ITEM 1. BUSINESS
COMPANY OVERVIEW
Avista Corporation (Avista Corp., or the Company), formerly known as The Washington Water Power Company, was incorporated in the State of Washington in 1889, and is a diversified energy services company. The name change to Avista Corporation became effective on January 1, 1999. At December 31, 1998, the Company's employees included 1,536 people in its utility operations and approximately 2,153 people in its majority-owned non-regulated businesses (energy and non-energy). The Company's corporate headquarters are in Spokane, Washington (Spokane), which serves as the Inland Northwest's center for manufacturing, transportation, health care, education, communication, agricultural and service businesses.
Regulatory, economic and technological changes have brought about the accelerating transformation of the electric utility industry from a vertically integrated monopoly to separate market driven businesses. Changes underway in the utility and energy industries are creating new opportunities to expand the Company's businesses and serve new markets. In pursuing such opportunities, the Company is shifting its strategic direction to growth in order to achieve its goal of becoming a diversified North American energy company. The Company's strategies are described below.
The Company seeks to strengthen its position of leadership in energy delivery and generation as well as energy trading and marketing on a local, regional and national basis. The Company will seek to increase its asset and customer base through a focus on acquisitions and strategic alliances in all parts of its business. The Company intends to focus on growing its core energy business by seeking to acquire control of physical assets, specifically power generation assets and electric and natural gas transmission and distribution assets. The Company expects that initial growth will come at a local and regional level, with national growth to follow. Key strengths of the Company today include its position as one of the lowest cost producers of power in the nation, expertise in hydroelectric and power system management, plus capabilities in trading and wholesale and retail marketing of natural gas and electric energy.
Locally. The Company is a long-standing leader in the Northwest region of the United States, providing some of the lowest cost energy to its customers. The Company's strategy is to add selectively to its already strong foundation of state-regulated utility assets to solidify its position as a leading supplier of low-cost electric and natural gas energy services.
Regionally. The Company intends to add to its regulated and non-regulated assets on a regional basis and participate in industry consolidation to further optimize its assets and create greater economies of scale. In addition to energy delivery and generation, the Company plans to concentrate on growing its energy trading and marketing business. The strong growth in this business is expected to be driven by the Company's significant base of knowledge and experience in the operation of physical systems - for both natural gas and electric energy - in the region, as well as its relationship-focused approach to the customer. The Company will also focus on expanding its telecommunications business through its newest subsidiary, Avista Communications. (See Non-Energy business for additional information.)
Nationally. The Company's strong regional energy trading and marketing skills serve as a platform for the Company's growing national presence. The Company will seek to expand its customer base through Internet-based specialty billing and information services and relationships with other energy providers outside the Northwest, thereby leveraging its existing trading and marketing skills. On February 1, 1999, Avista Energy, Inc., (Avista Energy) a national energy trading and marketing subsidiary of Avista Corp. acquired Vitol Gas & Electric LLC, one of the top 20 energy marketing companies in the United States. (See National Energy Trading and Marketing for additional information.)
The Company conducts the majority of its Non-energy business through its wholly owned subsidiary, Pentzer Corporation (Pentzer). Pentzer's business strategy is to acquire controlling interests in a broad range of middle market companies, facilitate improved productivity and growth, and ultimately sell such companies to the public or a strategic buyer.
The Company's growth strategy will expose the Company to risks associated with rapid expansion, challenges in recruiting and retaining qualified personnel, risks associated with acquisitions, joint ventures and increasing competition. In addition, growth in the energy and trading and marketing business will expose the Company to increased financial and credit risks associated with commodity trading activities. The Company believes however, that its extensive experience in the electric and natural gas business, coupled with its strong management team, will allow the Company to effectively manage its transition to a diversified North American energy company.
In order to implement its growth strategies, the Company has reorganized its operations into four lines of business - Energy Delivery, Generation and Resources, National Energy Trading and Marketing and Non-energy. The regulated utility
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operations fall within Energy Delivery and Generation and Resources. The Energy Delivery business includes retail electric and natural gas distribution and transmission services. The Generation and Resources business includes generation and production, resource optimization, electric and natural gas commodity trading and wholesale marketing. Both the Energy Delivery and Generation and Resources lines of business fall within Avista Utilities, an operating division of Avista Corp. Avista Capital, which is a wholly-owned subsidiary of Avista Corp., owns all of the companies engaged in the National Energy Trading and Marketing and Non-energy lines of Business. The National Energy Trading and Marketing line of business includes Avista Advantage, Inc. (Avista Advantage), Avista Energy, Inc. (Avista Energy) and Avista Power, Inc. (Avista Power). See Item 1. Business - National Energy Trading and Marketing and Notes 1, 3 and 4 of Notes to Financial Statements for additional information. As of December 31, 1998 the Company had common equity investments of $216.6 million ($493.4 million including convertible securities) and $271.8 million in Avista Utilities and Avista Capital, respectively. The Non-energy line of business, also owned by Avista Capital, includes Avista Fiber, Inc. (Avista Fiber), Avista Development, Inc. (Avista Development), Avista Labs, Inc. (Avista Labs), Avista Communications, Inc. (Avista Communications) and Pentzer Corporation, which is the parent company to the majority of the Company's non-energy businesses. See Item 1. Business - Non-energy Business and Notes 1 and 17 of Notes to Financial Statements for additional information.
Below is the list of major companies owned by Avista Capital:
Avista Energy - An electricity and natural gas marketing and trading company.
Avista Advantage - A leading provider of Internet-based specialty billing and information services.
Avista Power - Created in December 1998 to develop and own generation assets, primarily in support of Avista Energy.
Pentzer - A wholly owned subsidiary of Avista Capital and the parent company for a majority of Avista Corp.'s Non-energy subsidiaries.
Avista Fiber - Designs, builds and manages metropolitan area fiber optic cable networks.
Avista Development - Real-estate and other investments.
Avista Labs - The developer of proton exchange membrane fuel cell technology.
Avista Communications - Created in January 1999 to provide local high-speed telecommunications services to under- served Northwest communities.
The Company's lines of business are illustrated below:
[FLOW CHART]
[ ] - denotes a business entity. o - denotes an operating division or line of business.
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For the twelve months ended December 31, 1998, 1997 and 1996, respectively, the Company derived operating revenues and income/(loss) from operations in the following proportions:
N/A - Not Applicable Gross margin is calculated by subtracting resource costs from operating revenues. (See Schedule of Information by Business Segments for further information).
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ENERGY DELIVERY
GENERAL
Energy Delivery provides electricity and natural gas distribution and transmission services in a 26,000 square mile area in eastern Washington and northern Idaho with a population of approximately 825,000. Energy Delivery also provides natural gas service in a 4,000 square mile area in northeast and southwest Oregon and in the South Lake Tahoe region of California, with the population in these areas approximating 495,000.
At the end of 1998, retail electric service was supplied to approximately 305,000 customers in eastern Washington and northern Idaho; retail natural gas service was supplied to approximately 262,000 customers in parts of Washington, Idaho, Oregon and California.
The Company expects economic growth to continue in its eastern Washington and northern Idaho service area. The Company, along with others in the service area, is continuing its efforts to facilitate expansion of existing businesses and attract new businesses to the Inland Northwest. Agriculture, mining and lumber were the primary industries for many years, but health care, education, electronic and other manufacturing, tourism and the service sectors have become increasingly important industries that operate in the Company's service area. The Company also anticipates moderate economic growth to continue in its Oregon service area.
The Company anticipates residential and commercial electric load growth to average approximately 2.3% annually for the next five years primarily due to increases in both population and the number of businesses in its service territory. The number of electric customers is expected to increase and the average annual usage by residential customers is expected to remain steady on a weather-adjusted basis.
The Company anticipates natural gas load growth, including transportation volumes, in its Washington and Idaho service area to average approximately 2.7% annually for the next five years. The Oregon and South Lake Tahoe, California service areas are anticipated to realize 3.1% growth annually during that same period. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations: Results of Operations: Future Outlook for additional information.
ELECTRIC OPERATIONS
Energy Delivery currently receives all of its electric supply from Generation and Resources. (See Generation and Resources - Electric Resources for additional information.)
Challenges facing the retail electric business include cost management, self-generation and fuel switching by commercial and industrial customers, the costs of increasingly stringent environmental laws and the potential for stranded or non-recoverable utility assets. In April 1996, the Federal Energy Regulatory Commission (FERC) issued Orders No. 888 and No. 889 which require electric utility companies to provide third-party access to their transmission systems and to establish an Open Access Same-time Information System (OASIS) to provide transmission customers with information about available transmission capacity, prices and other information, by electronic means. In addition, state legislatures in the Company's service territory are continuing to evaluate restructuring the retail electric business to full competition. When electric utility companies are required to provide retail wheeling service, which is the transmission of electric power from another supplier to a customer located within such utility's service area, the Company believes it will face minimal risk for stranded generation, transmission or distribution assets due to its low cost structure. However, the Company cannot predict the potential impact, if any, of restructuring the electric utility industry on the Company's future financial condition and results of operations. (See Industry Restructuring and Note 1 of Notes to Financial Statements for additional information.)
NATURAL GAS OPERATIONS
Natural gas remains competitively priced compared to alternative fuel sources for residential, commercial and industrial customers. Because of abundant supplies and competitive markets, natural gas should sustain its market advantage. The Company continues to advise electric customers as to the cost advantages of converting space and water heating needs to natural gas. Significant growth has occurred in the Company's natural gas business in recent years due to increased demand for natural gas in new construction. The Company also makes sales and provides transportation service directly to large natural gas customers and makes non-retail sales to marketers and producers where points of delivery are outside the Company's retail distribution area.
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Most of the Company's large industrial customers purchase their own natural gas requirements through gas marketers. For these customers, the Company provides transportation from the Company's pipeline interconnection to the customer's plant. The Company has numerous special contracts for natural gas transportation service, most of which contain negotiated rates for Company distribution service based on the customer's competitive alternatives. Seven of the Company's largest natural gas customers are provided natural gas transportation service by the Company under special contracts. These negotiated contracts were entered into to retain these customers who can either by-pass the Company's distribution system or have competitive alternative fuel capability. All special contracts are subject to regulatory review and approval. The competitive nature of the spot natural gas market results in savings in the cost of purchased natural gas, which encourages large customers with fuel-switching capabilities to continue to utilize natural gas for their energy needs. The total volume transported on behalf of transportation customers for 1998, 1997 and 1996 was approximately 226.1, 245.1 and 237.9 million therms, which represented approximately 39%, 43% and 40% of the Company's total system deliveries. In addition, the Company sells firm transportation to third parties when it is not needed to serve the Company's customers.
NATURAL GAS RESOURCES
Natural Gas Supply A diverse portfolio of resources allows the Company to capture market opportunities that benefit the Company's natural gas customers. Natural gas supplies are available from both domestic and Canadian sources through both long- and short-term, or spot market, purchases. The Company holds capacity on six pipelines and owns natural gas storage facilities which allow the Company to optimize its available resources.
Firm natural gas supplies are purchased by the Company through negotiated agreements having terms ranging between one month and seven years. During 1998, approximately one-third of the Company's purchases were in the short-term market, with contracts on a month-to-month basis. Approximately 14% of the natural gas supply was obtained from domestic sources, with the remaining 86% from Canadian sources. Nearly all natural gas purchased from Canadian sources is contracted in U.S. dollar denominations, limiting any foreign currency exchange exposure. The Company does not consider Canadian natural gas supplies to be at greater risk of non-delivery than U.S. supplies.
The Company holds capacity on six natural gas pipelines, Northwest Pipeline Company (NWP), Pacific Gas Transmission (PGT), Paiute Pipeline (Paiute), Tuscarora Gas Transmission Company (Tuscarora), NOVA Pipeline, Ltd. (NOVA) and Alberta Natural Gas Co. Ltd. (ANG), which provide the Company access to both domestic and Canadian natural gas supplies. In 1998, the Company obtained gas from over 25 different suppliers.
The Company contracts with NWP for three types of firm service (transportation, liquefied natural gas storage and underground storage), with Paiute for firm transportation and liquefied natural gas storage and with PGT, Tuscarora, NOVA and ANG for firm transportation only.
Jackson Prairie Natural Gas Storage Project (Storage Project) The Company owns a one-third interest in the Storage Project, which is an underground natural gas storage field located near Chehalis, Washington. The role of the Storage Project in providing flexible natural gas supplies is increasingly important to the Company's natural gas operations. It enables the Company to place natural gas into storage when prices are low or to meet minimum natural gas purchasing requirements, as well as to withdraw natural gas from storage when spot prices are high or as needed to meet high demand periods. The Company is in the process of increasing the capacity at the Storage Project. The increased capacity will be optimized by Avista Energy for the next 10 years, and in return, Avista Energy will be responsible for the capital costs related to the project expansion. The Company has contracted to release some of its Storage Project capacity to two other utilities until 2000 and 2001, with a provision under one of the releases to partially recall the released capacity if the Company determines additional natural gas is required for its own system supply.
ENERGY DELIVERY REGULATORY ISSUES
The Company, as a regulated public utility, is currently subject to regulation by state utility commissions with respect to prices, accounting, the issuance of securities and other matters. The retail electric operations are subject to the jurisdiction of the Washington Utilities and Transportation Commission (WUTC), the Idaho Public Utilities Commission (IPUC) and the Montana Public Service Commission (MPSC). The retail natural gas operations are subject to the jurisdiction of the WUTC, the IPUC, the Oregon Public Utility Commission (OPUC) and the California Public Utilities Commission (CPUC). The Company is also subject to the jurisdiction of the FERC for its (wholesale) natural gas rates charged for the release of capacity from the Jackson Prairie Storage Project.
In each regulatory jurisdiction, the price the Company may charge for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) is currently determined on a "cost of service" basis and is designed to provide, after recovery of allowable
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operating expenses, an opportunity to earn a reasonable return on "rate base." "Rate base" is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items (see Note 1 of Notes to Financial Statements for additional information about regulation, depreciation and deferred taxes). Over time, rate base is increased by additions to utility plant in service and reduced by depreciation of utility plant. As the energy business is restructured, traditional "cost of service" ratemaking may evolve into some other form of ratemaking. Rates for transmission services are based on the "cost of service" principles and are set forth in tariffs on file with the FERC. (See Industry Restructuring for additional information.)
General Rate Cases The Company's last general electric rate cases were effective in March 1987 for the State of Washington and September 1986 for the State of Idaho; both allowed a return on equity of 12.90%.
On December 18, 1998, the Company filed for a general electric rate increase of $14,223,000 or 11.56% with the IPUC. The Company is requesting a return on equity of 12.00%. An order is expected in the latter part of 1999. The Company anticipates filing for a retail increase in the State of Washington later in 1999.
On June 27, 1997, the Company filed a general natural gas rate increase of $7.87 million with the WUTC. A settlement agreement resulted in a $5 million, or 7.5%, increase effective January 1, 1998. Included in the settlement agreement was a stated return on equity of 10.75%. However, the agreements reached in the settlement do not set a precedent for future rate filings. The Company's last general natural gas rate cases involving litigated cost of capital resulted in allowed return on equity of 12.90% for the State of Washington, effective August 1990 and 12.75% for the State of Idaho, effective October 1989.
Power Cost Adjustment (PCA) The Company has a PCA in Idaho which tracks changes in hydroelectric generation, surplus energy prices, related changes in thermal generation and the Public Utility Regulatory Policies Act of 1978 (PURPA) contracts, but not changes in revenues or costs associated with other wheeling or power contracts. Rate changes are triggered when the deferred balance reaches $2.2 million, provided no more than two surcharges or rebates are in effect at the same time. See Note 1 of Notes to Financial Statements for additional information.
Service Territory Agreement In August 1998, the Company executed a new electric service territory agreement with Inland Power and Light Company. Inland Power and Light is an electric cooperative serving approximately 30,000 customers in various suburban and rural areas of Eastern Washington, including areas around Spokane. The Company had an existing service territory agreement with Inland Power and Light that was due to expire in December 1998. The Company entered into the new agreement in order to protect service provided to existing customers and to establish rules for service to new customers. Under the agreement, generally, the utility with the closest electric facilities will serve a new customer. However, new customers with loads larger than 3 megawatts can choose their service provider. The agreement is for a fifteen year term and was approved by the WUTC on October 9, 1998.
Purchased Gas Adjustment (PGA or Natural Gas Trackers) Natural gas trackers are supplemental tariffs filed with state regulatory commissions which are designed to pass through changes in purchased natural gas costs and therefore, do not normally result in any changes in net income to the Company. On September 30, 1998, the Company filed a PGA with the WUTC. This filing requested a net revenue reduction of $42,000 or .06%. On December 1, 1998, a modified version of the original filing became effective with rates subject to change based on the WUTC's continuing audit. In January 1999, the audit was concluded with no adjustment to rates, and in February 1999, the Commission closed the investigation. In November 1998, the OPUC approved a $1.1 million, or 2.25% decrease effective December 1, 1998. In October 1998, the Company filed a natural gas tracker with the IPUC requesting a $1.1 million, or 4.0%, increase which was approved, effective December 7, 1998.
