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HomeMy WebLinkAbout20040622Hessing Direct.pdf"\ r- c~..I tj "1/ ~ FiLED 'inn! n n.l t') "~ i". ".", "'.:!i; '.' I'rl oJ\.. \! "'" n 'O d U UTIL iifES cl~'~SlOt1 BEFORE THE IDAHO PUBLIC UTiliTIES COMMISSION IN THE MATTER OF THE APPLICATION OF A VISTA CORPORATION FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC AND NA TU RAl GAS SERVICE TO ELECTRIC AND NATURAL GAS CUSTOMERS IN THE STATE OF IDAHO. ) CASE NO. AVU-O4-) AVU-O4- DIRECT TESTIMONY OF KEITH HESSING IDAHO PUBLIC UTiliTIES COMMISSION JUNE 21 , 2004 Please state you~ name and business address for the record. My name is Kei th D. Hessing and my business address is 472 West Washington Street, Boise, Idaho. By whom are you employed and in what capaci ty? I am employed by the Idaho Public Utilities Commission as a Public Utilities Engineer. What is your educational and experience background? I am a Registered Professional Engineer in the State of Idaho.I received a Bachelor of Science Degree in Civil Engineering from the Uni versi ty of Idaho in 1974.Since then, I worked six years for the Idaho Department of Water Resources, and two years for Morrison-Knudsen.I have been continuously employed the Commission since August 1983. As a member of the Commission Staff , my prlmary areas of responsibility have been electric utility power supply, revenue allocation and rate design. What is the purpose of your testimony in this proceeding? My testimony discusses electric issues including Jurisdictional Separations, Class Cost of Service and PCA issues including Deal ~An and Deal ~ CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF gas purchase issues carried into this case from Case No. AVU-03-6 by Commission Order No. 29377.I al so propose a change in PCA methodology.My testimony concludes with a brief discussion of average rate changes for each customer class and an exhibit showing the overall effects of Staff's rate proposal. Please summarize your testimony. I recommend that the Commission accept the Jurisdictional Separation study proposed by the Company. I also recommend that the Class Cost of Service methodology proposed by Avista be accepted by the Commission.I provide Cost of Service resul ts, that include Staff's accounting adjustments, to Staff witness Schunke which he uses as the starting point in allocating revenue requirement to the various customer classes. I recommend that the Commission accept the Company s calculation of base power supply costs for use in future PCA calculations.I recommend that losses on the purchase and subsequent sale of Deal ~Bn gas in the amount of $6,496,669 not be charged to customers.I al propose a reduction in PCA rates. I propose that the PCA rate design methodology be changed once the current deferral balance is eliminated.Currently increases and decreases are spread to customer classes based on each class CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESSING, K (Di) STAFF percentage of total revenue and recovered in the energy charge for each class.I propose that PCA increases and decreases be surcharged or rebated to customers on the basis of energy consumption.My proposal would apply an equal cents per kWh rate to all customer classes except lighting classes which would receive the average percentage lncrease or decrease. My testimony concludes with an exhibit showing the combined average revenue changes for each customer class caused by Staff's base rate proposal, DSM Rider rate proposal and PCA rate change proposal.The overall net electric increase proposed by Staff is 2.4%. JURISDICTIONAL SEPARATIONS AND CLASS COST OF SERVICE What Jurisdictional Separation and Class Cost of Service methodology is used by the Company? The Company applied the same Jurisdictional Separation methodology accepted by the Commission in its last general rate case, Case No. WWP-E- 98 -11.The methodology directly assigns revenues, costs and investment to jurisdictions where appropriate and allocates the remaining amounts.The methodology uses 2002 test year booked amounts without adjustment.All adjustments are included on an Idaho System basis at the beginning of the Cost of Service process. The Company used the same Peak Credit Cost CASE NOS. AVU-E- 04 -1/AVU-G- 04-06/21/04 HESSING, K (Di) STAFF of Service methodology that it used in its last general rate case with minor modifications.The Commi s s ion accepted that methodology as the starting point for revenue allocation in that case.Staff proposes only an incremental move toward full cost of service in recognition of the fact that cost of serVlce results are not precise and unacceptably large increases to some classes would occur.Staff witness Schunke discusses revenue allocation to the various customer classes in his testimony. Is there value in applying consistent Jurisdictional Separation and Class Cost of Service methodology from case to case? Yes, there is.It allows the usage and customer characteristics that form the allocators and the accounting data to drive the resul ts.There are substantial changes caused by these factors wi thout changing the methodology. Does the Staff accept the methodology and allocation factors used by the Company in its filing? Yes. Have you prepared an exhibi t that shows the Class Cost of Service resul ts that have been used as the starting point for revenue allocation in Staff's case? Yes, I have.Staff Exhibit No. 138 shows CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF Class Cost of Service resul ts based on a total revenue requirement of $169,326,876 which is a $23,078,876, 15.78% increase above existing base rates.This information was provided to Staff witness Schunke for revenue allocation purposes. PCA ISSUES Deal "A" and Deal " Please summarize the Deal ~An and Deal ~ lssue carried into this case by Commission Order No. 29377 from Case No. AVU-03-6, which was the Company last PCA case. In March 2001 , Avista Utilities purchased gas at index to operate its gas-fired resources for the purpose of producing electrici ty.Deal ~An deliveries were for 27 658 dth/day for a 36-month period beginning November 1, 2001.Deal ~Bn deliveries were 20,000 dth/day for a 17-month period beginning June 1 2002. Total Deal ~An and Deal ~Bn purchases were exactly the quanti ty of gas required to run the Coyote Springs 2 CCCT at its full generating capacity of 280 MW. In April and May of 2001 , using 4 separate transactions, the Company fixed the price, using hedges, for 40,000 dth/day, which is 84 percent of the gas.The hedged price averaged approximately $6.00 per decatherm. The other 16 percent of the gas remained at index.The CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESSING, K (Di) STAFF Company s Confidential Exhibit 7 , Schedule 16, summarlzes the Deal ~An and ~Bn transactions. When the various gas price hedges were established , electric forward market prices were high and if the electric prices would have persisted in real time a number of good things could have happened to the Company and its customers using the fixed price gas. discuss those later in this testimony.However, between the time that the price was fixed and the time the gas supplies were to be delivered, electric and gas market prices dropped precipi tously.After this happened, the best plan for the Company and its customers was to sell the gas at a loss and purchase the Company s electric needs from the wholesale electric market each month.The Company had losses on Deal ~An and Deal Bn which it proposed to include in the PCA.The PCA would have passed 90% of the losses for the Idaho jurisdiction on to customers while the Company s shareholders would have been responsible for the other 10%.In its comments in the referenced case , Staff proposed that only Deal ~ losses be excluded from PCA treatment and recovery from ratepayers.In its final order in that case, the Commission did not rule on the issue but required that both Deal ~An and Deal ~Bn losses be examined in more detai I in thi s proceeding.Staff Exhibi t No. 139 is a CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF copy of the Staff Comments filed in Case No. AVU-03- The detailed discussion of Deal ~An and Bn begins on page 6.An understanding of the referenced comments and testimony is essential to full understanding of the Deal An and ~Bn issues in this case. Please summarize Staff's conclusions in that case. With regard to the Company s Energy Resources Risk Policy, the Staff concluded that Deal ~ purchases violated risk policy provisions.Al so, Deal Bn price hedges were entered into with Avista Energy (AE) , an unregulated affiliate of the regulated utility. Staff concluded that appropriate safeguards were not place or followed to protect customers when the regulated utility does business with its affiliate.Safeguards could include a proper Code of Conduct or a requirement for lower-of -cost or market pricing.The Staff also concluded that the Company took unusual risks when hedging the price for the length of these gas purchase deals for its electric customers.Similar risks were not taken for its natural gas customers. What has changed with regard to Deal ~An and Bn purchases since the Staff filed its comments in the last PCA case? Several months have passed and the time CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF frame for gas delivery under Deal ~Bn is over.It ended at the end of October 2003.In the last few months of the deal, Avista sold some of the gas at a loss but burned some of the Deal ~Bn gas profitably. Has Staff's position changed since its PCA filing? No, but Staff does recognlze that some Deal Bn gas has since been burned profitably.It is only fair that the savings on the price of the gas when the market is above $6.00 be netted against losses when the market is below $6.00.Staff's position in this case that the net of Deal ~Bn profits and losses, net losses, should not be included in the PCA. Does the Company s filing in this case address the concerns that Staff raised in its filed comments in Case No. AVU-03- Only partially.In his testimony, Company witness Lafferty presents and discusses Deal ~An and Deal Bn purchases from a longer-term , resource planning, point of view instead of the near term, risk policy, point of view presented by Staff in its previously referenced PCA comments. Please discuss some of the differences in the two approaches. The risk policy perspective Vlews resource CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESSING, K (Di) STAFF decisions for the coming 18 -month period.This process initially assumes normal load and resource conditions and updates both based on forecasts as they become available. Forecasts become more accurate as they near real time. The policy includes written rules and maximum long and short position limits that vary based on the period of time remaining before energy lS needed, real time. general the Company' s ~position n is the difference between expected loads and expected resources. The long-term planning view presumably guides resource decisions that are made for periods further than 18 months out.It assumes cri tical water conditions resulting in approximately 150 average MW' less available generation than under normal water condi t ions.Eighteen months out from real time , where the planning criteria time period and operating criteria time period meet, loads and resources that are perfectly balanced based on the long-term critical water planning criteria result in an approximate 150 MW long position under the risk policy review criteria because the