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SECURITIES AND EXCHANGE COMMISSION
Washington D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported): July 18, 2001
AVISTA CORPORATION
| Washington | 1-3701 | 91-0462470 | ||
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| (State or other jurisdiction of incorporation or organization) |
(Commission File Number) |
(I.R.S. Employer Identification No.) |
| 1411 East Mission Avenue, Spokane, Washington | 99202-2600 | |
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| (Address of principal executive offices) | (Zip Code) |
| Registrant’s telephone number, including area code: Web site: http://www.avistacorp.com |
509-489-0500 |
| Item 5. Other Information | ||||||||
| Item 7. Exhibits | ||||||||
| SIGNATURES | ||||||||
| EXHIBIT 99.(A) | ||||||||
| EXHIBIT 99.(B) | ||||||||
| EXHIBIT 99.(C) | ||||||||
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Item 5. Other Information
On July 18, 2001, the Company issued a press release announcing that it will ask regulators in Washington and Idaho to approve an energy surcharge to electric customers in each state. The surcharges are intended to offset the costs of a severe shortage of hydropower generation and volatile energy market prices. The Company requested a surcharge of 36.9 percent in Washington and 14.7 percent in Idaho. The proposed surcharges would be applied as a uniform percentage increase to the rates for all customer classes in each state. The press release and each surcharge request are filed as exhibits hereto.
Neither the filing of any press release as an exhibit to this Current Report nor the inclusion in such press releases of a reference to the Company’s Internet address shall, under any circumstances, be deemed to incorporate the information available at such Internet address into this Current Report. The information available at the Company’s Internet address is not part of this Current Report or any other report filed by the Company with the Securities and Exchange Commission.
Item 7. Exhibits
| 99(a) | Press Release dated July 18, 2001 | ||
99(b) |
Petition filed with the Washington Utilities and Transportation Commission | ||
| 99(c) | Application filed with the Idaho Public Utilities Commission |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| AVISTA CORPORATION (Registrant) |
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| Date: | July 18, 2001 | /s/ Jon E. Eliassen |
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Jon E. Eliassen Senior Vice President and Chief Financial Officer (Principal Accounting and Financial Officer) |
1 Exhibit 99(a) Press Release dated July 18, 2001 [AVISTA CORP. LOGO] NEWS RELEASE - -------------------------------------------------------------------------------- CONTACT: Media: Hugh Imhof (509) 495-4264 hugh.imhof@avistacorp.com Investors: Angie Teed (509) 495-2930 angela.teed@avistacorp.com FOR IMMEDIATE RELEASE: July 18, 2001 7:45 a.m. EDT AVISTA REQUESTS ELECTRICITY SURCHARGE TEMPORARY CHARGE IS NEEDED TO OFFSET POWER PURCHASE COSTS SPOKANE, WASH.: Avista Corp. (NYSE:AVA) today announced that it will ask regulators in Washington and Idaho to approve an energy surcharge to electric customers in both states. The surcharge is intended to offset the costs of a severe shortage of hydropower generation and volatile energy market prices. The request is for a surcharge of 36.9 percent in Washington and 14.7 percent in Idaho. The proposed surcharge would be applied as a uniform percentage increase to the rates for all customer classes in each state. "We know this will be difficult for many of our customers and we have taken extraordinary steps to avoid this request. But the volatile energy markets we have experienced in recent months have required us to ask for a price increase," said Avista Utilities President Scott Morris. "We must ensure that our company has sufficient resources to maintain cash flow, obtain needed financing and thereby provide adequate and reliable energy supplies for our service area." Morris said efforts to assist Avista customers include energy conservation and efficiency programs, conservation rebates, energy conservation workshops and programs aimed at limited income seniors, support of Project Share and the company's CARES program that provides assistance to those having difficulty paying their bills. During the past decade, Avista customers have saved more than 50 megawatts through energy conservation programs. The monthly increase for a residential customer in Washington using an average 1,000 kilowatt-hours per month would be $16.26. For an Idaho customer using the same amount of electricity, the increase would be $7.55. The proposed surcharge would result in an increase in annual revenue to the company of $87.4 million in Washington and $17.9 million in Idaho. A power cost adjustment mechanism has been in place since 1989 for Idaho customers and they are currently paying a surcharge of 4.8 percent.
2 The surcharge in each state would begin on Sept. 15, 2001. Avista has requested that the surcharge continue until the end of 2003. However, if conditions allow, the surcharge could be removed sooner. Gary Ely, Avista Corp. chairman, president and chief executive officer, said the need for a surcharge has arisen through a combination of volatile electricity prices, changing market conditions and a continued deterioration in availability of hydroelectric generation, which has weakened the financial condition of the company. "Hydroelectric generation in 2001 is the lowest in the 73 years that records have been kept," said Ely. "The conditions have caused us to purchase additional energy in the wholesale market to cover our power needs." As of June 30, 2001, Avista had deferred more than $140 million in costs for energy purchased on the wholesale market. Deferred power costs are cash expenses that Avista has incurred in acquiring power from the marketplace for its retail customers, but not recovered in rates, thereby limiting Avista's ability to meet ongoing cash needs and other financial obligations. The deferral balances continue to grow and are expected to reach $267 million by the end of 2001 unless rate relief is granted. Accounting mechanisms have been in place to allow the company to set aside or defer its increased power costs for possible later recovery. Avista expects to be in a surplus power supply condition beginning in 2002. Projections earlier this year indicated the value of the surplus energy would allow the company to offset its deferred costs with profits from the sale of this surplus in the wholesale market, reducing the deferral balance to zero by early 2003. Under a plan approved by Washington regulators in May, Avista's ability to fully offset the deferred costs attributable to Washington, was based on a number of assumptions including stream flow conditions, thermal plant performance, level of retail loads, and wholesale market prices during the deferral period. In Idaho, Avista has had a formal cost recovery mechanism in place for several years. Until June, Avista expected that these mechanisms, coupled with profits from sales of surplus energy, would allow adequate recovery of the deferral balances attributable to Idaho over a period of time. In June, changing market conditions, compounded by federally imposed price limits, drastically reduced prices for future energy sales, significantly reducing the company's ability to offset its deferred costs with cash generated through surplus power sales. May power prices were in the range of $300 per megawatt hour. Prices have now declined to around $40 per megawatt hour. "Improving the company's cash flow is critical to being able to complete financing plans and to meet various debt covenants," said Ely. "Without the surcharges in each state, the company will not be in a position to access capital at reasonable costs. Commission support and action is critical to enable Avista to complete financing for generation facilities currently being constructed to provide energy for retail customers." Ely also noted that Avista continues to implement internal cost saving measures, including a hiring freeze.