Natural Gas Benchmark Mechanism On December 1, 1998, the Company filed a proposal with the WUTC and IPUC to eliminate gas procurement operations within Avista Utilities and consolidate gas procurement operations under Avista Energy. A smaller natural gas staff would remain in Avista Utilities to prepare load forecasts and support regulatory activities. The ownership of the natural gas assets would remain with Avista Utilities, but would be managed by Avista Energy through an agency agreement.
Consolidation of natural gas procurement operations under Avista Energy would allow the Company to gain synergies and better manage its risk by combining and operating the two portfolios as one portfolio and to gain efficiencies by eliminating duplicate functions. The proposal to state regulators includes a Gas Benchmark mechanism that is designed to provide certain guaranteed benefits to retail customers as well as provide Avista Corp. the opportunity to improve earnings, i.e., a performanced-based mechanism.
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The Idaho Gas Benchmark mechanism sets three separate benchmarks or targets: commodity, pipeline capacity and Jackson Prairie storage. To the extent that Avista Energy optimizes these three components of gas costs, Avista Energy will retain the benefits. Likewise, if Avista Energy incurs costs in excess of the targets, it will absorb the loss.
The Gas Benchmark Mechanism was approved by the IPUC on February 1, 1999. The proposal is currently pending before the WUTC and the Company is currently working with WUTC staff to resolve issues in the proceeding. The Company is preparing a similar proposal for its Oregon natural gas procurement operations. The Company plans to file with the OPUC in March 1999.
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ENERGY DELIVERY OPERATING STATISTICS
(1) Transfer to Generation and Resources represents the portion of revenues collected by Energy Delivery from retail customers attributable to the sale of the electric energy commodity delivered by Energy Delivery.
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(1) Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic average indicate warmer than average temperatures).
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GENERATION AND RESOURCES
GENERAL
The Generation and Resources line of business manages the Company's natural gas and electric energy resource portfolio, which is used to serve Energy Delivery's retail customers and Generation and Resources' wholesale customers. The primary business focus of Generation and Resources is to optimize the availability and operation of generation resources. The Company owns and operates eight hydroelectric projects, a wood-waste fueled generating station and two natural gas combustion turbine (CT) peaking units. See Item 2.
ITEM 2. PROPERTIES
ENERGY DELIVERY
Electric Distribution and Transmission Plant
The Company operates approximately 12,200 miles of primary and secondary distribution lines in its electric system in addition to a transmission system of approximately 550 miles of 230 kV line and 1,550 miles of 115 kV line. The Company also owns a 10% interest in 495 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana, and a 15% interest in three miles of a 500 kV line from Centralia, Washington to the nearest Bonneville Power Administration (Bonneville) interconnection.
The 230 kV lines are used to transmit power from the Company's Noxon Rapids and Cabinet Gorge hydroelectric generating stations to major load centers in the Company's service area as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect with Bonneville at five locations and at one location each with PacifiCorp, Montana Power and Idaho Power Company. The Bonneville interconnections serve as points of delivery for power from the Colstrip and Centralia generating stations as well as for the interchange of power with entities outside the Pacific Northwest. The interconnection with PacifiCorp is used to integrate Mid-Columbia hydroelectric generating facilities to the Company's loads as well as for the interchange of power with entities within the Pacific Northwest.
The 115 kV lines provide for transmission of energy as well as providing for the integration of the Spokane River hydroelectric and Kettle Falls wood-waste generating stations with service area load centers. These lines interconnect with Bonneville at nine locations, Grant County Public Utility District (PUD), Seattle City Light and Tacoma City Light at two locations and one interconnection each with Chelan County PUD, PacifiCorp and Montana Power.
Natural Gas Plant
The Company has natural gas distribution mains of approximately 3,897 miles in Washington and Idaho and 1,755 miles in Oregon and California, as of December 31, 1998.
The Company, NWP and Puget Sound Energy each own a one-third undivided interest in the Storage Project, which has a total peak day deliverability of 5.7 million therms, with a total working natural gas inventory of 155.2 million therms.
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GENERATION AND RESOURCES
The Company's electric generation properties, located in the States of Washington, Idaho and Montana, include the following:
Generating Plant
N/A Not applicable.
(1) Nameplate Rating, also referred to as "installed capacity", is the manufacturer's assigned power rating under specified conditions.
(2) Capability is the maximum generation of the plant without exceeding approved limits of temperature, stress and environmental conditions.
(3) The formal relicensing process began in September 1995 for Cabinet Gorge and Noxon Rapids. (See Generation and Resources - Hydroelectric Relicensing for additional information.)
(4) Jointly owned; data above refers to Company's respective 15% interests.
(5) Used primarily for peaking needs.
(6) Sold in early 1999.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
In December 1996, the Company filed a Complaint for declaratory relief and money damages against Underwriters at Lloyds of London (Lloyds) in Spokane County Superior Court. The purpose of this action was to seek a declaration of the insurance policies issued to the Company by Lloyds with respect to any liabilities of the Company for environmental damage associated with the oil spill at the Central Steam Plant and other environmental remediation efforts. The policies at issue were in effect during the period between 1926 and 1966; thereafter, the Company maintained its policies with another underwriter, Aegis. The Company's Complaint sought money damages in excess of $16 million. On March 10, 1999, Avista Corp. and Lloyds signed a settlement agreement resolving the claim.
Refer to Note 20 of Notes to Financial Statements and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Future Outlook: Other for additional information on this and other legal proceedings.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
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PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Outstanding shares of Common Stock are listed on the New York and Pacific Stock Exchanges. As of February 26, 1999, there were approximately 23,758 registered shareholders of the Company's no par value Common Stock.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations: Future Outlook for additional information about common stock dividends.
Refer to Notes 1 and 17 of Notes to Financial Statements for additional information. For high and low stock price information, refer to Note 23 of Notes to Financial Statements.
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ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
* Energy Delivery and Generation and Resources figures contain some minor consolidating intersegment eliminations.
(1) The change from 1997 was affected by the conversion of shares of common stock for Convertible Preferred Stock. The 1998 earnings per share would have been $1.35 had the conversion occurred on January 1, 1998. (See Notes 14 and 18 of Notes to Financial Statements for additional information.)
(2) The Company reduced its common stock dividend from the $0.31 per share paid in each of the first three quarters of the year to $0.12 per share in the fourth quarter of 1998.
(3) Includes the $41.4 million after-tax effect of the income tax recovery (see Note 8 of Notes to Financial Statements for additional information).
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ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Avista Corporation (Avista Corp. or the Company), formerly The Washington Water Power Company, operates as a regional utility providing electric and natural gas sales and services and as a national entity providing both energy and non-energy products and services. The utility portion of the Company, doing business as Avista Utilities, consists of two lines of business which are subject to state and federal price regulation -- (1) Energy Delivery and (2) Generation and Resources. The national businesses are conducted under Avista Capital, which is the parent company to the Company's subsidiaries.
The Energy Delivery line of business includes transmission and distribution services for retail electric operations, all utility natural gas operations, and other energy products and services. Costs associated with electric energy commodities, such as purchased power expense, as well as the revenues attributable to the recovery of such costs from retail customers, have been eliminated from the Energy Delivery line of business and are reflected in the results of the Generation and Resources line of business. The results of all natural gas operations are included in the Energy Delivery line of business because natural gas trackers allow natural gas costs to pass through within this line of business without the commodity prices having a material income effect. Usage by retail customers varies from year to year primarily as a result of weather conditions, customer growth and the economy in the Company's service area. Other factors which may influence long-term energy usage include conservation efforts, appliance efficiency and other technology.
The Generation and Resources line of business includes the generation and production of electric energy, and short- and long-term electric and natural gas sales trading and wholesale marketing, primarily to other utilities and power brokers in the Western Systems Coordinating Council (WSCC). Energy trading includes short-term sales and purchases, such as next hour, next day and monthly blocks of energy. Wholesale marketing includes sales and purchases under long-term contracts with one-year and longer terms. Generation and Resources manages the Company's electric energy resource portfolio, which is used to serve Energy Delivery's retail electric customers and Generation and Resources' wholesale electric customers. In managing the electric energy resource portfolio, Generation and Resources seeks to optimize the availability and operations of generation resources. Revenues and the cost of electric power purchases vary from year to year depending on the electric wholesale power market, which is affected by several factors, including the availability of water for hydroelectric generation, the availability of base load plants in the region, marginal fuel prices and the demand for power in other areas of the country. Other factors affecting the wholesale power market include lower unit margins on new sales contracts than were realized in the past, fewer long-term power contracts being entered into, deregulation of the electric utility industry and competition from low cost generation being developed by independent power producers.
Avista Capital is the parent company to the National Energy Trading and Marketing and Non-energy businesses. In order to proactively respond to deregulation, the Company created the National Energy Trading and Marketing line of business, which is comprised of Avista Energy, Avista Advantage and Avista Power. Avista Energy focuses on commodity trading, energy marketing and other related businesses on a national basis, which includes conducting business within the WSCC. Avista Energy's business is affected by several factors, including the demand for and availability of power throughout the United States, lower unit margins on new sales contracts, fewer long-term power contracts being entered into, marginal fuel prices and deregulation of the electric utility industry. Avista Advantage provides a variety of energy-related products and services to commercial and industrial customers on a national basis. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling. Avista Power was formed in December 1998 to develop and own generation assets primarily in support of Avista Energy. See Liquidity and Capital Resources: Energy Trading Business and Risk Management.
The Non-energy business is conducted primarily by Pentzer Corporation (Pentzer), which is the parent company to the majority of the Company's Non-energy businesses. Pentzer's business strategy is such that its earnings result from both transactional and non-transactional earnings. Transactional gains arise from a one-time event or a specific transaction, such as the sale of an investment or individual company from Pentzer's portfolio of investments. Non-transactional earnings arise out of the ongoing operations of the individual portfolio companies.
Changes underway in the utility and energy industries are creating new opportunities to expand the Company's businesses and serve new markets. In pursuing such opportunities, the Company is shifting its strategic direction to growth in order to achieve its goal of becoming a diversified North American energy company.
RESULTS OF OPERATIONS
OVERALL OPERATIONS
1998 COMPARED TO 1997
Overall reported earnings per share for 1998 were $1.28, compared to $1.96 in 1997. The primary factors causing the decrease from 1997 were an income tax recovery, net of associated items, which increased 1997 earnings per share by $0.49, and decreased operating income from the Generation and Resources line of business in 1998. In addition, in December 1998, the Company exchanged 15,404,595 shares of its common stock for shares of
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Convertible Preferred Stock (see Notes 14 and 18 of Notes to Financial Statements for additional information about the new Convertible Preferred Stock and earnings per share). If these shares had been exchanged at the beginning of the year, basic and diluted earnings per share for 1998 would have been $1.39 and $1.35, respectively.
Net income available for common stock decreased $39.7 million in 1998 from 1997. The 1998 results primarily reflect hydroelectric generation 21% lower than 1997 and increased purchased power prices and volumes, partially offset by improved earnings at Avista Energy. In addition, the 1997 results include the impact of $41.4 million, after-tax, in an income tax recovery from the Internal Revenue Service, which was partially offset by $14.0 million, after-tax, in environmental reserves and non-recurring adjustments (see below and Note 8 of Notes to Financial Statements for additional information about the income tax recovery). Excluding these items, utility (Energy Delivery and Generation and Resources) income available for common stock decreased $20.2 million, or 30%, in 1998, contributing $0.88 to earnings per share in 1998, compared to $1.22 in 1997. National Energy Trading and Marketing income available for common stock increased $9.6 million, contributing $0.22 to earnings per share in 1998 as compared to $0.04 in 1997 when there were only 5 months of operations. Non-energy operating income available for common stock decreased $1.8 million, or 15%, in 1998 and contributed $0.18 to earnings per share in 1998, compared to $0.21 in 1997. Transactional gains recorded by Pentzer totaled $4.3 million, or $0.08 per share, and $7.3 million, or $0.13 per share, in 1998 and 1997, respectively.
Interest expense increased $2.8 million in 1998, as compared to 1997, primarily due to higher levels of outstanding debt during the year. During 1998, $84.0 million of long-term debt was issued, while $14.0 million of long-term debt matured or was redeemed. At December 31, 1998, there was no short-term debt outstanding, compared to $108.5 million at December 31, 1997. Long-term debt outstanding at December 31, 1998 was $32.2 million lower than at the end of 1997.
Income taxes decreased $17.7 million, or 29%, in 1998 from 1997, primarily due to higher taxes in 1997 on the interest income received as a part of the income tax recovery, partially offset by adjustments related to revised estimates on certain tax issues.
Preferred stock dividend requirements increased $3.0 million in 1998 over 1997 due to the exchange of shares of common stock for shares of $12.40 Convertible Preferred Stock, Series L, which occurred in December 1998. This was partially offset by the redemption of $10 million in Preferred Stock, Series I in June 1998.
1997 COMPARED TO 1996
Overall earnings per share for 1997 were $1.96, compared to $1.35 in 1996. The 1997 results include the receipt of $41.4 million, after-tax, in an income tax recovery from the Internal Revenue Service, which was partially offset by environmental reserves and non-recurring adjustments (see below and Note 8 of Notes to Financial Statements for additional information about the income tax recovery). The 1996 results reflect $11.1 million in after-tax operating expenses related to storm damage on the electric distribution system and the expensing of $10.3 million in after-tax non-operating costs related to the terminated proposed merger between the Company and Sierra Pacific Resources (see Note 22 of Notes to Financial Statements for additional information about the merger termination). The 1996 results also reflect transactional gains totaling $15.1 million recorded by Pentzer primarily as a result of the sale of property by one of its subsidiary companies and the sale of stock in Itron, Inc. (Itron). Excluding all of these unusual items, earnings per share in 1997 would have been $1.47 as compared to $1.73 for 1996.
Net income available for common stock increased $33.9 million, or 45%, in 1997 over 1996. In 1997, the income tax recovery resulted in an increase of $0.74 in earnings per share for 1997, which was offset by $0.25 per share in environmental reserves and other miscellaneous non-recurring adjustments. The ice storm (see below) and merger-related expenses resulted in decreases of $0.20 and $0.18, respectively, in earnings per share for 1996. Utility income contributed $1.71 in 1997, compared to $0.97 in 1996. National Energy Trading and Marketing income available for common stock increased $3.6 million in 1997, contributing $0.04 to earnings per share in 1997 compared to a loss of $0.02 in 1996. Non-energy operating income available for common stock decreased $10.7 million, or 48%, in 1997 and contributed $0.20 to earnings per share in 1997 and $0.40 in 1996. Transactional gains recorded by Pentzer totaled $7.3 million, or $0.13 per share, in 1997, and $15.1 million, or $0.27, in 1996.
Interest expense increased $3.0 million in 1997, as compared to 1996, primarily due to higher levels of outstanding debt and new Preferred Trust Securities issued during the year. In 1997 and 1996, $70 million and $20 million, respectively, in preferred stock was redeemed, which resulted in higher levels of short-term borrowings. In addition, a total of $110 million in Preferred Trust Securities were issued in January and June 1997, distributions on which are included in interest expense. (See Note 15 of Notes to Financial Statements and Liquidity and Capital Resources for additional information.) During 1997 and 1996, $51.5 million and $38.0 million, respectively, of long-term debt matured or was redeemed, while $20.0 million in long-term debt was issued in 1997. At December 31, 1997, there was $108.5 million of short-term debt outstanding, compared to $85.0 million at December 31, 1996. Long-term debt outstanding at December 31, 1997 was $2.3 million lower than at the end of 1996.
In June 1997, the Company received $81 million from the Internal Revenue Service (IRS) to settle an income tax claim relating to its investment in the terminated nuclear project 3 of the Washington Public Power Supply System (WNP3). The $81 million recovery included $34 million in income taxes the Company overpaid in prior years plus
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$47 million in accrued interest, which in total contributed $41.4 million, or $0.74 per share, to net income. (See Note 8 of Notes to Financial Statements for additional information about the income tax recovery.)
Income taxes increased $11.6 million, or 23%, in 1997 over 1996. The increased taxes in 1997 were primarily due to the taxes on the interest income received as a part of the income tax recovery, partially offset by an $11.4 million income tax benefit associated with the income tax recovery and adjustments related to revised estimates on certain tax issues.
Preferred stock dividend requirements decreased $2.6 million in 1997 from 1996 due to the redemption of $20 million in Preferred Stock, Series I in June 1997 and the redemption of the entire $50 million Flexible Auction Preferred Stock, Series J in August 1997. These securities were redeemed with a portion of the proceeds of the Preferred Trust Securities which were issued in January and June 1997. However, as described above, distributions on the Preferred Trust Securities are accounted for in interest expense, not preferred dividends.
ENERGY DELIVERY
1998 COMPARED TO 1997
Energy Delivery's income from operations increased $3.2 million in 1998 over 1997 primarily due to increased revenues in 1998. Energy Delivery's operating revenues increased $29.2 million, while operating expenses increased $26.0 million during 1998 as compared to 1997.
