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HomeMy WebLinkAbout20020513Order No 29026.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AN ENERGY COST FINANCING ORDER AND AUTHORITY TO INSTITUTE AN ENERGY COST BOND CHARGE. IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AUTHORITY)TO IMPLEMENT A POWER COST ADJUSTMENT (PCA) RATE FOR ELECTRIC SERVICE FROM MAY 16, 2002 THROUGHMAY 15, 2003. CASE NOS. IPC-02- IPC- E-02- ORDER NO. 29026 On March 11 , 2002, Idaho Power Company filed an Application (Bond Application) for an "energy cost financing order" authorizing the issuance and sale of up to $172 million in Energy Cost Recovery Bonds (Bonds). The Bond Application requested that the Commission allow Idaho Power to impose a usage-based Energy Cost Bond Charge (Bond Charge) ranging between 0.50 and 0.65 cents per kilowatt hour (kWh). Bond Application at 18. Consistent with its annual Power Cost Adjustment (PCA) filing and as an alternative in part to issuing Bonds Idaho Power also filed an Application (PCA Application) on April 15, 2002.The PCA Application, which included final forecast and true-up computations for this year s PCA reiterated the Company s request that it be allowed to issue Bonds to recover up to $172 million from customers over three years and recover the remaining true-up and forecast costs over a one- year period using the traditional PCA rate. Idaho Power provides electric service to approximately 370 000 customers in southern Idaho. In this Order, the Commission denies Idaho Power s Application for authority to issue Bonds. Instead, the Commission authorizes the recovery of $244.4 million over a one-year period and defers $11.5 million to be recovered from the Irrigation and Small General Service classes in the 2003-2004 PCA. We also discontinue the three-tiered rate structure for residential customers. The Commission finds it appropriate to recover this year s PCA surcharge from customer classes using a flat cents per kWh rate. Finally, the Commission authorizes Idaho Power to implement a tariff rider to collect one-half of one percent (0.5%) of each customer class s base revenues to fund Demand-Side Management (DSM) programs for its customers. ORDER NO. 29026 I. BACKGROUND A. Statutory Authority for Bonds In 2001 , the Idaho Legislature passed Senate Bill 1255 (codified at Idaho Code 61-1501 et seq. ), which allows energy utilities to recover increases in their short-term costs through the issuance of moderate-term (1 to 5 years) bonds. At the time this legislation was enacted, Idaho and the western United States were experiencing extraordinarily high wholesale energy market prices and the second-worst water conditions ever recorded in Idaho. By enacting this legislation, the Legislature provided an alternative to large rate increases caused by Power Cost Adjustments (PCA) and other cost recovery mechanisms by permitting the issuance of multi-year Bonds. Idaho Code ~ 61-1501. Thus, the legislation provides electric and gas public utilities with a mechanism to recover extraordinary fuel or power costs immediately while leveling" the rate impact on customers. Idaho Code ~ 61-1503(2) states that the Commission shall not issue an energy cost financing order unless the sum of: (1) any PCA then in effect; (2) plus any Bond Charge then in effect; and (3) the amount identified in the utility's PCA Application would exceed a minimum threshold amount previously approved by the Commission. In June 2001 , the Commission established this minimum threshold amount as one cent per kWh (or approximately $128 million in annual revenues) in Case No. IPC-01-19. Order No. 28761. Because the Company alleged the amount recoverable in the present PCA Application will exceed this threshold, Idaho Power requested authorization to spread recovery of the $172 million over three years by issuing Bonds rather than recovering it through the standard one-year surcharge. In reviewing Idaho Power s Bond Application, the Commission must determine if the public interest would be better served by recovering the PCA amounts over the term of the proposed Bonds (i., three years) or by a one-year recovery period without Bonds. Idaho Code ~ 61-1503(1). If it finds the Bond issuance to be in the public interest, the Commission shall issue an energy cost financing order to allow Idaho Power to recover the approved PCA amount. Id. B. History of PCA Because Idaho Power Company is an electric utility that relies predominantly upon hydroelectric generation, the Company s actual costs of providing electricity (i., its "power supply costs ) can vary from year to year depending upon changes in streamflow and market ORDER NO. 29026 pnces. When streamflows or snowpacks are low, Idaho Power must rely increasingly upon its other generating resources and/or off-system market purchases that are more costly than its hydro generation. Conversely, in years of abundant streamflows with correspondingly plentiful inexpensive hydro generation, the Company s power supply costs are lower. To ameliorate the adverse consequences of fluctuating power supply costs both to customers and the Company, the Commission instituted a "power cost adjustment" (PCA) mechanism in 1993. The PCA is comprised of two major components. First, the Company is allowed to recover its above normal power supply costs ! for the preceding 12 months2 including off-system purchases used to serve Idaho system load.3 Second, rates are adjusted on an annual basis to compensate for the forecasted succeeding 12 months' power supply costs based on expected Snake River streamflows and storage. Order No. 24806 at 2-3. For example, for projected periods of low water, the Company is allowed to recover its costs to generate or purchase the necessary replacement power. For periods of high water, customers experience credits from the sale of surplus power. Thus, under the PCA mechanism ratepayers receive a credit when power costs are low and are assessed a surcharge when power costs are high.4 During the nine years that the PCA has been in effect, there have been three annual credits that benefited ratepayers by approximately $57.5 million. Until last year s extraordinary power costs, the PCA surcharge has not exceeded $17.3 million a year. Idaho Power rates are adjusted each May after the Company files its PCA Application. The PCA rate usually extends from May 16 to May 15 of the following year. Procedurally, PCA cases are normally processed on an expedited basis through the submission of written comments. IDAPA 31.01.01.122.02. 1 The term "power supply costs" means additional purchases and fuel costs plus decreased surplus sales revenue. 2 Although the PCA mechanism historically recovers amounts accrued over 12 months, this PCA Application seeks to recover 13 months of costs because last year s PCA only recovered costs for 11 months. See Order No. 28722 at 3 The term "Idaho system load" means that amount of electricity necessary to serve Idaho ratepayers. 4 The Company may recover 90% of the difference between the projected power cost and the Commission approved base power cost. Order No. 25880. 5 Last year the Commission authorized Idaho Power to recover $217 million in PCA costs. ORDER NO. 29026 C. The Bond Application The Company proposes to finance approximately $172 million of accrued PCA costs by issuing Energy Cost Bonds. Idaho Power s retail customers would pay the Bonds back over a planned three-year period itemized on their monthly bills. By statute, the charge would be based on energy consumed - a charge per kilowatt-hour. The $172 million represents three primary components: (1) $147 million of Idaho Power s PCA costs associated with voluntary load reductions for irrigation customers and for Astaris LLC; (2) $18 million of the remaining uncollected expenses associated with the October 1 , 2001 PCA rate increase; and (3) up to $7 million in estimated overhead costs for issuing the Bonds. The Company anticipates the Bonds will carry a 4.5% interest rate, which it described as the best bond rate attainable. Tr. at 291. If the Commission approved the sale of the three-year Bonds, a special purpose financing entity (SPE) would be created. The SPE would then issue Bonds and Idaho Power would convey reimbursement rights to the SPE. Finally, customers would be assessed a monthly Bond Charge to repay the SPE. D. The PCA Application This year s PCA includes forecasted costs and a true-up of last year s forecasted costs to actual costs. The forecast rate of .2156~ per kWh is expected to recover approximately $28. million. PCA Application at 3. The true-up amount that the Company would include in this year s PCA is approximately $223.3 million. Id. at 4. The Company proposes to recover $147 million of the true up amount over three