Av g Av g Av g Sy s t e m L o a d 15 8 4 98 S IS 1 2 10 0 S 1S S 5 10 4 0 17 2 6 10 7 9 )7 7 6 11 0 9 18 2 6 11 4 2 18 6 4 11 7 7 19 4 6 12 1 5 20 0 3 12 5 1 20 5 7 12 8 5 Pa c l f i C o r p E x c h a n g e Pu g e ! # 2 Pa c i H C o r p 1 9 9 4 PG E # 1 15 0 15 0 15 0 1~ 0 15 0 15 0 15 0 15 0 15 0 15 0 BP A . Wr ' J P # 3 . 3 2 Ni c h o l s P u m p i n g . 8 Re s e r v e s 24 8 25 1 25 6 26 3 26 8 27 3 27 8 26 5 29 0 29 6 TO T A L R E Q U I R E M E N T S 20 1 6 10 5 9 20 1 4 10 5 4 20 7 2 10 7 3 21 4 2 11 1 2 21 9 5 11 4 2 22 5 2 11 7 5 23 1 3 12 1 0 23 8 2 12 4 8 24 4 4 12 8 4 25 0 4 13 1 8 -- - - " " RE S O U R C E S Sy s t e m H , ' d r o 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 97 3 32 0 Co n t r a c t H y d r o 19 6 19 6 19 6 19 6 18 1 17 8 17 5 17 5 17 3 17 0 Ca n E n l R e t u m Sm a l l P o w e r l U p r i v e r :: " ' No r t h e a s t C T s 11 , 59 . Ke l t l e F a l l s C T Bo u l d e r P a r k - . 1 7 Ra l h d r u m C T s 16 4 , 11 2 16 4 16 4 10 9 . 16 4 11 6 16 4 12 5 16 4 12 8 16 4 11 6 16 4 13 0 16 4 13 2 16 4 13 5 SE M P R A Pa c i f i C o r p E x c h a n g e En t i t l e m e n t & S u p p l e m e n t a l SP A R e s , E x c h a n g e BP A , WN P # 3 CS P E T r a n s A l l a . Ce n l r a l i a 20 0 14 3 . 20 0 14 3 Th e r m a l . 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