Total electric retail revenues increased $1.8 million in 1998 as compared to 1997, primarily as a result of increased commercial and industrial revenues, partially offset by decreased revenues from residential customers. Total natural gas revenues increased $27.4 million in 1998 over 1997, primarily due to a combination of 4.4% customer growth, increased natural gas prices approved by the Washington Utilities and Transportation Commission (WUTC), effective in January 1998, and an increase in non-retail sales, partially offset by decreased customer usage as a result of weather 13% warmer than normal in 1998 as compared to 5% warmer than normal in 1997.
Natural gas purchased costs increased $15.3 million in 1998 due to increased sales volumes as a result of customer growth and higher non-retail sales. Administrative and general expenses increased $7.0 million due primarily to executive changes, corporate name change expenses and incentives. Depreciation and amortization increased $2.0 million due to higher amounts of plant-in-service.
1997 COMPARED TO 1996
Energy Delivery's income from operations increased $24.3 million, or 27%, in 1997 over 1996 primarily due to $17.1 million in pre-tax expenses associated with the storm damage on the Company's electric distribution system in 1996. Energy Delivery's operating revenues increased $0.1 million, while expenses decreased $24.2 million during 1997 as compared to 1996.
On November 19, 1996, the eastern Washington and northern Idaho region experienced an ice storm that resulted in damage to the Company's electric transmission and distribution system. The Company's service area was affected by continuing snow and rain, which hampered the Company's efforts to restore electric service to some customers until December 1, 1996. Initially, over one-third, or 100,000, of the Company's retail electric customers were without electric service. Repairing the damage to the Company's system cost approximately $21.8 million, of which $17.1 million (pre-tax) was attributable to operations and maintenance expenses, including labor and materials, for the repair of damaged lines, transformers and other equipment. The remainder of the cost represents capital expenditures to replace poles and other equipment damaged beyond repair.
Total electric retail revenues increased $5.6 million in 1997 as compared to 1996, primarily as a result of increased transmission revenues, partially offset by decreased revenues from retail electric customers. Transmission revenues increased $7.6 million in 1997 over 1996 due to increased wholesale electric sales. Electric retail revenues decreased $3.4 million, primarily due to decreased industrial sales as a result of the DADS tariff and other adjustments, partially offset by a 1.6% growth in retail customers during 1997. Total natural gas revenues decreased $5.5 million in 1997 from 1996, primarily due to decreased therm sales as a result of weather 5% warmer than normal in 1997, compared to 9% colder than normal in 1996, and decreased natural gas prices, partially offset by an increase in non-retail sales and 5.7% customer growth.
Operating and maintenance expenses decreased $21.4 million in 1997 from 1996 primarily due to the $17.1 million in expenses recorded in 1996 related to the storm damage on the Company's electric distribution system. Natural gas purchased expense decreased $2.7 million in 1997 from 1996 primarily due to lower therm sales as a result of warmer weather.
GENERATION AND RESOURCES
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1998 COMPARED TO 1997
Generation and Resources' income from operations decreased $38.4 million, or 59%, in 1998 from 1997. The decrease was due to hydroelectric generation 21% lower than 1997, which resulted in increased purchased power costs due to both increased prices and volumes. Generation and Resources' operating revenues and expenses increased $128.4 million and $166.8 million, respectively, during 1998 as compared to 1997.
Generation and Resources' revenues increased 25% in 1998 over 1997, primarily due to increased short-term sales; however, this was more than offset by increased purchased power and fuel costs. Revenues from short-term sales increased $163.2 million, while long-term revenues decreased $35.8 million in 1998 as compared to 1997. Total sales volumes during 1998 increased 17% over 1997. Short-term sales volumes increased 3.4 million mwhs, or 28%, while long-term sales decreased 0.6 million mwhs.
Increased short-term sales volumes and prices 30% higher than the previous year resulted in a $160.4 million, or 52%, increase in electric purchased power expense in 1998 over 1997, which accounts for the majority of the increase in Generation and Resources' operating expenses. Fuel costs increased $9.8 million in 1998 compared to 1997 as a result of increased generation at the thermal generating plants to meet the demand for energy.
1997 COMPARED TO 1996
Generation and Resources' income from operations decreased $19.6 million, or 23%, in 1997 from 1996. The decrease was due to an $11.8 million decrease from the expiration of older sales contracts with higher margins, lower unit margins on new sales contracts and higher transmission expenses due to increased sales. Generation and Resources' operating revenues and expenses increased $92.6 million and $112.2 million, respectively, during 1997 as compared to 1996. Results from this business segment included activities for the first seven months of 1997 that as of August 1997 were conducted by Avista Energy.
Generation and Resources' revenues increased 22% in 1997 over 1996, primarily due to increased short-term sales. Revenues from short-term sales increased $99.8 million, while long-term revenues decreased $0.4 million in 1997 as compared to 1996. Total sales volumes during 1997 increased 47% over 1996. Short-term sales volumes increased 5.4 million mwhs, or 82%, while long-term sales decreased 0.2 million mwhs.
Increased short-term sales resulted in a $119.4 million, or 63%, increase in electric purchased power expense in 1997 over 1996. Fuel costs decreased $6.1 million in 1997 compared to 1996 as a result of economic dispatch of the thermal generating plants.
NATIONAL ENERGY TRADING AND MARKETING
National Energy Trading and Marketing includes the results of Avista Energy, the national energy marketing subsidiary, Avista Advantage, the energy services subsidiary, and Avista Power, which was formed in December 1998 to develop and own generation assets primarily in support of Avista Energy. Avista Power operations had no impact on 1998 earnings. Although Avista Energy and Avista Advantage began incurring start-up costs during 1996, Avista Energy only became operational in July 1997 and began trading operations in August 1997. Year to year results are not comparable since 1997 only represents five months of operations. Avista Energy maintains a trading portfolio which it marks to fair market value on a daily basis (mark-to-market accounting), and which may cause earnings variability in the future.
1998 COMPARED TO 1997
National Energy Trading and Marketing's income available for common stock increased $9.6 million over 1997, while income from operations increased $17.7 million in 1998 over 1997, primarily due to a full year of operations at Avista Energy. This increase was partially offset by a loss from the energy services business, due to customers and revenue streams that did not materialize as expected and a longer than anticipated sales cycle. National Energy Trading and Marketing's operating revenues and expenses increased $2.16 billion and $2.14 billion, respectively, during 1998 as compared to 1997 when the Company only had five months of operations.
Avista Energy provided positive results in 1998 despite the price volatility experienced in power markets in the Midwest and East during various periods of the year. The company was well-positioned in its market, which allowed net gains in its portfolio during periods of high volatility. Avista Energy expected high volatility in Eastern electric markets in the summer of 1998 based on expected demand and the high probability of a weather-related impact on energy prices. As a result, Avista Energy established positions in anticipation of volatile market swings, and in turn experienced positive earnings in its portfolio during this period. However, there is no guarantee that positive results can or will always be achieved. For additional information about market risk and credit risk, see Liquidity and Capital Resources: Risk Management.
National Energy Trading and Marketing's total assets and liabilities increased by approximately $739.9 million from December 31, 1997 to December 31, 1998. This increase resulted primarily from the increased volume of
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transactions, as well as the impact of the market's price volatility on forward price curves, which increased the valuation of Avista Energy's mark-to-market assets and liabilities.
1997 COMPARED TO 1996
National Energy Trading and Marketing's income from operations increased $4.0 million in 1997 over 1996. This increase was primarily due to Avista Energy becoming operational, partially offset by continued start-up costs at both Avista Energy and Avista Advantage and, for the energy services business, customers and revenue streams that did not materialize as expected and a longer than anticipated sales cycle. National Energy Trading and Marketing's operating revenues and expenses increased $247.5 million and $243.5 million, respectively, during 1997 as compared to 1996.
NON-ENERGY
1998 COMPARED TO 1997
Non-energy income available for common stock for 1998 was $9.8 million, which was a $1.8 million decrease from 1997 earnings. Transactional gains decreased to $4.3 million in 1998 from $7.3 million in 1997, while non-transactional earnings from Pentzer's portfolio companies increased $2.2 million. The non-transactional earnings included an approximate $4.4 million after-tax loss in the fourth quarter at a Pentzer operating company due to a business repositioning and an inventory adjustment.
Income from operations totaled $9.7 million, which was a $0.8 million increase over 1997. Non-energy operating revenues and expenses increased $68.3 million and $67.5 million, respectively, primarily as a result of acquisitions and increased business activity from several of Pentzer's portfolio companies.
1997 COMPARED TO 1996
Non-energy net income for 1997 was $11.5 million, which represents a $10.7 million, or 48%, decrease from 1996. The decrease in 1997 earnings primarily resulted from transactional gains recorded by Pentzer in 1997 totaling $7.3 million, from the sale of Itron stock and the sale of a portfolio company, compared to transactional gains during 1996 totaling $15.1 million, net of taxes and other adjustments, as a result of the sale of property by one of its subsidiary companies and the sale of stock in Itron.
Operating income decreased $6.1 million in 1997 from 1996 primarily as a result of lower earnings contributions from Pentzer portfolio companies. Non-energy operating revenues and expenses increased $18.2 million and $24.2 million, respectively, primarily as a result of acquisitions.
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LIQUIDITY AND CAPITAL RESOURCES
Overall Operations
Operating Activities Cash from operating activities less cash dividends paid provided all funds needed for capital expenditures in 1998, 1997 and 1996. Net cash provided by operating activities in 1998 increased over 1997 due primarily to the $143.4 million provided by the monetization of a contract (see below and Note 1 of Notes to Financial Statements for additional information). In addition, changes in various working capital components, such as receivables and payables, caused cashflows to decrease by $44.6 million from 1997, primarily due to the growth in Avista Energy's operations.
Investing Activities Net cash used in investing activities decreased in 1998 from 1997 primarily due to the sale of marketable securities held for investing activities by Pentzer, compared to the sale of subsidiary assets by Pentzer in 1997. Utility operations' capital expenditures, excluding Allowance for Funds Used During Construction (AFUDC) and Allowance for Funds Used to Conserve Energy (AFUCE, a carrying charge similar to AFUDC for conservation-related capital expenditures), were $268 million for the 1996-1998 period.
Financing Activities Net cash used in financing activities totaled $108.7 million in 1998 compared to $66.2 million in 1997. In 1998, $84.0 million of proceeds were received from the issuance of Medium-Term Notes. These proceeds, plus cash provided from operating activities, were used to retire $14.0 million of long-term debt, redeem $10 million of preferred stock and pay down $108.5 million of short-term debt. In 1997, $110 million of preferred trust securities were issued (see Note 15 of Notes to Financial Statements for additional information), the proceeds of which, along with an additional $20.0 million from the issuance of Secured Medium-Term Notes, were used for the maturity and redemption of $70.0 million of preferred stock and $51.5 million of long-term debt. During the 1996-1998 period, $203.5 million of long-term debt and preferred stock matured, was mandatorily redeemed or was optionally redeemed and refinanced at a lower cost.
During 1998, the Company entered into an agreement that increased the amount of customer accounts receivable the Company could sell from $40 million to $80 million to provide additional funds for capital expenditures, maturing long-term debt and preferred stock sinking fund requirements. At December 31, 1998, $25.0 million in receivables had been sold pursuant to the agreement.
In August 1998, the Company announced a dividend restructuring plan that reduced the Company's annual common stock dividend from $1.24 per share to $0.48 per share, a 61% reduction, which was effective with the payment of the common stock dividend paid on December 15, 1998. At the same time, an exchange offer was made whereby shareholders were provided the opportunity to exchange their shares of common stock for mandatorily convertible preferred shares, each of which pays an annual dividend of $1.24 per share for a period of about three years. After three years, the new-issue preferred shares will automatically convert back to common stock, based on the shares converted. The Company has the option of converting some or all of the new-issue shares to common stock prior to the end of the three-year period. Shareholders who chose not to participate in the exchange plan retained their ownership in Avista Corporation common stock. The annual savings resulting from the dividend restructuring are approximately $30 million for the next three years, increasing to about $42 million annually once the convertible preferred shares are converted back to common stock, which will assist in funding a portion of the Company's capital expenditures, maturing long-term debt and preferred stock sinking fund requirements. See Note 14 of Notes to Financial Statements for additional information about the new convertible preferred stock.
ENERGY DELIVERY AND GENERATION AND RESOURCES OPERATIONS
The Company funds capital expenditures with a combination of internally-generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates annually. Cash provided by operating activities remains the Company's primary source of funds for operating needs, dividends and capital expenditures.
Capital expenditures are financed on an interim basis with notes payable (due within one year). The Company has $200 million in committed lines of credit. In addition, the Company may currently borrow up to $100 million through other borrowing arrangements with banks. As of December 31, 1998, there were no outstanding borrowings under the committed lines of credit or the other short-term borrowing arrangements.
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From time to time the Company enters into sale/leaseback arrangements for various long-term assets which provide additional sources of funds. See Note 12 of Notes to Financial Statements for additional information.
In December 1998, the Company assigned and transferred certain rights under a long-term power sales contract to a funding trust. In return, the Company received approximately $143.4 million, representing the present value of the cash flows for the majority of the remaining payments due under the long-term sales contract. The Company utilized the funds to repay short-term bank borrowings and other debt.
The Company is restricted under various agreements as to the additional securities it can issue. Under the most restrictive test of the Company's Mortgage, an additional $623 million of First Mortgage Bonds could be issued as of December 31, 1998. As of December 31, 1998, under its Restated Articles of Incorporation, approximately $715 million of additional preferred stock could be issued at an assumed dividend rate of 6.95%.
During the 1999-2001 period, utility capital expenditures are expected to be $283 million, and $127.5 million will be required for long-term debt maturities and preferred stock sinking fund requirements. During this three-year period, the Company estimates that internally-generated funds will provide approximately 80% of the funds needed for its capital expenditure program. External financing will be required to fund a portion of capital expenditures, maturing long-term debt and preferred stock sinking fund requirements. Sources of funds would include, but are not necessarily limited to, cash flows from the reduction in the Company's common stock dividend, sales of certain assets, additional long-term debt, leasing or other equity securities. These estimates of capital expenditures are subject to continuing review and adjustment. Actual capital expenditures may vary from these estimates due to factors such as changes in business conditions, construction schedules and environmental requirements.
See Notes 2, 10, 11, 12, 13, 14, 15, 16 and 17 of Notes to Financial Statements for additional details related to financing activities.
NATIONAL ENERGY TRADING AND MARKETING OPERATIONS
During 1998, the Company invested $65.1 million in the common equity of Avista Capital. Avista Capital utilized the majority of the proceeds from this investment to increase its total investment in the common equity of Avista Energy to $106.7 million. Avista Energy funds its ongoing operations with a combination of internally-generated cash and external financing. The Company expects continued significant growth in Avista Energy's national energy trading and marketing business activities. This rapid growth will require increased capital investment, as well as an increased need for credit and financial support.
Effective December 23, 1998, Avista Energy arranged for an increase in its credit facility with a commercial bank from $50 million to $100 million. The credit agreement expires April 1, 1999. The facility provides capital resources to accommodate growth, principally in the form of letters of credit used to enhance credit for natural gas and electricity purchases. The credit facility also provides Avista Energy liquidity in the form of short-term borrowings used to finance inventory and receivables. The maximum cash component of credit extended by the bank is $30 million, with availability of up to $100 million in the issuance of letters of credit. The credit agreement may be terminated by the bank at any time and all extension of credit under the agreement are payable upon demand, in either case at the bank's sole discretion. The facility is guaranteed by Avista Capital and is secured by substantially all of Avista Energy's assets. At December 31, 1998 and 1997, there were no cash advances (demand notes payable) outstanding. Letters of credit outstanding under the facility totaled approximately $20.2 million and $2.8 million at December 31, 1998 and 1997, respectively. See Note 11 of Notes to Financial Statements for additional information.
At December 31, 1998, the National Energy Trading and Marketing operations had $38.0 million in cash and cash equivalents and $0.9 million in long-term debt outstanding.
The 1999-2001 National Energy Trading and Marketing capital expenditures are expected to be $10.1 million.
NON-ENERGY OPERATIONS
Capital expenditures for the non-energy operations were $28.0 million for the 1996-1998 period. During this period, $45.5 million of debt was repaid and capital expenditures were partially financed by the $62.6 million in proceeds from new long-term debt.
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The non-energy operations have $54.0 million in short-term borrowing arrangements ($21.4 million outstanding as of December 31, 1998) to fund corporate requirements on an interim basis. At December 31, 1998, the non-energy operations had $18.0 million in cash and marketable securities with $54.0 million in long-term debt outstanding.
The 1999-2001 non-energy capital expenditures are expected to be $17.8 million, and $32.3 million in debt maturities will also occur. During the next three years, internally-generated cash and other debt obligations are expected to provide the majority of the funds for the non-energy capital expenditure requirements.
Avista Labs, a subsidiary of Avista Capital, recently announced the receipt of a $2 million technology development award from the Department of Commerce's National Institute of Standards and Technology Advanced Technology Program. The Company will contribute another $1.22 million over a two-year period. Avista Labs plans to work on technology that will increase the energy density of its fuel cell design and develop multiple fuel processing approaches using propane, methane and methanol as base fuels to integrate into its fuel cell subsystem.