years by bonding, which would require the Company customers to repay the cost of the bonds. The remaining true up amount, $76.3 million, would be recovered with a one-year PCA rate of .5785~ per kWh. Tr. at 294. The Company estimates first year bond cost to customers to be .5600~ per kWh. Tr. at 295. The PCA costs would be an additional .7941~ per kWh which includes the additional true-up and the forecast costS.6 This year s total PCA rate including bonding would be 1.3541~ per kWh which would provide an average rate reduction of 6.64 percent, 5.38 percent to the residential class. Tr. at 295. If the Commission denies the Company s request to issue Bonds, the Company requests authority to implement a Power Cost Adjustment (PCA) of 2.2885~ per kWh applicable to all customers for the period May 16, 2002 through September 30, 2002, and a PCA of 1.9059~ 6 .7941~ = .5785~ + .2156~ ORDER NO. 29026 per kWh for the period October 1 , 2002 through May 15, 2003. Tr. at 271. In other words, the Company seeks to recover $223.3 million in additional power supply costs incurred from March 2001 through March 31 , 2002 and $28.5 million for next year s projected power supply costs in a single year. Approximately $18 million remains on the current PCA for recovery during the October 1 , 2001 through September 30, 2002 time period, thus making the total amount requested $269.7 million. If approved, this single year recovery alternative would result in an average rate increase of 10.1 % to all customer classes effective May 16 2002. Tr. at 271-72. On October 1 2002, customer rates would decrease by an average of 6.2%. Tr. at 272. E. Proceedings Although the Company filed separate Applications for authority to issue Bonds and to recover the PCA costs, the Commission consolidated the Applications into a single proceeding. Order No. 28988. The Commission further established deadlines for intervention and public comment, scheduled public workshops and hearings, and set a technical hearing for April 26 2002. To gather public input on the Bond and PCA Applications, the Commission held three workshops and public hearings in Twin Falls, Pocatello, and Boise. Approximately 84 people attended the workshops and 77 people attended the three hearings. Of those who attended, 30 people testified at the hearings. In Order No. 28988 , the Commission also solicited written public comments regarding the Applications to be filed on or before April 26, 2002. The Commission received 274 timely written comments from the public. F. Parties The following persons were made parties to the Bond and PCA proceedings. Parties Counsel Idaho Power Company Larry D. Ripley Commission Staff Lisa Nordstrom Deputy Attorney General Land & Water Fund of the Rockies Idaho Rivers United Idaho Rural Council Mary McGown William M. Eddie ORDER NO. 29026 R. Simplot Company R. Scott Pasley Industrial Customers of Idaho Power Peter J. Richardson Richardson & O'Leary Idaho Power Company, Commission Staff, and the Industrial Customers of Idaho Power (ICIP) each filed written testimony. With the permission of the Commission and other parties, the Land & Water Fund of the Rockies, Idaho Rivers United, Idaho Rural Council and Mary McGown (collectively referred to as the Conservation Groups) provided written comments directed solely at policy issues involving residential tiered rates and funding of Demand-Side Management (DSM) conservation programs. J.R. Simp lot Company did not file written testimony and did not participate at the technical hearing. Staff and the Company participated in all of the public hearings. With this background, we turn to the issues. II. COMPONENTS OF THE POWER COST ADJUSTMENT A. The Water Forecast As explained above, the forecasted water conditions for the next 12 months are the second component of the PCA. In their respective testimonies, Idaho Power witness Greg Said and Staff witness Keith Hessing agreed that expected power supply costs for the period April 1 2002 through March 31 2003 totaled $106 509 695, based on forecasted April through July 2002 stream inflows into Brownlee reservoir.Tr. at 267; 490-91. Above normal forecast costs totaled $33.4 million, of which the Idaho jurisdictional share is $28.5 million. Staff and the Company agreed that a rate of .2156~ per kWh was necessary to recover anticipated power supply costs. Tr. at 268; 490. Staff witness Hessing testified that this rate is based on projected Brownlee April through July inflows of 3.63 million acre-feet, which are only 58% of normal due to last year s drought. Tr. at 490. The other parties did not dispute these calculations. Commission Findinf!s Based upon our review of the record, the agreement of Staff and Idaho Power, and the lack of any disagreement by the other parties, the Commission finds that the appropriate PCA rate attributable to predicted streamflows is .2156~ per kWh. The PCA was designed to allow consistent recovery of anticipated power supply costs, particularly when less water is available for hydro generation. Thus, the Commission finds it reasonable and in the public interest to allow recovery of the forecasted power supply costs in the current 2002-2003 PCA. ORDER NO. 29026 B. Excess Purchased Power Supply Costs Of the total $269.7 million PCA revenue requested by the Company, approximately $223.3 million is attributable to last year s unrecovered power supply costs. This amount includes $185.9 million resulting from the irrigation and Astaris load-reduction programs. Case Nos. IPC-01-3 and IPC-01-9. The $223.3 million requested by Idaho Power also includes approximately $18 million authorized for recovery by Order No. 28852 last October that has not yet been recovered. Staff recommended that the Commission only allow recovery of $207.3 million of the $223.3 million in power supply costs. Staff indicated that these costs were reasonably and prudently incurred to serve the Company s Idaho customers. The Company and Staff agreed on one adjustment regarding real-time pricing. Idaho Power s PCA Application decreased the true-up component by approximately $4.3 million to reflect the repricing of "real-time" power purchases from July 2001 through March 2002. These purchase transactions were originally priced under the Federal Energy Regulatory Commission s (FERC) method, in which Idaho Power received IE's highest purchase price in any hour for energy transfers to IE and paid IE's lowest sales price in any hour for energy transfers from IE. Tr. at 282. However, Idaho Power asserted ratepayers were disadvantaged under the FERC method because at times these transactions were: unrelated to the Northwest markets; there was no weighting by volume; and there were more trading hours without real-time transactions in them than when both purchases and sales were used. Tr. at 283. Although not approved by FERC, Idaho Power proposes to use a weighted average of all relevant IE purchases and sales transactions to set the real-time prices for transactions with Idaho Power. This weighted average method would provide a market proxy for what Idaho Power would have paid or received from a non-affiliate and was initially approved by this Commission in Case No. IPC-OO-13. Tr. at 283. Idaho Power witness Gale further testified that the Company continues to work with FERC to resolve this issue. Tr. at 285-86. Staff reviewed the Company s real-time adjustment and agreed that it was needed to reflect a more equitable transfer pricing methodology for both the Company and its customers. Tr. at 421. The other parties did not take a position on this issue. Commission Findinf!s The Commission finds that the real-time pricing adjustment which was agreed to by the Company and the Staff, is reasonable and should be adopted. Thus ORDER NO. 29026 the PCA's true-up component should be decreased by $4 306 635.82 to reflect the repricing of real-time transactions from July 2001 through March 2002. This adjustment benefits ratepayers and allows real-time pricing to be based on regional markets that reflect the cost of power bought and sold in the Northwest, rather than the United States as a whole. Moreover, it is consistent with the methodology approved by this Commission in Case No. IPC-OO-13. Staff also recommended that $16 million in unrecovered power supply costs be More specifically, the Staff recommended four adjustments for: 1) irrigation lostdenied. revenues; 2) mobile generation expenses; 3) Mountain Home gas transportation costs; and 4) Williams capital facility charge be denied recovery in the PCA. Tr. at 423-28. Parties other than Idaho Power neither supported nor disputed the Staffs four adjustments. We address the Staffs four adjustments below. 