risk policy is based on normal water condition assumptions. Eighteen months out, the long limit allowed in the risk management plan is 150 MW above normal water conditions. Therefore, the Company would move into the risk policy analysis period with the largest amount of extra CASE NOS. AVU-E- 04 -1/AVU-G- 04-06/21/04 HESSING, K (Di) STAFF resources that the plan allows.Of course, if the Company is just a little long based on long-term critical water planning criteria, it transitions into the risk policy period above the established limits and would immediately have to sell energy to get below the long limit contained in the Company s Risk Policy. Does Company witness Lafferty suggest that there are concerns, other than cri tical water , that the Company should be allowed to consider when it purchases fuel for its gas fired resources? In addition to water conditions Mr.Yes. Lafferty suggests that loads and outages should also be considered.He states that actual loads could be higher than expected by 87 MW and that a unit outage at Colstrip could reduce generating capability by 100 MW.Pg. 4 3 ) Does it make sense to purchase energy or fixed price fuel to produce energy for 300+ MW of unusual def iciencies? No, not before the deficiencies become known.The chances of all three events occurrlng together are extremely improbable. Is it reasonable to have some energy reserve to address these types of deficiency causing events they do occur? Yes, it is.The Company s risk policy very CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF specifically provides for this by establishing a long limi t of 150 MW.The Company s Risk Policy says, Reasons to maintain long positions may include strategies to mitigate potential negative impacts of unplanned loss of resources, adverse changes in hydro conditions, or adverse impacts of load variations as compared to the forecastn (Exhibit 139, Energy Resources Risk Policy, Attachment J, Pgs. 3 and 4 of 15) Do the differing perspectives concerning appropriate reVlew cri teria cause the Company and Staff to reach different conclusions? I think so.The long-term perspective used by the Company to justify these transactions is very different than the Company s near term risk policy perspective used by the Staff. How are the Deal ~An and ~Bn purchases initially positioned relative to the 18-month transition point between the long-term and short-term analytical approaches? As indicated in Staff comments in the last PCA case, both purchases were ongoing at the 18 -month transition point which was about October 2002. Why does Staff utilize the Company shorter-term risk policy method of analysis to evaluate the merits of the gas transactions? CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF The Energy Resources Risk Policy is written and well defined.It is designed to address the very situations that the Company says could occur.The Resource planning process that Staff is familiar with, the Integrated Resource Planning (IRP) process, does not incl ude cri teria for acquiring energy or gas to produce energy which is the issue being addressed here. Was the Company using a long-term planning process like the one discussed in its testimony and used to justify its long out-of-limit position before the Deal An and Bn gas purchases? I f the Company was using it's long termNo. resource acquisition plan , its resource positions would have been long, probably even long out of limits in its Position Reports.As shown on the Company s Posi tion Limit Chart for March 7 , 2001 (Exhibit No. 139, Confidential Attachment K , pg. 1), the load resource balance is short coming into the 18 month planning period and remains short or minimally long, 35 MW maximum , for the entire period.This report reflects the Company position just prior to Deal ~An and ~Bn transactions. This is not consistent with the long-term acquisition process the Company says it uses. In Staff's previously mentioned PCA comments, Staff pointed out that Avista s gas operations CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF did not make the same kind of long-term purchases for its gas customers in early 2001.What information do you have that supports this position? Staff Exhibit No. 140 was provided by the Company in response to Staff Production Request No.2 7 . The Exhibit shows that in early 2001 the Company did not purchase gas two and three years into .the future for its gas customers.The fact that the Company failed to purchase gas with the same kind of long-term deals for its gas customers that it did for its electric customers demonstrates the Company s inconsistency.If long-term gas purchases were expected to be beneficial to the electric utility, why would they have not been expected to be beneficial to the gas utility?Staff Exhibit No. 140 shows that in the same time frame, the Company rarely purchased gas for its gas customers at Deal ~An or ~ prices and never made fixed price purchases for use more than two years in the future. In its PCA comments the Staff discussed the hedge transactions between Avista Utilities and Avista Energy (AE) that fixed the gas cost for Deal Bn in April and May of 2001.Do you have anything further to add to that discussion? When the gas cost was fixed withYes. Avista Energy, both AE and the utility along with its CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF customers were exposed to risk.AE's risk was that gas prices would go up and that when it needed gas for delivery it would be more costly. The utility was exposed to several types of risk.It had the risk that gas prices would go down and gas would cost less when it was needed.The utility also had the risk that electric and gas prices would go down such that the gas could not be economically used to produce electricity and the gas would have to be sold a loss.Of course, through the PCA 90% of any loss would be recovered from customers.This created a si tuation where one affiliate essentially bet against the other affiliate.One was going to prof i t and one was going to pay and because of the PCA, Avista shareholders were substantially protected from paying.Because the deal with AE was not provided to Avista Utilities at cost, AE had the opportunity to profit by keeping the difference between the actual cost and fixed price of gas sold to the regulated utility.In fact a counter party such as AE would not have made the deal if it did not expect to profi t.In the end, AE profited and the regulated utility is proposing that its customers pay 90% of the costs.If AE chose not to hedge its risks on the transactions , it profited by the difference between actual and fixed price.In the end regulated utility CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESSING, K (Di) STAFF shareholders paid 10% of the AE profit and utility ratepayers paid the other 90% of AE's profi t.It is Staff's position that whether AE profi ted or not, Deal Bn was not at the lower-of-cost or market and, therefore, constituted an inappropriate affiliate transaction.Staff's Deal ~Bn proposal in this case, that net losses on the gas sales should not be allowed in the PCA , amounts to giving the customer the bet ter deal, cost or market. Why does Staff propose to disallow Deal ~ loss recovery and accept Deal ~An loss recovery? Deal ~An hedges were not done with an Avista affiliate, but Deal ~Bn hedges were.Also, the Deal ~ gas purchase did not put the Company over the long I imi t contained in it's Risk Policy, the Deal Bn purchase which was executed at a later point in time caused the utility to exceed the long limit.Not only did the transaction place Avista above the long limit, but Avista s position continued to stay above the limit. Has the information provided by the Company changed Staff's position regarding disallowance of Deal Bn net losses from PCA treatment? It remains Staff's position that netNo. losses on the sale of Deal ~Bn gas should not be included in the PCA. CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESS ING, (Di) STAFF What is the basis for this conclusion? It is Staff's position that the Company violated both the intent and the written requirements of its own Energy Resources Risk Policy.The Company purchased gas for electric generation that exceeded the limits allowed by the policy, then fixed the price which created a speculative posi tion that led to the losses. Also in executing the Deal ~Bn price hedges with its unregulated affiliate, Avista Energy, the Company created a potential conflict of interest.In order to avoid potential abuse or even the appearance of abuse, the Company needs to provide its customers with the best deal by recording the transaction at the lower-of -cost or market absent other specific rules established to protect customers.Staff believes that it was extremely risky to lock the price of gas at a traditionally high price in gas market with prices falling even though forward electric prlces were high. What other reasons could have caused the Company to take the risks that it took in the Deal ~ and ~Bn purchases? Avista needed the Coyote Springs 2 plant to reduce its dependence on what had become a highly volatile energy market.Coyote Springs 2 was to be one of the most efficient combined cycle gas-fired combustion CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF turbines in the reglon with a 7 000 BTU/kWh heat rate. Avista was financially stressed and needed to obtain a gas supply in order to secure financing for the proj ect. Deal ~An provided the necessary gas transportation along wi th gas supply.If electric prices held at or near the forward level at the time of the Deal ~An and ~Bn hedges, the operation of CS 2 would have been profitable.Power needed by customers could be generated at a cost below the market price.If the Company was long on supply, it could generate power and sell the power for profit.Ten percent of the prof it would go to shareholders, whi Ie 90 percent of the prof it would go to the PCA to buy down PCA balances and reduce customer rates. This philosophy could have worked if the electric sale of the long energy had also been made the same time to lock in the gain and reduce the long posi tion.Absent such an electric power sale, the transaction was purely speculation. Al so, if all had gone according to the Company s plan , Coyote Springs 2 would have been demonstrated to be used and useful and therefore, easily rate based. The Company fixed the gas prlces for 84% of the Deal ~An and ~Bn gas.Could Avista have fixed electric forward prices as well? CASE NOS. AVU-04-1/AVU-04- 06/21/04 HESSING, K (Di) STAFF Yes, but the cost may have been substantial and may have reduced or eliminated the expected profits. If the cost of fixing the electric forward prlces was high or prohibi ti ve, what would this tell Avista about the risk of the transaction? If the parties who sell this type of financial instrument wanted a high premium to fix the forward price of electricity they obviously believed that there was a great deal of risk in selling forward at a fixed prlce.If there is a great deal of risk that forward electric prices would be lower than forecast , the Company should have chosen shorter term less risky deals that would have captured the benefi ts of layering or dollar cost averaging.Again as previously stated, absent electric sale transactions this acti vi ty was based on speculation.Customers should not pay for Avista to speculate. In two different places in his testimony, Company witness Lafferty characterizes Staff's proposal that electric forward prices could