(1) Capital expenditures exclude AFUDC and AFUCE.
(2) Excludes notes payable (due within one year).
The Company's total common equity decreased $260.8 million to $488.0 million at the end of 1998. The 1998 decrease was primarily due to the exchange of shares of common stock for shares of $12.40 Convertible Preferred Stock, Series L (see Note 14 of Notes to Financial Statements for additional information). The Company's consolidated capital structure at December 31, 1998, was 45% debt, 25% preferred securities (including the Preferred Trust Securities) and 30% common equity as compared to 46% debt, 9% preferred securities (including the Preferred Trust Securities) and 45% common equity at year-end 1997. Had the convertible preferred stock been converted back to common stock, the Company's consolidated capital structure at December 31, 1998, would have been 45% debt, 9% preferred securities (including the Preferred Trust Securities) and 46% common equity.
ADDITIONAL FINANCIAL DATA
At December 31, 1998, the total long-term debt of the Company and its consolidated subsidiaries, as shown in the Company's consolidated financial statements, was approximately $730.0 million. Of such amount, $237.5 million represents long-term unsecured and unsubordinated indebtedness of the Company, and $449.3 million represents secured indebtedness of the Company. The balance of $43.2 million represents indebtedness of the subsidiaries. Consolidated long-term debt does not include the Company's subordinated indebtedness held by the issuers of Company-obligated preferred trust securities.
FUTURE OUTLOOK
Business Strategy
Changes underway in the utility and energy industries are creating new opportunities to expand the Company's businesses and serve new markets. In pursuing such opportunities, the Company is shifting its strategic direction to growth in order to achieve its goal of becoming a diversified North American energy company.
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The Company's growth strategy will expose the Company to risks associated with rapid expansion, challenges in recruiting and retaining qualified personnel, risks associated with acquisitions and joint ventures and increasing competition. In addition, growth in the energy trading and marketing business will expose the Company to increased financial and credit risks associated with commodity trading activities. The Company believes that its extensive experience in the electric and natural gas business, coupled with its strong management team, will allow the Company to effectively manage its transition to a diversified North American energy company.
Energy
The Company seeks to strengthen its position of leadership in energy delivery and generation as well as energy trading and marketing on a local, regional and national basis. The Company will seek to increase its asset and customer base through a focus on acquisitions and strategic alliances in all parts of its business. The Company intends to focus on growing its core energy business by seeking to acquire control of physical assets, specifically power generation assets and electric and natural gas transmission and distribution assets. The Company expects that initial growth will come at a local and regional level, with national growth to follow. Key strengths of the Company today include its position as one of the lowest cost producers of power in the nation, expertise in hydroelectric and power system management, plus capabilities in trading and wholesale and retail marketing of natural gas and electric energy. The Company is also continuing to develop a unique approach to commercialization of fuel cell technology.
Locally. The Company is a long-standing leader in the Northwest region of the United States, providing some of the lowest cost energy to its customers. The Company's strategy is to add selectively to its already strong foundation of state-regulated utility assets to solidify its position as a leading supplier of low-cost electric and natural gas energy services.
Regionally. The Company intends to add to its regulated and non-regulated assets on a regional basis and participate in industry consolidation to further optimize its assets and create greater economies of scale. In addition to energy delivery and generation, the Company plans to concentrate on growing its energy trading and marketing business. The strong growth in this business is driven by the Company's significant base of knowledge and experience in the operation of physical systems - for both natural gas and electric energy in the region, as well as its relationship-focused approach to the customer. The Company will also focus on expanding its telecommunications business through its newest subsidiary, Avista Communications. (See Note 21 of Notes to Financial Statements for additional information about this subsidiary.)
Nationally. The Company's strong regional energy trading and marketing skills serve as a platform for the Company's growing national presence. The Company will seek to expand its customer base through relationships with other energy providers outside the Company's Northwest stronghold, thereby leveraging its existing trading and marketing skills, as well as through its Internet-based specialty billing and information services.
Non-Energy
The Company conducts the majority of its non-energy business through Pentzer, its wholly owned subsidiary. Pentzer's business strategy is to acquire controlling interests in a broad range of middle market companies, facilitate improved productivity and growth, and ultimately sell such companies to the public or a strategic buyer.
Competition and Business Risk
The Company continues to compete for new retail electric customers with various rural electric cooperatives and public utility districts in and adjacent to its service territories. Challenges facing the retail electric business include evolving technologies that provide alternate energy supplies, the cost of the energy supplied, the potential for retail wheeling, self-generation and fuel switching by commercial and industrial customers and increasingly stringent environmental laws. When electric utility companies are required to provide retail wheeling service, the Company believes it will be in a position to benefit since it is committed to remaining one of the country's lowest-cost providers of electric energy. Consequently, the Company believes it faces minimal risk for stranded generation, transmission or distribution assets due to its low cost structure. The Company's need for new future electric resources to serve retail loads is expected to remain very minimal.
Natural gas remains priced competitively compared to other alternative fuel sources for residential, commercial and industrial customers and is projected to remain so into the future due to abundant supplies and competition. Challenges facing the Company's retail natural gas business include the potential for customers to by-pass the Company's natural gas system. To reduce the potential for such by-pass, the Company prices its natural gas services,
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including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of special contracts. The Company has long-term transportation contracts with seven of its largest industrial customers which reduces the risks of these customers by-passing the Company's system in the foreseeable future.
Generation and Resources and Avista Energy continue to compete in the wholesale electric market with other utilities, federal marketing agencies and power marketers. It is expected that competition to sell capacity will remain vigorous, and that prices will remain depressed for at least the next several years, due to increased competition and surplus capacity in the western United States. Competition related to the sale of capacity and energy is influenced by many factors, including the availability of capacity in the western United States, the availability and prices of natural gas and oil, spot energy prices and transmission access. Business challenges affecting the Generation and Resources and National Energy Trading and Marketing lines of business include competition from low-cost generation being developed by independent power producers, declining margins due to a greater reliance on short-term sales, evolving technologies that provide alternate energy supplies and deregulation of electric and natural gas markets.
The Company's energy-related businesses are exposed to risks relating to changes in certain commodity prices and counterparty performance. In order to manage the various risks relating to these exposures, the Company utilizes electric, natural gas and related commodity derivatives, and has established risk management oversight for these risks for each area of the Company's energy-related business. The Company has implemented procedures to manage such risk and has established a comprehensive Risk Management Committee, separate from the units that create such risk exposure and overseen by the Audit and Finance Committee of the Company's Board of Directors, to monitor compliance with the Company's risk management policies and procedures.
Economic and Load Growth
The Company expects economic growth to continue in its eastern Washington and northern Idaho service area. The Company, along with others in the service area, is continuing its efforts to facilitate expansion of existing businesses and attract new businesses to the Inland Northwest. Agriculture, mining and lumber were the primary industries for many years, but health care, education, electronic and other manufacturing, tourism and the service sectors have become increasingly important industries that operate in the Company's service area. The Company also anticipates moderate economic growth to continue in its Oregon service area.
The Company anticipates residential and commercial electric load growth to average approximately 2.3% annually for the next five years primarily due to increases in both population and the number of businesses in its service territory. The number of electric customers is expected to increase and the average annual usage by residential customers is expected to remain steady on a weather-adjusted basis. A Public Utility Regulatory Policies Act of 1978 (PURPA) contract with the Company's largest customer expires in 2002. The customer is expected to self-generate at that time, which will reduce the load to this customer by the amount the Company has been purchasing and then reselling to them. Although it will have no material impact on loads, it will reduce the Company's costs since the PURPA contract is at above-market prices. Overall, the load growth, adjusted for this situation, is 2.4% annually.
The Company anticipates natural gas load growth, including transportation volumes, in its Washington and Idaho service area to average approximately 2.7% annually for the next five years. The Oregon and South Lake Tahoe, California service areas are anticipated to realize 3.1% growth annually during that same period.
The forward-looking projections set forth above regarding retail sales growth are based, in part, upon publicly available population and demographic studies conducted independently. The Company's expectations regarding retail sales growth are also based upon various assumptions including, without limitation, assumptions relating to weather and economic and competitive conditions and an assumption that the Company will incur no material loss of retail customers due to self-generation or retail wheeling. Changes in the underlying assumptions can cause actual experience to vary significantly from forward-looking projections.
Environmental Issues
Since December 1991, a number of species of fish in the Northwest, including the Snake River sockeye salmon and chinook salmon, the Kootenai River white sturgeon, the upper Columbia River steelhead and the bull trout have been listed as threatened or endangered under the Federal Endangered Species Act (ESA). A listing of the upper Columbia River spring chinook is anticipated by mid-1999. Thus far, measures which have been adopted and implemented to save the Snake River sockeye salmon and chinook salmon have not directly impacted generation levels at any of the
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Company's hydroelectric dams. The Company does, however, purchase power from four projects on the Columbia River that are being directly impacted by ongoing mitigation measures for spring chinook, salmon and steelhead. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on the Company at this time. It is currently not possible to accurately predict the likely economic costs to the Company resulting from all future actions.
The Company is currently in the process of relicensing the Cabinet Gorge and Noxon Rapids hydroelectric projects on the Clark Fork River in northern Idaho and western Montana. The restoration of native salmonid fish, in particular bull trout, is a principal focus for the members of the collaborative relicensing team. Bull trout are native to this area and a "threatened" listing for bull trout occurred in 1998 under the ESA. The Company is working closely with the U.S. Fish and Wildlife Service, Native American tribes and the states of Idaho and Montana to institute coordinated recovery measures on the lower Clark Fork River. A settlement agreement reached in conjunction with the filing in February 1999 for new FERC licenses establishes a plan for bull trout restoration, including annual budget estimates.
Relicensing studies in 1997 and 1998 indicated very high levels of atmospheric gas supersaturation below Cabinet Gorge Dam during periods of heavy spill. The settlement agreement provides for additional studies to identify what, if any, effects there are to aqueous resources and whether abatement measures, and what type, will be required at Cabinet Gorge.
See Note 20 of Notes to Financial Statements for additional information.
YEAR 2000
The Company continues to move forward with a comprehensive program to address areas of risk associated with the Year 2000. Systems and programs that may be affected by the Year 2000 problem have been identified and activities are underway to make these systems Year 2000 ready. At this time, it is the Company's belief that all identified modifications that are within the Company's operating control will be made within the required time frames.
State of Readiness
In order to address Year 2000 issues, several project activity teams were created and a comprehensive readiness plan was developed to bring the Company's business critical systems into Year 2000 readiness by the middle of 1999. The Company defines business critical systems as systems that directly affect the Company's ability to deliver energy services to customers. The Company's Year 2000 project was originally divided into four major categories of activities: Desktop Computer Systems, Business Systems, Supply Chain and Embedded Systems. Contingency Planning developed into its own category in late 1998.
Desktop Computer Systems All desktop computer hardware has been Year 2000 tested and an inventory and assessment of desktop resident third-party software has been completed. The Company expects hardware remediation to be completed by mid-1999. All non-compliant third-party software programs and critical business desktop applications are expected to be upgraded, converted, tested and made Year 2000 ready by the middle of 1999.
Business Systems Many of the Company's critical business systems would not have operated correctly in the year 2000 and beyond, and thus have been or are in the process of being re-programmed, upgraded or replaced. Key business systems have been inventoried and assessed. The Company has completed remediating all mainframe computer code that required fixing to address the Year 2000 issue and testing has been completed on all but two of the Company's mainframe computer business systems. Testing of the two remaining mainframe business systems is scheduled to be completed before the end of April 1999. Implementation of a new Materials Management system is scheduled for late 1999. The Company is in the process of developing alternative plans in the unlikely event the Company is unable to implement the new Materials Management System before the year 2000. A failure of these systems would not jeopardize the Company's ability to deliver energy services to customers, but might affect its ability to perform selected accounting and business-related functions. The Company has completed testing and remediation of approximately 85% of its business critical systems.
Supply Chain The Company recognizes its dependence on outside suppliers of goods and services and is working to assure that the necessary products and services are available. To address these issues, the Company has communicated with suppliers and identified critical suppliers in order to investigate their efforts to become Year 2000 ready. In addition, the Company has made site visits to select key suppliers and will be reviewing their contingency plans.
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Embedded Systems The Embedded System team is responsible for locating, assessing, testing, fixing or replacing microprocessor-controlled devices. Inventory and assessment is 99 percent complete, and to date very few embedded systems have been found that require remediation. None of these requiring remediation would have caused a disruption in service to customers. Remediation and testing is complete at all eleven of the Company's generation sites and these sites are Year 2000 ready.
The Company's Supervisory Control and Data Acquisition (SCADA) system, which monitors and controls the majority of the Company's generating and substation equipment and the transmission system, was run "in the Year 2000" for three days without incident. Testing of electric metering and devices in the Company's transmission and distribution substations systems has been completed and full testing of selected substations is in process and scheduled to be completed by mid-1999.
Contingency Planning
The Company has developed contingency plans for the Company's electric and natural gas services and has also participated in the development of region-wide contingency plans for electric service through the Company's electric reliability region - the Western Systems Coordinating Council (WSCC).
A major Year 2000 project activity for the Company during 1999 will be the development and implementation of detailed operational plans to support the Company's contingency plans. Key activities in 1999 include the assignment of resources to key locations for the evening of December 31, 1999 and the morning of January 1, 2000, training of personnel, testing of backup procedures and the completion of tasks that support the Company's contingency plans. The Company will continue to participate in the further development and testing of the region-wide contingency plans. This includes region-wide drills coordinated by the WSCC scheduled for April 9, 1999 and September 9, 1999.
Costs
The Company estimates that the cost of its Year 2000 project will be approximately $6-7 million in incremental costs during the 1997-1999 time period. Through December 31, 1998, the Company has spent $3.5 million in incremental costs. These costs are being funded through operating cashflows. The Company does not expect costs associated with the Year 2000 project to materially affect the Company's earnings in any one year.
Risks
Based upon information to date, the Company believes that, in the most reasonably likely worst-case scenario, Year 2000 issues could result in abnormal operating conditions, such as short-term interruption of generation, transmission and distribution functions, as well as Company-wide loss of system monitoring and control functions and loss of voice communications. These conditions, along with disruptions in natural gas service caused by failures of gas suppliers or interstate gas pipelines coupled with power outages due to the possible instability of the regional electric transmission grid, could result in the possible temporary interruption of service to customers. The Company does not believe the overall impact of this scenario will have a material impact on its financial condition or operations due to the anticipated short-term nature of interruptions.
The Company believes the primary areas of Year 2000 risk to be internal business systems, which are discussed above, and external factors, which include the regional electric transmission grid and natural gas pipelines. There can be no guarantee that systems of other companies on which the Company's systems rely will be timely converted. A failure to convert by another company or a conversion that is incompatible with the Company's systems could have an effect on the Company's ability to provide energy services.
Electric The Company is working with the other energy suppliers in the area to address risks related to the regional electric transmission grid, which consists of the interconnected transmission systems of each utility within the WSCC. Such interconnected systems are critical to the reliability of each interconnected electric service provider, as the failure of one such interconnected provider to achieve Year 2000 compliance could disrupt the others from providing electric services. Should the regional electric transmission grid become unstable, power outages may occur. The Company cannot assure Year 2000 compliance or assess the effect of non-compliance by systems or parties that the Company does not control.
In addition to the traditional electric utility operations of the Company, the energy trading business conducted by Avista Energy is subject to Year 2000 risk. Most of Avista Energy's internal business systems do not require any
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significant upgrading and those that do are being addressed. However, if any of Avista Energy's counterparties experience Year 2000 problems (including, but not limited to, problems arising out of failures in the generation or transmission systems of utilities or other energy suppliers), such problems could impair the ability of Avista Energy or any of its counterparties to fulfill their contractual obligations. Avista Energy is in the process of contacting its counterparties to assess their Year 2000 readiness and of developing contingency plans. See "Energy Trading Business".
Natural Gas The Company has performed an inventory and assessment of the equipment in its natural gas distribution systems and believes that there are no devices in the systems that will cause a disruption in the delivery of natural gas to customers due to a Year 2000 problem. However, the Company depends on natural gas pipelines which it does not own or control, and if one or more of the pipelines is unable to deliver natural gas, the Company in turn will be unable to deliver natural gas to customers. In order to address this issue, the Company has contacted each of the natural gas pipeline companies with which it has contracts to assess their Year 2000 readiness efforts and will continue to take reasonable steps to ensure that these suppliers are addressing any Year 2000 related problems that would result in a disruption in natural gas services to customers.
ENERGY TRADING BUSINESS
The participants in the emerging wholesale energy market are public utility companies and, increasingly, power marketers which may or may not be affiliated with public utility companies or other entities. The participants in this market trade not only electricity and natural gas as commodities but also derivative commodity instruments such as futures, forwards, swaps, options and other instruments. This market is largely unregulated and most transactions are conducted on an "over-the-counter" basis, there being no central clearing mechanism (except in the case of specific instruments traded on the commodity exchanges). Power marketers, whether or not affiliated with other entities, generally do not own production facilities and are not subject to net capital or other requirements of any regulatory agency.