1. Irrigation Lost Revenue Adiustment.Last year, the Commission approved a program to pay irrigators to reduce their consumption of energy and authorized Idaho Power to recover its direct costs associated with the program in this year s PCA. Order No. 28992. Staff verified $73 941 839.42 in direct program costs and that they were properly included in the PCA account. Tr. at 424. In addition to these direct costs, Idaho Power calculated that it "lost" $15 146 639.32 in revenue when irrigators participated in the Irrigation Load Reduction Program.Staff recommended disallowance of the "lost" revenues per Order No. 28992, in which the Commission denied recovery of the Company s reduced revenues. Id. Commission Findinf!s This issue has been thoroughly addressed during the proceedings in Case No. IPC-01-34. In that case we stated , " in the context of the market situation that existed at the time this Program was approved, it was the prudent if not required action for the Company to take and that further incentives, such as the recovery of lost revenues to develop and utilize a program of this type were not needed.Order No. 28992 at 7- Consistent with our final Order in Case No. IPC-01-, we disallow recovery of the $15 146 639.32 included by Idaho Power. 2. Mobile Generation Adiustment.Because forward market prices for the summer and fall of 2001 were projected to be more than $200 per megawatt-hour, Idaho Power leased 25 7 "Lost" revenue refers to revenue that the utility would have earned if it had sold power to the participating irrigators instead of paying the irrigators to reduce their electric consumption. 8 On May 2 2002, Idaho Power filed a Petition for Reconsideration in Case No. IPC-01-34. ORDER NO. 29026 diesel-powered generation units during the months of May through October 2001. After installing and operating 17 of the 25 units for a few days, Idaho Power shut them down because of complaints from nearby homeowners and attempted to relocate them. The remaining 8 units had not yet begun the siting permit process when the Company applied for new siting permits for the 17 units that were to be relocated. After FERC-mandated price caps were implemented for western energy trading in June 2001 , the market price of purchased power dropped below the operating cost of the units. As a result, the units were not operated after that time. In September 2001 , the Commission authorized the Company to use the PCA mechanism when it sought to recover its mobile generation expenses. However, the Commission stated that recovery of such expenses would occur after first determining whether the expenses were reasonably incurred. Order No. 28837 at 7. In comments filed in Case No. IPC-01- that were included with Staff witness Alden Holm s testimony in these cases, Staff expressed concern that the Company s voluntary shut down of the 17 units was unreasonable and costly to the general body of ratepayers. Staff Exhibit No. 101 at 3. By never applying for siting permits for eight of the generators, Staff argued that ratepayers were subjected to paying for the units without any offsetting benefits. Id.Thus, Staff recommended in this proceeding that the Company s associated power costs be reduced by $3 832 663 to reflect diesel generation costs and purchased power benefits that would have occurred if the 25 generating units had been continuously dispatched against market prices beginning May 1 , 2001. Tr. at 425. Idaho Power did not address Staff s recommended adjustment in its testimony. Commission Findings. As a preliminary matter, the Commission first addresses a procedural" argument made by Idaho Power during the April 26, 2002 technical hearing. While questioning Staff witness Alden Holm on his proposed disallowance of mobile generator expenses, counsel for Idaho Power argued: Staff has not presented any new evidence to allow or to contend for any disallowance. They simply relied upon what they previously submitted to the Commission, what the Commission had. . . before when it issued the orders authorizing the inclusion of certain costs in the PCA. Tr. at 448.However, Idaho Power s argument is misplaced. The question is not whether the Staff s evidence is "new" or "old" but if it is relevant to the question of whether mobile generator expenses were reasonably incurred. In Order No. 28837 issued in September 2001 , we stated: ORDER NO. 29026 We make no decision in this case regarding the dollar amount to be included in the PCA nor do we foreclose the Staff or other parties from challenging the reasonableness of said amounts when the Company requests recovery. Order No. 28837 at 7. With these words the Commission made clear that while the Order allowed mobile generator expenses to be recovered through the PCA, we did not approve a specific dollar amount for recovery until the expenses could be formally reviewed in the Company s PCA filing. Thus, the Commission did not authorize a recovery amount for Idaho Power s mobile generators at that time and purposely left the issue open. Although Idaho Power s counsel argues that the Commission "simply got a regurgitation of a prior argument made already to the Commission " we find Staffs IPC-01-14 comments as incorporated into its filed testimony in these cases to be adequate evidence regarding this issue. Tr. at 448. Staff was not required to provide additional evidence. In fact, Staff simply resubmitted its prior consistent comments which does not make this evidence defective. As the record stands, Staff s recommendation to disallow $3 832 663 of the mobile generator expenses has not been rebutted by Idaho Power. We now turn to the substantive issue of whether or not the Commission should authorize recovery of the Company s mobile generator expenses. In September 2001 , the Commission directed Idaho Power "to plan for (deficient) power supply in advance and take prudent steps to have adequate, reliable supply available. Order No. 28837 at 6. We also recognized in that Order that if months later it appears "that other options turned out to be lower cost, (that fact) does not invalidate the prudent decision made based on information known at the time.Id.In other words, we would evaluate the reasonableness of Company actions in the context of the known information and events at that time.With this standard in mind, the Commission generally finds that the acquisition of generation units at that time was prudent and reasonable. Although leasing the units was reasonable, it is apparent that the Company s decision about where to operate the units is less so. We share the Staffs concerns regarding Idaho Power s unilateral decision to idle and relocate 17 of the 25 generators without the permits necessary to resume operation in another location. Had those 17 generators been operational Idaho Power could have purchased less power on the costly wholesale market. However, we also recognize the concerns expressed by nearby residents regarding whether the units were placed at appropriate locations even though the sites were properly permitted. The other eight ORDER NO. 29026 units were not operated. We find it reasonable to allow recovery of the costs associated with the 17 generating units and power purchase costs incurred as a result of shutdown. However, we disallow the costs associated with the failure to site and operate the remaining 8 units. Ratepayers never had an opportunity to receive benefits that would have occurred had these 8 units been properly sited and operated. These units were never used and useful in generation of power. Therefore, the Commission disallows recovery of $1 226 452 of purchase power costs because the 8 units never operated during May and June 2001. 3. Mountain Home Gas Transportation Adjustment.In Order No. 28773, the Commission allowed Idaho Power to account for and recover expenses associated with fuel and transportation for its natural gas fired plant in Mountain Home through the PCA mechanism. Although Idaho Power is not required to pay for unneeded fuel, the Company must pay for firm fuel transportation if it intends to use the plant when market prices are higher than the cost of running the plant. Staff argued that $682 272.40 of the Company s $3.3 million in fuel expenses should be disallowed because the plant was not operational during part of the time period for which Idaho Power had contracted for firm fuel transportation. Tr. at 427. The Company contracted for firm transportation on April 11 , 2001 , projecting that the plant would be finished in July 2001. However, due to various delays, the plant did not operate until September 25 2001. Staff maintained that because customers never had the opportunity to benefit from the transportation expense incurred by the Company during the months of July, August and most of September, it was not "used or useful" during that time period. Id. The Company did not address this issue in its testimony. Commission Findinf!s We find that payment for firm transportation prior to the facility becoming operational was not a reasonable expense. Once the plant is operational, it is important to have firm transportation available so that the plant can be operated when market prices are higher than the cost of running the plant. However, the Mountain Home facility did not require a firm transportation commitment when non-firm options would have satisfied the Company s testing, maintenance and training requirements before the plant became operational. The Company was not able to mitigate these expenses by reselling the unnecessary firm 9 $1 226 452 = (8/25) x (3 832 663) ORDER NO. 29026 transportation because there was little demand for firm transportation in the summer months. Because ratepayers never had an opportunity to benefit from the plant and it was not used and useful until September 25, the Commission disallows recovery of the $682 272.40 associated with this period. 