have been hedged along with gas prices as ~retrospective (pg. 47) or ~after the factn (pg. 51) views.Would you please comment. It is a common practice in the energy business to capture the benefits of a deal by locking in all prices.It requires no hindsight to see the CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF advantages of so doing in the Deal ~An and ~ transactions.By not locking the electric forward prlces in these transactions the Company gambled that electric prices would not decline substantially.The Company lost on that gamble.As stated previously, customers should not pay for speculation or a gamble. What amount does Staff recommend be removed from the PCA deferral account to reflect Deal ~Bn losses? Deal ~Bn losses are calculated on Staff Confidential Exhibit No. 141.The bottom line shows that 90% of Idaho jurisdictional losses on Deal ~Bn that have been deferred for recovery are $6 496,669.This is the amount that Staff recommends be removed from the PCA deferral account. Does Staff Exhibit No. 141 also show the Deal ~An losses that Staff is not proposing to remove from PCA treatment? Ninety percent of the IdahoYes. jurisdictional share of Deal ~An losses are shown to be $8,677 766. Upda ted PCA Components Are base PCA net power supply costs to be updated as a resul t of this general rate case? Staff proposes that base power supplyYes. costs be updated as a resul t of this case.The Company CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF proposed the same.Company wi tness Johnson shows the new base amounts on Exhibi 10, Schedule What are base power supply costs used for in the PCA? The PCA calculates the difference between actual and authorized base Idaho jurisdictional power supply costs and, after appropriate sharing and a load change revenue adjustment, defers the difference for later recovery or rebate. Does Staff support the base amounts proposed by the Company as shown in Company wi tness Johnson Exhibi t 10, Schedule 4? Yes. Is there another PCA component that the Company proposes to update in this case? In his testimony, Company wi tnessYes. Johnson proposes to update the load change revenue adj ustment mul tiplier. What change is proposed in the mul tiplier? The Company proposes that the multiplier be changed from 21.23 $/MWh to 36.38 $/MWh. How is the multiplier used? The multiplier is the average annual variable power supply cost of meeting new load as determined from the Company s power supply model.It is CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF multiplied times the difference between base and actual loads to determine the cost of load changes that occur and accrue in the PCA.The resul ting cost is used to adjust the power supply cost deferral for changes in power supply costs associated with load growth or decline.By removing this resul ting amount from the PCA calculation, power supply costs associated wi th load change are reserved for consideration in general rate cases. Does Staff agree wi th the Company calculation of the load change revenue adjustment mul tiplier. Yes. PCA Rate Reduction Does the Company recommend a reduct ion in current PCA rates? In its filing the Company estimated aYes. deferral balance of approximately $23 million at the end of September 2004.The Company proposes to implement reduced PCA rates in this case designed to recover $11. million of the estimated balance each year for two years. What is Staff's PCA rate proposal? Staff proposes to reduce the Company actual end of May 2004 balance of $26,261 334 by $ 6, 496, 669 in Deal Bn losses and calculate rates to CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF recover the remalnlng balance over 2 years.This reduces the PCA revenue requirement by $17 963,835 per year. Staff believes it is more appropriate to use actual amounts than estimates even though the PCA trues the amounts up to actual. Other PCA Matters Does Staff propose a change in the PCA mechanism? Staff proposes to change the way ratesYes. are calculated in the PCA mechanism once the current PCA deferral balance is eliminated.The current PCA mechanism assigns class revenue responsibili ty based on a uniform percentage of revenue spread to each class and then assigns recovery to the energy portion of the rate wi thin each class.Staff proposes that PCA costs be recovered from Avista ratepayers on a uniform cents per kWh basis. The PCA rate would be the same for all schedules except lighting schedules.Lighting schedules would pay/receive the Idaho average increase/decrease. Why should this change be made? The allocation of PCA costs to individual rate classes based on a percentage of total revenue assumes and relies on a mix of fixed and variable costs like those allocated to each customer class through the Cost of Service process.Above or below normal power CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF supply costs that are captured in the PCA mechanism are directly related to the variable costs of providing energy.The fixed costs of power supply are not captured in the PCA.Therefore, it is more appropriate to recover variable power supply costs wi th an equal cents per kWh charge that applies to all energy use. When does Staff propose this change be made? Staff proposes that this change be made when the current deferral balance is eliminated. Why not make the change with the new rates that will resul t from this case? As pointed out by the Company in this case there is a very substantial PCA deferral balance that has accumulated and that will be recovered from customers in the next few years.Staff believes that because the balance was accumulated under the current methodology is fair to recover this balance under the current methodology.However , when the balance is eliminated, the methodology should be changed.The proposed methodology causes high load factor customers,such as Potlatch and others,pay/receive a larger percentage of surcharges/rebates.To impose such a change when there is a large balance to surcharge would initially penalize high load factor customers.It is only fair to make the change when the current balance is at or near CASE NOS. AVU-04-1/AVU-04-06/21/04 HESSING, K (Di) STAFF zero and, golng forward, there is an equal probability of credi t or surcharge. FINAL REVENUE ALLOCATION What rates does Staff propose to change as the resul t of this case? Staff proposes that base rates change based on the revenue requirement spread included in Staff witness Schunke s testimony.His testimony also provides Staff's proposed base rates.In addition , Staff witness Anderson proposes a change in DSM Rider rates.Finally, my testimony recommends changes to PCA rates. I propose that these PCA rate changes stay in place until October 2005 when an annual review of the deferral balance could cause them to change.Staff Exhibit No. 142 shows all of the revenue requirement changes by customer class and the resul ting net percentage lncreases and decreases measured from existing rates.As shown on the exhibi t , the overall change is a 2.4% lncrease above existing rates. Does this conclude your direct testimony in this proceeding? Yes, it does. CASE NOS. AVU-E- 04 -1/AVU-G- 04-06/21/04 HESSING, K (Di) STAFF CERTIFICA TE OF SERVICE HEREBY CERTIFY THAT I HAVE THIS 21ST DAY OF JUNE 2004 SERVED THE FOREGOING DIRECT TESTIMONY OF KEITH HESSING, IN CASE NO. AVU-04-l/AVU-04-, BY MAILING A COpy THEREOF POSTAGE PREP AID, TO THE FOLLOWING: DAVID J. MEYER SR VP AND GENERAL COUNSEL VISTA CORPORATION PO BOX 3727 SPOKANE WA 99220-3727 KELLY NORWOOD VICE PRESIDENT STATE & FED. REG. VISTA UTILITIES PO BOX 3727 SPOKANE W A 99220-3727 CONLEY E WARD GIVENS PURSLEY LLP PO BOX 2720 BOISE ID 83701-2720 DENNIS E PESEAU, PH. D. UTILITY RESOURCES INC 1500 LIBERTY ST SE, SUITE 250 SALEM OR 97302 CHARLES L A COX EV ANS KEANE 111 MAIN STREET PO BOX 659 KELLOGG ID 83837 BRAD M PURDY ATTORNEY AT LAW 2019 N 17TH ST BOISE ID 83702 CERTIFICATE OF SERVICE HECE1VED ill lLED F'- 2.DII11 JUN 2' Pi; \: 58 '" '", '" ""' ,! ( UT 11-(:( IE;;.! C~i;1i'~hS'SlON BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF A VISTA CORPORATION FOR AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC AND NATURAL GAS SERVICE TO ELECTRIC AND NATURAL GAS CUSTOMERS IN THE STATE OF IDAHO. ) CASE NO. AVU-O4-) AVU-O4- EXHIBITS OF KEITH HESSING IDAHO PUBLIC UTILITIES COMMISSION JUNE 21 2004 ALLEGEDLY PROPRIETARY DATA HAS BEEN DELETED FROM THESE EXHIBITS ~~ nt ' r 1 N . PJ ~ .. . . . . . . :: : r ' .. . . . . . . . . ~ ( D ,.. . . . . 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' "f.- " '' ,: ':, " ..' , 1'\, '" ,.. "." -' LA!\;......0; I-JSCOTT WOODBURY DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION PO BOX 83720 BOIS;:, IDAHO 83720-0074 (208) 334-0320 BAR NO. 1895 f::""I ' ' C'. ,.., ;', . . !, . ,- '- """"""""""""'" ""' t'J ';"'. ~" . iJJtr .'cl,Cl ' ' , : rl , . " ILJ G PUBLiC.. IT , " -;.-t' ,-!'"~' ," " r-, '-" 1.."lit 'L. lIt.. ;)' .. ' Trli ,0:1 UJ'4 Street Address for Express Mail: 472 W. WASHINGTON BOISE, IDAHO 83702-5983 Attorney for the Commission Staff BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE SUBMISSION OF THE SCHEDULE 66 PCA STATUS REPORT OF ) AVISTA CORPORATION AND APPLICATION FOR CONTINUATION OF A SCHEDULE 66 POWER COST ADJUSTMENT (PCA) SURCHARGE. CASE NO. A VU-O3- COMMENTS OF THE COMMISSION STAFF CONIES NOW the Staff of the. Idaho Public Utilities Commission, by and through its Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of Application, Notice of Modified Procedure, Notice of Comment/Protest Deadline and Notice of PCA/Energy Discussion issued on August 27 2003 submits the following comments. BACKGROUND On August 11 , 2003 , Avista Corporation dba Avista Utilities (Avista; Company) filed a Power Cost Adjustment (PCA) Schedule 66 Status Report with the Idaho Public Utilities Commission (Commission) and an Application requesting approved recovery of excess power costs deferred through June 30, 2003 and further continuation of a 19.4% ($23.6 million) PCA surcharge currently scheduled to expire on October 11 , 2003. Following a public hearing, the 19.40/0 surcharge was originally authorized by the Commission in Order No. 28876 dated ST AFF COMMENTS SEPTEMBER 30, 2003 ::::; .......~ ~ 00 r., ..,...., Cj ~ 0'\ (.j...j ....... :::J :::J .s ....... ~ ~ r/.) OJ:) o~~ bD~ !