The Company (to the extent that the Generation and Resources segment conducts energy trading) and Avista Energy are subject to the various risks inherent in commodity trading including, particularly, market risk and credit risk.
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by supply (in the case of electricity, adequacy of generating reserve margins as well as scheduled and unscheduled outages of generating facilities) and demand (extreme variations in the weather, whether or not predicted). Market risk includes the risk of fluctuation in the market price of associated derivative commodity instruments. All market risk is influenced to the extent that the performance or non-performance by market participants of their contractual obligations and commitments affect the supply of, or demand for, the commodity.
Credit risk relates to the risk of loss that the Company (to the extent of Generation and Resources' trading activities) and/or Avista Energy would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with the Company or Avista Energy, as the case may be. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counterparty may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances which relate to other market participants which have a direct or indirect relationship with such counterparty. The Company and Avista Energy seek to mitigate credit risk (and concentrations thereof) by applying specific eligibility criteria to prospective counterparties. However, despite mitigation efforts, defaults by counterparties occur from time to time. To date, no such default has had a material adverse effect on the Company or Avista Energy.
Avista Capital provides guarantees for Avista Energy's line of credit agreement, and in the course of business may provide guarantees to other parties with whom Avista Energy may be doing business. The Company's investment in Avista Capital totaled $271.8 million at December 31, 1998.
RISK MANAGEMENT
The risk management process established by the Company is designed to measure both quantitative and qualitative risk in the business. The Company and Avista Energy have adopted policies and procedures to manage the risks inherent in their businesses and have established a comprehensive Risk Management Committee, separate from the units that
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create the risk exposure and overseen by the Audit and Finance Committee of the Company's Board of Directors, to monitor compliance with the Company's risk management policies and procedures on a regular basis. Nonetheless, adverse changes in interest rates, commodity prices and foreign currency exchange rates may result in losses in earnings, cash flow and/or fair values.
The forward-looking information presented below provides only estimates of what may occur in the future, assuming certain adverse market conditions, due to reliance on model assumptions. As a result, actual future results may differ materially from those presented. These disclosures are not indicators of expected future losses, but only indicators of reasonably possible losses.
Interest Rate Risk The Company is subject to the risk of fluctuating interest rates in the normal course of business. The fair value of the Company's cash and short-term investment portfolio and the fair value of notes payable at December 31, 1998 approximated carrying value. Given the short-term nature of these instruments, market risk, as measured by the change in fair value resulting from a hypothetical change in interest rates, is immaterial.
The Company manages interest rate risk by taking advantage of market conditions when timing the issuance of long-term financings and optional debt redemptions and through the use of fixed rate long-term debt with varying maturities. A portion of the Company's capitalization consists of floating rate Company-Obligated Mandatorily Redeemable Preferred Trust Securities, of which the interest portion of the $50 million Series B resets on a quarterly basis, reflecting current market conditions. As of December 31, 1998, a hypothetical 15% change in interest rates would result in an immaterial change in the Company's cash flows related to the increased interest expense associated with these floating rate securities.
Commodity Price Risk The Company and Avista Energy are exposed to market fluctuations in the price and transportation costs of electric and natural gas commodities and, therefore, enter into contracts to hedge the impact of these fluctuations on their energy-related assets, liabilities, and other contractual arrangements. In addition, Avista Energy enters into these contracts for trading purposes to take advantage of market opportunities. At times this may create a net open position in its portfolio that could result in material losses if prices do not move in the manner or direction anticipated. The Company and Avista Energy's risk management program and policies are designed to manage the risks associated with market fluctuations in the price of electricity and natural gas commodities (see Note 3 of Notes to Financial Statements for additional information).
Avista Energy measures the risk in its derivative commodity portfolio on a daily basis utilizing a Value-at-Risk (VAR) model and monitors its risk in comparison to established thresholds. VAR measures the worst expected loss over a given time interval under normal market conditions at a given confidence level. The Company and Avista Energy also use other measures to monitor the risk in their derivative commodity portfolios on a monthly, quarterly and annual basis.
The VAR computations are based on an historical simulation, which utilizes price movements over a specified period to simulate forward price curves in the energy markets to estimate the unfavorable impact of one-day's price movement in the existing portfolio. The quantification of market risk using VAR provides a consistent measure of risk across diverse energy markets and products. VAR represents an estimate of reasonably possible net losses in earnings that would be recognized on its portfolio assuming hypothetical movements in future market rates and is not necessarily indicative of actual results that may occur.
Avista Energy's VAR computations utilize several key assumptions, including a 95% confidence level for the resultant price movement and a one-day holding period. The calculation includes derivative commodity instruments held for trading purposes and excludes the effects of written and embedded physical options in the trading portfolio.
At December 31, 1998, Avista Energy's estimated potential one-day unfavorable impact on gross margin was $3.3 million, as measured by VAR, related to its commodity trading and marketing business. The average daily VAR for 1998 was $3.0 million. Changes in markets inconsistent with historical trends or assumptions used could cause actual results to exceed predicted limits. Market risks associated with derivative commodity instruments held for purposes other than trading were not material at December 31, 1998.
In addition to commodity price risk, the Company's commodity positions are also subject to operational and event risks including, among others, increases in load demand, transmission or transport disruptions, fuel quality specifications and forced outages at generating plants.
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Foreign Currency Risk The Company has investments in several Canadian companies through Pentzer's acquisition of Universal Showcase, Inc. and Avista Energy Canada, Ltd. and its acquisition of Coast Pacific Management, Inc. (see Note 21 for additional information about these acquisitions). The Company's exposure to foreign currency risk and other foreign operations risk was immaterial to the Company's consolidated results of operations and financial position in 1998 and is not expected to change materially in the near future.
OTHER
On July 28, 1998, the United States District Court for the District of Idaho issued its finding that the Coeur d' Alene Tribe of Idaho (Tribe) owns the bed and banks of the Coeur d' Alene Lake and the St. Joe River lying within the current boundaries of the Coeur d' Alene Reservation. The disputed bed and banks comprise approximately the southern one-third of the Coeur d' Alene Lake. This action had been brought by the United States on behalf of the Tribe against the State of Idaho. The decision has been appealed by the State of Idaho to the Ninth Circuit. While the Company is not a party to this action, it is meeting with the Tribe to evaluate the impact of this decision on storage rights on the reservoir and operation of the Company's hydroelectric facilities on the Spokane River, downstream of the Coeur d' Alene Lake, which is the reservoir for these plants.
The Board of Directors considers the level of dividends on the Company's common stock on a continuing basis, taking into account numerous factors including, without limitation, the Company's results of operations and financial condition, as well as general economic and competitive conditions. The Company's net income available for dividends is derived from its retail electric and natural gas utility operations.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
The Company is including the following cautionary statement in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions (many of which are based, in turn, upon further assumptions) and are all statements which are other than statements of historical fact, including without limitation those that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," and similar expressions. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that the Company's expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the Company's business or the extent to which any such factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
Energy Delivery and Generation and Resources Operations -
In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the Company and its Energy Delivery and Generation and Resources operations to differ materially from those discussed in forward-looking statements include prevailing legislative developments, governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures, weather conditions, wholesale and retail competition (including but not limited to electric retail wheeling and transmission cost), availability of economic supplies of natural gas, present or prospective natural gas distribution or transmission competition (including but not limited to prices of alternative fuels and system deliverability costs), recovery of purchased power and purchased gas costs, present or prospective generation, operations and construction
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of plant facilities, and acquisition and disposal of assets or facilities.
National Energy Trading and Marketing Operations -
In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the National Energy Trading and Marketing operations to differ materially from those discussed in forward-looking statements include further industry restructuring evolving from federal and/or state legislation, regulatory actions by state utility commissions, demand for and availability of energy throughout the country, wholesale competition, availability of economic supplies of natural gas, margins on purchased power, and the formation of additional alliances or entities.
Non-Energy Operations -
Certain important factors which could cause actual results or outcomes for the Company's non-energy operations to differ materially from those discussed in forward-looking statements include competition from other companies, the ability to obtain new customers and retain old ones, reliability of customer orders, business acquisitions, disposal of assets, the ability to obtain funds from operations, debt or equity, research and development findings and the availability of economic expansion or development opportunities.
Factors Common to All Operations -
The business and profitability of the Company are also influenced by economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions, population growth rates and demographic patterns, market demand for energy from plants or facilities, changes in tax rates or policies, unanticipated project delays or changes in project costs, unanticipated changes in operating expenses or capital expenditures, labor negotiation or disputes, changes in credit ratings or capital market conditions, inflation rates, inability of the various counterparties to meet their obligations with respect to the Company's financial instruments, changes in accounting principles and/or the application of such principles to the Company, changes in technology and legal proceedings.
ITEM 7a.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See "Management's Discussion and Analysis of Results and Operations: Liquidity and Capital Resources: Risk Management."
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Independent Auditor's Report and Financial Statements begin on the next page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
INDEPENDENT AUDITORS' REPORT
Avista Corporation Spokane, Washington
We have audited the accompanying consolidated balance sheets and statements of capitalization of Avista Corporation and subsidiaries (the Company) as of December 31, 1998 and 1997, and the related and consolidated statements of income, comprehensive income and retained earnings, and cash flows for each of the three years in the period ended December 1998, which included the schedules of information by business segments. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1998 and 1997, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Seattle, Washington January 29, 1999 (February 1, 1999 as to Note 21 and March 10, 1999 as to Note 20)
CONSOLIDATED STATEMENTS OF INCOME, COMPREHENSIVE INCOME AND RETAINED EARNINGS
Avista Corporation - -------------------------------------------------------------------------------- For the Years Ended December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CONSOLIDATED BALANCE SHEETS
Avista Corporation - -------------------------------------------------------------------------------- At December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
Avista Corporation - ------------------------------------------------------------------------------- At December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CONSOLIDATED STATEMENTS OF CASH FLOWS Increase (Decrease) in Cash and Cash Equivalents
Avista Corporation - ------------------------------------------------------------------------------- For the Years Ended December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
SCHEDULE OF INFORMATION BY BUSINESS SEGMENTS
Avista Corporation - ------------------------------------------------------------------------------- For the Years Ended December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
AVISTA CORPORATION - -------------------------------------------------------------------------------- NOTES TO FINANCIAL STATEMENTS - --------------------------------------------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
Avista Corporation (Avista Corp. or the Company), formerly The Washington Water Power Company, was incorporated in the State of Washington in 1889, and operates as a regional utility providing electric and natural gas sales and services and as a national entity providing both energy and non-energy products and services. The utility portion of the Company, doing business as Avista Utilities, consists of two lines of business which are subject to state and federal price regulation - -- (1) Energy Delivery and (2) Generation and Resources. The national businesses are conducted under Avista Capital, which is the parent company to the Company's subsidiaries.
Changes underway in the utility and energy industries are creating new opportunities to expand the Company's businesses and serve new markets. In pursuing such opportunities, the Company is shifting its strategic direction to growth in order to achieve its goal of becoming a diversified North American energy company.
The Company's growth strategy will expose the Company to risks associated with rapid expansion, challenges in recruiting and retaining qualified personnel, risks associated with acquisitions and joint ventures and increasing competition. In addition, growth in the energy trading and marketing business will expose the Company to increased financial and credit risks associated with commodity trading activities. The Company believes that its extensive experience in the electric and natural gas business, coupled with its strong management team, will allow the Company to effectively manage its transition to a diversified North American energy company.
The Energy Delivery line of business includes transmission and distribution services for retail electric operations, all utility natural gas operations, and other energy products and services. Usage by retail customers varies from year to year primarily as a result of weather conditions, customer growth, the economy in the Company's service area, conservation efforts, appliance efficiency and other technology.
The Generation and Resources line of business includes the generation and production of electric energy, and short- and long-term electric and natural gas sales trading and wholesale marketing primarily to other utilities and power brokers in the western United States. Energy trading includes short-term sales and purchases, such as next hour, next day and monthly blocks of energy. Wholesale marketing includes sales and purchases under long-term contracts with one-year and longer terms. Generation and Resources manages the Company's electric energy resource portfolio, which is used to serve Energy Delivery's retail electric customers and Generation and Resources' wholesale electric customers. In managing the electric energy resource portfolio, Generation and Resources seeks to optimize the availability and operations of generation resources. Revenues and the cost of electric power purchases vary from year to year depending on the electric wholesale power market, which is affected by several factors, including the availability of water for hydroelectric generation, the availability of base load plants in the region, marginal fuel prices and the demand for power in other areas of the country. Other factors affecting the wholesale power market include lower unit margins on new sales contracts than were realized in the past, fewer long-term power contracts being entered into, deregulation of the electric utility industry and competition from low cost generation being developed by independent power producers.
Avista Capital is the parent company to the National Energy Trading and Marketing and Non-energy businesses. The National Energy Trading and Marketing businesses are conducted by Avista Energy, Avista Advantage and Avista Power. Avista Energy focuses on commodity trading, energy marketing and other related businesses on a national basis. Avista Energy's business is affected by several factors, including the demand for and availability of power throughout the United States, lower unit margins on new sales contracts, fewer long-term power contracts being entered into, marginal fuel prices and deregulation of the electric utility industry. Avista Advantage provides a variety of energy-related products and services to commercial and industrial customers on a national basis. Its primary product lines include consolidated billing, resource accounting, energy analysis and load profiling. Avista Power was formed in December 1998 to develop and own generation assets primarily in support of Avista Energy. Avista Power operations had no impact on 1998 earnings.
The Non-energy business is conducted primarily by Pentzer Corporation (Pentzer), which is the parent company to the majority of the Company's Non-energy businesses. Pentzer's business strategy is such that its earnings result from both transactional and non-transactional earnings. Transactional gains arise from a one-time event or a specific transaction, such as the sale of an investment or individual company from Pentzer's portfolio of investments. Non-transactional earnings arise out of the ongoing operations of the individual portfolio companies.
BASIS OF REPORTING
The financial statements are presented on a consolidated basis and, as such, include the assets, liabilities, revenues and expenses of the Company and its wholly owned subsidiaries. All material intercompany transactions have been eliminated in the consolidation. The accompanying financial statements include the Company's proportionate share of utility plant and related operations resulting from its interests in jointly owned plants (See Note 6). The financial activity of each of the Company's lines of business is reported in the "Schedule of Information by Business
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Segments." Such information is an integral part of these financial statements.
The preparation of the Company's consolidated financial statements in conformity with generally accepted accounting principles necessarily requires management to make estimates and assumptions that directly affect the reported amounts of assets, liabilities, revenues and expenses.
ALLOCATION OF REVENUES AND EXPENSES FOR REPORTING BUSINESS SEGMENTS
A portion of the utility's revenues and expenses have been allocated between the two business segments in order to report results of operations by the individual lines of business - (1) Energy Delivery and (2) Generation and Resources. The Energy Delivery business reports the results of the Company's transmission and distribution services for retail electric operations and all natural gas operations. Costs associated with electric energy commodities, such as purchased power expense, as well as the revenues attributable to the recovery of such costs from retail customers, have been eliminated from the Energy Delivery line of business and are reflected in the results of the Generation and Resources line of business. The transfer of revenues between the two utility lines of business occurs through the use of a transfer price, primarily based on cost of production studies, that is associated with the sale of a kilowatthour of electricity. The results of all natural gas operations are included in the Energy Delivery line of business because natural gas trackers allow natural gas costs to pass through within that line of business without the commodity prices having a material income effect. The Generation and Resources line of business includes the generation and production of electric energy, and short- and long-term electric and natural gas commodity trading and wholesale marketing primarily to other utilities and power brokers in the western United States.
SYSTEM OF ACCOUNTS
The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the appropriate state regulatory commissions.
REGULATION
The Company is subject to state regulation in Washington, Idaho and Montana for its electric operations. Natural gas operations are regulated in Washington, Idaho, Oregon and California. The Company is subject to regulation by the FERC with respect to its wholesale electric transmission rates and the natural gas rates charged for the release of capacity from the Jackson Prairie Storage Project.
OPERATING REVENUES
The Company accrues estimated unbilled revenues for electric and natural gas sales and services provided through month-end. Avista Energy follows the mark-to-market method of accounting for energy contracts entered into for trading and price risk management purposes. Avista Energy recognized revenue based on the change in the market value of outstanding derivative commodity sales contracts, net of future servicing costs and reserves, in addition to revenue related to physical and financial contracts that have matured.
OTHER INCOME (DEDUCTIONS)--NET
Other income (deductions)-net is composed of the following items:
EARNINGS PER SHARE
Financial Accounting Standard (FAS) No. 128, "Earnings Per Share," became effective in the fourth quarter of 1997 and requires two presentations of earnings per share - "basic" and "diluted." Basic earnings per share (EPS) is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if dilutive securities, such as stock options and convertible stock, were exercised or converted into common stock that then shared in the earnings of the Company. See Note 18 for more information regarding the EPS calculations.
UTILITY PLANT
The cost of additions to utility plant, including an allowance for funds used during construction and replacements of units of property and betterments, is capitalized. Costs of depreciable units of property retired plus costs of removal less salvage are charged to accumulated depreciation.