4. Williams Facility Charge Adjustment.Williams Gas Pipeline West (Williams) charged Idaho Power the first annual billing for payment of $419 054 to install a meter station control equipment, and a 4 200 foot pipeline from the mainline to Idaho Power s Mountain Home natural gas facility. A fluctuating annual facility charge will pay for these items over the next 30 years. Staff argued that this charge is more like a capital cost than an annual gas delivery expense. Thus, it would be more appropriate to seek recovery of this amount as a capital asset cost in ratebase than to be recovered through the PCA. Tr. at 427-28. The Company indicated that because it is booked to a PCA-appropriate account, is fuel-related, and varies year to year the facilities charge is appropriate for inclusion in the PCA. Tr. at 561. Commission Findinf!s The Commission finds that although the facilities charge is not a capital expense per se, it has many of the characteristics of a capital expense normally recovered as an asset in rate base. The charge pays for plant investment over time and includes expenses related to depreciation, interest, a return and maintenance on the plant investment. Although this charge enables Idaho Power to buy fuel from Williams, the repayment structure over 30 years is typical of a capital investment. Thus, the facilities charge should be considered for recovery in Idaho Power s next rate case - not in this PCA case. The $419 054 shall not be recovered through the PCA. In summary, the Commission finds that $209 414,437.79 in excess power supply costs should be recovered through the PCA mechanism as true-up expenses that were reasonably and prudently incurred. III. RECOVERY OF DEFERRED PCA AMOUNTS Having determined that the Company is authorized to recover $255.9 million through the PCA, we next must decide how this amount is recovered from ratepayers. The Commission was presented with a variety of methods to recover the deferred PCA costs. These options included securitizing a portion of the amount through the issuance of Bonds, instituting a to $255 894 232 = 28 479 794 (forecast) + 209 414 438 (true-up) + 18 000 000 (unrecovered October 1 2001 PCA). ORDER NO. 29026 multiple-year recovery without issuing Bonds, and implementing a traditional single-year recovery. We address these alternatives below. A. Energy Bonds 1. Idaho Power. Idaho Power s preferred method of recovering a portion of the deferred PCA amount is to securitize the amount by issuing Bonds. According to Idaho Power witness Ric Gale, spreading the recovery of a portion of these costs over a number of years offers an opportunity to reduce rates immediately and finance these costs at favorable interest rates. Tr. at 288. The Company proposes to issue $172 million in Bonds. When both the fees and interest are considered, the average percentage rate of the financing will range from 5.9% to 7. depending on the final administrative costs. Tr. at 294. Mr. Gale testified that authorizing bonds would immediately increase the Company cash flow and improve its financial ratios because rating agencies exclude bond financings in their ratio analysis. Tr. at 298. The Company proposed that the remaining true-up costs , $76 million, and the water forecast amount of $28.5 million be recovered in one year through a separate PCA rate. Moreover, Idaho Power witness Greg Said calculated that issuing three-year energy bonds would result in an immediate rate decrease of 6.6%. Tr. at 272. 2. ICIP . The Industrial Customers of Idaho Power (ICIP) supported the concept of bonding but urged the Commission to spread the proposed rate increase over a period of five years (the maximum amount of time allowed under the energy Bond statute). The ICIP believes last year s rate increases put Idaho s industry at a serious competitive disadvantage that may be aggravated if a rate reduction is not immediately forthcoming. Tr. at 373-74. According to ICIP witness Stuart Trippel, bonding appeared to be " a fair and equitable way to accomplish this goal with minimal financial impact on Idaho Power and its ratepayers.Tr. at 273. The ICIP advocated spreading recovery over five years because "the benefits of extending the pay back and further lowering our rates far outweigh the perceived harm from pancaked rates." Tr. at 374. 3. Commission Staff.Although it acknowledged the benefits Idaho Power would receive if Bonds were issued, Staff did not support the issuance of Bonds because "the costs and risks to customers for securitization outweigh the benefits to customers." Tr. at 433. According to Staff, issuing Bonds would alter the existing PCA mechanism s allocation of responsibility for carrying charges on the deferred amounts during recovery from the Company to customers. Tr. at 431. Staff was also concerned about additional expenses to be paid by customers, that would ORDER NO. 29026 include up to $7 million in initial borrowing fees, $1.5 million in ongoing servicing fees and trustee expenses, and approximately $12 million in interest expenses over the three years. Tr. 432. Staff also feared a "pancaking effect" would result if customers are paying off the Bonds at the same time large future PCA expenses must be recovered. Id. Commission Findinf!s.Based on our review of the record in this case, the Commission denies the Company s Bond Application. The Commission has carefully reviewed Idaho Code ~ 61-1503(1), which states in pertinent part: . . .if the commission finds that the public interest would be better served if the energy cost amounts were recovered through the issuance of energy cost recovery bonds over the term of such bonds than if the ECA amounts were recovered over a period of one (1) year, assuming a conventional financing of such amounts, the Commission shall issue an energy cost financing order to allow the public utility to recover energy cost amounts. The Commission finds that the public interest is better served in this instance by recovering the vast majority of the $255.9 million authorized in this Order over a single year as originally contemplated by the PCA mechanism rather than spreading large amounts of recovery over multiple years. We reach this conclusion largely out of our concern for uncertainties the future may hold. One of our primary concerns is the water supply necessary to generate the electricity that Idaho Power relies on to supply 60% of its system load. Snowpacks the last two years have been significantly lower than average, particularly in the upper Snake River Basin. Idaho reservoirs have not yet refilled and the opportunity to generate hydroelectricity is thus diminished in the near term.If another drought year were to occur while Bonds were outstanding, electricity rates could easily climb again. In addition to the unpredictability of the weather, the Commission is concerned about potential volatility in the western wholesale power markets once FERC's price mitigation orders terminate on September 30, 2002.11 Although structural changes have been made to the regional wholesale market since FERC's orders were issued in 2001 , prices may escalate again once the price restrictions are removed. The Commission is loath to knowingly enter a period of market uncertainty with large amounts of deferred PCA costs slated for recovery through 2004. 