=:.,.... ~ Z ~ ~ Q) .,.... Q) ~--,..q r./) ~....... ro . N~U ~\O --- deferral balance at a higher level than the current rate for customer deposits. Staff and the :J :J cr ~ Company agreed to a compromise solution adopted by the Commission in Order No. 29323 , dateo"" ~ Ci ~ ;::J ;::J .s (\),.....; ~~CIJ 0.0o~~ on&; ...... ~ Z -.::t,..D (\)...... (\) --- ...c:: rfJ ~,.....; C\S . C"'I~U ~\O October 11 , 2001 in CaseNo. A VU-Ol-11. A 12-month continuation of the surcharge was authorized following a public workshop and comments in Order No. 29130 in Case No. A VU-02- ST AFF REVIEW Audit Results Staff has performed a review and audit of the amounts that went into the deferral balance in the current filing. Staff s review covered expenses incurred for the period July 2002 through June 2003. Staff was able to look at a representative cross section of transactions included in the Purchased Power account (FERC 555), Thennal Fuel account (FERC 501), CT Fuel account (FERC 547) and the Power Sales account (FERC 447). Based 011 its review' of these sale transactions, Staff concludes that the transactions appear reasonable at the time they were entered into. Other than the net fuel expense item that will be discussed in detail later in these comments Staff finds the amounts recorded to be correct and recommends that they be included in the deferral balance as of June 30, 2003. The PGE credit recognizes continued 18-year amortization from the monetization of a contract A vista had with Portland General Electric in the last rate case. A line item in the PCA mechanism recognizes this credit by reducing a surcharge or increasing a rebate., The Company received approval to accelerate the amortization from 18 years to fifteen months in order to offset the impact of low water and high market prices. The accelerated amortization of the PGE credit directly benefited the customers as the amount of the PCA surcharge is less and the length of the surcharge is shorter by its inclusion. The amounts recorded in the PCA deferral balance are correct. The PGE credit is $2 309 280 per month and expired at the end of 2002. In this current PCA filing, the PGE credit contributed $13 855 680. Staffnotes that this benefit will not be included in future PCA deferrals. Interest Rate Adjustments On May 16, 2003, the Company filed an Application requesting that the Commission issue an Order setting the interest rate that applies to the Company s Power Cost Adjustment (PCA) STAFF COMMENTS SEPTEMBER 30, 2003 August 21 , 2003. A 200 basis point increase will be allowed in the interest rate applied to year end deferral balances during recovery based on the first in first out (FIFO) method of accounting. The customer deposit interest rate would continue to apply to new deferral balances accnled during the calendar year. This interest rate methodology would begin January 1 , 2003 and continue through June 30, 2005. Commission Order 29323 was issued after the Company filed its status report in this case. As such, the new interest methodology was not applied in the case as filed by the Company. Staff proposes to include the results of the new methodology in this current PCA year s deferral balance and calculations. The result of Staffs adjustment increases the current year s deferral amount by $256,727. This amount reflects the application of a 200 basis point adder to the current years customer deposit rate of 20/0, calculated on the existing balance throughout the months of January through June 2003; and the application of the customer deposit rate of 20/0 on the new deferrals which continues to be calculated at simple interest. The Staff s calculations are shown in Attachment A. Deferral Balance Components The Company is requesting Commission approval for recovery of the Unrecovered Deferral Balance of $27 843 108 as of June 30, 2003. The Unrecovered Deferral Balance at June , 2003 is calculated by starting with the Unrecovered balance at June 30, 2002, adding in the net deferral activity for the current period of July 1, 2002 through June 30, 2003; and subtracting the anlortizations related to surcharge revenues. Unrecovered Balance at June 30, 2002 Net Deferral Activity (July 2002 - June 2003) Amortization s Related to Surcharge Revenues (July 2002 - June 2003) Unrecovered Balance at June 3 , 2003 $45 600 228 6,789 503 (24,456,623) $27 843 108 Exhibit No. 139 Case No. AVU-04-1/ A VU 04- , K. Hessing, Staff 6/21/04 Page 3 of 30 STAFF COMMENTS SEPTEMBER 30, 2003 The net deferral activity consists of several pieces. The Company s Application lists the deferral activity detail that goes into the Net Deferral ,Activity (July 2002 - June 2003) in the amount of$6 789 503. The net deferral activity is comprised of the follow items and amounts: Net Increase in Power Supply Cost Centralia Capital and O&M Credit (Order No. 28876) PGE Monetization Accelerated Amortization (Order No. 28876) Small Generation Capital Costs and Interest (Order No. 29130) Intervenor Funding Payment (Order No. 29147) Interest $23 383 629 ($2 817 996) ($13 855 680) ($921 184) 138 $999 596 The Centralia Capital and O&M- Credit reflects the Centralia capital costs such as return on investment and Centralia O&M expense. Since base rates were set, the Centralia power plant has been sold. The Centralia credit is designed to offset the Centralia revenue requirement that is still part of base rates. The Centralia credit is not subject to 90/1 0 sharing. . The PGE Monetization reflects the accelerated amortization of the credit balance related to the Monetization of a Portland General Electric (PGE) sale agreement. This credit balance is now zero. The Small Generation Capital Costs and Interest were disallowed in the last PCA filing, Case No. A VU-02-6. The costs included in the deferral balance that represented capital costs and the interest thereon, were excluded from deferral balance and subsequent recovery. The intervenor funding payment resulted from Order No. 29147 in Case No. GNR-02-1 dated October 31 2002, an Order dealing with published rate eligibility and contract length for PURP A proj ects. The Commission directed the three participating utilities to equally share the intervenor funding amount, to book the payment as a purchased power expense and" ... to recover same in their next Power Cost Adjustment (PCA) filing or general rate case. The largest component of the net deferral activity is the Net Increase in Power Supply Cost. The total net increase in power supply cost, $23 , 383 629, is comprised of the following items: 1. Purchased Power 2. Thermal Fuel 3. CT Fuel4. Sales for Resale5. PGE Capacity Revenue True Up 6. Potlatch 25 aMW 7. Kettle Falls Bi-Fuel ($7 083 766) ($5 942 944) ($948 195) $21 605 030 ($2,483 328) 260 572 102 506 Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 4 of 30 STAFF COMMENTS SEPTEMBER 30, 2003 8. Net Fuel Expense - Loss on Natural Gas Resold 9. Idaho Retail Revenue Adjustment 10. Wood Power Inc. Amortized Expense 11. Reverse Coyote Test Power Sales $11 817 650 $651 882 $352 788 $51 434 1. Purchased Power represents the difference in costs the Company incurred for power purchases when compared to base rates. The negative amount represents a benefit to ratepayers - the Company bought less power in the market than is currently built into base rates. 2. Thernlal Fuel is the amount spent for fuel, primarily coal, used to produce electricity. This item is the difference in costs the Company incurred for thermal fuel when compared base rates. The negative amount represents a benefit to ratepayers - the Company bought less coal than is currently built into base rates. 3. CT Fuel is the cost of natural gas burned in the Company s conlbustion turbines. This amount represents the difference in costs the Company incurred for CT fuel when compared to base rates. The negative amount is a benefit to ratepayers. 4. Sales for Resale represents revenues the Company is able to generate through long-tenn and short-term off-system sales. These revenues reduce the revenue requirement for ratepayers. The positive amount represents a decrease in off-system sales. This amount represents an increased cost to customers over what is currently built into rates. 5. The PGE Capacity Revenue True up adjustment was approved in Order 28775 , Case No. A VU-OI-, when the PCA mechanism was modified. The Adjustment records an additional amount of revenue to the recorded revenue in Account 447 so that there is no PCA impact of the PGE capacity sale. 6. The Potlatch conlponent is a direct assignment to Idaho of Potlatch costs and revenues (Lewiston faciE ty). 7. The Kettle Falls Bi-Fuel colnponent is the final payment on the Company s lease of temporary generators for the Kettle Falls Bi-Fuel project. Temporary generators were leased and placed at Kettle Falls to avoid additional high-cost purchases of energy from the that the lease costs for these temporary generators was properly included in the PCA. 8. Net Fuel Expense is discussed in more depth in the next section. short-term wholesale markets. The projects represented the lowest cost resource options available at the time. In Order No. 29130, Case No. A VU-02-, the Commission found :::::; ........q- .q- 00 ,.,....... 0'1 I d , ~ ~ ....... (1) ....... r:/J OJ)o~~ bi3~ .,..... :~Z ~3P...... (1) ---- ...t:: r.I) )001..( ....... ro . N~U ~\O SEPTEMBER 30, 2003STAFF COMMENTS 9. The Idaho Retail Revenue Adjustment is an adjustment for changes in load. If the load grows, revenue is added, if the load declines, there is an adjustment to reflect the decreased load. A revenue credit of retail load is computed,using a variable cost of power supply of 21.23 mills/kWh multiplied by the growth in load. 10. Wood Power operated a PURP A qualified wood waste powered generation facility at Plummer, Idaho. Washington Water Po'wer entered into a power sales agreement with Wood Power on August 19 1982 to purchase the energy and capacity from that facility. September 30, 1996, Washington Water Power entered into an agreement with vVood Power and Rayonier tenninating the 1982 power sales agreement. In Order No. 26751 , Case No. WWP-96-, the Company received authorization for rate ,making and accounting treatment of the buy-out of the Wood Power, Inc. contract. The Commission found that the deferral and amortization of the buy-out over eight years 'was reasonable. This amount is the current year amortization of the buy-out of that contract. 11. The Coyote Springs test power sales are included in the Sales for Resale accounts. When testing was being done at the Coyote Springs II facility, the power was sold and the sales recorded in the Sales for Resale account. This adjustment removes them from the PCA deferral balance. A significant portion of the net increase in Power Supply Costs is due to the expiration of long-tenn power sales contracts. The expiration of profitable contracts reduced Sales for Resale revenue dramatically. In the PCA, Sales for Resale revenue is an offset to Power Supply Costs. The loss of revenue from expired contracts is partially offset by reductions in fuel costs and Purchased Power costs. Total long-term sales contracts fell from twenty-one in the base case to eight in June of2003. The reduction in recent time periods of energy sales and associated revenue is shown on Attachment B. Net Fuel Expense Avista Utilities has an obligation to provide electrical service to its customers. To satisfy this obligation, the Company both generates and buys electricity. Part of the utility s generating resources are fueled by natural gas. When gas prices are low enough that electricity can be uses it to produce electricity. generated at a cost below the cost of buying electricity on the market, the Company buys gas and Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 6 of 30 SEPTEMBER 30 2003STAFF COMMENTS In the last PCA case, A VU-02-, Staff questioned the circumstances surrounding acquisition and later sale of natural gas purchased by the Company to fuel the Coyote Springs II CCCT (Combined Cycle Combustion Turbine). The Company maintains that at the time natural gas was purchased, it was anticipated that Coyote Springs II would be operational and more economical to operate,than making market energy purchases. As it turns out, Coyote Springs II \vas neither operational nor was it economical to use the gas at the Company s other facilities given the price of the gas with previously purchased fixed-for-floating financial swaps. The effect is an abnonnally high percentage of hedged gas to serve available resources at prices found to be uneconomical when cOlnpared to energy purchased from the mar~et. In Case No. A VU-02-, Staff proposed that the Commission withhold judgment on $578 748 in net fuel expense incurred in June of2002 to serve Coyote Springs until a