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ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. In accordance with the uniform system of accounts prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and is credited currently as a noncash item to Other Income (see Other Income above). The Company generally is permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a fair return thereon, through its inclusion in rate base and the provision for depreciation after the related utility plant has been placed in service. Cash inflow related to AFUDC does not occur until the related utility plant investment is placed in service.
The effective AFUDC rate was 10.67% in 1998, 1997 and 1996. The Company's AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the requirements of regulatory authorities.
DEPRECIATION
For utility operations, depreciation provisions are estimated by a method of depreciation accounting utilizing unit rates for hydroelectric plants and composite rates for other properties. Such rates are designed to provide for retirements of properties at the expiration of their service lives. The rates for hydroelectric plants include annuity and interest components, in which the interest component is 6%. For utility operations, the ratio of depreciation provisions to average depreciable property was 2.60% in 1998, 2.59% in 1997 and 2.58% in 1996.
The average service lives and remaining average service lives, respectively, for the following broad categories of property are: electric thermal production - 35 and 18 years; hydroelectric production - 100 and 80 years; electric transmission - - 60 and 29 years; electric distribution - 40 and 32 years; and natural gas distribution property - 44 and 31 years.
CASH AND CASH EQUIVALENTS
For the purposes of the Consolidated Statements of Cash Flows, the Company considers all temporary investments with an initial maturity of three months or less to be cash equivalents.
TEMPORARY INVESTMENTS
Investments in debt and marketable equity securities are classified as "available for sale" and are recorded at fair value. Investments totaling $4.3 million and $5.8 million are included on the Consolidated Balance Sheets at December 31, 1998 as other property and investments and current assets, respectively. Investments totaling $28.2 million and $22.6 million are included on the Consolidated Balance Sheets at December 31, 1997 as other property and investments and current assets, respectively. Unrealized investment gains, as of December 31, 1998 and 1997, of $0.02 million and $2.1 million, respectively, net of taxes, are reflected as a component of other comprehensive income.
DEFERRED CHARGES AND CREDITS
The Company prepares its financial statements in accordance with the provisions of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation." A regulated enterprise can prepare its financial statements in accordance with FAS No. 71 only if (i) the enterprise's rates for regulated services are established by or subject to approval by an independent third-party regulator, (ii) the regulated rates are designed to recover the enterprise's cost of providing the regulated services and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels that will recover the enterprise's costs can be charged to and collected from customers. FAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. In certain circumstances, FAS No. 71 requires that certain costs and/or obligations (such as incurred costs not currently recovered through rates, but expected to be so recovered in the future) be reflected in a deferral account in the balance sheet and not be reflected in the statement of income or loss until matching revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued application of FAS No. 71 to all or a portion of the Company's regulated operations, the Company could be required to write off its regulatory assets and could be precluded from the future deferral in the Consolidated Balance Sheet of costs not recovered through rates at the time such costs were incurred, even if such costs were expected to be recovered in the future.
The Company's primary regulatory assets include Investment in Exchange Power, conservation programs, deferred income taxes, the provision for postretirement benefits and debt issuance and redemption costs. Those items without a specific line on the Consolidated Balance Sheets are included in Deferred Charges - Other-net. Deferred credits include natural gas deferrals, unrecovered purchased gas costs and the gain on the general office building sale/leaseback which is being amortized over the life of the lease, and are included on the Consolidated Balance Sheets as Non-current Liabilities and Deferred Credits - Other Deferred Credits.
DEFERRED REVENUES
In December 1998, the Company received cash proceeds of $143.4 million from the monetization of a contract in which the Company assigned and transferred certain rights under a long-term power sales contract to a funding trust. The proceeds were recorded as deferred revenue and are being amortized into revenues over the 16-year period of the long-term sales contract.
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POWER AND NATURAL GAS COST ADJUSTMENT PROVISIONS
The Company has a power cost adjustment mechanism (PCA) in Idaho which allows the Company to modify electric rates to recover or rebate a portion of the difference between actual and allowed net power supply costs. The PCA tracks changes in hydroelectric generation, secondary prices, related changes in thermal generation and Public Utility Regulatory Policies Act of 1978 (PURPA) contracts. Rate changes are triggered when the deferred balance reaches $2.2 million. A $3.1 million (2.7%) rebate was effective February 1, 1999, which will expire January 31, 2000. The following surcharges and rebates were in effect during the past three years: a $2.7 million (2.4%) rebate effective June 1, 1998, which will expire May 31, 1999; a $2.6 million (2.3%) rebate effective September 1, 1997, which expired August 31, 1998; a $2.6 million (2.4%) rebate effective June 1, 1997, which expired May 31, 1998; a $2.5 million (2.3%) rebate effective September 1, 1996, which expired August 31, 1997; and a $2.3 million (2.4%) surcharge effective September 1, 1995, which expired August 31, 1996. The rebates balance and the deferred balance are included in the Current Liabilities - - Other and Non-Current Liabilities and Deferred Credits - Other Deferred Credits lines, respectively, on the Consolidated Balance Sheets.
Under established regulatory practices, the Company is also allowed to adjust its natural gas rates from time to time to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs allowed in rates are deferred and charged or credited to expense when regulators approve inclusion of the cost changes in rates. In Oregon, regulatory provisions include a sharing of benefits and risks associated with changes in natural gas prices, as well as a sharing of benefits if certain threshold earnings levels are exceeded. The balance is included on the Consolidated Balance Sheets as Non-current Liabilities and Deferred Credits - Other Deferred Credits.
INCOME TAXES
The Company and its eligible subsidiaries file consolidated federal income tax returns. Subsidiaries are charged or credited with the tax effects of their operations on a stand-alone basis. The Company's federal income tax returns have been examined with all issues resolved, and all payments made, through the 1994 return.
STOCK-BASED COMPENSATION
Compensation cost for stock options is measured as the excess of the quoted market price of the Company's stock at the date of grant over the amount an employee must pay to acquire the stock. Restricted stock is recorded as compensation cost over the requisite vesting periods based on the market value on the date of grant. The Company accounts for its stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" rather than using the fair-value-based method of accounting for stock-based employee compensation plans as prescribed under FAS No. 123, "Accounting for Stock-Based Compensation." However, the Company has adopted the disclosure requirements of FAS No. 123. See Note 20 for more information about the Company's stock-based compensation plans.
OTHER COMPREHENSIVE INCOME
Effective January 1, 1998, the Company adopted FAS No. 130, "Reporting Comprehensive Income," which establishes new rules for the reporting and display of comprehensive income (net income plus all other changes in net assets from nonowner sources) and its components. The adoption had no impact on the Company's net income or stockholders' equity. Prior year financial statements have been reclassified to conform to these requirements. The following table reflects the accumulated balances of other comprehensive income:
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CUMULATIVE FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Assets and liabilities of one of Pentzer's portfolio companies are denominated in Canadian dollars and translated to U. S. dollars at exchange rates in effect on the balance sheet date. Revenues, costs and expenses for the company are translated using an average rate. Cumulative translation adjustments resulting from this process are reflected as a component of other comprehensive income in the shareholders' equity section in the Consolidated Statements of Capitalization.
NEW ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) issued FAS No. 132, entitled "Employers' Disclosures about Pensions and Other Postretirement Benefits," which is effective for fiscal years beginning after December 15, 1997. This statement revises disclosures, but does not change the measurement or recognition of the plans. The Company adopted FAS No. 132 in 1998 and the required disclosure can be found in Note 7.
The FASB issued FAS No. 133, entitled "Accounting for Derivative Instruments and Hedging Activities" which will be effective for fiscal years beginning after June 15, 1999. The statement requires that all derivative financial instruments be recognized as either assets or liabilities on the company's balance sheets at fair value. The accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. Avista Energy currently accounts for derivative commodity instruments entered into for trading purposes using the mark-to-market method of accounting, in compliance with EITF 98-10, "Accounting for Energy Trading and Risk Management Activities." The Company is in the process of researching the statement and its possible impact on the Company's financial position and results of operations.
RECLASSIFICATIONS
Certain prior year amounts have been reclassified to conform to current statement format. These reclassifications were made for comparative purposes and have not affected previously reported total net income or common shareholders' equity.
NOTE 2. ACCOUNTS RECEIVABLE SALE
In July 1997, WWP Receivables Corp. (WWPRC) was incorporated as a wholly owned, bankruptcy-remote subsidiary of the Company for the purpose of acquiring or purchasing interests in certain accounts receivable, both billed and unbilled, of the Company. Subsequently, WWPRC and the Company have entered into an agreement whereby WWPRC can sell without recourse, on a revolving basis, up to $80.0 million in those receivables. WWPRC is obligated to pay fees which approximate the purchaser's cost of issuing commercial paper equal in value to the interests in receivables sold. On a consolidated basis, the amount of such fees is included in operating expenses of the Company. At December 31, 1998 and 1997, $25.0 million and $40.0 million, respectively, in receivables had been sold pursuant to the agreement, which qualify as sales of assets under FAS No. 125.
NOTE 3. ENERGY COMMODITY TRADING
The Company's energy-related businesses are exposed to risks relating to changes in certain commodity prices and counterparty performance. In order to manage the various risks relating to these exposures, the Company utilizes electric, natural gas and related derivative commodity instruments, such as forwards, futures, swaps and options, and Avista Energy engages in the trading of such instruments. The Company and Avista Energy have adopted policies and procedures to manage the risks inherent these activities and have established a comprehensive Risk Management Committee, separate from the units that create such risk exposure and overseen by the Audit and Finance Committee of the Company's Board of Directors, to monitor compliance with the Company's risk management policies and procedures.
GENERATION AND RESOURCES
The Company protects itself against price fluctuations on electric energy and natural gas by limiting the aggregate level of net open positions which are exposed to market price changes and through the use of electric, natural gas and related derivative commodity instruments for hedging purposes. The net open position is actively managed with strict policies designed to limit the exposure to market risk and which require daily and weekly reporting to management of potential financial exposure. The Risk Management Committee has limited the types of commodity instruments the Company may trade to those related to electricity and natural gas commodities and those instruments are to be used for hedging price fluctuations associated with the management of resources. Commodity instruments are not generally held by the Company for speculative trading purposes. Gains and losses related to derivative commodity instruments which qualify as hedges are recognized in the Consolidated Statements of Income when the underlying hedged physical transaction closes (the deferral method) and are included in the same category as the hedged item (natural gas purchased or purchased power expense, as the case may be). At December 31, 1998 and 1997, the Company's derivative commodity instruments outstanding were immaterial.
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NATIONAL ENERGY TRADING AND MARKETING
Avista Energy purchases natural gas and electricity directly from producers and other trading companies, and its customers include commercial and industrial end-users, electric utilities, natural gas distribution companies, and other trading companies. Avista Energy's marketing and energy risk management services are provided through the use of a variety of derivative commodity contracts to purchase or supply natural gas and electric energy at specified delivery points and at specified future dates. Avista Energy also trades natural gas and electricity derivative financial instruments on national exchanges and through other unregulated exchanges and brokers from whom these commodity derivatives are available, and therefore experiences net open positions in terms of price, volume, and specified delivery point.
The open position exposes Avista Energy to the risk that fluctuating market prices may adversely impact its financial position or results of operations. However, the net open position is actively managed with strict policies designed to limit the exposure to market risk and which require daily reporting to management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily earnings at risk as well as total Value-at-Risk (VAR) measurement.
Derivative commodity instruments sold and purchased by Avista Energy include: forward contracts, involving physical delivery of an energy commodity; futures contracts, which involve the buying or selling of natural gas, electricity or other energy-related commodities at a fixed price; over-the-counter swap agreements which require Avista Energy to receive or make payments based on the difference between a specified price and the actual price of the underlying commodity; and options, which mitigate price risk by providing for the right, but not the requirement, to buy or sell energy-related commodities at a fixed price.
Foreign currency risks associated with the fair value of the energy commodity portfolio are managed using a variety of financial instruments, including forward rate agreements.
Avista Energy's trading activities are subject to mark-to-market accounting, under which changes in the market value of outstanding electric, natural gas and related derivative commodity instruments are recognized as gains or losses in the period of change. Gains and losses on electric, natural gas and related derivative commodity instruments utilized for trading are recognized in income on a current basis (the mark-to-market method) and are included on the Consolidated Statements of Income in operating revenues or resource costs, as appropriate, and on the Consolidated Balance Sheets as current or non-current energy commodity assets or liabilities. Contracts in a receivable position, as well as the options held, are reported as assets. Similarly, contracts in a payable position, as well as options written, are reported as liabilities. Cashflows are recognized during the period of settlement.
Contract Amounts and Terms Under Avista Energy's derivative instruments, Avista Energy either (i) as "fixed price payor," is obligated to pay a fixed price or amount and is entitled to receive the commodity (or currency) or a variable amount or (ii) as "fixed price receiver," is entitled to receive a fixed price or amount and is obligated to deliver the commodity (or currency) or pay a variable amount. The contract or notional amounts and terms of Avista Energy's derivative commodity investments outstanding at December 31, 1998 are set forth below (volumes in thousands of mmBTUs and MWhs, dollars in thousands):
At December 31, 1998, Avista Energy also had sales and purchase commitments associated with contracts based on market prices totaling 898,316,063 mmBTUs, with terms extending up to 12 years. Fixed index electric transactions totaled 1,875,576 MWhs, with terms extending up to 10 years.
Contract or notional amounts reflect the volume of transactions, but do not necessarily represent the amounts exchanged by the parties to the derivative instruments. Accordingly, contract or notional amounts do not accurately measure Avista Energy's exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset in the markets at any time in response to Avista Energy's risk management needs.
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Fair Value The fair value of Avista Energy's derivative commodity instruments outstanding at December 31, 1998, and the average fair value of those instruments held during the year are set forth below (dollars in thousands):
The weighted average term of Avista Energy's natural gas and related derivative commodity instruments as of December 31, 1998 was approximately three months. The weighted average term of Avista Energy's electric derivative commodity instruments at year-end was approximately ten months. The change in the fair value position of Avista Energy's energy commodity portfolio, net of the reserves for credit and market risk from December 31, 1997 to December 31, 1998 was $22.8 million and is included on the Consolidated Statements of Income in operating revenues.
MARKET RISK
The Company manages, on a portfolio basis, the market risks inherent in its activities subject to parameters established by its Risk Management Committee. Market risks are monitored by the Risk Management Committee to ensure compliance with the Company's stated risk management policies. The Company measures the risk in its portfolio on a daily basis in accordance with value-at-risk and other risk methodologies established by the Risk Management Committee. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products.
CREDIT RISK
The Company is exposed to credit risk in the event of nonperformance by customers or counterparties of their contractual obligations. The concentration of customers and/or counterparties may impact overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. However, the Company maintains credit policies with regard to their customers and counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential customers' and counterparties' financial condition and credit rating, collateral requirements or other credit enhancements such as letters of credit or parent company guarantees, and the use of standardized agreements which allow for the netting or offsetting of positive and negative exposures associated with a single counterparty. The Company maintains credit reserves which are based on management's evaluation of the credit risk of the overall portfolio. Based on these policies, exposures and the credit reserves, the Company does not anticipate a materially adverse effect on financial position or results of operations as a result of customer or counterparty nonperformance. New York Mercantile Exchange traded futures and option contracts are financially guaranteed by the Exchange and have nominal credit risk.
Avista Energy has concentrations of suppliers and customers in the electric and natural gas industries, including electric utilities, natural gas distribution companies and other energy marketing and trading companies. In addition, Avista Energy has concentrations of credit risk related to geographic location. Avista Energy operates in North America, principally within the West and Mid-West United States and Western Canada. These concentration of counterparties and concentrations of geographic location may impact Avista Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
NOTE 4. NATIONAL ENERGY TRADING AND MARKETING EQUITY INVESTMENT
Effective November 30, 1998, Avista Energy sold its 50% ownership interest in Howard/Avista Energy LLC to H&H Star Energy, Inc. The sales price, which represented Avista Energy's equity investment, was $25 million in the form of a short-term unsecured note receivable from H&H Star Energy, Inc., and is guaranteed by H&H Star Energy, Inc.'s parent company, Howard Publications, Inc. The note is due April 30, 1999.
The Company's initial equity investment in Howard/Avista Energy, LLC was $25 million and the investment in the net assets of the unconsolidated subsidiary amounted to $26.8 million at December 31, 1997. Dividends of $0.7 million were received from Howard/Avista Energy, LLC in 1998. Avista Energy's pre-tax equity in earnings of Howard/Avista Energy LLC were $(1.0) million and $1.8 million for the eleven months ended November 30, 1998 and the five months ended December 31, 1997, respectively.
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NOTE 5. PROPERTY, PLANT AND EQUIPMENT
The year-end balances of the major classifications of property, plant and equipment are detailed in the following table (thousands of dollars):
National Energy Trading and Marketing's and Non-energy's plant, property and equipment under capital leases totaled $13.3 million and $12.9 million and the associated accumulated depreciation totaled $2.8 million and $2.6 million in 1998 and 1997, respectively.