11 San Diego Gas & Electric Company, 95 FERC ~ 61 418 (June 19 2001). ORDER NO. 29026 The Commission is also concerned that the longer power supply cost recovery is delayed, the greater the risk that the customers taking service when the deferred costs were incurred will not be the same customers that will later pay for them. A significant number of public commentors, in writing and at the public hearings, indicated that it was preferable to pay off the PCA amount in a single year rather than pay the carrying costs associated with deferral. We largely agree with this sentiment. The Commission also questions the fairness of requiring Idaho Power ratepayers to pay the approximately $21 million in interest and fees associated with energy bonds when IdaCorp s unregulated subsidiaries will benefit as a result. Tr. at 332- 567-68. Based on the facts of this case, we find it unreasonable and contrary to the public interest to mortgage the future of ratepayers simply to achieve a small rate decrease this year. The Commission is sympathetic to the concerns of the Industrial Customers that a rate increase will place them at a competitive disadvantage. However, spreading recovery over multiple years in exchange for a small decrease this year will prolong high power rates and delay the substantial rate decrease that all customers seek. Adding nearly $21 million in bond fees and interest to the $269.7 million requested by Idaho Power is an expensive price to pay for the option of multi-year PCA recovery. Thus, the Commission declines to authorize issuance of energy bonds for recovery over three years, or over five years as the Industrial Customers requested. According to the testimony of Idaho Power witness Gale, only one year of extraordinary high costs remain to be recovered through rates. Tr. at 288. We certainly hope that this is the last year Idaho Power ratepayers will be faced with such extraordinarily high deferred PCA costs. However, as we have learned over the past two years, there are no guarantees about future streamflows or market prices. In short, the Commission does not want to spread large amounts for recovery out over multiple years, and it is not cost-effective to securitize smaller amounts. Tr. at 433. Because mortgaging our future through the issuance of Bonds is not in the public interest at this time, we turn our discussion to other recovery options. B. Other Recovery Alternatives 1. Idaho Power. Under normal operations, the PCA surcharge or credit is effective over a 12-month period. If the Company s energy bond proposal were rejected, Idaho Power has indicated that its secondary proposal is the one-year recovery associated with traditional PCA ORDER NO. 29026 treatment. Tr. at 272. That proposal would increase existing rates now and reduce them on October 1 , 2002 as the second part of last year s PCA increase expires. 2. Commission Staff.Staff presented four recovery options in its testimony. The first option consisted of the Company s securitization proposal with Staffs adjusted true-up. Option No.2 recovered all of the PCA costs in the first PCA year, which required an increase above existing rates. The third option continued the existing rates in the first PCA year and carried the unrecovered costs over to the 2003 PCA year with interest. Staff Option No. reduced rates in the first year by an average amount of9.6% and carried the unrecovered amount into the 2003 PCA year for recovery.Staff recommended the fourth option because it immediately decreased rates, recovers the PCA costs in two years, and avoided bonding costs and some of the interest associated with securitization. Tr. at 496. 3. ICIP. The ICIP requested that if a multiple-year recovery option were adopted by the Commission, the Industrial Customers would like a one-year option to be offered. Tr. at 359. Under such an arrangement, individual customers within a certain schedule or who use a threshold amount of kilowatt hours could choose by a date certain to pay the entire amount based on the customer s historical consumption within one year, rather than extend payment of the PCA amount over multiple years. Tr. at 360-, 363 , 366. At the end of the year, the estimated one-year payment amount would be trued-up to reflect actual usage. Tr. at 366. Commission Findinf!s While the Commission understands the reasons why cost recovery or some portion thereof might be amortized over time, the Commission largely declines to adopt this recommendation. As with any requested rate increase, the Commission must balance the needs of the Company to maintain its financial viability and recover its reasonable expenses with customer concerns of fair rates and rate stability. During the last two years extraordinary conditions have resulted in large purchase power costs and a low water forecast. Given the amount of purchases the Company has already made, it is reasonable and appropriate for the Company to recover the majority of the $255.9 million approved for recovery within the normal one-year timeframe. The Commission does not make this decision lightly. We understand the hardships that continuation of last year s large rate increase will impose on customers. However, as we stated in our Energy Bonds findings, the Commission is very concerned about the unknown water and market conditions that lie ahead. Weare also reluctant to create a situation where ORDER NO. 29026 customers are required to continue paying costs from this year on top of whatever increases may be required in future years. Passing through the majority of the PCA costs in one year will be unpleasant and create a hardship for some customers, but it will clear the way for significant rate decreases in the future barring any unforeseen circumstances. The PCA was designed for a single-year recovery of PC A costs and we continue to honor its original design. We noted in the original PCA Order that if the PCA were to result in large rate increases, it may be appropriate to defer a percentage of that year s power supply costs. Order No. 24806 at 20. In Order No. 28722 issued in last year s PCA case, we declined to spread recovery out over a period longer than one year despite the large rate increases that resulted. When forced to increase rates yet again this year, we find it is appropriate to make some rate allowances for the Irrigation (Schedule 24) and Small General Service (Schedule 7) customer classes. At the public hearings, several irrigators testified that they were not aware that a 7% increase in irrigation rates was approved by the Commission last October. Tr. at 102-, 121-22. This can largely be attributed to the fact that most irrigators typically end their seasonal usage in October. Thus, the irrigation class as a whole had very little opportunity to adjust to the October rate increase. Moreover, it is likely that the typical irrigator did not include that increase in his/her budget when calculating expenses for 2002. Tr. at 122. Rather than increase irrigation rates by 11.5% to recover the $35.6 million allocated to the irrigation class in a single year, the Commission finds it appropriate to defer $11.0 million for recovery in the 2003-2004 PCA and recover the remaining $24.6 million in irrigation rates this PCA year. Although the majority of the irrigation class s PCA costs will be recovered in the traditional PCA period, deferring the $11.0 million willlirnit their rate increase to the 5.051~ per kWh rate ordered last May in Order No. 28722. The $35.6 million in total PCA costs allocated to the irrigation classjncludes the $20 134.29 attributed to the irrigation class in Order Nos. 28699 and 28770 for intervenor funding. The Commission also finds it reasonable to defer $600 000 of the total $5.2 million in PCA expenses attributable to the Small General Service customer class (Tariff Schedule 7) until the 2003-2004 PCA year. The Small General Service class typically includes small businesses 12 If confronted again with extraordinary power costs, another alternative would be to implement an immediate interim surcharge rather than defer such costs for recovery in the next 12-month PCA. ORDER NO. 29026 and outbuildings that use less than 3 000 kWh per month. With the exception of the Lighting classes, the Small General Service class was the only class to have rates set in excess of 8~ per kWh after last October s rate increase. Order No. 28852. Rather than raise their rates above the already high 8.021~ average rate Schedule 7 customers currently pay, the Commission finds it appropriate to minimize hardship to this class by continuing their current rate for this PCA year and to allow recovery of the remaining portion next year. IV. THE CARRYING CHARGE By previous agreement between the Company and Staff, a single Commission- approved carrying charge or interest rate (i., the interest rate paid on customer deposits effective at the beginning of the PCA year) has previously been used to calculate interest on balances for all months in the PCA deferral year.13 IDAPA 31.21.01.106. The carrying charge used during the 2001-2002 PCA deferral period is 6%. The carrying charge for calendar year 2002 is 4%. Prior to this Order, the Commission had not determined the appropriate carrying charge if balances were ordered to be carried for periods longer than one year. The parties recommended several interest rates. 