more complete evaluation was conducted regarding anticipated online dates, reasons for the operational delay and timing of the sale of gas acquired for use at the plant. Pending further investigation, the Commission in its Order removed the $578 748. As part of its current PCA investigation and as a result of concerns raised regarding the circumstances surrounding acquisition and sale of natural gas in Case No. A VU-02-, Staff has completed a comprehensive review of gas purchase and sales transactions that generated losses on fuel resold and the excess net fuel costs requested for recovery in this case. In March of 2001 , A vista entered into two contracts to secure gas and gas transportation for its Coyote Springs II gas fired power plant. Initially Coyote Springs II was scheduled for testing in early 2002 and \-vas expected to be commercially available in July of2Q02. The two purchases for Coyote Springs II, with five corresponding financial swap transactions, are of primary concern to Staff. These purchases and financial swaps are shown in detail on Staff's Confidential Attachment C. The first gas supply contract (Deal A) was to be delivered November 2001 through November 1 2004. The fixed-for-floating financial swaps associated with this supply contract consist of two transactions. See Confidential Attachment C for specific volumes and prices. Since the delivery period did not begin for another 6 months, the price for October 2004 was locked 3 1/2 years into the future without additional documentation showing analyses beyond October 2002. Additional analyses that should have been fully documented with the swap order should include volatility analyses, price trend analyses and load requirements for the time STAFF COMMENTS SEPTEMBER 30 , 2003 :::::. .......~ ~ 00 (.,...,..... ~ d ~ 00'\ I ~ r---M~~.s (!)....... ;? ;? CIJ Ot)o~~ bi)~ !::.,...., ~ Z ~ ~ ,.D (!) . ,...., (!) '"r' ---..s::: trJ i-I-!""'"C':I . N~U ~\O period involved. The second gas supply contract (Deal B) was for delivery to begin June 1 , 2002 and continue through October 31 2003. Avista entered into two fixed-for-floating financial swap contracts that were subsequently combined into one contract, for the entire delivery period. This transaction locked in the price of gas for a period of 17 months. Since the delivery period did not begin for another 13 months, the October 2003 price was locked 2 1/2 years into the future. Gas from both contracts is sufficient to operate Coyote Springs II at its full 180 MW generating capacity through October 31 , 2003. At the time the Deals were first entered into and at the time the prices were locked, forward prices for electricity for an 18-month period were expected to be very high and the Company expected substantial purchased povver cost savings and/or sales for resale revenues from the gas purchases. A portion of these savings or revenue credits would have flowed through the PCA to benefit Idaho ratepayers and a portion would have benefited Company shareholders. During June of2001 , day ahead electric market prices fell below $1 OO/MWh for the first time in a year and by Septen1ber they were approximately $25/MWh, which is near the historic nonnal wholesale electric price. See Staff Attachment Given approximately $6.00 gas, the drop in electric prices made it uneconomical to operate any of Avista s gas fired plants to make electricity. Instead Avista simply purchased its power needs on the electric market and sold the gas back into the gas market at a loss because gas prices had also declined. See Staff Attachments E through H. In A vista s PCA filing last year, which covered the time period July 2001 through June 2002 , losses on the sale of gas from Deal A amounted to approximately $5.6 million and were approved for recovery. (See Confidential Attachment I) The loss on Deal B last year was approximately $0.6 million. This amount was not recovered in the last PCA, but deferred to the current PCA year for evaluation. In this year s PCA, which covers July 2002 through June 2003 A vista has included $11.8 million in losses due to gas sales. It is likely that there will be more losses on the sale of this gas through the end of the longest contract, which ends on November 1 2004. In Order No. 29130 the Commission directed Staff to investigate and assess the reasonableness of Avista s Risk Management Policy and how it affects the Company s short-tenn resource acquisition decision and to submit its findings and conclusions in the Company s next ~ ~ -.::t -.::t ("'j PCA review. Staff has completed its review and incorporates its findings and conclusions in these ~ 0 ~ ~0'\ I I comments. A vista has an electric Risk Policy for managing the financial risk associated with ~ ~ ~ c55 ~ ~ ~ ~~ ,....... 0 i:n -.::t.D ~ 0; ..... 'U "'ri :::::....c:: CIJ ~ nt-:: ro . N~U STAFF COMMENTS SEPTEMBER 30, 2003 providing electric energy to its customers. (Confidential Attachment J; A vista Corp.s Energy Resources Risk Policy.) The policy addresses the purchase and sale of electricity as well as the purchase and sale of natural gas acquired to generate electricity. In general, this Policy defines a mechanism that eliminates differences between loads and resources as the actual time of need approaches. The Company s Risk Policy typically extends 18 months out, and tracks surpluses and deficiencies month by month down to projected needs in the coming month. Avista s Risk Policy (dated November 9 , 2000, page 1 of 15) specifically states , " This Policy is intended to focus on short-term power and natural gas supply management, meaning the period of eighteen months forward from any current date, as they relate to meeting near-term energy load obligations." Deficits are eliminated with relatively small purchases that may occur over several months. Surpluses are eliminated with sales in the saIne way. The plan does not take a price view - that is, there are no purchases or sales made based on speculative judgments as to whether electric market prices are going up or coming down. ' Surpluses or deficits are systematically eliminated over time without speculation with regard to price. Such a plan is designed to reduce the financial risks that might otherwise be associated with large quantity, long-term sales or purchases made at a single point in time. In theory, Staff does not oppose entering into financial swaps or hedges to fix the price of gas. However, Staff is concerned about the length of the swaps that A vista entered into and the apparent lack of additional support 2 Y2 and 3 Y2 years in the future. The Company previously received from the Commission an accounting Order authorizing the deferral of the costs of a financial hedge for Avista s gas operations; however, that financial transaction was entered into in December 2000 for delivery during January through March 2001. That transaction occurred shortly before delivery was taken, and only covered a period of 3 months. The financial swaps that Avista entered into for the March 9, 2001 transaction covered 3 years, and delivery was not to begin for another 6 months in the future. Because the swaps locked prices for the last month 3 'lj years out, these swaps were inherently risky instruments. The gas deals that A vista entered into were unusual. A vista Electric had no recent history of entering into purchase or sales arrangements that went outside of its normal 18-month position report planning period. A vista Gas Operations did not make purchases outside of a 12-month period that it uses to balance its gas need for its gas customers. STAFF COMMENTS Exhibit No. 139 Case No. A VU-04- A VU 04- K. Hessing, Staff 6/21/04 Page 9 of 30 SEPTEMBER 30, 2003 Staffbelieves that the losses on the sale of gas from the two purchases resulted from substantial risks that the Company took when it locked in the price for large quantities of gas for a period of time up to 3 1/2 years after the date of the purchase. The risk substantially stems from the price paid, the fact that the price was established at only 2 points in time approximately 30 days apart, gas price levels and trends over time, the volume of gas purchased, the length of forward analysis and the duration of the purchases. Prices averaging $6.00 per dth are historically high. Gas prices for the period of months leading up to the Company s purchases had been very high and very volatile. The Company should have known that locking in gas prices at historical highs based prilnarily on long-tenn future po\ver prices with volatile and/or illiquid forward markets was very risky. The March 2001 contracts for gas delivery assured the gas and transportation. The April and May 2001 financial swaps were entered into to lock in the price of gas. Locking in a high purchase price at 2 points in time approximately one month apart for long-term purchases does not capture the risk reducing benefits of layering or cost averaging that would be captured with monthly purchases or reduced volumes at fixed prices spread over the period of power need. Risks could have been reduced if smaller quantities of 2 , 3 or 5 thousand dthlday had been purchased over time instead of 4 financial swaps entered into over the period of a month totaling 000 dth/day (decathenn/day) for much of the entire 3-year period. Not only did the Company lock into the purchase side of the gas transaction at historically high gas prices, in large volumes at essentially one point in time, it failed to mitigate the risk by also securing some mechanism to lock in the power sale side of the transaction for the excess energy. If the Company had locked into forward electricity sale agreements for the excess power generation, some of the risk of the gas fixed-for-floating financial swap purchase could have been mitigated. The Company appears to have done nothing to mitigate the risk of locking in the price of the gas. Historical trends and changes in rig counts and production levels support that prices should decline and if the Company continued with the initial Deals, i.e. index plus a small adder, the risk would have been significantly smaller. If the financial transactions had never taken place, the gas, ifbumed, would have been purchased at a price within pennies of the spot price, and if the gas had been sold, it would have been sold at a price within pennies of the spot price. These risk considerations are the type of issue where stakeholder and customer input into the Risk Policy would be beneficial. ST MF COMMENTS SEPTEMBER 30, 2003 :::::;~ 0 ..q-..q- 4-; ~Cjt:::o0'\ IM~"""-+-' Q) ~~(/) b1)o~~ bB~ !