3 "Avista has not been able to obtain additional financing for completion of the Coyote Springs II generation project currently under construction to meet retail customers needs. Lenders have growing concerns about the projected deferral balances and the absence of some form of mechanism to currently recover the deferred costs on a current basis," he said. Avista Corp. is an energy, information and technology company whose utility and subsidiary operations focus on delivering superior products and providing innovative solutions to business and residential customers throughout North America. Avista Corp.'s affiliate companies include Avista Utilities, which operates the company's electric and natural gas generation, transmission and distribution business. Avista's non-regulated businesses include Avista Advantage, Avista Labs, Avista Communications, Avista Energy, and Avista Power. Avista Corp.'s stock is traded under the ticker symbol "AVA." For more information about Avista Corp. and its affiliate businesses, visit the corporate website at www.avistacorp.com Avista Corp. and the Avista Corp. logo are trademarks of Avista Corporation. All other trademarks mentioned in this document are the property of their respective owners. This news release contains forward-looking statements regarding the company's current expectations. Forward-looking statements are all statements other than historical facts. Such statements speak only as of the date of the news release and are subject to a variety of risks and uncertainties, many of which are beyond the company's control, which could cause actual results to differ materially from the expectations. These risks and uncertainties include, in addition to those discussed herein, all of the factors discussed in the company's Annual Report on Form 10-K for the year ended Dec. 31, 2000 and the Quarterly Report on form 10-Q for the quarter ended March 31, 2001. -0145-
1 Exhibit 99(b) Petition filed with the Washington Utilities and Transportation Commission BEFORE THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION In the Matter of the Petition of Avista ) Corporation d/b/a Avista Utilities for a ) DOCKET NO. UE-01_______ Surcharge in Electric Rates ) ) PETITION OF AVISTA CORP ) ) - -------------------------------------------- Pursuant to WAC 480-09-420(7), Avista Corporation doing business as Avista Utilities (hereinafter Avista or Company), at 1411 East Mission Avenue, Spokane, Washington, respectfully petitions the Commission for an order approving a surcharge electric rate increase of 36.9% effective September 15, 2001. As the Company will explain in this Petition, the combination of low hydroelectric conditions and unprecedented high wholesale market prices occurring at the same time has caused the need for prompt rate relief in order to enable it to obtain financing necessary to support the ongoing operations of the Company. Hydroelectric conditions for 2001 have continued to deteriorate to the lowest level in the 73 years of record. The Company has not yet been able to obtain construction financing for the Coyote Springs II project, because lenders are concerned about the size of the deferral balances and the absence of some form of rate relief to deal with the deferred costs. Current estimates show that if prompt rate relief is not granted, the Company will not be able to complete anticipated financings and will not be able to meet certain debt covenants by the end of this year. As a result, the Company would not be able to borrow under its line of credit. With the requested surcharge, and recovery of the deferral balances, under current plans the Company would be able to continue to access capital to meet its obligations. Communications in reference to this Petition should be addressed to: Thomas D. Dukich David J. Meyer Director, Rates and Tariff Administration Senior Vice President and General Counsel Avista Corporation Avista Corporation 1411 E. Mission Avenue 1411 E. Mission Avenue Spokane, Washington 99220 Spokane, Washington 99220 Phone: (509) 495-4724 Phone: (509) 495-4316 Fax: (509) 495-8058 Fax: (509) 495-4361 I. INTRODUCTION On August 9, 2000, in Docket No. UE-000972, the Commission approved the Company's request for a deferred accounting mechanism that allowed Avista to defer certain increased power supply related costs beginning July 1, 2000, and ending June 30, 2001. In Docket UE-000972, by order dated January 24, 2001, the Commission approved the Company's request to modify the deferred accounting mechanism to include certain other power supply related components and actual system load requirements in the deferral calculation effective December 1, 2000. On May 23, 2001, the Commission approved a Settlement Stipulation between Avista and the other parties in Docket No. UE-010395 which, among other things, extended the deferred accounting mechanism through the earlier of February 28, 2003, or the date the deferred balance was estimated to become zero. In that
2 Docket Avista explained that it had positioned the Company to be in a surplus power supply condition beginning in 2002, and that projections showed the value of the surplus would allow the Company to offset the deferred costs and reduce the balance to zero by February 28, 2003. The goal under the Settlement Stipulation was for the Company to fully recover its deferred costs without a price increase to its retail customers. As outlined in the Settlement, the ability to fully offset the deferred costs under the Settlement Stipulation, was based on a number of assumptions including, but not limited to, streamflow conditions, thermal plant performance, level of retail loads, and wholesale market prices during the deferral period. On page 4 of the Settlement Stipulation it states that: "The Company shall petition the Commission to alter, amend, or terminate the Settlement Stipulation (or propose other appropriate action) should the deferral balance increase or be reasonably anticipated to increase substantially due to unanticipated or uncontrollable events, such as an unplanned outage of a large Company-owned thermal unit, or worsening drought conditions. Nothing in this Settlement is intended to predetermine any issue in that proceeding or to preclude the Company from proposing any particular remedy in its Petition, including the need for rate relief." Subsequent to the approval of the Settlement Stipulation, power supply operating conditions for Avista have deteriorated substantially resulting in increased costs, due primarily to changes in hydroelectric generation and wholesale market prices. It was necessary for the Company to make additional purchases of energy at high prices from the short-term wholesale market in order to cover deficits caused by the further decline in hydroelectric generation. Increased costs have been substantial enough that without prompt rate relief, the Company will not be able to meet certain debt covenants by the end of this year or execute needed financings. At the time the Settlement Stipulation was developed, it did not seem desirable to request a rate increase when the information available at the time showed the opportunity to recover the deferred costs without a rate increase. The Stipulation contemplated, however, that if conditions changed substantially, other action would be necessary to address recovery of the deferred costs, including rate relief. Therefore, the Company's request for rate relief through a surcharge is consistent with the prior Settlement Stipulation. A copy of the Stipulation is attached as Attachment 1. II. SURCHARGE REQUEST Through this filing the Company is requesting that the Commission approve a surcharge increase in rates for Avista's Washington electric customers of 36.9% effective September 15, 2001. Because of the Company's immediate need for rate relief, Avista is proposing that the surcharge be implemented "subject to refund." As will be explained later, the Company has a critical and immediate need for increased cash flow, and to reduce the size of the deferral balance. Implementing the rate increase "subject to refund" would allow the determination of the ultimate prudence of the deferred costs to occur during the next general rate filing (discussed below), while allowing the needed increase in cash flow to occur immediately. If, at the conclusion of the prudence determination, costs have been collected from customers that were determined to be imprudent, the appropriate refund or credit would be applied to customers on a going-forward basis. Avista would file a general rate case during November 2001. That filing would address, among other things, the prudence of the deferred power costs, the regulatory treatment of the Coyote Springs II project that is scheduled for commercial operation in June 2002, a long-term periodic power cost adjustment mechanism, and the power supply related issues that the Commission ordered Avista to address in its Third Supplemental Order, dated September 29, 2000, in Docket No. UE-991606.