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has investments in jointly owned generating plants. Financing for the Company's ownership in the projects is provided by the Company. The Company's share of related operating and maintenance expenses for plants in service is included in corresponding accounts in the Consolidated Statements of Income. See Note 17 for additional information related to potential impacts of Clean Air Act Amendments on these plants. The following table indicates the Company's percentage ownership and the extent of the Company's investment in such plants at December 31, 1998:
NOTE 7. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a pension plan covering substantially all of its regular full-time employees. Certain of the Company's subsidiaries also participate in this plan. Individual benefits under this plan are based upon years of service and the employee's average compensation as specified in the Plan. The Company's funding policy is to contribute annually an amount equal to the net periodic pension cost, provided that such contributions are not less than the minimum amounts required to be funded under the Employee Retirement Income Security Act, nor more than the maximum amounts which are currently deductible for tax purposes. Pension fund assets are invested primarily in marketable debt and equity securities. The Company also has other plans which cover the executive officers and key managers.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. The Company accrues the estimated cost of postretirement benefit payments during the years that employees provide services and allows recognition of the unrecognized transition obligation in the year of adoption or the amortization of such obligation over a period of up to twenty years. The Company elected to amortize this obligation of approximately $34,500,000 over a period of twenty years, beginning in 1993.
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The following table sets forth the pension and health care plan disclosures:
Assumed health cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 1998 by approximately $2.6 million and the service and interest cost by approximately $212,000.
The Company also sponsors an employee savings plan which covers substantially all employees. Employer matching contributinos of $2.8 million, $2.9 million and $2.8 million were expensed in 1998, 1997 and 1996, respectively.
NOTE 8. ACCOUNTING FOR INCOME TAXES
In June 1997, the Company received $81 million from the Internal Revenue Service (IRS) to settle an income tax claim relating to its investment in the terminated nuclear project 3 of the Washington Public Power Supply System (WNP3). The $81 million recovery included $34 million in income taxes the Company overpaid in prior years plus $47 million in accrued interest, which in total contributed $41.4 million, or $0.74 per share, to net income.
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The Company had claimed that it realized a loss in 1985 relating to its $195 million investment in WNP3 entitling it to current tax deductions. The IRS, however, originally denied the Company's claim and ruled that the investment should be written off over 32.5 years, the term of a settlement agreement between the Company and the Bonneville Power Administration relating to WNP3. The Company disagreed with this ruling and had been pursuing a reversal for several years. The IRS has now agreed with the Company's position.
The Company entered into settlement agreements with the WUTC and the IPUC in 1987 and 1988 providing for the recovery through retail prices of approximately 60% of the Company's $195 million investment in WNP3. As a result of these agreements, customers have been and will continue to receive the tax benefits relating to the recoverable portion of WNP3 over the recovery periods specified in the settlement agreements. The settlement agreements resulted in a write-off of approximately $75 million of the Company's WNP3 investment, with the entire write-off charged to shareholders. The tax recovery and related accrued interest from the IRS will flow through to the benefit of shareholders. The cash was used to fund new business investment, including growth opportunities in national energy markets, and reduced the need for issuance of long-term debt during 1997.
As of December 31, 1998 and 1997, the Company had recorded net regulatory assets of $171.0 million and $176.7 million, respectively, related to the probable recovery of FAS No. 109, "Accounting for Income Taxes," deferred tax liabilities from customers through future rates. Such regulatory assets will be adjusted by amounts recovered through rates.
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) tax credit carryforwards. The net deferred federal income tax liability consists of the following (thousands of dollars):
A reconciliation of federal income taxes derived from statutory tax rates applied to income from continuing operations and federal income tax as set forth in the accompanying Consolidated Statements of Income and Retained Earnings is as follows (the current and deferred effective tax rates are approximately the same during all periods):
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NOTE 9. LONG-TERM PURCHASED POWER CONTRACTS WITH REQUIRED MINIMUM PAYMENTS
Under fixed contracts with Public Utility Districts (PUD), the Company has agreed to purchase portions of the output of certain generating facilities. Although the Company has no investment in such facilities, these contracts provide that the Company pay certain minimum amounts (which are based at least in part on the debt service requirements of the supplier) whether or not the facility is operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in operations and maintenance expense in the Consolidated Statements of Income. Information as of December 31, 1998, pertaining to these contracts is summarized in the following table:
(1) The annual costs will change in proportion to the percentage of output allocated to the Company in a particular year. Amounts represent the operating costs for the year 1998.
(2) Included in annual costs.
Actual expenses for payments made under the above contracts for the years 1998, 1997 and 1996, were $6.2 million, $5.9 million and $5.4 million, respectively. The estimated aggregate amounts of required minimum payments (the Company's share of debt service costs) under the above contracts for the next five years are $3.9 million in 1999, $4.0 million in 2000, $4.0 million in 2001, $5.5 million in 2002 and $5.2 million in 2003 (minimum payments thereafter are dependent on then market conditions). In addition, the Company will be required to pay its proportionate share of the variable operating expenses of these projects.
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NOTE 10. LONG-TERM DEBT
The annual sinking fund requirements and maturities for the next five years for long-term debt outstanding at December 31, 1998 are as follows:
The sinking fund requirements may be met by certification of property additions at the rate of 167% of requirements. All of the utility plant is subject to the lien of the Mortgage and Deed of Trust securing outstanding First Mortgage Bonds.
In 1998, $84.0 million of Unsecured Medium-Term Notes were issued, while $14.0 million of Unsecured Medium-Term Notes matured or were redeemed. In 1997, $20.0 million of First Mortgage Bonds in the form of Secured Medium-Term Notes were issued, while $26.5 million of Secured Medium-Term Notes and $25.0 million of Unsecured Medium-Term Notes matured or were repurchased. As of December 31, 1998, the Company had remaining authorization to issue up to $89.0 million of Secured Medium-Term Notes, which were issued in January 1999, and $166.0 million of Unsecured Medium-Term Notes.
At December 31, 1998, the Company had no outstanding balances under borrowing arrangements. See Note 11 for details of credit agreements.
Included in other long-term debt are the following items related to non-energy operations (thousands of dollars):
NOTE 11. BANK BORROWINGS
At December 31, 1998, the Company maintained lines of credit with various banks under two separate credit agreements amounting to $200.0 million. The Company has one revolving line of credit, expiring June 29, 1999, which provides a total credit commitment of $125 million. The second revolving credit agreement, which expires on June 29, 2001, provides a total credit commitment of $75 million. The Company pays commitment fees of up to 0.09% per annum on the average daily unused portion of each credit agreement.
In addition, under various agreements with banks, the Company can have up to $100.0 million in loans outstanding at any one time, with the loans available at the banks' discretion. These arrangements provide, if funds are made available, for fixed-term loans for up to 180 days at a fixed rate of interest.
The amount of unused letter of credit available to Avista Corp. for use in Generation and Resources activities totaled $2.5 million at December 31, 1998. This letter of credit expires on February 28, 1999.
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Balances and interest rates of bank borrowings under these arrangements were as follows:
Avista Energy and its subsidiary, Avista Energy Canada, Ltd., as co-borrowers, have a credit agreement with a commercial bank in the aggregate amount of $100 million, expiring April 1, 1999. The credit agreement may be terminated by the bank at any time and all extensions of credit under the agreement are payable upon demand, in either case at the bank's sole discretion. The agreement also provides, on an uncommitted basis, for the issuance of letters of credit to secure contractual obligations to counterparts. The facility is guaranteed by Avista Capital and is secured by substantially all of Avista Energy's assets. The maximum cash component of credit extended by the bank is $30 million, with availability of up to $100 million for the issuance of letters of credit. At December 31, 1998 and 1997, there were no cash advances (demand notes payable) outstanding. Letters of credit outstanding under the facility totaled approximately $20.2 million and $2.8 million at December 31, 1998 and 1997, respectively. The total amount of unused credit available to the Company at December 31, 1998 was $79.8 million.
Non-energy operations have $54.0 million in short-term borrowing arrangements available. At December 31, 1998 and 1997, $21.4 million and $18.6 million, respectively, were outstanding.
NOTE 12. LEASES
The Company has entered into several lease arrangements involving various assets, with minimum terms ranging from one to thirteen years and expiration dates from 1999 to 2011. Certain of the lease arrangements require the Company, upon the occurrence of specified events, to purchase the leased assets for varying amounts over the term of the lease. The Company's management believes that the likelihood of the occurrence of the specified events under which the Company could be required to purchase the property is remote. Rent expense for the years ended December 31, 1998, 1997 and 1996 was $17.6 million, $16.9 million and $15.2 million, respectively. Future minimum lease payments (in thousands of dollars) required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1998 are estimated as follows:
The Company also has various other cancelable operating leases, which are charged to operating expense, consisting of the Rathdrum combustion turbines, the Company airplane and a large number of small, relatively short-term, renewable agreements for various items, such as office equipment and office space.
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The payments under National Energy Trading and Marketing's and Non-energy's capital leases for the next five years are $3.0 million in 1999, $2.4 million in 2000, $1.0 million in 2001, $0.5 million in 2002 and $0.1 million in 2003.
NOTE 13. PREFERRED STOCK
CUMULATIVE PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION:
In December 1998, as part of a dividend restructuring plan, the Company issued 1,540,460 shares of its $12.40 Convertible Preferred Stock, Series L. See Note 14 for additional information.
The Company redeemed its $50 million of Flexible Auction Preferred Stock, Series J in August 1997. The dividend rate on this preferred stock was reset every 49 days based on an auction.
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
Redemption requirements:
$6.95, Series K - On September 15, 2002, 2003, 2004, 2005 and 2006, the Company must redeem 17,500 shares at $100 per share plus accumulated dividends through a mandatory sinking fund. Remaining shares must be redeemed on September 15, 2007. The Company has the right to redeem an additional 17,500 shares on each September 15 redemption date.
There are $3.5 million in mandatory redemption requirements during the 1999-2003 period.
In June 1998, the Company redeemed the final $10 million, or 100,000 shares, of its $8.625 Series I.
NOTE 14. CONVERTIBLE PREFERRED STOCK
In December 1998, as part of a dividend restructuring plan, the Company issued 1,540,460 shares of its $12.40 Convertible Preferred Stock, Series L, in exchange for 15,404,595 shares of common stock, on the basis of a one-tenth interest in one share of preferred stock for each share of common stock. The Convertible Preferred Stock, Series L has a liquidation preference of $182.8125 per share.
Unless previously converted into common stock by the Company, on November 1, 2001 each share of the Convertible Preferred Stock, Series L will be converted into (1) ten shares of common stock (subject to antidilution adjustments) and (2) the right to receive an amount, in cash, equal to accrued and unpaid dividends.
The Convertible Preferred Stock, Series L may be converted, at the option of the Company, at any time prior to November 1, 2001, in whole but not in part, into, for each share so converted (1) a number of shares of common stock equal to the Optional Conversion Price then in effect, plus (2) the right to receive an amount, in cash, equal to the accrued and unpaid dividends thereon to but excluding the conversion date, plus (3) the right to receive the Optional Conversion Premium. As used above,
* the "Optional Conversion Price" will be, for each share of Convertible Preferred Stock, Series L so converted, a number of shares of common stock equal to the lesser of (a) the amount of $24 divided by an amount equal to the current market price of the common stock, multiplied by ten and (b) one share of common stock (subject to antidilution adjustments); and
* the "Optional Conversion Premium" will be, for each share of Convertible Preferred Stock, Series L so converted, an amount in cash, initially equal to $20.90, declining by $0.02111 for each day following December 15, 1998 to and including the optional conversion date and equal to zero on and after September 15, 2001; provided, however, that in lieu of delivering such amount in cash, the Company may, at its option, deliver a number of shares of common stock equal to the quotient of such amount divided by an amount equal to the current market price of the common stock.
NOTE 15. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES
On January 23, 1997, Avista Capital I, a business trust, issued to the public $60,000,000 of Preferred Trust Securities having a distribution rate of 7 7/8%. Concurrent with the issuance of the Preferred Trust Securities, the Trust issued $1,855,675 of Common Trust Securities to the Company. The sole assets of the Trust are the
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Company's 7 7/8% Junior Subordinated Deferrable Interest Debentures, Series A, with a principal amount of $61,855,675. These debt securities may be redeemed at the Company's option on or after January 15, 2002 and mature January 15, 2037.
On June 3, 1997, Avista Capital II, a business trust, issued to the public $50,000,000 of Preferred Trust Securities having a floating distribution rate of LIBOR plus 0.875%, calculated and reset quarterly (initially 6.6875%). The distribution rate paid during 1998 ranged from 6.77734% to 6.13625%, which was the rate outstanding at December 31, 1998. Concurrent with the issuance of the Preferred Trust Securities, the Trust issued $1,547,000 of Common Trust Securities to the Company. The sole assets of the Trust are the Company's Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of $51,547,000. These debt securities may be redeemed at the Company's option on or after June 1, 2007 and mature June 1, 2037.
The Company has guaranteed the payment of distributions on, and redemption price and liquidation amount in respect of, the Preferred Trust Securities to the extent that the Trust has funds available for such payment from the debt securities. Upon maturity or prior redemption of such debt securities, the Trust Securities will be mandatorily redeemed. The Company's Consolidated Statements of Capitalization reflect only the $60 million and $50 million of Preferred Trust Securities, accordingly all intercompany transactions have been eliminated.
NOTE 16. FAIR VALUE OF FINANCIAL SECURITIES
The fair value of the Company's long-term debt (excluding notes payable and other) at December 31, 1998 and 1997 is estimated to be $735.5 million, or 107% of the carrying value and $647.3 million, or 105% of the carrying value, respectively. The fair value of the Company's mandatorily redeemable preferred stock at December 31, 1998 and 1997 is estimated to be $38.5 million, or 110% of the carrying value and $49.8 million, or 111% of the carrying value, respectively. The fair value of the Company's preferred trust securities at December 31, 1998 and 1997 is estimated to be $106.9 million, or 97% of the carrying value and $109.4 million, or 99% of the carrying value, respectively. These estimates are all based on available market information. The fair value of the Company's convertible preferred securities at December 31, 1998 was $301.4 million, or 112%, of the carrying value. This valuation was based on the closing price of the securities on December 31, 1998.
NOTE 17. COMMON STOCK
In April 1990, the Company sold 1,000,000 shares of its common stock to the Trustee of the Investment and Employee Stock Ownership Plan for Employees of the Company (Plan) for the benefit of the participants and beneficiaries of the Plan. In payment for the shares of Common Stock, the Trustee issued a promissory note payable to the Company in the amount of $14,125,000. Dividends paid on the stock held by the Trustee, plus Company contributions to the Plan, if any, are used by the Trustee to make interest and principal payments on the promissory note. The balance of the promissory note receivable from the Trustee ($9.3 million at December 31, 1998) is reflected as a reduction to common equity. The shares of Common Stock are allocated to the accounts of participants in the Plan as the note is repaid. During 1998, the cost recorded for the Plan was $3.7 million. Interest on the note payable to the Company, cash and stock contributions to the Plan and dividends on the shares held by the Trustee were $0.9 million, $2.8 million and $0.9 million, respectively.
In February 1990, the Company adopted a shareholder rights plan, which was subsequently amended, pursuant to which holders of Common Stock outstanding on March 2, 1990, or issued thereafter, have been granted one preferred share purchase right (Right) on each outstanding share of Common Stock. Each Right, initially evidenced by and traded with the shares of Common Stock, entitles the registered holder to purchase one two-hundredth of a share of Preferred Stock of the Company, without par value, at an exercise price of $40, subject to certain adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10% or more of the Common Stock or announces a tender offer, the consummation of which would result in the beneficial ownership by a person or group of 10% or more of the Common Stock. Upon any such acquisition, each Right would entitle the holder to purchase a number of shares of Common Stock of the Company (or, in the case of a merger of the Company into another person or group, common stock of the acquiring person) having a fair market value equal to twice the exercise price. In no event will the Rights be exercisable by a person which has acquired 10% or more of the Company's Common Stock. The Rights may be redeemed, at a redemption price of $0.005 per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10% or more of the Common Stock. The Rights will expire on February 16, 2000.
During 1992, the Company received authorization to issue 1.5 million shares of Common Stock under a second Periodic Offering Program (POP). No shares were issued under the POP during 1996, 1997 or 1998. At December 31, 1998, 572,400 shares remained authorized but unissued.
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The Company has a Dividend Reinvestment and Stock Purchase Plan under which the Company's stockholders may automatically reinvest their dividends and make optional cash payments for the purchase of the Company's Common Stock at current market value.
The Company purchases stock on the open market to fulfill obligations of the 401(K) and Dividend Reinvestment Plans. Sales of Common Stock for 1998, 1997 and 1996 are summarized below (thousands of dollars):
NOTE 18. EARNINGS PER SHARE
Average shares outstanding for basic EPS were 54,603,926 in 1998. At December 31, 1998, 1,540,460 shares of $12.40 Convertible Preferred Stock, Series L, which were convertible into 15,404,595 million shares of common stock, were outstanding. All of these potential common shares were excluded from the computation of diluted EPS for 1998 because their inclusion had an antidilutive effect on EPS. Options to purchase 647,900 shares of common stock were outstanding during 1998, but 150,000 shares were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares for the year and, therefore, the effect would be antidilutive. Average number of common shares outstanding for both basic and diluted EPS was 55,960,360 for both 1997 and 1996. Basic and diluted EPS were the same in 1997 and 1996 as the Company did not have any common stock equivalents outstanding in either of those years.