=:...... ~ Z ..q- ..D ...... Q) ~--.... rfJ ~~ro . N~U ~\O The Company s decisions were contrary to the previously cited principals of good risk management. The Company s Risk Policy allows for purchases that exceed 18 months in the future with proper authorization. These purchases met the Company s authorization requirements. However, Staff contends the documentation to support these substantially longer transactions is lacking. The Deal tickets provided some explanation as to why the long-tenn purchases were made at this point in time. The workpapers reiterate again and again that the purchases were entered into for the sole purpose of securing financing for the Coyote Springs II Project. The financial swaps were completed on May 10 , 2001. Board Minutes and other documents reflect that the financing package for construction financing for the development of the Coyote Springs II Project was proposed to and approved by the Board of Directors at the quarterly meeting on May , 2001. The primary reason for locking in gas supply and price for the Coyote Springs II Proj ect appears to be for the purpose of obtaining outside financing for the proj ect. This may explain why the Company undertook financial transactions that Staff believes were largely outside its existing Risk Policy. To the extent the transactions were made for the purpose of financing Coyote Springs II, they were to meet Avista s cash flovv requirements that were not necessarily associated with u~ility operations. Ironically, the project financing was not achieved with this approach. Whether the transactions were implemented for the purpose of obtaining proj ect financing or not, the effect of undertaking financial swaps beyond the generally accepted period of months as specified in the Company s Risk Policy was $39 465 033 in losses on a system basis. This amount, which translates to $11 785 048 on an Idaho jurisdictional basis after sharing, consists of losses during the period of July 2002 through June 2003 for the swaps entered into on April 10, 2001 and May 2, 2001 , and losses associated with swaps during the months of June 2002 through June 2003 entered into on April 11 , 2001 , May 10, 2001 and rolled into one swap on June , 2002. As previously mentioned, losses on these financial swaps during future PCA periods is also likely. Deal B Adjustment However, while Staff has been critical of the Company with respect to its overall gas acquisition approach for Coyote Springs II and questions the reasonableness of the long-tenn """""'........ ........ I financial transactions, it does not recommend a cost recovery adjustment based on total gas sales C! ~ ~ d it:: ........~::)::)........"""" ~C/J ~o~~ ci)~ I=: ...... ';:: Z ~ ~ ..D 00...... 0 ~........... ...s::: rn ....."""" ro . N~U ~\O STAFF COMMENTS SEPTEMBER 30, 2003 losses during the PCA period at issue in this case. Instead, Staff limits its recommended adjustment to losses associated with Deal B during the period from June 2002 through June 2003. Gas losses incurred under Deal B carryall of the risk concerns previously identified with one additional concern, the purchase put the Conlpany in a long position outside of established risk management limits. Staff recommends that losses on the sale of Deal B gas not be allowed to be deferred for PCA recovery. After Avista entered into Deal A on March 9 2001 , the next Company position report generally showed that A vista s resource/load balance stayed within established risk guideline limits for the delivery period. When A vista entered into Deal B the position reports showed A vista to be surplus beyond the established limits. A vista resisted selling the above limit energy for a period of time by getting a waiver from its Risk Ivlanagelnent COlllillittee but eventually sold the gas and took the loss. At this point in time all the gas purchased under Deals A and B was sold at a loss and energy needs were purchased from the electric market because it was the most economic choice. Less electrical energy was purchased than could have been generated with the gas because the Company did not need all the energy the gas would have generated. The additional gas purchase activity more clearly falls under the definition of taking a "Speculative Position" as defined on p. 11 of 15 in the Company s Risk Policy. It is speculative because the generation is not needed for load; it focuses on future price changes and is not documented and shown to reduce "Business Risk." The Company provided Staff with a sample of daily Position Reports and Position Limit Charts. The Position Limit Charts show projected energy surpluses and deficits for Heavy Load Hours (HLH) and Light Load Hours (LLH) in average Megawatts for a period of 18 months along with their relationship to risk linlits. Confidential Attachment K, pages 1 through 4 are copies of Position Limit Charts on 4 selected days. Page 1 shows the Company s projected positions on March 7, 2003 , which is prior to either of the gas purchase deals. For the period beginning November 2001 and beyond it shows small surpluses and deficits except for two substantial deficits that are outside the short position limits. Page 2 shows the Company s projected positions on March 21 2001. This chart shows the Conlpany s projected positions after it acquired gas under Deal A but before it entered into Deal B. The purchase of gas to be used to generate energy moved all of the Company s 2002 positions in the surplus direction, as one would expect. At this STAFF COMMENTS SEPTEMBER 30 , 2003 ;::::;....... """""" ~ 00 age ~ d ~ N0\ I ~ ~....... M ::J ......, +-' \1) """' ~~UJ bl)o~~ o.O~ ...... :~Z ~""" ..0 \1) ...... \1) ~ ......... ....c: ifJ ~....... ro . N~U ~\O point in time, the chart shows no long or short positions outside of risk management limits. 3 shows the Company s projected positions on March 28 2003. At this point in time the Company had entered into Deal B, which was the additional gas purchase that began in June of 2002. At this point in time all 2002 positions are surplus and LLH in the third quarter are surplus beyond the limit. To be surplus outside of the risk managen1ent limits in one quarter 18 months out does not cause Staff a great deal of concern. However, it is the only full quarter shown on that chart that captures the effect of both gas purchases., In order to show the effect on the Company of both gas purchases the next position limit chart is for June 20 2001. Staff proposes that this chart be viewed in three parts. July 2001 through November 2001 show positions that are long and short but all within position limits. December 2001 through May 2002 show the time period that Deal A gas is to be delivered. Positions are long and in 2 months slightly outside of position limits. June 2002 through December 2002 is the period of time when gas is to be delivered to generate power under both Deal A and Deal B. In general, positions are quite long and in all month HLH or LLH energy or both are outside of position limits. The calculation of the loss on the gas sales is shown on page one of Staff Confidential Attachment 1. Staff calculated the purchase amounts of Deal A and B by multiplying 20 000 dth/day times the price, times the number of days in each month for each deal. Staff calculated the sale amounts by multiplying the 20 000 dth/day times the number of days in each month times the average 'weighted price for the month. Staff used workpapers supplied during the audit to calculate the average monthly sales price received for sales of gas purchased and resold. When the Company prepares DJ 042 entries (Diarized Journal 042), the average price per therm that the gas is sold at is calculated. The worksheets Staff obtained during the audit provided the information necessary to calculate sales price of the gas resold on a monthly basis. Staff used that amount to calculate the loss on the sale of the gas. The loss on the sale is the monthly difference between the purchase price of the 20, 000 therms per day of gas, and the sales price of the 20 000 thenns per day of natural gas. Staff separated the loss between Deal A and Deal B. The amounts are then multiplied by the jurisdictional allocation factor (33.18%, the Production and Transmission allocation ratio) and then multiplied by 900/0 to reflect the customer portion after the 90/1 0 sharing. Staff calculated the loss on each Deal for the months of November 2001 through June of 2003. Staff calculated the loss on each Deal for the months of November 2001 through June of ~:+ ~ ~ 0 2003. Staff recommends disallowing the losses from Deal B for the months of June 2002 through ~ 0 ~ ~~66 ...... ~?r.f) bB~ ...... ~ z ~ ~ P..... Q) ~-..... ...s::: rJ) i-I-I ,...... ro . C"1~U ~\C STAFF COMMENTS SEPTEMBER 30, 2003 June 2003, in the amount of$5 849 100, with associated carrying charges of$87 343 , for a total adjustment of $5 933,433. Staff s decision to limit its recommendation to the losses associated vvith Deal B is due to several factors. The most obvious is the market conditions faced by the Company at the time the transactions were made. Forward prices for both natural gas and electricity were high for periods beyond 18 months. The Company s existing Risk Policy was sufficiently broad to allow deviation with sufficient authorization and without specific documentation. While the Policy needs to be modified in this regard, Staff does not necessarily believe that an adjustment incorporating all losses beyond the 18-month policy period is warranted. Finally, Staff cannot ignore the financial impact that such an adjustment could have on the Company. While Avista s financial situation has improved since 2001 , and Staff believes the Company can and should absorb the losses associated with Deal B, cost recovery adjustment beyond that level could cause significant , negative impact. Rate Impact Staff proposes that the loss on the sale of gas associated with Deal B be removed from the PCA deferral account along with associated interest The swaps on Deal B were-entered with Avista Energy. The electric operations have claimed no dealings with Avista Energy so proper pricing mechanisms with safeguards have not been established. Absent an approved mechanism, the affiliate transactions with A vista Energy should be priced at the lower cost or market. Therefore, the losses on Deal B should be repriced at market with the Company absorbing the loss rather passing it to customers through the PCA. The loss on the sale of gas captured in the Idaho PCA deferral balance amounts to 849 100 and reduced interest amounts to $87 343 , which reduces the deferral balance to $21 906 665 dollars as of the end of June 2003. Existing PCA rates are designed to recover approximately $23.6 million in a year. If PCA rates were adjusted based on Staff s calculations the rates vvould be reduced frorh19.4% to 18.00/0. However, Staff proposes that existing PCA rates be continued until the next PCA regardless of the final decision reached in this case. Rates can remain unchanged because in the future any differences between deferred costs and PCA revenues including accrued interest will be trued-up. Staff Attachment L shows the deferral STAFF COMMENTS SEPTEMBER 30, 2003 ::::. ,.....; 0 ~~ 4-.00 d~~ ~ ~ ~ ~,.....;,.....;~(/) ~ bB~ .,..... ~ Z ~ ~ ,.D ~o .,..... ~ ~.......... ..r::: I:/) .......,.....; ;..:: ro . N~U ~\O balance as a result of Staff s adjustments. CONSUMER ISSUES The Application filed by A vista on August 11 , 2003 contained both the customer notice and press release. Both met the requirements of IDAP A 31.21.02.102. A vista sent its customer notifications beginning with customer bills on August 12, 2003 and ending September 11 , 2003. The IPUC held public workshops in both Lewiston and Coeur d'Alene regarding Avista proposed continuation of its 19.40/0 surcharge. One customer attended the Lewiston workshop and no customers attended the Coeur d' Alene workshop. From the time Avista filed its PCA and through September 29, 2003, the Commission received 6 written comments from customers. The deadline for filing comments is September 30 2003. None of those who commented were in favor of the continuation of the surcharge. One custon1er suggested in her comments that A vista implement a program similar to V erizon ' s ITSAP program. The Idaho Telecommunications Service Assistance Program (ITSAP) participants save $13.62 per month on local telephone bills. The program is mandated by Idaho Code and monies are recovered from residential and wireless telephone