3 The Company is proposing that the surcharge remain in place until December 31, 2003. At the conclusion of the general rate case, the Company would modify the surcharge amount and the duration of the surcharge rate, if needed, in order to reflect the outcome of the general rate case. This Petition provides a summary explanation of the Company's need for rate relief and the conditions that led to that need. Avista is filing this Petition prior to completing its testimony in order to start the flow of information between parties as soon as possible. The Company plans to file written testimony on August 2, 2001 that will provide additional details related to its request for rate relief. The Company proposes the following procedural schedule related to processing its request for a surcharge rate increase on a "subject to refund" basis: Avista Petition Filed July 18, 2001 Avista Prefiled Testimony August 2, 2001 Staff and Intervenor Testimony August 22, 2001 Avista Rebuttal Testimony August 28, 2001 Hearings During Week of September 3-7, 2001 Commission Order September 14, 2001 Surcharge Implemented September 15, 2001 The Company is proposing this compressed schedule because of its urgent need for rate relief. Prompt relief is necessary to improve cash flow, but more importantly, to begin to deal with the large deferral balances so that the Company can continue to finance expenditures for energy included in the deferral balance, for its construction expenditures and its day-to-day operations. As stated earlier, the Company has not yet obtained separate construction financing for the Coyote Springs II project, and by year-end, could be precluded from borrowing under its primary commercial bank credit line. Investors and lenders are concerned about the size of the deferral balances and the absence of some form of rate relief to deal with the deferred costs. The Coyote Springs II generating resource and some demand-side management programs were selected through Avista's Request for Proposals (RFP) process conducted in 2000 as the next resources to serve the Company's load obligations. It is imperative that the Company be able to obtain financing for these new resources, which will be an integral part of the resources needed to serve future loads. III. RECENT CHANGES IN CONDITIONS AND REVISED DEFERRED COST BALANCES The Company's filing in Docket No. UE-010395, that led to the Settlement Stipulation, included deferral estimates for the Washington jurisdiction that were approximately $75 million at December 31, 2001, and decreased to zero in February 2003. A chart showing the estimated monthly deferral balances, at that time, from January 2001 through December 2003 is provided on page 1 of Attachment 2. The actual balance of the deferral account for the Washington jurisdiction at June 30, 2001, however, has increased to $109 million. Current estimates show a deferral balance for the Washington jurisdiction of $198 million at December 31, 2001, $211 million at the end of 2002, and $251 million at the end of 2003, as shown on the chart on page 2 of Attachment 2. A major portion of the increase in the deferral balance at December 31, 2001 is driven by a continued deterioration in hydroelectric generation. Actual generation through June 2001 together with estimates for the remainder of the year, show that hydroelectric generation in 2001 for Avista will be the lowest in the 73 years of record. The chart on page 3 of Attachment 2 shows the monthly deviation from the normal level of
4 hydroelectric generation for 2001. The chart also shows the expected generation for Avista under "critical water" conditions as determined by the Northwest Power Pool hydro regulation study (i.e., the worst water conditions on record). Under "critical water" conditions the annual reduction in generation is expected to be approximately 150 aMW. The generation for 2001 is currently estimated to be 194 aMW below normal, which is well below the 150 aMW reduction expected under "critical water" conditions. Page 4 of Attachment 2 includes a chart showing the variance in Avista's hydroelectric generation from normal for each calendar year from 1929 through 2001, and illustrates that generation for 2001 is the lowest on record. For deferral estimates under the Settlement Stipulation, hydroelectric generation for 2001 was estimated to be 135 aMW below normal. The current estimate of 194 aMW below normal is an additional substantial reduction (59 aMW) in available hydroelectric generation. The Company did not expect hydroelectric conditions to decline to a new record low. Page 5 of Attachment 2 includes a chart showing a comparison of the expected 2001 monthly hydroelectric generation at the time of the Settlement Stipulation (annual average of approximately 135 aMW below normal) with the current estimate averaging 194 aMW below normal. The record low hydroelectric conditions required the Company to purchase energy in the forward short-term wholesale market to replace the lost generation and cover its energy deficiencies. These purchases were made at unprecedented high wholesale market prices, and caused deferral balances to increase substantially. Page 6 of Attachment 2 shows the actual short-term electric wholesale market prices for the period August 1996 through June 2001, as reported by Dow Jones for the Mid-Columbia Firm Electric Index. The loss of a record 194 aMW of hydroelectric generation during 2001 has resulted in an estimated increase in gross costs to Avista of $290 million on a system basis, at the wholesale market prices being experienced by the Company during the year. The impact on the Company in prior years from very low hydroelectric conditions ranged from $20 million to $30 million annually, because the wholesale market prices were significantly lower. In addition to the lower hydroelectric conditions, the Company's proforma study (for July 2000 - June 2001) in its last general rate case showed the Company as a net purchaser of energy from the short-term wholesale market of approximately 90 aMW, under normal hydroelectric conditions. A comparison of the wholesale purchase prices being experienced by the Company in 2001 versus the market prices included in the last rate case results in increased costs associated with the 90 aMW of market purchases of approximately $110 million on a system basis. The combination of the hydroelectric impacts and the market purchases for 2001 is approximately $400 million on a system basis. This exceeds Avista's annual gross retail electric revenues on a system basis of approximately $360 million. Furthermore, in the past month wholesale prices have decreased dramatically, due in large part to FERC's price mitigation order issued on June 19, 2001. The decision to implement some form of price cap on a West-wide basis was something that FERC and the Bush Administration had continually rejected until June. The substantial decline in forward market prices in the last month has reduced the value of future surplus energy on Avista's system that could be used to offset the increased power costs experienced by the Company in 2001. Therefore, it no longer appears possible to offset the deferred power costs through the value of future surplus energy sales. Page 7 of Attachment 2 includes a graph showing a comparison of the forward market prices that were included in the deferral estimates under the Settlement Stipulation, and the current (July 3, 2001) forward market prices. The Company has taken a number of measures to mitigate the increased power costs such as increased operation of its thermal resources, locking in fixed-price purchases in the prior year, aggressively pursuing
5 conservation and load curtailment programs, and implementing a hiring freeze and cutting budgets. However, the costs associated with the hydroelectric conditions and wholesale market prices (costs beyond the Company's control) have overwhelmed the benefits these measures have provided. IV. FINANCIAL IMPLICATIONS In addition to the cash required to support power cost deferrals, Avista also has cash needs for funding gas deferrals, for normal construction and capital improvements, for the completion of construction of Coyote Springs II and a number of small generation projects, to fund conservation programs, and to repay maturing securities. Page 1 of Attachment 3 includes a chart showing total electric and natural gas deferral balances for both the Washington and Idaho jurisdictions for each month of 2001. The chart includes actual balances through June 2001 and estimates for July - December 2001. The chart shows total electric and natural gas deferral balances of $319 million at December 31, 2001. Current estimates show that without a surcharge, utility financing needs will total $434 million from now until the end of 2002, primarily to fund energy costs, required utility construction (including generation projects), and debt and preferred stock maturities. Investor concerns surrounding cash flows, deferral balances and the ability to recover costs in a timely manner have already had an impact on the Company's financings. In April of this year, the Company issued $400 million of Senior Unsecured Notes. As a result of these investor concerns, the notes were issued at a spread over Treasuries of nearly 500 basis points, which is significantly higher than the Company has ever paid before, and much higher than other comparably-rated securities issued during the same time period. The notes also included terms and ongoing covenants that had not been required of the Company in the past and that limit the Company's financing flexibility. In addition, when the Company renegotiated its corporate short-term credit facility in May 2001, a new fixed charge coverage ratio covenant was required by the banks in order to close the transaction. While such coverage ratio tests are not unusual, they were imposed on Avista for the first time due to the Company's weakened financial position. The Company expected that the proceeds of the $400 million note offering, the construction financing for Coyote Springs II ($93 million in 2001), and the issuance of common stock ($67 million) in the third quarter of 2001 would cover the Company's cash needs through the middle of 2002. However, as previously discussed, changes that have occurred since the notes were issued have had a significant impact on the Company's ability to complete planned financings. As of mid-July, the entire proceeds of the note offering had been used and the Company expects to begin borrowing under its line of credit in late July. The Company had not expected to need to use the line of credit at all in 2001. Projected ratios under the bank line new covenants are shown on page 2 of Attachment 3. Columns C and D of the projections show that without the proceeds from the anticipated sale of common stock and the Coyote Springs II construction loan, the Company will be in violation of covenants under the line of credit by September 30 of this year, and would continue to be in violation throughout 2002. Not meeting the covenant would be an event of default under the current credit agreement. In this event, the Company would be required to repay any outstanding borrowings under the line of credit and would be precluded from borrowing any additional amounts to the future. This