The computation of basic and diluted earnings per common share is as follows (in thousands, except per share amounts):
For additional information regarding the convertible preferred stock and stock option plans, see Notes 14 and 19, respectively.
NOTE 19. STOCK COMPENSATION PLANS
The Company and certain subsidiaries have adopted stock-based compensation plans.
Avista Corp.
In 1998, the Company adopted and shareholders approved an incentive compensation plan, the Long-Term Incentive Plan (Plan). Under the Plan, certain key employees, directors and officers of the Company and its
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subsidiaries may be granted stock options, stock appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The Company has made available a maximum of 2.5 million shares of its common stock for grant under the Plan. The shares issued under the Plan will be purchased by the trustee on the open market.
The following summarizes stock options activity for 1998 under the Plan:
(1) The fair values of these options were estimated at the dates of the grants using a Black-Scholes option pricing model using the following assumptions: dividend yield of 3.01%, expected volatility of 22.19%, risk-free interest rate range of 4.81% to 5.53% depending on the grant date, and an expected life of 7 years.
The Company granted 102,036 shares of restricted common stock under the Plan in 1998. Plan participants are entitled to dividends and to vote their respective shares. The sale or transfer of restricted stock is prohibited during the vesting period except as specified in the award agreements. The value of restricted stock awards is established by the average market price on the date of grant. Restricted stock awarded in 1998 have vesting periods from 4 - 5 years.
Common equity was reduced in the accompanying Consolidated Balance Sheets by the cost of restricted shares acquired by the Plan trustee on the open market. Accordingly, the Company is recording compensation expense ratably over the restriction periods based on the reduction to common equity.
The Company accounts for stock based compensation using APB Opinion No. 25, "Accounting for Stock Issued to Employees." Under this method, compensation cost is recognized on the excess, if any, of the market price of the stock at grant date over the exercise price of the option. As the exercise price for options granted under the Plan was equal to the market price at grant date, no compensation expense has been recorded by the Company in connection this the Plan. In accordance with FAS No. 123, "Accounting for Stock-Based Compensation," compensation expense is determined based on the fair value of the award and recognizes that cost over the service period. Had compensation costs for these plans been determined based on the fair value at the grant dates with FAS No. 123, the Company's net income would have been reduced to the pro forma amounts indicated below:
(2) Includes pro forma effect of subsidiary companies stock option plans.
Subsidiary Companies
Certain subsidiaries of the Company have adopted employee stock incentive plans under which key employees and directors were granted the opportunity to purchase shares of subsidiary common stock at prices equal to the fair market value as determined by each subsidiary's Board of Directors. Restricted shares are subject to transfer agreements and vest over various periods as defined in the plans. The subsidiaries record compensation expense based on the increase in the adjusted net book value of the shares subject to the plans.
Certain subsidiaries of the Company have adopted employee stock incentive plans under which certain employees and directors of the Company and the subsidiaries are granted options to purchase subsidiary shares at prices no less than the fair market value on the date of grant. Options outstanding under these plans usually become fully
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exercisable between three and five years from the date granted and terminate ten years from the date granted. Upon termination of employment, vested options may be exercised and the related subsidiary shares may be, but are not required to be, repurchased by the applicable subsidiary at fair value.
NOTE 20. COMMITMENTS AND CONTINGENCIES
The Company believes, based on the information presently known, the ultimate liability for the matters discussed in this note, individually or in the aggregate, taking into account established accruals for estimated liabilities, will not be material to the consolidated financial position of the Company, but could be material to results of operations or cash flows for a particular quarter or annual period. No assurance can be given, however, as to the ultimate outcome with respect to any particular lawsuit.
NEZ PERCE TRIBE
On December 6, 1991, the Nez Perce Tribe filed an action against the Company in U. S. District Court for the District of Idaho alleging, among other things, that two dams formerly operated by the Company, the Lewiston Dam on the Clearwater River and the Grangeville Dam on the South Fork of the Clearwater River, provided inadequate passage to migrating anadromous fish in violation of rights under treaties between the Tribe and the United States made in 1855 and 1863. The Lewiston and Grangeville Dams, which had been owned and operated by other utilities under hydroelectric licenses from the Federal Power Commission (the "FPC", predecessor of the FERC) prior to acquisition by the Company, were acquired by the Company in 1937 with the approval of the FPC, but were dismantled and removed in 1973 and 1963, respectively. Allegations of actual loss under different assumptions ranged between $425 million and $650 million, together with $100 million in punitive damages.
On November 21, 1994, the Company filed a Motion for Summary Judgment of Dismissal. On March 28, 1996, a U.S. District judge entered a summary judgment in favor of the Company dismissing the complaint. The Tribe filed a notice of appeal to the Ninth Circuit Court of Appeals on April 24, 1996. A mediation conference was held on October 11, 1996. Following the conclusion of that conference, briefing schedules were vacated indefinitely to accommodate a mediation process, which ultimately resulted in a settlement of this matter on January 15, 1999. In accordance with that settlement, the Company will pay the Nez Perce Tribe $2.5 million initially, part of which was already expensed and the remainder deferred for possible future rate recovery. The Company will provide 44 annual payments thereafter in the amount of $835,498 for utility taxes, Tribal employment rights, fees and rights-of-ways, which will be expensed as paid.
OIL SPILL
The Company completed an updated investigation of an oil spill from an underground storage tank that occurred several years ago in downtown Spokane at the site of the Company's steam heat plant. Underground soil testing conducted in 1993 showed that the oil had migrated approximately one city block beyond the steam plant property. The Clean-up Action Plan determined by the Department of Ecology (DOE) is underway, and remediation facilities have been constructed and installed and are being operated.
On August 17, 1995, a lawsuit was filed against the Company in Superior Court of the State of Washington for Spokane County by Davenport Sun International Hotels and Properties, Inc., the owner of a hotel property in downtown Spokane, Washington. The Complaint alleged that the oil released from the Company's Central Steamplant trespassed on property owned by the plaintiff. In addition, the plaintiff claimed that the Steamplant has caused a diminution of value of plaintiff's land. After mediation, the matter was resolved by settlement and compromise, subject to certain conditions. In December 1997, the settlement was restructured, certain amounts were paid, the litigation was dismissed with prejudice, a release was obtained, and other conditions remain to be fulfilled, none of which would affect the dismissal of this action.
The Company pursued recovery from insurers and reached settlement with one of the two insurance carriers. On December 13, 1996, the Company filed a Complaint for declaratory relief and money damages against Underwriters at Lloyds of London (Lloyds), the remaining carrier, in Spokane County Superior Court. The purpose of this action was to seek a declaration of the insurance policies issued to the Company by Lloyds with respect to any liabilities of the Company for environmental damage associated with the oil spill at the Central Steamplant and other environmental remediation efforts. The policies at issue were in effect during the period between 1926 and 1966; thereafter, the Company maintained its policies with a new underwriter, Aegis. The Company's Complaint sought money damages in excess of $16 million. On March 10, 1999, Avista Corp. and Lloyds signed a settlement agreement resolving the claim.
SPOKANE GAS PLANT
The Company is participating with the Washington State Department of Transportation in an environmental study relating to the former Spokane Natural Gas Plant site (which was operated as a coal gasification plant for
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approximately 60 years until 1948) acquired by the Company through a merger in 1958. The Company no longer owns the property. Initial core samples taken from the site indicate environmental contamination at the site. On January 15, 1999, the Company received notice from the State of Washington's Department of Ecology that it had been designated as a potentially liable person (PLP) with respect to any hazardous substances located on this site, stemming from the Company's past ownership of the former Gas Plant. In its notice, the DOE stated that it intended to complete an on-going remedial investigation of this site, complete a feasibility study to determine the most effective means of halting or controlling future releases of substances from the site, and implement appropriate remedial measures.
The Company responded to the DOE acknowledging its listing as a PLP, but requested that additional parties also be listed as PLPs. The Company also committed to pursue additional characterization of the site, with more drillings and samples, and is in the process of determining the extent of further work. The Company will be negotiating with the DOE on the remedial measures.
EASTERN PACIFIC ENERGY
On October 9, 1998, Eastern Pacific Energy (Eastern Pacific), an energy aggregator participating in the restructured retail energy market in California, filed suit against the Company and its affiliates, Avista Advantage and Avista Energy in the United States District Court for the Central District of California. Eastern Pacific alleges, among other things, a breach of an oral or implied joint venture agreement whereby the Company agreed to supply not less than 300 megawatts of power to Eastern Pacific's California customers and that Avista Advantage agreed to provide energy-related products and services. The complaint seeks an unspecified amount of damages and also seeks to recover any future profits earned from sales of the aforementioned amount of power to California consumers. The Company and its affiliates intend to vigorously defend against all of the claims.
On December 4, 1998, Avista Advantage, Avista Energy and the Company jointly filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. Following a responsive pleading from the plaintiff, the court took the matter under advisement and notified the parties that a decision will be issued in due course concerning this motion to dismiss.
OTHER CONTINGENCIES
The Company routinely assesses, based on in-depth studies, expert analyses and legal reviews, its contingencies, obligations and commitments for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties who have and have not agreed to a settlement and recoveries from insurance carriers. The Company's policy is to immediately accrue and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation, cleanup and monitoring costs to be incurred.
The Company must be in compliance with requirements under the Clean Air Act Amendments (CAAA) by the year 2000 at both the Colstrip and Centralia thermal generating plants, in which the Company maintains an ownership interest. The anticipated share of costs at Colstrip are not expected to have a major economic impact on the Company, but estimates at Centralia are expected to be approximately $35 million, which have been included in the Company's future projected capital expenditures.
The Company has potential liabilities under the Federal Endangered Species Act (ESA) for species of fish that have either already been added to the endangered species list, been listed as "threatened" or been petitioned for listing. Thus far, measures which have been adopted and implemented have had minimal impact of the Company. Future actions to save these, and other as yet unidentified fish or wildlife species, particularly as the Company is relicensing several of its hydroelectric facilities, could impact the Company's operations. It is currently not possible to determine the likely financial impact of any further actions.
The Company has long-term contracts related to the purchase of fuel for thermal generation, natural gas and hydroelectric power. Terms of the natural gas purchase contracts range from one month to five years and the majority provide for minimum purchases at the then effective market rate. The Company also has various agreements for the purchase, sale or exchange of electric energy with other utilities, cogenerators, small power producers and government agencies.
As of December 31, 1998, the Company's collective bargaining agreement with the International Brotherhood of Electrical Workers represented approximately 50% of employees. The current agreement with the union local representing the majority of the bargaining unit employees expires on March 25, 2002. A local agreement in the South Lake Tahoe area, which represents 7 employees, also expires on March 25, 1999. The Company and the union are currently negotiating this agreement.
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NOTE 21. ACQUISITIONS AND DISPOSITIONS
In April 1998, Pentzer completed the purchase of two new companies that produce store fixtures -- Universal Showcase, Ltd., in Toronto, Canada and Triangle Systems, Inc., in New York. In October 1998, Pentzer acquired two additional store fixtures companies -- Horizon Terra, Inc., in Indiana and Pacific Coast Showcase, Inc., in Washington. During 1997, Pentzer acquired three new companies: Target Woodworks, Inc., a Florida-based company; White Plus, a California-based company; and Proco Wood Products, a Minnesota-based company. All three companies provide point-of-purchase and in-store merchandising services. During 1996, Pentzer acquired one company that provides point-of-purchase and in-store merchandising services.
During the first quarter of 1998, Pentzer sold Systran Financial Services, resulting in an after-tax gain of $5.5 million. In May 1997, Pentzer sold its interest in a portfolio company, Safety Speed Cut, resulting in a gain of approximately $2.0 million, net of taxes. In 1996, Pentzer Development Corporation, a subsidiary of Pentzer, sold the Spokane Industrial Park, resulting in a gain of approximately $10.8 million, net of taxes and other adjustments.
In November 1998, the Company reached an agreement in principal to purchase a majority ownership in One Eighty Communications, a competitive local exchange carrier that provided local dial tone and data services to commercial accounts in local communities. The acquisition was completed in January 1999, and the new company was renamed Avista Communications. It will provide local high-speed telecommunications services to under-served Northwest communities.
In December 1998, Avista Energy Canada, Ltd. acquired Coast Pacific Management, Inc. (Coast Pacific), a natural gas marketing company based in Vancouver, British Columbia, Canada. Coast Pacific manages and transports approximately 70,000 MMBtu of natural gas per day to some 70 large and medium size industrial customers throughout British Columbia. Coast Pacific also acts as gas manager for more than 40% of the large industrial market in the interior of British Columbia.
Effective February 1, 1999, Avista Energy completed and closed the purchase of Vitol Gas & Electric, LLC (Vitol), based in Boston, Massachusetts. Vitol is one of the top 20 energy marketing companies in the United States. Vitol trades gas, electricity, coal and SO2 allowances in markets in the eastern half of the United States. The acquisition was funded through the issuance of additional shares of common stock to Avista Capital.
NOTE 22. MERGER TERMINATION
On June 28, 1996, the Board of Directors of the Company terminated the Agreement and Plan of Reorganization and Merger, dated as of June 27, 1994 by and among the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power Company, a subsidiary of SPR (SPPC), and Altus Corporation, a wholly owned subsidiary of the Company (Altus, formerly named Resources West Energy Corporation), which would have provided for the merger of the Company, SPR and SPPC with and into Altus. The Company had approximately $15.8 million, or $10.3 million after-tax, in merger-related transaction and transition costs that were expensed in 1996. No increase in rates occurred as a result of these costs being expensed.
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NOTE 23. SELECTED QUARTERLY INFORMATION (UNAUDITED)
The Company's energy operations are significantly affected by weather conditions. Consequently, there can be large variances in revenues, expenses and net income between quarters based on seasonal factors such as temperatures and streamflow conditions. A summary of quarterly operations (in thousands of dollars except per share amounts) for 1998 and 1997 follows:
The effects of the conversion from common stock to convertible preferred stock are reflected in the fourth quarter 1998 results. See Notes 14 and 18.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Registrant has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant's annual meeting of shareholders to be held on May 13, 1999.
Executive Officers of the Registrant
All of the Company's executive officers, with the exception of Messrs. Turner and Woodworth, were officers or directors of one or more of the Company's subsidiaries in 1998.
Executive officers are elected annually by the Board of Directors.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant's annual meeting of shareholders to be held on May 13, 1999.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
(a) Security ownership of certain beneficial owners (owning 5% or more of Registrant's voting securities):
None.
(b) Security ownership of management:
Information regarding security ownership of management has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant's annual meeting of shareholders to be held on May 13, 1999.
(c) Changes in control:
None.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information regarding certain relationships and related transactions has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant's annual meeting of shareholders to be held on May 13, 1999.
PART IV
ITEM 14.
ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K
(a) 1. Financial Statements (Included in Part II of this report):
Independent Auditors' Report
Consolidated Statements of Income, Comprehensive Income and Retained Earnings for the Years Ended December 31, 1998, 1997 and 1996
Consolidated Balance Sheets, December 31, 1998 and 1997
Consolidated Statements of Capitalization, December 31, 1998 and 1997
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996
Schedule of Information by Business Segments for the Years Ended December 31, 1998, 1997 and 1996
Notes to Financial Statements
(a) 2. Financial Statement Schedules:
None
(a) 3. Exhibits:
Reference is made to the Exhibit Index commencing on page 75. The Exhibits include the management contracts and compensatory plans or arrangements required to be filed as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
(b) Reports on Form 8-K:
Dated June 4, 1998, announcing the appointment of the Company's new Chief Executive Officer.
Dated August 19, 1998, regarding a dividend restructuring plan, a broad corporate refocus and the corporate name change.
Dated October 21, 1998, announcing third quarter earnings, a potential future rate increase in Idaho, a lawsuit filed against the Company, a potential change in capital expenditures in future periods and an update on the Company's progress on the Year 2000 issue.
Dated January 6, 1999, regarding the corporate name change effective January 1, 1999.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
THE WASHINGTON WATER POWER COMPANY
March 19, 1999 By /s/ T. M. Matthews - ------------------------- -------------------------------------------- Date T. M. Matthews Chairman of the Board, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 2-81697, 2-94816, 33-54791, and 33-32148 on Form S-8, and in Registration Statement Nos. 33-49662, 33-53655, 333-39551,333-16353, 333-16353-01, 333-16353-02, and 333-16353-03 on Form S-3 of our report dated January 29, 1999 (February 1, 1999 as to Note 21 and March 10, 1999 as to Note 20), appearing in this Annual Report on Form 10-K of Avista Corporation for the year ended December 31, 1998.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Seattle, Washington March 19, 1999
EXHIBIT INDEX
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*Incorporated herein by reference.
**Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference.
**Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference.
**Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference.
**Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference.
**Filed herewith.
EXHIBIT INDEX (continued)
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* Incorporated herein by reference.
** Filed herewith.
*** Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.