users; it is not a program initiated by Verizon. While some states have additional funds available for energy assistance for low-income residents, Idaho does not mandate electric companies in Idaho to collect funds from residential customers to assist low-income customers with energy costs. The customer added in her comments that she qualifies for and receives heating bill assistance from the federally funded energy assistance program called Low Income Home Energy Assistance Program (LIHEAP). In July of2003 , Avista donated $50 000 to Project Share in north Idaho. Project Share is a fuel fund that helps qualified customers pay heating bills. Although some states mandate electric companies to donate to fuel funds, Idaho does not. Project Share monies come from the utility company, customers, and organizations who voluntarily give donations. The administrator for Proj ect Share in northern Idaho said the funds this year ani ved from A vista in July and some were used immediately to help low income customers pay electric bills who needed power connected run electric fans during this past summer s exceptionally high temperatures. Customers may receive financial assistance from both LIHEAP and Project Share. Project Share is sometimes used to assist those "vho might be in a wage group slightly above the income requirements needed to receive federal LIHEAP funds. STAFF COMMENTS SEPTEMBER 30, 2003 ~,.......; 0 "'t' "'t' 4-;00 ~d~\Ij~66 """";,.......; ~~(/J ~o~~ bB~ ...... :~z ~"'t',.D (t) ...... (t) -....... ...t:: r.I) ~ ,.......; cd . ~ ~U ~\o Avista also continues to offer rebate programs to customers who convert to energy efficient heating or water heating equipment. A vista continues to promote Comfort Level Billing to help customers level out payments over a twelve-month period. Comfort Level Billing is often a helpful budgeting tool for customers \-vho have difficulty paying high bills in the heating months and yet have low electric bills in the summer. Approximately 13 % of A vista s customers use Comfort Level Billing. Since the last PCA was approved in October of2002 , the Commission s Consumer Assistance Staff received 150 complaints and inquiries from customers regarding electricity issues. Forty-five percent of those complaints and inquiries were related to credit and collection issues, with the majority being about discolmection for non-payment of the customer s electric bill. (These figures are typical for Idaho electric companies). The number of complaints and , inquiries regarding electric issues decreased by 25% between the months of October 2002 through September 2003 when compared with the corresponding time period of October 2001 through September 2002. In both time periods, approximately one-half of the complaints were related to disconnection of service for non-payment. RE CO lVIMEND A TI 0 NS Staff proposes that the Commission accept the filing with the following recommendations and modifications. Staff specifically recommends that: 1. The current surcharge be continued until the next PCA filing regardless of the final decision reached by the Commission in this case. Staff also recommends any actual remaining deferral balance at June 30 2004 be subject to review by the Commission prior to establishing a surcharge for an additional period of time, as provided for in Order No. 28876, Case No. A VU-01-11. 2. The net fuel expense for losses on natural gas CT fuel sold rather than burned under Deal B" be denied for recovery in the PCA in the amount of$5 849 100 and interest. 3. That the deferral balance be modified to include Staff s adjustments and corresponding adjustments to the carrying charges. 4. The Conlpany work with the Commission Staff and customers in developing an acceptable Risk Policy for the Utilities division of Avista Corporation. Exhibit No. 139 Case No. A VU-O4- , ' C ,\., ,J-u , ()" ., "" 'l~,, 6/21/04 Page 16 of 30 ST AFF COMMENTS SEPTEMBER 30, 2003 Respectively submitted this Technical Staff:Kathy Stockton Maril yn Parker Keith Hessing i :umisc/commen ts/a vueO3. 6swklskhmp STAFF COMMENTS 7'1\ day of September 2003. Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 17 of 30 SEPTEMBER 30, 2003 Idaho Public Utilities Commission Staff Adjustment A Interest Calculation Avista Utilities Idaho PCA Case No. AVU-O3- 6/30/2002 Balance excJudino interest 568 103 Interest Jul-Deferral 927 566 PGE amortization RJ216 309 280) Surcharge Amortization 822 555) 7/31/2002 Balance before interest 363 834 Interest ;:jj!;10j~~i~~9"7 /31/2002 Balance excludinq interest 363 834 Aug-Deferral 885 964 PGE amortization -RJ216 (2,309 280) Surcharge Amortization (1,962 847) 8/31/2002 Balance before interest 977 671 Interest 8/31/2002 Balance excluding interest 977 671 Sep-Deferral 372 898 PGE amortization -RJ216 309 280) Surcharge Amortization 917 598) 9/30/2002 Balance before interest 123 691 Interest ;j:i;:;:t;11~~~~~'9/30/2002 Balance excluding interest 123 691 Oct-Deferral 2,416 760 PGE amortization RJ216 309 280) Surcharge Amortization 821,411) 10/31/2002 Balance before interest 409 760 Interest 10/31/2002 Balance excludinq interest 31,409 760 Nov-Deferral 364,437 Intervenor Funding Order 137 PGE amortization -RJ216 309 280) Surcharge Amortization 069 140) 11/30/2002 Balance before interest 396 914 Interest :;I;(:ii!\il~Q~~~~~:'11/30/2002 Balance excluding interest 396 914 Dec-Deferral 348 526 PGE amortization -RJ216 (2,309 280) Surcharge Amortization 317 523) 12/31/2002 Balance before interest 118 637 Interest 12/31/2002 Balance excludinq interest 118 637 Total Interest to Date 807 074 Deferral Balance 12/31/02 with Interest $30 925 711 Beqin New Interest Calculation Old Balance Continue Simple Interest on New Balance Jan-Deferral $30 925 711 3,454 572 Surcharge Amortization 421,489) 1/31/2003 Balance before interest ?R 1:;".11. ??? ;:;;j)~9:~1!!:il~:f!I~;:1 j;!!;; :1::;il;ii\::!!!':~;i~~~~iii~Interest 1/31/2003 Balance excludinq interest Balance 607 308 3,454 572 Feb-Deferral 245 118 Surcharge Amortization 227 385) 2/28/2003 Balance before interest 379 923 699 690 Interest 10~;:J;;:::!:liill~11i;11i;1;jl:j: $~:~~~~~; i;1jiji;;!itiA~;~~~;'2/28/2003 Balance excludinq interest Balance 26.475 2B1 699 690 Mar-Deferral 626 742 Surcharge Amortization (2,184 726) 3/31/2003 Balance before interest ?4 ?a" 1:;1:;1:;326 432 Interest j)lii)j;,;\iti~jl!I,I.ii:iii;I~~l~~~.jll,ji:;111!:jliizt~~~J;;3/31/2003 Balance excludinq interest Balance 378 806 326 432 Apr-Deferral 332 541 Surcharge Amortization 052 1 B7) 4/30/2003 Balance before interest ?? "I?~ ~ 1 9 .,..~~.~~~~.~?? , Interest .ll11jl)!~f~g~~I,:::i':ili\id,~1~S;'4/30/2003 Balance excludinq interest Balance 22,407 B82 658 973 May-Deferral 488 717 Surcharge Amortization 864 170) 5/31/2003 Balance before interest '0 !;4~712 ;:j)j;ji!~~~~~~.Interest ill;;;;I;j;;i;:II!~!'!I.I!r~;~~~:5/31/2003 Balance excludinq interest Balance 618 405 147 690 Jun-Deferral 101 792 Surcharge Amortization 885 592) 6/30/2003 Balance before interest 1 ~~~I~~~~~~249.482 Interest """""""":':': :13""579"'ii;Wi;i!,ti,J., ..", 6/30/2002 Balance excludinq interest Balance 1 B 801 541 249,482 Simple interest and $744 944 Compound interest $511 379 Total Interest for 2002-2003 PCA Period 256 323 Company accumulated interest for Jan 1 2003 through June 2003 $999 596 Difference due Case No.AVU-03-$256 727 Exhibit No. 139 Case No. A VU-04- A VU-04- K. Hessing, Staff 6/21/04 Page 18 of 30 Attachment A Case A VU-03- Staff ConTInents 9/30/03 \0 ( / ) 0 " " " ' " -- - l " " " + ~ p: J ~~ ( " D ~ oz t r o 8 ~ ~ ~ 9 2 l" " " + I en tT 1 0'\ 50 0 00 0 45 0 00 0 40 0 00 0 - :2 3 5 0 00 0 ~ 3 0 0 00 0 :: J :r : 2 5 0 00 0 ~ 2 0 0 00 0 ~ 1 5 0 00 0 10 0 00 0 00 0 VI S T A UT I L I T I E S L O N G - TE R M P O W E R S A L E S ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~r b . ~ " ' ? - ~r b . ~ ~ -1 " , ? - 'i O ~ O cJ ~r b . ~ ~ r b . ~ " , ? - ~ ~r b . -1 " , ? - 'i o cJ ~r b . ~ ~ r b . ~ " , ? - ~r b . Ex h i b i t N o . 13 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 1 9 of 3 0 $6 0 00 0 00 0 . $5 0 00 0 00 0 . - $ 4 0 00 0 00 0 . :: J $3 0 00 0 00 0 . 00 c ;:: , . a: : $2 0 00 0 00 0 . $1 0 00 0 00 0 . $0 . ATTACHMENT C IS CONFIDENTIAL Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 20 of 30 $6 0 0 . $5 0 0 . $4 0 0 . 00 - 2 $ 3 0 0 . -. . . . Y) - $2 0 0 . $1 0 0 . Mo n t h l y A v e r a g e M i d - Co l u m b i a P r i c e \O U ) O ~ -- - ~ ~ ~ VJ ~ C/) t: ! : ? ( 1 ) -- - . . ?; 1 8" ~ C) ~ C) ~ C) ~ C) ~ C) ~ C) ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ '? ~ '? ~ '? ~ ~ ~ g ') r i J (; ' ~ qJ ~ r i J ') V 0 ~ ~ o ') r i J (; ' ~ qJ ~ r i J ') V 0 ~ ~ O ') r i J (; ' ~ qJ ~ r i J ') V 0 ~ ~ O ') r i J (; ' ~ qJ ~ r i J ') V (1 ) ~t ) tn Ex h i b i t N o . 13 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 2 1 o f $0 . $5 4 , $4 8 . $4 2 . $3 6 . :: J ... . .~ $ 3 0 . C1 ) en $2 4 . :: J U') - $1 8 . $1 2 . $6 . \D ( j ) ( J ~ l: : i ~ ~ .. . . . . . .. . . . . f / ) .- + ~~ ( j ) ~ (J ~ o 2 ~ I ~ (j ) t T j :: : 1 I l. J . J .- + f/ ) ( j , ) $0 . .. - .. - .. - (o f ' ) Ex h i b i t N o . 1 3 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 2 2 of 3 0 Hi s t o r i c a l D a i l y G a s Pr i c e s a t M a l h i , O r e g o n .. - .. - I'- .. - .. - .. - .. - .. - .. - .. - .. - .. - .. - (J ) .. - .. - (o f ' ) I'- .. - .. - .. - .. - .. - .. . - .. - .. - .. - .. - .. - (J ) .. - .. - (o f ' ) I'- (J ) .. - .. - .. - \D C / ) n ~ -- - - r- + P ' r- + VJ P' C/ ) r - + S2 ~ ( 1 ) ~ w 0 ~ S ~ ~ ~ (1 ) t T J t - r j ;j r- + C/ ) W $3 5 . $3 0 . $2 5 . $2 0 . .f f l - :: J $1 5 . $1 0 . $5 . Na t u r a l G a s P r i c e P e r MM B t u U S $ at s e l e c t e d Hu b s a n d C i t y Ga t e s .., .., ... . . ... . .. . . , .., .. , ... . , .., "" " "" " " , "0 , ". . ." . . "" " "" " "- " " " "" " "" " "" ' "0 . "'" " " "" " "" " ,," "0 . -, , , , , , "0 . 0" " " "" " "0 " " "" " "0 " 0 ' 23 - Ju n - So u r c e : N a t u r a l G a s W e e k 09 - Ja n - 28 - Ju l - 1 3 - F e b - 01 - Se p - 20 - Ma r - O3 Ex h i b i t N o . 13 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 2 3 of 3 0 -. . - Su m a s ( B C ) .. . . B . . . . K; i n g s g a t e ( B C ) "" , :: : : ", AE C O C ( A l b e r t a ) ... . : : ' : : : . . . . Op a l (W y o ) Ch i c a g o C i t y G a t e -0 - - H e n r y Hu b $1 0 . $9 . $8 . $7 . ;: ) $6 . IX ) :2 : :2 : $5 . ;: ) tf l - $4 . $3 . $2 . $1 . '- D ( / ) n ~ -- - M - p) M - Wp ) C/ ) t: : t ! ( l ) p ) -- - . " (" ) t: r W 0 ~ B ~ ~ g (l ) t I 1 ' " :: 1 I ~ J M- Cf ) W Hi s t o r i c a l D a t a G a s P r i c e s .., .. , 05 - Ja n - 2 4 - Ju l - 98 0 9 - Fe b - 2 8 - Au g - 1 5 - Ma r - 98 99 99 01 - 0c t - 19 - Ap r - 0 5 - No v - 2 4 - Ma y - 1 0 - De c - 01 01 02 28 - Ju n - Ex h i b i t N o . 1 3 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 2 4 o f -+ - S u m a s (B C ) -m - Ki n g s g a t e ( B C ) ... . :: , ' :. . . . AE C O C ( A l b e r t a ) .. . . ;: " ' : " . . ' Op a l (W y o ) -- - ? I E - Ch i c a g o C i t y G a t e -e - H e n r y Hu b \o ( J ) n ~ -- - . - + P ' .- + L0 P' C/ J . - + t: : t ! ( \ ) -- - . . (" ) n~ 2 " 0 2 ~ I ~ (\ ) t : T j I ~ .- + C/ J L 0 $6 . $5 . $4 . .. .:E $ 3 . U) - $2 . $1 . An n u a l A v e r a g e N a t u r a l G a s P r i c e s $5 . $5 . $5 . Su m a s ( B C ) Ki n g s g a t e ( B C ) AE C O C ( A l b e r t a ) Op a l (W y o ) Ex h i b i t N o . 