6 would eliminate a critical external source of liquidity the Company needs to fund expenditures on a current basis. Columns G and H show the same ratios if we receive a surcharge that would provide opportunity to complete the financings under our current plan. As can be seen, the Company would not be in violation of covenants in that case. It is critical to note that the Company will not be able to complete any financings absent substantial progress toward recovery of the deferral balances, including an immediate increase in rates. The corporate credit facility covenants were based on projections provided in early May 2001 which showed that the deferral balances would be virtually recovered by February 2003, which mirrors our original Settlement Stipulation in Washington. Under that plan (which assumed completion of the Coyote Springs II financing and the issuance of common stock in 2001), the Company was able to meet all covenants. As previously outlined, over the past few weeks the outlook has changed dramatically. Deferral balances not only are continuing to grow but are not expected to decline over the next 18 months. These latest projections were provided to banks who had previously received credit approval to underwrite the Coyote Springs II construction financing. Since the projections have changed so dramatically, the banks have told Avista that they will not complete the construction financing of Coyote Springs II based on the Company's current credit risk. In a letter the Company received from a bank on July 13, 2001 it stated: "Specifically, the Avista corporate credit risk must be less than it is today if you are to receive any significant degree of financial leverage on the CS2 project. Regulatory certainty regarding rate increases and the full recovery of electric and gas deferrals is an absolute prerequisite to any financing." Absent the construction financing for Coyote Springs II, the Company would need to borrow significant amounts under the corporate credit facility to finance Coyote Springs II. However, based on current projections for the bank line covenants, without the construction financing for Coyote Springs II, the Company would be precluded from borrowing under the credit facility since it would not meet the coverage tests. Given the latest projections, the Company will not be able to obtain financing without the assurance of near-term cash recovery of deferred energy costs. The Company had also planned to sell common stock this fall to provide a portion of the external funds needed. Financial advisors have told the Company that projections showing that Avista may be unable to borrow under its bank credit line will make it very difficult, if not impossible, to sell common stock at a reasonable price and in the time period the Company had planned. The Company currently has an investment grade credit rating (BBB with a negative outlook for its senior unsecured debt). Page 3 of Attachment 3 shows Avista's credit rating history for secured and unsecured debt. Page 4 of Attachment 3 shows key financial indicators that Rating Agencies look at when rating a company
7 and compares Avista's indicators over time with the requirements for certain rating categories. As can be seen, the ratios have been deteriorating and without additional equity financing and improved cash flows from operations, projected 2001 financial indicators as shown in Attachment 3, pages 4-8 are not adequate to maintain an investment grade (BBB) credit rating. Institutional investors such as pension fund managers are much less likely to purchase securities with ratings below investment grade. As a result, a drop to below investment grade would have a significant impact on the Company and its customers by causing a substantial increase in borrowing costs to finance the business. Attachment 3, pages 4-8 also show the same indicators for 2001 and 2002 with a surcharge and completion of a planned sale of common stock. Although the indicators improve, we do not immediately return to investment grade levels. It is imperative that the Company be able to obtain financing for new base load resources such as Coyote Springs II, which will be an integral part of the resources needed to serve the Company's load obligations. The Company also needs to issue common stock to move financial ratios toward a level that provides a credit rating that will allow the Company to complete financings when needed and at a reasonable cost. Improving the Company's cash flow is critical to being able to generate cash flows sufficient to fund Coyote Springs II, fund current and future power purchases, and to enable the Company to sell common stock. Approval of a surcharge will not only provide needed cash flows but, just as important, will be a signal to the financial community that the Commission will continue to take prompt actions to support the financial health of the Company. Commission support and action through a surcharge is critical to enable the Company to complete financings needed for continued utility operations and to help mitigate potential reductions in credit ratings. It is important to note that because of the approved deferred accounting mechanism, recent utility earnings and rates of return have not fully reflected the impacts of the hydro and power market conditions discussed to this point. If the full impact of the deferral balance was reflected by amortizing the projected balance in the deferral account over twenty-seven months (October 2001 through December 2003), Avista's Washington electric rate of return would be approximately a negative 0.5% (-0.5%) for the duration of the amortization period. Avista has made extraordinary efforts to avoid the situation now facing the Company and its customers. Unfortunately, financial exigencies now require the Company to request an immediate surcharge. The Company has reviewed prior Commission orders regarding such requests and believes that it meets all previously articulated criteria to be granted an immediate surcharge. To not grant a surcharge would clearly jeopardize the financial integrity of Avista and cause a detriment to its ratepayers.
8 V. PROPOSED TARIFF CHANGES In developing the surcharge of 36.9% the Company attempted to achieve a balance of mitigating the overall impact to customers, while also reducing the surcharge balance to zero as quickly as possible to address the concerns of the financial community. The Company is proposing to use the deferred credit on the Company's balance sheet related to the monetization of the Portland General Electric (PGE) Sale Agreement as an offset to the power cost deferral balance to reduce the overall rate impact to customers. The Company is then proposing that the remaining balance of the deferred costs be recovered by the end of 2003 through the surcharge. With regard to the PGE monetization credit, the Company is currently amortizing the PGE monetization credit balance over a multi-year period, as well as reflecting appropriate rate base reductions, per the Commission's Third Supplemental Order, dated September 29, 2000, in Docket No. UE-991606. The Company is proposing in this filing to accelerate the amortization of the PGE credit balance, beginning in October 2001, and apply the increased amortization against the deferred power cost balance, which would reduce the amount of deferred power costs that must be collected from customers through the surcharge. The Company is proposing that the amortization be increased to a level that would cause the PGE balance remaining on Avista's balance sheet at October 1, 2001 to be fully amortized by December 31, 2002. This is one year earlier than the targeted date of December 31, 2003 to eliminate the power cost deferral balance. By using the PGE credits at a faster rate than the December 31, 2003 date, the overall surcharge to customers is decreased. The accelerated amortization of the PGE balance would not improve the Company's cash flow, since these entries would be non-cash accounting entries, but would mitigate the overall impact to customers from the power cost deferrals. The accelerated amortization of the PGE balance would reduce the deferred power cost balance by $53.8 million by December 31, 2002. The Fourth Supplemental Order granting reconsideration in Docket No. UE-991606, paragraph 57, notes that the Company may petition for amortization of the PGE balance. After reducing power cost deferrals by the accelerated amortization of the PGE balance, the Company calculated the surcharge (36.9%) necessary to reduce the deferred power cost balance to zero by December 31, 2003. These calculations include the actual deferral balance at June 30, 2001, and estimated deferral entries through December 2003. The resulting monthly deferral balances decrease to zero by December 2003, as shown in the chart on page 1 of Attachment 4. December 2003 was chosen in an effort to balance a number of competing considerations including the size of the surcharge, the duration of recovery of the deferral balance, the need to immediately improve the financial health of the Company, as well as taking into consideration the timing of the need for additional power resources. A surcharge period shorter than December 2003 would improve the financial health of the Company sooner, but would result in a significantly higher surcharge rate increase. A surcharge period beyond December 2003 would extend into a period when the Company shows a need for new firm energy resources. The Company's existing 200 MW purchase from TransAlta expires in December 2003, and Avista will need additional firm energy resources beginning in 2004. The costs associated with these new resources may cause an increase in retail rates, therefore, the Company is proposing a surcharge period that ends prior to 2004.