1. Idaho Power.Because deferral balances are greater than ever anticipated and the energy crisis has disrupted the "symmetry of outcomes" originally envisioned for the PCA, Idaho Power recommended changing the interest rate applied to the deferral balances to be the same as the Company s overall rate of return (9.2%) on a prospective basis beginning June 1 , 2002. Tr. at 295-96. The Company asserted that the overall rate of return more appropriately reflects the Company s significant costs of financing large balances. 2. Commission Staff.Staff did not agree with using the Company s overall rate of return for calculating the carrying charge, largely because steps have been taken to limit the amounts in the deferral account going forward. Tr. at 434. Instead, Staff advocated leaving the PCA mechanism unchanged with carrying charges continuing to accrue at the customer deposit rate (4%). However, Staff also recommended that the Company should be able to accrue interest equal to the larger of its short-term debt rate or customer deposit rate for amounts held in the deferred account longer than the traditional one-year recovery period. Tr. at 435-36. 13 This practice was instituted to simplify the true-up calculation and adopts the interest rate established by the Commission at the beginning of each calendar year. ORDER NO. 29026 3. ICIP.The ICIP stated that it is reasonable and fair for the Company to receive interest on deferrals, but it did not specify an interest rate to be applied. Tr. at 377. Commission Findinf!s To remain consistent with prior PCA case~, the Commission declines to change the rate applied to PCA balances in the deferral period and continues to find it appropriate to apply the 4% customer deposit interest rate to the deferred balances. The current customer deposit rate of 4% will be applied to balances being deferred during the traditional 12- month PCA deferral period of April 1 , 2002 through March 31 , 2003. However, the Commission also recognizes the additional costs associated with large deferral balances - particularly those extending beyond the traditional one-year PCA recovery period. Thus, the Commission finds in this instance that it is appropriate for the Company to receive a higher interest rate than the current customer deposit rate of 4% on the $11.5 million that will be deferred for recovery beyond one-year.The Commission finds that 6% is reasonable rate. This carrying charge is higher than the deposit rate and short-term debt rate but lower than the rate of return. This rate is also reasonable given that it was the customer deposit rate applicable in the 2001 PCA year when the deferral amounts were incurred. V. FUNDING OF DEMAND-SIDE MANAGEMENT PROGRAMS 1. Idaho Power. In response to Order No. 28922 , Idaho Power Company proposed a tariff rider as a means of funding conservation or Demand-Side Management (DSM) programs in Case No. IPC-OI-13. The rider, as proposed, would be 0.5% (one-half of one percent) of the Company s base revenue requirement on all electric bills for all customer classes. It has been estimated that the rider would provide approximately $2.6 million annually for DSM measures. Tr. at 500.An Energy Efficiency Advisory Group - comprised of customer representatives Company and Commission Staff personnel, and conservation program experts - has been formed to review DSM programs for all customer sectors and make recommendations to Idaho Power accordingly. Idaho Power supported funding conservation progi-ams through an Energy Efficiency Rider because it does not add to the already significant DSM deferred balance approximating $27 million for past DSM programs. Tr. at 310. 2. Commission Staff.Staff also supported approval of a 0.5% tariff rider to fund additional conservation efforts. Tr. at 500. Staff further recommended that the approximate $2. million generated by this tariff rider be included in rates this year. This would cause additional ORDER NO. 29026 true-up amounts to be deferred with interest to allow customers to receive the full decrease proposed by Staff for this PCA year. Tr. at 501. 3. ICIP. The ICIP testified that DSM costs should be recovered by Idaho Power on an ongoing basis and that the industrial class should be permitted to self-direct all funds collected from it for DSM purposes rather than funnel it through other agencies. Tr. at 377. 4. Conservation Groups. In their written comments, the Conservation Groups stated that the 0.5% of Company revenues recommended by Idaho Power and Staff is too low to fund all cost-effective DSM opportunities. Instead, they recommended that the tariff rider be set at a level of 1.5% of revenues. The Conservation Groups also indicated that the Commission should direct Idaho Power to initiate a comprehensive study to evaluate cost-effective DSM opportunities in its service territory, which identifies: (1) cost-effective DSM opportunities in each customer class; (2) estimated costs to fully fund those opportunities; and (3) opportunities for reductions in peak loads as well as reductions in total energy consumption. According to the Conservation Groups, the Commission should approve the tariff rider subject to later review and require Idaho Power to report regularly on DSM program implementation, costs, customer response, and new DSM opportunities. Commission Findinf!s In granting the rate increase authorized by this Order, the Commission recognizes that consumers need avenues to reduce their consumption. As we recognized in Order No. 28722, conservation and DSM programs are powerful tools Idahoans can use to mitigate the impact of this rate increase as well as ones that may occur in the future. The Commission believes that funding a comprehensive conservation program is critical given last year s market volatility and the opportunity to benefit from long-term demand-side measures. The Commission finds it reasonable to authorize a tariff rider in the amount of 0. of each customer class s base revenues to support analysis and implementation of new DSM programs. This amount may be increased in the future if necessary to take advantage of other cost-effective DSM measures as circumstances warrant. This tariff rider shall appear as a line item expense on customers' monthly bills so that customers are advised what portion oftheir bill goes toward energy conservation. This tariff rider shall be imposed as a flat $0.30 per-month charge to residential customers and as a cent per-kilowatt hour charge for all other customer classes. The maximum amount charged to any irrigation meter under this tariff shall not exceed ORDER NO. 29026 $15.00 per month. The irrigation rate will be .0301~ per kWh applied to a maximum of 50 000 kWh per meter. These charges are set out in Appendix 1 in greater detail. We recognize that this amount of funding may not be adequate to support some programs that could be very beneficial. However, we find it is a reasonable starting point and will reassess the level of this change annually. We believe the Energy Efficiency Advisory Group will be a valuable resource in recommending and evaluating potential conservation programs for Idaho Power.The Commission expects that the Advisory Group will meet frequently to recommend the initial DSM programs and at least quarterly thereafter. The Company shall file an annual written report to the Coinmission detailing: the Advisory Group s recommendations, the Company s response to those recommendations, the associated program costs, the DSM accounting numbers customer response data, and information on new DSM opportunities. Idaho Power shall file this annual report no later than January 30 of each year, so that the Commission may review the DSM programs and adjust the rider if necessary when the new PCA rate is implemented in May. Furthermore, Idaho Power shall consult the Energy Efficiency Advisory Group regarding the need to initiate a comprehensive DSM study of the IPC service territory relative to the priority for DSM funds to identify: (1) cost-effective DSM opportunities in each customer class; (2) estimated costs to fully fund those opportunities; and (3) opportunities for reductions in peak loads as well as reductions in total energy consumption. The Commission is particularly concerned about DSM programs for the Residential Class. As discussed in further detail below, the return to a uniform residential rate will eliminate the less costly rate designed to provide a reasonable rate for basic electrical service necessary for customer health and safety. It is our hope that the programs created by the DSM rider will empower customers to exercise control over their energy consumption