1 3 9 Ca s e N o . A V U - 04 - A V U - 04 - K. H e s s i n g , S t a f f 6/ 2 1 / 0 4 P a g e 2 5 o f IE . I Av e 9 8 Ei l l J A v e 9 9 .A v e 0 0 EJ Av e 0 1 . A v e 0 2 IE J A v e 0 3 ATTACHMENT I IS CONFIDENTIAL Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 26 of ATTACHMENT J IS CONFIDENTIAL Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 27 of 30 ATTACHMENT K IS CONFIDENTIAL Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 28 of 30 Idaho Public Utilities Commission Staff Adjustment L A vista Utilities Idaho PCA Deferred Cost Balances Case No. A VU-O3- Company 2002-2003 Deferral Calculation Deferral Activity Detail Net Increase in Power Supply Cost Centralia Capital and O&M Credit PGE Monetization Accelerated Amortization Transfer Small Generation Capital Costs and Interest Intervenor Funding Payment Interest Company Deferral for July 2002 - June 2003 period $23 383 629 817 996 $13 855 680 $921 184 138 999 596 789 5031 Staff 2002-2003 Adjustment to Deferral Balance Staff Adjustment to Loss on Natural Gas Sales Interest Adjustment due to Staff Adjustment Adjust In~ef~$t C~lculation for Case No. AVU-03- Total Staff Adjustment to Company Deferral for 2002-2003 !Staff Proposed Deferral for July 2002 - June 2003 849 100 $87 343 $256 727 679 716 109 787 Unrecovered Balance at June 30 , 2002 Staff Net Deferral Activity (July 2002 - June 2003) Amortizations Related to Surcharge Revenues (July 2002 - June 2003) , Unrecovered Balance at June 30, 2003 $45 600 228 109 787 $24 546 623 $22 163 392 Exhibit No. 139 Case No. AVU-04- VU -04- K. Hessing, Staff 6/21/04 Page 29 of 30 Attachment L Case No. A VU-03- Staff Comments 9/30/03 CER TIFI CA TE OF SER VI CE HEREBY CERTIFY THAT I HAVE THIS 30TH DAY OF SEPTEMBER 2003 SERVED THE FOREGOING COlVIMENTS OF THE COMMISSION STAFF, IN CASE NO. AVU-03-, BY MAILING A COpy THEREOF POSTAGE PREPAID TO THE FOLLOWING: DAVID J. MEYER SR VP AND GENERAL COUNSEL VISTA CORPORATION PO BOX 3727 SPOKANE W A 99220-3727 KELLY NORWOOD VICE PRESIDENT VISTA CORPORATION PO BOX 3727 SPOKANE W A 99220-3727 MAILED TO DON FALKNER AT: dfalkner~avistacorp. com SECRETARY CERTIFICATE OF SERVICE Exhibit No. 139 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 30 of 30 VISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: CASE NO: REQUESTER: TYPE: REQUEST NO. Idaho A VU-O4-01 / A VU-O4- IPUC Data Request Staff 27 -Supplemental DATE PREPARED: WITNESS: RESPOND ER: DEP ARTMENT: TELEPHONE: 05/10/2004 R. Gruber Energy Resources (509) 495-4001 REQUEST: A vista has recently relied on financial hedging to provide some level of natural gas price stability. Please provide all data on all hedges executed from 1999 to present. Please provide the analysis that indicates that maintaining this practice is preferred (operationally and/or financially) to reacquiring all of Avista s storage resources. SUPPLEMENTAL RESPONSE: Avista s original response inadvertently omitted the data requested on all hedges executed from 1999 to present. A spreadsheet listing all hedges executed by A vista for Washington/Idaho for the period requested is attached. These hedges are all fixed for float swaps and represent only deals done for natural gas utility core load. All of the hedges with transaction dates up to and including May 16, 2001 were executed by the Utility outside of the Benchmark Mechanism. Hedges transacted after that date were executed by A vista Energy on behalf of the Utility as part of the Benchmark Mechanism as modified effective April of 2002. Exhibit No. 140 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 1 of 2 Avista Corporation Benchmark Mechanism Evaluation Natural Gas Prices Fixed for Washington & Idaho Lock.in Quantity Date DthiDa Term Basin Price 12/4/2000 5000 January 2001 through March 2001 Sumas 12.6500 12/4/2000 5000 January 2001 through March 2001 Alberta 200012/4/2000 5000 January 2001 through March 2001 Rockies 4000 12/4/2000 5000 January 2001 through March 2001 Sumas 12.650012/14/2000 4739 November 2001 through March 2002 Alberta 25 Cdn 2/5/2001 5000 November 2001 through March 2002 Rockies 0400 3/7/2001 5000 November 2001 through March 2002 Alberta 3000 3/7/2001 5000 April 2001 through October 2001 Alberta 16003/7/2001 5000 November 2001 through October 2002 Alberta 7750 3/7/2001 5000 April 2001 through October 2001 Rockies 7500 3/7/2001 5000 November 2001 through October 2002 Rockies 63504/23/2001 5000 November 2001 through October 2002 Alberta 8100 4/23/2001 5000 November 2001 through October 2002 Sumas 9000 5/2/2001 5000 November 2001 through October 2002 Sumas 25005/8/2001 5000 November 2001 through October 2002 Alberta 22005/15/2001 5000 November 2001 through March 2002 Alberta 7450 5/15/2001 5000 November 2001 through March 2002 Rockies 59505/16/2001 5000 November 2001 through March 2002 Sumas 7.30004/4/2002 3000 November 2002 through March 2003 Alberta 3300 4/4/2002 1000 November 2002 through March 2003 Rockies 42504/4/2002 1000 November 2002 through March 2003 Sumas 78005/22/2002 6000 December 2002 through January 2003 Alberta 74005/22/2002 2000 December 2002 through January 2003 Sumas 33505/22/2002 2000 December 2002 through January 2003 Rockies 77005/3012002 3000 December 2002 through February 2003 Alberta 52005/30/2002 1000 December 2002 through February 2003 Sumas 83005/30/2002 1000 December 2002 through February 2003 Rockies 59005/30/2002 3000 November 2002 through February 2003 Alberta 3.48005/30/2002 1000 November 2002 through February 2003 Sumas 75005/30/2002 1000 November 2002 through February 2003 Rockies 51006/13/2002 3000 November 2002 through March 2003 Alberta 33006/13/2002 1000 November 2002 through March 2003 Sumas 67006/13/2002 1000 November 2002 through March 2003 Rockies 30507/12/2002 6000 November 2002 through October 2003 Alberta 20007/12/2002 2000 November 2002 through October 2003 Sumas 35507/12/2002 2000 November 2002 through October 2003 Rockies 97507/14/2002 3000 November 2002 through March 2003 Alberta 20007/14/2002 1000 November 2002 through March 2003 Sumas 50007/14/2002 1000 November 2002 through March 2003 Rockies 07008/29/2002 3000 December 2002 through March 2003 Alberta 39708/29/2002 1000 December 2002 through March 2003 Rockies 3.20308/29/2002 1000 December 2002 through March 2003 Sumas 848011/7/2002 5890 December 2002 through March 2003 Alberta 3.405011/7/2002 2010 December 2002 through March 2003 Sumas 700011/7/2002 2010 December 2002 through March 2003 Rockies 29004/15/2003 2745 November 2003 through March 2004 Alberta 03504/15/2003 1005 November 2003 through March 2004 Sumas 53504/15/2003 1250 November 2003 through March 2004 Rockies 12006/13/2003 2010 November 2003 through March 2004 Sumas 67006/13/2003 5490 November 2003 through March 2004 Alberta 34506/13/2003 2500 November 2003 through March 2004 Rockies 28007/14/2003 2745 November 2003 through March 2004 Alberta 78507/14/2003 5490 April 2003 through October 2004 Alberta 02507/14/2003 2010 April 2003 through October 2004 Sumas 06007/14/2003 1005 November 2003 through March 2004 Sumas 15007/14/2003 2500 April 2003 through October 2004 Rockies 25807/14/2003 1250 November 2003 through March 2004 Rockies 25808/22/2003 2745 December 2003 through March 2004 Alberta 02508/22/2003 1250 December 2003 through March 2004 Rockies 11008/22/2003 1005 December 2003 through March 2004 Sumas 34008/14/2003 2745 November 2003 through March 2004 Alberta 81008/14/2003 1250 November 2003 through March 2004 Rockies 86008/14/2003 1005 November 2003 through March 2004 Sumas 11008/22/2003 5490 December 2003 through February 2004 Alberta 11508/22/2003 2500 December 2003 through February 2004 Rockies 19008/22/2003 2010 December 2003 through February 2004 Sumas 56008/22/2003 5490 December 2003 through January 2004 Alberta 11608/22/2003 2500 December 2003 through January 2004 Rockies 20108/22/2003 2010 December 2003 through January 2004 Sumas 570010/20/2003 2010 December 2003 through March 2004 Sumas 945010/20/2003 5490 December 2003 through March 2004 Alberta 655010/20/2003 2500 December 2003 through March 2004 Rockies 810010/31/2003 2500 October 2004 Rockies 060010/31/2003 2010 October 2004 Sumas 135010/31/2003 5490 October 2004 Alberta 045010/31/2003 2500 April 2004 Rockies 033010/31/2003 2010 April 2004 Sumas 003010/31/2003 5490 April 2004 Alberta 00304/14/2004 2500 November 2004 through March 2004 Alberta 5.46504/14/2004 1250 November 2004 through March 2004 Rockies 60504/14/2004 1250 November 2004 through March 2004 Sumas 6800 Staff DR-027 -Supp_Attach.xls Staff Data Request No. 27-Supplemental Response Exhibit No. 140 Case No. A VU-04- A VU -04- K. Hessing, Staff 6/21/04 Page 2 of 2 5/10/2004 STAFF EXHIBIT NO. 141 IS CONFIDENTIAL Exhibit No. 141 Case No. A VU-O4- VU -O4- K. Hessing, Staff 6/21/04 st a f f C a s e A v i s t a Ut i l i t i e s - E l e c t r i c st a t e o f I d a h o Re v e n u e A l l o c a t i o n No r m a l i z e d 1 2 - Mo n t h s E n d i n g D e c e m b e r 3 1 , 20 0 2 Li n e TY D e o f S e r v i c e Cu r r e n t Re v e n u e (8 ) Ne t Re v e n u e Ad i u s t m e n t s (9 ) (1 0 ) (1 1 ) Av e r a g e Ra t e Pe r c e n t ~/ k W h Ch a n g e (1 ) (2 ) (3 ) Ra t e Av e r a g e Sa l e s Sc h . N u m b e r of No r m a l i z e d No . Cu s t o m e r s fM W h l (4 ) (5 ) Pr o p o s e d Ge n e r a l In c r e a s e (6 ) Pr o p o s e d PC A De c r e a s e (7 ) Pr o p o s e d DS M R i d e r De c r e a s e Pr o p o s e d Re v e n u e Re s i d e n t i a l 87 , 4 9 4 98 8 , 38 0 60 , 10 2 00 0 87 8 , 02 2 (6 , 4 1 7 , 94 0 ) (3 6 5 , 70 1 ) 09 4 , 38 2 19 6 , 38 2 Ge n e r a l S e r v i c e 16 , 05 1 22 5 , 32 8 19 , 43 6 , 00 0 84 5 , 70 6 (2 , 03 8 , 82 8 ) (1 1 2 66 4 ) (3 0 5 , 78 6 ) 19 , 13 0 , 21 4 1. 6 % La r g e G e n e r a l S e r v i c e 78 9 67 4 , 17 7 41 , 68 2 , 00 0 47 2 , 78 2 46 4 , 13 9 ) (2 4 2 70 4 ) (2 3 4 , 06 0 ) 41 , 4 4 7 94 0 Ex t r a L a r g e G e n e r a l S e r v i c e 30 3 , 70 7 34 6 , 00 0 10 0 , 01 2 13 5 , 68 0 ) (7 4 10 5 ) 89 0 22 7 13 , 23 6 , 22 7 Po t l a t c h 87 0 , 08 6 33 , 05 6 , 00 0 11 6 , 50 1 (3 , 40 9 , 93 6 ) (2 1 2 30 1 ) 49 4 26 4 33 , 55 0 , 26 4 Pu m p i n g S e r v i c e 04 3 48 , 92 2 99 7 , 00 0 34 5 , 12 6 (2 6 2 , 18 5 ) (1 8 , 10 1 ) 64 , 84 0 06 1 , 84 0 St r e e t a n d A r e a Li g h t s 41 - 12 , 98 3 22 8 , 00 0 32 0 , 72 8 (2 3 5 , 12 7 ) (1 3 , 04 8 ) 55 3 30 0 55 3 17 . To t a l / A v e r a g e 12 3 , 58 3 17 1 , 84 7 , 00 0 23 , 07 8 , 87 7 (1 7 , 96 3 , 83 5 ) (1 , 03 8 , 62 3 ) 07 6 , 41 9 17 5 , 92 3 , 41 9 . I n c l u d e s al l p r e s e n t r a t e a d j u s t m e n t s ; R e s i d e n t i a l E x c h a n g e C r e d i t , C e n t r a l i a C r e d i t , P C A S u r c h a r g e , DS M R i d e r ~~ (j t T j N' ~ ~ ... . . . . ~ e n . :: r -- - ~ ( t ) ,. . . . . (t ) cr " .J : : . . ~ Z~ . ,. . . . . 0 qq ~~ ~ (/ ' l ~ ~ " " ' " S- C C. J : : . . rh I N ~C 1 t T j .J : : . . .J : : . . .. . . . . . : : : : : U: \ k h e s s i n I A V U E 0 4 0 1 \ S t a f f C a s e \ S t a f f C a l c u l a t i o n s 6/1 7 / 2 0 0 4 , . tI 1 tJ j Cl n ~ ~ ::: : : : :: r : C3 O 0 ~ tI 1 ~~ ~ (; ) tJ j tJ j (; ) ~ ~ ~ tI 1 ~ ~ S :: r : t r 1 t r 1 tI 1 ~' - ' tI 1 tI 1 tV ~ t; . ) ::r : Cl V1 -.. . . . J tI 1 tJ 0 t; . ) t V -.. . . . J fc i 0 ~ :: r : t r 1 ~ Z ~ tr 1 00 t I 1 \0 O tI 1 tJ j tr 1 t; . ) tr 1 0 !j ~ \0 ~ ~ ~ -.. . . . J tV r ~ ~ ~ r -. . . . . J Z .. ~ tV " Z ~ -. . . . . J ~ tJ j :: r : tI 1 ~ ~ ~ == ~ r ~ ! ~ Cl :: r : 00 ~ O ~ tI 1 tJ j tJ j "" ' tI 1 ~ O ~ ~ ~ ~ \0 ~ r 0 ~ ~ ~g s U J :: r : tr 1 tI 1 ~ ~ ~ ~ r ~ ~ ~ ~ ~ rJ ' l S ~ ~ ~ Ed == t V tr 1 tI 1 :: r : ~ ~ ~ ~ ~ tI 1 tr 1 = = e n ~ ~ ~ -. . . . . J e n \0 ~ e n tr 1 ;: j 0 ~ tI 1 0 ~ ~ tV tr 1 \0 ~ ~ ~ tV ~ \0 t r 1 en n " tV e n l t J ~ ~ tI 1 t I 1 en e n :: r : Z ~ t; . ) C Z -.. . . . J ~ n tI 1 -.. . . . J tI 1 Cl tI 1 tr 1 e n tI 1 tr 1 ~ Z g tI 1 ~ O tI 1