9 The determination of the final revenue requirement for the surcharge utilized the standard conversion for miscellaneous revenue related expense and taxes. The conversion factors utilized were from the same calculations authorized in the Company's most recent general case, updated for actuals through December 31, 2000, and as filed with the Commission. Outside of equity deferral entries associated with the Company's small generation projects, plus the Coyote Springs II Project, which required an income tax gross-up component, only revenue related expense items were used in the conversion calculation. This calculation resulted in an overall surcharge increase of 36.9%, as shown on page 2 of Attachment 4. The Company recognizes that a portion of the costs included in the 27-month recovery plan (through December 2003) are projected at this time, and proposes that the surcharge rates under tariff Schedule 93 be adjusted in the future based on actual costs. The Company has included language under the proposed tariff addressing periodic review and adjustment of the rates by the Commission. As an alternative to the proposal, the Company considered proposing a surcharge to recover the actual balance of deferred costs at June 2001 of $109 million over a 12-month period. However, the result would have been a higher immediate increase in rates (46%) than the proposed increase. The Company proposes to recover the surcharge amount on a uniform percentage increase basis to all general service schedules. The annual revenue surcharge by service schedule would be applied only to the energy charge(s) within each schedule. For Residential Schedule 1 the increase is proposed to be applied on a uniform percentage basis to the present energy block rates under the Schedule. As the present rates under the Schedule increase as monthly usage increases (inverted-block structure), the surcharge on a cents per KWH basis will increase for usage in the higher (usage) blocks. This proposed application will maintain the present relationship between the rates under the Schedule and continue to encourage residential customers to conserve energy. The resulting increase for a residential customer using 1,000 KWH per month would be 35.8 %, or $16.26 per month. The percentage increase for a customer using 600 KWH per month would be 32.9%, or $9.04 per month. The increase for a customer using 1,400 KWH per month would be 37.1%, or $23.85 per month. As service schedules 11, 21, and 25 contain only a single energy-block, the application of the surcharge is more straightforward. For Pumping Service Schedules 31 and 32, the Company proposes application of the surcharge on an equal-cents per KWH basis to the two energy-block rates under the Schedule. The rates under the Schedule are presently on a declining-block basis, with an implied demand charge included in the first-block rate. For Street and Area Lighting Schedules 41-49, the proposed increase is being applied on a uniform percentage basis to the present rates under those Schedules. The calculation of the proposed rates is shown on page 3 of Attachment 4. The rates are set forth on proposed Schedule 93 -- Power Cost Surcharge, to become effective on September 15, 2001. The proposed accounting entries related to the accelerated amortization of the PGE balance would be to debit the PGE deferred revenue account and to credit the power cost deferral account, thereby reducing the power cost deferral balance to be recovered. VI. BPA RESIDENTIAL EXCHANGE SETTLEMENT CREDIT
10 In its Settlement Agreement with the Bonneville Power Administration (BPA), Avista received rights to 90 aMW of benefits from the federal hydropower system beginning October 1, 2001. The benefits related to this Settlement are to be shared among Avista's residential and small farm customers. Avista estimates that the total benefits from the Residential Exchange Settlement will result in a rate reduction for residential and small farm customers of approximately 10% in the first year of the Exchange period which begins October 2001. Although the rate reductions to residential and small farm customers related to the Residential Exchange Settlement benefits will be handled separately from the proposed surcharge rate increase, the timing of the Residential Exchange credit will serve to reduce the overall rate impact to approximately 27% for residential and small farm customers from the Company's surcharge request. The Company plans to file a proposal with the Commission in August to flow the benefits from Residential Exchange Settlement through to its customers. VII. REQUEST FOR RELIEF The Company respectfully requests that the Commission issue an order approving a surcharge increase in rates for Avista's Washington electric customers of 36.9% effective September 15, 2001, on a "subject to refund" basis. Implementing the rate increase "subject to refund" would allow the determination of the prudence of the deferred costs to occur during the next general rate filing, while allowing the needed increase in cash flow to occur immediately, as well as begin to reduce the size of the deferral balance. The Company is proposing that the surcharge remain in place until December 31, 2003. A general rate case would be filed by Avista during November 2001. At the conclusion of the general rate case, the Company would modify the surcharge amount and the duration of the surcharge rate, if needed, in order to reflect the outcome of the general rate case. The Company also requests approval of the proposed acceleration of the amortization of the PGE credit balance to partially offset the power cost deferral balance. Dated at Spokane, Washington this 17th day of July 2001. AVISTA CORPORATION BY --------------------------------------- Thomas D. Dukich Director, Rates and Tariff Administration
1 Exhibit 99(c) Application filed with the Idaho Public Utilities Commission Thomas D. Dukich Director, Rates and Tariff Administration 1411 E. Mission Avenue P.O. Box 3727 Spokane, Washington 99220 Phone: (509) 495-4724, Fax: (509) 495-8058 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF THE APPLICATION ) OF AVISTA CORPORATION FOR AUTHORITY ) CASE NO. AVU-E-01- TO IMPLEMENT A POWER COST ADJUSTMENT ) (PCA) SURCHARGE ) ________________________________________________________________________________ ______________________________________________________) I. INTRODUCTION Avista Corporation doing business as Avista Utilities (hereinafter Avista or Company), at 1411 East Mission Avenue, Spokane, Washington, respectfully petitions the Commission for an order approving an additional Power Cost Adjustment (PCA) surcharge of 14.7% effective September 15, 2001. As the Company will explain in this Application, the combination of low hydroelectric conditions and unprecedented high wholesale market prices occurring at the same time has caused the need for prompt rate relief in order to enable it to obtain financing necessary to support the ongoing operations of the Company. Hydroelectric conditions for 2001 have continued to deteriorate to the lowest level in the 73 years of record. The Company has not yet been able to obtain construction financing for the Coyote Springs II project, because lenders are concerned about the size of the deferral balances, and the absence of rate relief necessary to deal with the deferred cost balances in a timely manner. Current estimates show that if prompt rate relief is not granted, the Company will not be able to complete anticipated financings and will not be able to meet certain debt covenants by the end of this year. As a result, the Company would not be able to borrow under its line of credit. With the requested surcharge, and recovery of the deferral balances, under current plans the Company would be able to continue to access capital to meet its obligations. Communications in reference to this Application should be addressed to: Thomas D. Dukich David J. Meyer Director, Rates and Tariff Administration Senior Vice President and General Counsel Avista Corporation Avista Corporation 1411 E. Mission Avenue 1411 E. Mission Avenue Spokane, Washington 99220 Spokane, Washington 99220 Phone: (509) 495-4724 Phone: (509) 495-4316 Fax: (509) 495-8058 Fax: (509) 495-4361 II. SURCHARGE REQUEST Through this filing the Company is requesting that the Commission approve an additional PCA surcharge increase in rates for Avista's Idaho electric customers of 14.7% effective September 15, 2001. The present tariff Schedule 66-Temporary Power Cost Adjustment includes a surcharge of $5.7 million, or approximately 4.8%, which is due to