and reduce their bills. see the merit of the three efforts (Energy Code Support, Public School Energy Efficiency and Residential New Construction Pilot) cited by Idaho Power in its May 2, 2002 DSM report as beneficial programs that could be quickly developed and deployed. However, we believe residential DSM dollars are better spent on CFL coupon programs and pilot programs that can be expanded to the entire customer base rather than education alone. We also direct the Advisory Group and Idaho Power to investigate the implementation of a cost-effective, compact fluorescent light bulb (CFL) program that utilizes coupons toward their purchase or direct ORDER NO. 29026 distribution by the Company. Although the Commission previously ordered the Advisory Group to consider a Time-of-Use metering pilot program, we did not see it mentioned in the May 2 2002 report filed by Idaho Power. Order No. 28894 at 7. Consequently, we also direct the Advisory Group and the Company to evaluate and report to the Commission on the viability of a Time-of-Use residential metering program by September 12, 2002 (date certain). Although we appreciate the initiative shown by the ICIP's request to allow the industrial class to self-direct its DSM funds, the Commission finds it more appropriate to retain oversight of the expenditure of funds collected by this tariff rider. We encourage representatives of the industrial class to participate in the Energy Efficiency Advisory Group to ensure that DSM dollars collected by this tariff rider will also benefit their class. VI. RATE DESIGN Rates are normally adjusted each May once the Commission determines the appropriate revenue increase or decrease under the Company s PCA. As previously mentioned absent a Bond issuance, the Company s PCA filing sought to recover approximately $223. million through the imposition of a 2.2885~ per kilowatt-hour (kWh) PCA rate applicable to all customer classes for the period May 16, 2002 through September 30, 2002, and a PCA rate of 1.9059~ per kWh for the period October 1 2002 through May 15 2003. The Company requests that the new PCA rates become effective on May 16, 2002. A. Non-Residential Rates Last year in May and again in October, the Commission ordered a uniform cents per kWh charge on all non-residential customers. The May increase was effective over a 12 and one-half month period. 14 The additional increase in October was effective over a twelve-month period. Both Staff and the Company advocated that same rate design be implemented in this proceeding. Commission Findinf!s.We agree with the Company and Staff that the rate increases for non-residential customers should be implemented as a cents per kWh charge on all customers over a twelve month period. This rate design produces three PCA rates for the coming year. Irrigators shall pay 1.3415~ per kWh, the May 1 , 2001 PCA rate, for the coming year and carry 14 Although the PCA is generally recovered over 12 months, last year the Commission ordered an additional half- month of recovery to accommodate a May 1 (rather than a May 16) effective date. Order No. 28722 at 27. ORDER NO. 29026 approximately $11.0 million15 over for recovery in the 2003 PCA year. Small General Service customers shall pay 1.7241~ per kWh, the October 1 , 2001 PCA rate, and carry over approximately $600 00016 for recovery in the 2003 PCA year. All other non-residential customer classes will pay a PCA rate of 1.9370~ per kWh for the coming year with no carry-over into the 2003 PCA year. Appendix 2 shows all of Idaho Power s affected schedules and the associated average rates and increases. The table below is a simplified version of Appendix 2. CUSTOMER EXISTING APPROVED PERCENT AGE GROUP SCHEDULE SURCHARGE SURCHARGE INCREASE Irrigation 5.1~ per kWh 1~ per kWh Small General Service 0~ per kWh 0~ per kWh Large General Service 3~ per kWh 5~ per kWh Large Power Service 5~ per kWh 7~ per kWh Imposing a cents per kWh surcharge is reasonable and consistent with past PCA surcharges. We next turn to the rates for residential customers. B. Residential Rates Except for the residential customers in 2001-2002, PCA costs have historically been recovered on a uniform cents per kWh basis. Last year the Commission ordered residential PCA recovery to take place through a three-tiered inverted block rate structure. Order No. 28722 at 24. 1. Idaho Power. The utility recommended that the current residential three-tiered rate structure be eliminated in favor of a flat rate for all kilowatt-hours of energy consumption. Tr. at 301. The Company makes purchases to meet the system s load requirements rather than meet the load requirements of specific customer groups. Id. Consequently, Idaho Power argued that it is impossible to identify costs as being caused by certain customers. Id. In order for the PCA component of customers ' rates to be reflective ofthe cost ofthe energy commodity, and the nature in which the commodity is purchased, Idaho Power asserted the PCA should be uniform for all customers and all customer classes. Tr. at 302. To the extent that the energy charge is designed to recover only energy related costs, the Company argued that no cost basis exists for establishing variable energy prices based solely on quantity of consumption within customer classes. Tr. at 303. 15 $10 953 165.16 $577 033. ORDER NO. 29026 Idaho Power also recommended a flat PCA charge for residential customers for several other reasons. First, the Company argued that the current three-tiered rate structure unfairly penalizes customers who utilize electric energy for space heating and air condition and provides an incorrect price signal for customers who use less than 800 kilowatt-hours per billing cycle. Tr. at 304. Second, the three-tiered rate structure exacerbates the existing residential intra-class subsidy for recovery of fixed costs. Id. Third, the three-tiered rate structure results in the customer perception that meter reading intervals greater than 30 days are unfair. Tr. at 304- 05. 2. Commission Staff.Although the Company proposed that all rates (including residential) be uniformly increased, the Commission Staff recommended that the Commission continue an inverted three-block rate design for residential customers. However, Staff proposed that the tiered rates be modified to recognize abatement of the energy crisis and improved water conditions yet still preserve the conservation price signal. Tr. at 532. To reduce the cost burden on high energy users, Staff advocated reducing the rate difference between the first and third block from 2.2 cents per kWh to approximately 1 cent per kWh. Tr. at 534. 3. Conservation Groups. The Conservation Groups also supported continuation of a block rate design for residential customers. According to their written comments, tiered rates send an appropriate price signal and encourage customers to conserve and improve efficiency. Moreover, they supported the Commission s efforts in recent DSM-related orders to target those customers utilizing electric space heat for increased DSM program attention. 4. Public Comments. The Commission also received a tremendous public response on the issue of residential tiered rates. Of the 274 written comments received by the Commission, 132 opposed tiered rates while only 9 supported their continued use. More than 100 commentors specifically mentioned that they lived in all-electric homes. Of the 30 witnesses who testified at the public hearings about high-energy bills, 2 favored the tiered-rate structure while 16 opposed it. The two individuals who supported tiered rates generally did so because the rates brought attention to the need to conserve and prompted people to reduce their energy consumption. Those commentors who submitted written comments or testified at the public hearings generally opposed tiered rates because the rates "discriminated" against high energy users , " penalized" residents of the all-electric Gold Medallion homes once promoted by ORDER NO. 29026 Idaho Power, and left customers unable to reduce the consumption enough to see a significant difference in their bills. Commission Findinf!s Based upon the record, we find it is appropriate and reasonable to return to a uniform rate design for residential customers. We base this decision on several reasons, despite losing the conservation price signal sent by tiered rates. As discussed in the "Recovery of Deferred PCA Amounts" section above, the Commission finds a multiple-year deferral of large PCA amounts is not in the public interest given the uncertainty currently present in our water and wholesale market conditions. Tiered rates created unanticipated problems when Idaho Power s meter reading cycle extended beyond 30 days. To the extent that the kWh consumed between day 30 and