2 expire January 31, 2002. In this filing, the Company is proposing an incremental increase of 14.7%, resulting in a total surcharge in effect under Schedule 66 of 19.4%. The Company is proposing that the PCA surcharge on Schedule 66 remain in place until December 31, 2003. During the proposed surcharge period, the Company may propose to modify the surcharge amount and the duration of the surcharge rate, if needed, in order to reflect changed conditions. The Company recognizes that the proposed total surcharge of 19.4% would exceed the 10% limit recently approved by the Commission in Case No. AVU-E-01-1. In that Case, however, the Commission approved the Company's request to use the 10% of base revenues as a guide rather than a hard and fast rule. At page 13 of the Commission's Order No. 28775, dated July 12, 2001, approving modifications to the PCA mechanism it states: "As agreed to by the Company and Staff, the limit, not the trigger, on surcharges or rebates will be raised to $12 million or about 10% of base revenues. Rather than a hard and fast rule, the Company, if circumstances arise, may request and seek to justify a different amount." Thus, the PCA mechanism allows the Company to request a different amount, depending on the circumstances. We believe the record-low hydroelectric generation that has caused the Company to make purchases in the short-term wholesale market at unprecedented high prices, and the resulting financial impact on the Company, warrants the higher PCA surcharge being proposed at this time. This Application provides a summary explanation of the Company's need for rate relief and the conditions that led to that need. Avista is filing this Application prior to completing its testimony in order to start the flow of information between parties as soon as possible. The Company plans to file written testimony on August 2, 2001 that will provide additional details related to its request for rate relief. The Company proposes the following procedural schedule related to processing its request for a PCA surcharge: Avista Application Filed July 18, 2001 Avista Prefiled Testimony August 2, 2001 Staff and Intervenor Testimony August 22, 2001 Avista Rebuttal Testimony August 28, 2001 Hearings During Week of September 3-7, 2001 Commission Order September 14, 2001 Surcharge Implemented September 15, 2001 The Company is proposing this compressed schedule because of its urgent need for rate relief. Prompt relief is necessary to improve cash flow, but more importantly, to begin to deal with the large deferral balances so that the Company can continue to finance expenditures for energy included in the deferral balance, for its construction expenditures and its day-to-day operations. As stated earlier, the Company has not yet obtained separate construction financing for the Coyote Springs II project, and by year-end, could be precluded from borrowing under its primary commercial bank credit line. Investors and lenders are concerned about the size of the deferral balances and the absence of rate relief necessary to deal with the deferred costs in a timely manner. The Coyote Springs II generating resource and some demand-side management programs were selected through Avista's Request for Proposals (RFP) process conducted in 2000 as the next resources to serve the Company's load obligations. It is imperative that the Company be able to obtain financing for these new resources, which will be an integral part of the resources needed to serve future loads. III. RECENT CHANGES IN CONDITIONS AND DEFERRED COST BALANCES
3 The PCA deferral balance has risen substantially during the last two months (May and June). The actual balance of the deferral account for the Idaho jurisdiction at June 30, 2001 has increased to $30 million. Current estimates show a deferral balance for the Idaho jurisdiction of $69 million at December 31, 2001, $72 million at the end of 2002, and $88 million at the end of 2003, as shown on the chart on page 1 of Attachment 1. A major portion of the increase in the deferral balance is driven by a continued deterioration in hydroelectric generation. Actual generation through June 2001 together with estimates for the remainder of the year, show that hydroelectric generation in 2001 for Avista will be the lowest in the 73 years of record. The chart on page 2 of Attachment 1 shows the monthly deviation from the normal level of hydroelectric generation for 2001. The chart also shows the expected generation for Avista under "critical water" conditions as determined by the Northwest Power Pool hydro regulation study (i.e., the worst water conditions on record). Under "critical water" conditions the annual reduction in generation is expected to be approximately 150 aMW. The generation for 2001 is currently estimated to be 194 aMW below normal, which is well below the 150 aMW reduction expected under "critical water" conditions. Page 3 of Attachment 1 includes a chart showing the variance in Avista's system hydroelectric generation from normal for each calendar year from 1929 through 2001, and illustrates that generation for 2001 is the lowest on record. The record low hydroelectric conditions required the Company to purchase energy in the forward short-term wholesale market to replace the lost generation and cover its energy deficiencies. These purchases were made at unprecedented high wholesale market prices, and caused deferral balances to increase substantially. Page 4 of Attachment 1 shows the actual short-term electric wholesale market prices for the period August 1996 through June 2001, as reported by Dow Jones for the Mid-Columbia Firm Electric Index. The loss of a record 194 aMW of hydroelectric generation during 2001 has resulted in an estimated increase in gross costs to Avista of $290 million on a system basis, at the wholesale market prices being experienced by the Company during the year. The impact on the Company in prior years from very low hydroelectric conditions ranged from $20 million to $30 million annually, because the wholesale market prices were significantly lower. In addition to the lower hydroelectric conditions, a proforma study for July 2000 - June 2001 from the Company's most recent general rate case (in Washington), showed the Company as a net purchaser of energy from the short-term wholesale market of approximately 90 aMW, under normal hydroelectric conditions. A comparison of the wholesale purchase prices being experienced by the Company in 2001 versus the market prices included in the last rate case results in increased costs associated with the 90 aMW of market purchases of approximately $110 million on a system basis. The combination of the hydroelectric impacts and the market purchases for 2001 is approximately $400 million on a system basis. This exceeds Avista's annual gross retail electric revenues on a system basis of approximately $360 million. Furthermore, in the past month wholesale prices have decreased dramatically, due in large part to FERC's price mitigation order issued on June 19, 2001. The decision to implement some form of price cap on a West-wide basis was something that FERC and the Bush Administration had continually rejected until June. The substantial decline in forward market prices in the last month has reduced the value of future surplus energy on Avista's system that could be used to offset the increased power costs experienced by the Company in 2001. The Company has taken a number of measures to mitigate the increased power costs, such as increased operation of its thermal resources, locking in fixed-price purchases in the prior year, aggressively pursuing conservation and load curtailment programs, and implementing a hiring freeze and cutting budgets. However, the costs associated
4 with the hydroelectric conditions and wholesale market prices (costs beyond the Company's control) have overwhelmed the benefits these measures have provided. IV. FINANCIAL IMPLICATIONS In addition to the cash required to support power cost deferrals, Avista also has cash needs for funding gas deferrals, for normal construction and capital improvements, for the completion of construction of Coyote Springs II and a number of small generation projects, to fund conservation programs, and to repay maturing securities. Page 1 of Attachment 2 includes a chart showing total electric and natural gas deferral balances for both the Washington and Idaho jurisdictions for each month of 2001. The chart includes actual balances through June 2001 and estimates for July - December 2001. The chart shows total electric and natural gas deferral balances of $319 million at December 31, 2001. Current estimates show that without a surcharge, utility financing needs will total $434 million from now until the end of 2002, primarily to fund energy costs, required utility construction (including generation projects), and debt and preferred stock maturities. Investor concerns surrounding cash flows, deferral balances and the ability to recover costs in a timely manner have already had an impact on the Company's financings. In April of this year, the Company issued $400 million of Senior Unsecured Notes. As a result of these investor concerns, the notes were issued at a spread over Treasuries of nearly 500 basis points, which is significantly higher than the Company has ever paid before, and much higher than other comparably-rated securities issued during the same time period. The notes also included terms and ongoing covenants that had not been required of the Company in the past and that limit the Company's financing flexibility. In addition, when the Company renegotiated its corporate short-term credit facility in May 2001, a new fixed charge coverage ratio covenant was required by the banks in order to close the transaction. While such coverage ratio tests are not unusual, they were imposed on Avista for the first time due to the Company's weakened financial position. The Company expected that the proceeds of the $400 million note offering, the construction financing for Coyote Springs II ($93 million in 2001), and the issuance of common stock ($67 million) in the third quarter of 2001 would cover the Company's cash needs through the middle of 2002. However, as previously discussed, changes that have occurred since the notes were issued have had a significant impact on the Company's ability to complete planned financings. As of mid-July, the entire proceeds of the note offering had been used and the Company expects to begin borrowing under its line of credit in late July. The Company had not expected to need to use the line of credit at all in 2001. Projected ratios under the bank line new covenants are shown on page 2 of Attachment 2. Columns C and D of the projections show that without the proceeds from the anticipated sale of common stock and the Coyote Springs II construction loan, the Company will be in violation of covenants under the line of credit by September 30 of this year, and would continue to be in violation throughout 2002. Not meeting the covenant would be an event of default under the current credit agreement. In this event, the Company would be required to repay any outstanding borrowings under the line of credit and would be precluded from borrowing any additional amounts to the future. This would eliminate a critical external source of liquidity the Company needs to fund expenditures on a current basis. Columns G and H show the same ratios if we receive a surcharge that would provide opportunity to complete
5 the financings under our current plan. As can be seen, the Company would not be in violation of covenants in that case. It is critical to note that the Company will not be able to complete any financings absent substantial progress toward recovery of the deferral balances, including an immediate increase in rates. The corporate credit facility covenants were based on projections provided in early May 2001 which showed that the deferral balances would be virtually eliminated by February 2003. Under that plan (which assumed completion of the Coyote Springs II financing and the issuance of common stock in 2001), the Company was able to meet all covenants. As previously outlined, over the past few weeks, the outlook has changed dramatically. Deferral balances not only are continuing to grow but are not expected to decline over the next 18 months. These latest projections were provided to banks who had previously received credit approval to underwrite the Coyote Springs II construction financing. Since the projections have changed so dramatically, the banks have told Avista that they will not complete the construction financing of Coyote Springs II based on the Company's current credit risk. In a letter the Company received from a bank on July 13, 2001 it stated: "Specifically, the Avista corporate credit risk must be less than it is today if you are to receive any significant degree of financial leverage on the CS2 project. Regulatory certainty regarding rate increases and the full recovery of electric and gas deferrals is an absolute prerequisite to any financing." Absent the construction financing for Coyote Springs II, the Company would need to borrow significant amounts under the corporate credit facility to finance Coyote Springs II. However, based on current projections for the bank line covenants, without the construction financing for Coyote Springs II the Company would be precluded from borrowing under the credit facility since it would not meet the coverage tests. Given the latest projections, the Company will not be able to obtain financing without the assurance of near-term cash recovery of deferred energy costs. The Company had also planned to sell common stock this fall to provide a portion of the external funds needed. Financial advisors have told the Company that projections showing that Avista may be unable to borrow under its bank credit line will make it very difficult, if not impossible, to sell common stock at a reasonable price and in the time period the Company had planned. The Company currently has an investment grade credit rating (BBB with a negative outlook for its senior unsecured debt). Page 3 of Attachment 2 shows Avista's credit rating history for secured and unsecured debt. Page 4 of Attachment 2 shows key financial indicators that Rating Agencies look at when rating a company and compares Avista's indicators over time with the requirements for certain rating categories. As can be seen, the ratios have been deteriorating and without additional equity financing and improved cash flows from operations, projected 2001 financial indicators as shown in Attachment 2, pages 4-8 are not adequate to maintain an investment grade (BBB)
6 credit rating. Institutional investors such as pension fund managers are much less likely to purchase securities with ratings below investment grade. As a result, a drop to below investment grade would have a significant impact on the Company and its customers by causing a substantial increase in borrowing costs to finance the business. Attachment 2, pages 4-8 also show the same indicators for 2001 and 2002 with a surcharge and completion of a planned sale of common stock. Although the indicators improve, we do not immediately return to investment grade levels. It is imperative that the Company be able to obtain financing for new base load resources such as Coyote Springs II, which will be an integral part of the resources needed to serve the Company's load obligations. The Company also needs to issue common stock to move financial ratios toward a level that provides a credit rating that will allow the Company to complete financings when needed and at a reasonable cost. Improving the Company's cash flow is critical to being able to generate cash flows sufficient to fund Coyote Springs II, fund current and future power purchases, and to enable the Company to sell common stock. Approval of a surcharge will not only provide needed cash flows but, just as important, will be a signal to the financial community that the Commission will continue to take prompt actions to support the financial health of the Company. Commission support and action through a surcharge is critical to enable the Company to complete financings needed for continued utility operations and to help mitigate potential reductions in credit ratings. Avista has made extraordinary efforts to avoid the situation now facing the Company and its customers. Unfortunately, financial exigencies now require the Company to request an immediate surcharge. The Company has reviewed prior Commission orders regarding such requests and believes that it meets all previously articulated criteria to be granted an immediate surcharge. To not grant a surcharge would clearly jeopardize the financial integrity of Avista and cause a detriment to its ratepayers. V. PROPOSED TARIFF CHANGES The rates set forth under the proposed PCA Schedule 66 reflect an annual revenue surcharge amount of $23.6 million, or 19.4%. As stated before, the present Schedule 66 includes a surcharge of $5.7 million, or approximately 4.8%, which is due to expire January 31, 2002. The proposed incremental rate increase to customers is approximately 14.7%. In developing the surcharge of 14.7% the Company attempted to achieve a balance of mitigating the overall impact to customers, while also reducing the surcharge balance to zero as quickly as possible to address the concerns of the financial community. The Company is proposing to use the deferred credit on the Company's balance sheet related to the monetization of the Portland General Electric (PGE) Sale Agreement as an offset to the power cost deferral balance to reduce the overall rate impact to customers. The Company is then proposing that the remaining balance of the deferred costs be recovered by the end of 2003 through the surcharge. With regard to the PGE monetization credit, the Company is currently amortizing the PGE monetization credit balance over a sixteen-year period (1999-2014) to match the original revenue stream under the PGE contract. The Company is proposing in this filing to accelerate the amortization of the PGE credit balance, beginning in October