day 33 pushed customers into a higher rate block, customers paid a higher rate than they otherwise would have if the meter had been read on day 30. The Commission directs Idaho Power to continue its efforts to establish meter reading schedules that maximize efficiency and minimize ratepayer costs while reading meters as close to every 30 days as possible. If problems persist after the flat rate is implemented, the Commission intends to address this issue in a separate proceeding. The Commission is also concerned about the public s perception of tiered rates. Many customers attributed their high energy bills to the tiered rate structure rather than to the implementation of a 31 % residential increase over the previous winter s rate. Consumers using 2008 kWh of electricity experienced no difference in their bills under tiered rates than they would have under a flat rate surcharge. Those using less than that amount experienced increases less than a flat surcharge under the tiered rates because their bills were primarily comprised of the 0-800 kWh rate designed to allocate a portion of less expensive electricity to each customer for the purpose of maintaining essential service for customer health and safety. Although many high energy users assumed they paid the highest rate on all of their consumption, they actually benefited from the lowest rate for the first 800 kWh they consumed as well. Only 4% of Idaho Power s ratepayers used more than 3000 kWh per month. Many testified that energy used for barns, stock water heaters and other non-residential users were part of their residential bills. These non-residential users should not be metered through a residential meter. Outbuildings, farm uses and other non-residential energy consumption belong on a general service schedule separately metered. A customer using 3000 kWh per month would ORDER NO. 29026 receive a $219.36 bill - which is only $11.25 more than what they would have paid with a flat rate surcharge. From the public comments we received, it was apparent many ratepayers did not understand the purpose or actual dollar effect of tiered rates. For these reasons, the Commission finds it reasonable to implement a uniform 1.9370~ per kWh charge on all residential customers over a 12-month period. The table below shows average increases and decreases associated with the residential rate changes. TIERED RATE EXISTING APPROVED PERCENTAGE GROUPS AVERA GE RATE AVERA GE RATE INCREASE 800 kWh 6.2~ per kWh 1~ per kWh 15% 801-2000 kWh 0~ per kWh 1~ per kWh over 2000 kWh 8.4~ per kWh 7.1~ per kWh 15% Although it is appropriate to use flat residential rates this year, this Order should not be interpreted as precluding the use of tiered rates in the future. We believe that last year s tiered rates were effective in sending a price signal to customers to conserve. However, many of these customers experiencing an increase of 31 % or more had limited ability to significantly alter their energy consumption once they received the price signal. It is our belief that with additional customer education and increased availability of residential DSM programs like Time-of-Use metering, tiered residential rates may be an appropriate rate design option in the future as circumstances dictate. Although our return to a flat residential rate will alleviate the hardship posed to the small percentage of extremely high energy users, it will increase the burden on low energy users by eliminating the less costly block available with the tiered rate to promote customer health and safety. Low-income customers may also be eligible to receive financial assistance from energy programs like LIHEAP, Project Share, and Project Warmth. The Commission Staff or the community action agencies can provide additional information on these programs. While we recognize that some customers may not be able to conserve or reduce their consumption, there are programs for eligible residential customers to possibly convert to more efficient space heating appliances or receive assistance for high heating bills. For example, customers may also enroll in levelized pay programs that are intended to reduce or "levelize bills for high consumption months with bills for low consumption months. Regardless of whether a CFL ORDER NO. 29026 coupon program is initiated, customers who replace several incandescent light bulbs with CFLs may partially offset this increase and in some cases lower their bills. Customers interested in conserving energy may also view the US. Department of Energy s web site located at www.eren.doe.govibuildings/documents/high heating bills.The Idaho Office of Energy also dispenses low interest energy conservation loans. Interested persons can access applications and additional www.idwr.state.id.us/SaveEnergy/Residential.htm information their web site at: Finally,the Commission winter moratorium rule prohibits any electric or gas utility from terminating or threatening to terminate service during the months of December through February of any residential customer who declares that he or she is unable to pay in full for utility service and whose household includes children, the elderly, or infirmed persons. IDAP A 31.21.01.306.01. However, for families that use this protection, the full amount not paid during the moratorium period becomes due on March 1. In summary, the Commission is authorizing Idaho Power to recover approximately $255.9 million in PCA rates and $2.6 million in DSM rates. The Commission is ordering implementation of the PCA and DSM rate changes effective on May 16, 2002. We believe that allowing the Company to recover the majority of the customers' share of its above normal power costs in a timely fashion ensures the Company of continued financial viability and ensures that ratepayers will not mortgage their future opportunity for lower electric rates. ORDER IT IS HEREBY ORDERED that Idaho Power Company s Bond Application in Case No. IPC-02-2 is denied. IT IS FURTHER ORDERED that Idaho Power Company s PCA Application in Case No. IPC-02-3 is partially granted. The Company is authorized to implement the rates identified in this Order, which will generate approximately $244.4 million in 2002 PCA revenues. IT IS FURTHER ORDERED that recovery of approximately $11.5 million will be deferred for recovery in the 2003-2004 PCA year. Of this amount, approximately $11.0 million is attributable to the Irrigation Class and approximately $600 000 is attributable to the Small General Service Class. The carrying charge for amounts deferred beyond the traditional PCA ORDER NO. 29026 recovery period shall be 6% per year simple interest. Amounts are carried over in the Small General Service and Irrigation classes. IT IS FURTHER ORDERED that a separate tariff rider in the amount of .5% of each customer class s base revenues be collected as described above for the purposes of funding Demand-Side Management programs throughout the Idaho Power service territory. This tariff rider shall appear as a line item on customers' bills and labeled so as to indicate that the amount will fund conservation programs. IT IS FURTHER ORDERED that Idaho Power shall file an annual written report to the Commission no later than January 30 of each year detailing: the Advisory Group recommendations, the Company s response to those recommendations, the associated program costs, the DSM accounting numbers, customer response data, and information on new DSM opportunities. IT IS FURTHER ORDERED that Idaho Power consult the Energy Efficiency Advisory Group regarding the need to initiate a comprehensive DSM study of the IPC service territory relative to the priority for DSM funds to identify: (1) cost-effective DSM opportunities in each customer class; (2) estimated costs to fully fund those opportunities; and (3) opportunities for reductions in peak loads as well as reductions in total energy consumption. IT IS FURTHER ORDERED that the Company file tariffs in conformance with the rates described above in this Order. IT IS FURTHER ORDERED that the PCA and DSM rider rates established in this Order are effective May 16 2002. THIS IS A FINAL ORDER. Any person interested in issues finally decided by this Order or in interlocutory Orders previously issued in these Case Nos. IPC-02-2 and IPC-02- 3 may petition for reconsideration within twenty-one (21) days of the service date of this Order with regard to any matter finally decided in this Order or in interlocutory Orders previously issued in these Case Nos. IPC-02-2 and IPC-02-3. For purposes of filing a petition for reconsideration, this order shall become effective as of the service date. Idaho Code ~ 61-626. Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration. See Idaho Code ~ 61-626. 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