7 2001, and apply the increased amortization against the deferred power cost balance, which would reduce the amount of deferred power costs that must be collected from customers through the surcharge. The Company is proposing that the amortization be increased to a level that would cause the PGE balance on Avista's balance sheet at October 1, 2001 to be fully amortized by December 31, 2002. This is one year earlier than the targeted date of December 31, 2003 to eliminate the power cost deferral balance. By using the PGE credits at a faster rate than the December 31, 2003 date, the overall surcharge to customers is decreased. The accelerated amortization of the PGE balance would not improve the Company's cash flow, since these entries would be non-cash accounting entries, but would mitigate the overall impact to customers from the power cost deferrals. The accelerated amortization of the PGE balance would reduce the deferred power cost balance by $34.6 million by December 31, 2002. After reducing power cost deferrals by the accelerated amortization of the PGE balance, the Company calculated the additional surcharge (14.7%) necessary to reduce the deferred power cost balance to zero by December 31, 2003. As part of the overall proposal, the present surcharge under Schedule 66 of 4.8%, which is incorporated in the proposed Schedule 66 rates, would not expire at the end of January 2002, but continue through December 31, 2003. These calculations include the actual deferral balance at June 30, 2001, and estimated deferral entries through December 2003. The resulting monthly deferral balances decrease to zero by December 2003, as shown in the chart on page 1 of Attachment 3. December 2003 was chosen in an effort to balance a number of competing considerations including the size of the surcharge, the duration of recovery of the deferral balance, the need to immediately improve the financial health of the Company, as well as taking into consideration the timing of the need for additional power resources. A surcharge period shorter than December 2003 would improve the financial health of the Company sooner, but would result in a significantly higher surcharge rate increase. A surcharge period beyond December 2003 would extend into a period when the Company shows a need for new firm energy resources. The Company's existing 200 MW purchase from TransAlta expires in December 2003, and Avista will need additional firm energy resources beginning in 2004. The costs associated with these new resources may cause an increase in retail rates, therefore, the Company is proposing a surcharge period that ends prior to 2004. The determination of the final revenue requirement for the surcharge utilized the standard conversion for miscellaneous revenue related expense and taxes. The conversion factors utilized were from the same calculations authorized in the Company's most recent Idaho general case, updated for actuals through December 31, 2000, and as filed with the Commission. Outside of equity deferral entries associated with the Company's small generation projects, plus the Coyote Springs II Project, which required an income tax gross-up component, only revenue related expense items were used in the conversion calculation. This calculation resulted in an overall surcharge increase of 14.7%, as shown on page 2 of Attachment 3. The Company recognizes that a portion of the costs included in the 27-month recovery plan (through December 2003) are projected at this time, and proposes that the surcharge rates under tariff Schedule 66 be adjusted in the future based on actual costs. The Company has included language under the proposed tariff addressing periodic review and adjustment of the rates by the Commission. As an alternative to the proposal, the Company considered proposing a surcharge to recover the actual balance of deferred costs at June 2001 of $30 million over a 12-month period. However, the result would have been a higher immediate increase in rates (20%) than the proposed 14.7% increase. The Company proposes to recover the surcharge amount on a uniform percentage increase basis to all general service schedules. The annual revenue surcharge by service schedule is then applied only to the energy charge(s)
8 within each schedule. For Residential Schedule 1 the increase is proposed to be applied on a uniform percentage basis to the present energy block rates under the Schedule. As the present rates under the Schedule increase as monthly usage increases (inverted-block structure), the surcharge on a cents per KWH basis will increase for usage in the higher (usage) blocks. This proposed application will maintain the present relationship between the rates under the Schedule and continue to encourage residential customers to conserve energy. The resulting increase for a residential customer using 1,000 KWH per month would be 13.9%, or $7.55 per month. The percentage increase for a customer using 600 KWH per month would be 12.9%, or $4.16 per month. The increase for a customer using 1,400 KWH per month would be 14.4%, or $10.94 per month. As service Schedules 11, 21, and 25 contain only a single energy-block, the application of the surcharge is more straightforward. For Pumping Service Schedules 31 and 32, the Company proposes application of the surcharge on an equal-cents per KWH basis to the two energy-block rates under the Schedule. The rates under the Schedule are presently on a declining-block basis, with an implied demand charge included in the first-block rate. For Street and Area Lighting Schedules 41-49, the proposed increase is being applied on a uniform percentage basis to the present rates under those Schedules. The calculation of the proposed rates is shown on page 3 of Attachment 3. The rates are set forth on proposed Schedule 66 -- Temporary Power Cost Adjustment, to become effective on September 15, 2001. The proposed accounting entries related to the accelerated amortization of the PGE balance would be to debit the PGE deferred revenue account and to credit the power cost deferral account, thereby reducing the power cost deferral balance to be recovered. VI. BPA RESIDENTIAL EXCHANGE SETTLEMENT CREDIT In its Settlement Agreement with the Bonneville Power Administration (BPA), Avista received rights to 90 aMW of benefits from the federal hydropower system beginning October 1, 2001. The benefits related to this Settlement are to be shared among Avista's residential and small farm customers. Avista estimates that the total benefits from the Residential Exchange Settlement will result in a rate reduction for residential and small farm customers of approximately 10% in the first year of the Exchange period which begins October 2001. Although the rate reductions to residential and small farm customers related to the Residential Exchange Settlement benefits will be handled separately from the proposed PCA surcharge, the timing of the Residential Exchange credit will serve to reduce the overall rate impact to approximately 5% for residential and small farm customers from the Company's surcharge request. The Company plans to file a proposal with the Commission in August to flow the benefits from Residential Exchange Settlement through to its customers. VII. REQUEST FOR RELIEF The Company respectfully requests that the Commission issue an order approving an additional PCA surcharge increase in rates for Avista's Idaho electric customers of 14.7% effective September 15, 2001. The surcharge would
9 provide a critical increase in cash flow immediately, as well as begin to reduce the size of the deferral balance. The Company is proposing that the surcharge remain in place until December 31, 2003. During the proposed surcharge period, the Company may propose to modify the surcharge amount and the duration of the surcharge rate, if needed, in order to reflect changed conditions. The Company also requests approval of the proposed acceleration of the amortization of the PGE credit balance to partially offset the power cost deferral balance. Dated at Spokane, Washington this 17th day of July 2001. AVISTA CORPORATION BY --------------------------------------- Thomas D. Dukich Director, Rates and Tariff Administration