ITEM 1. BUSINESS
COMPANY OVERVIEW
The Washington Water Power Company (Company), which was incorporated in the State of Washington in 1889, primarily operates in the electric and natural gas utility businesses. At December 31, 1996, the Company's employees included 1,453 people in its energy operations and approximately 1,850 people in its majority-owned non-energy businesses. 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.
In August 1996, the Company reorganized its energy operations to take advantage of the changes in the Company's business environment and to proactively respond to regulatory and structural changes in the industry. The restructuring reinforces the Company's commitment to and advocacy of utility industry deregulation. The Company organized its energy operations into two lines of business. The Energy Delivery business includes retail electric and natural gas distribution and transmission services. The Energy Trading and Market Services (Energy Trading) business includes generation and production, electric and natural gas commodity trading and energy services.
Both the Energy Delivery and Energy Trading lines of business are currently conducted by separate business divisions within the Company. The Company intends eventually to conduct some or all of the Energy Trading line of business through one or more of the subsidiaries as discussed below.
In addition to its energy businesses, the Company owns Pentzer Corporation (Pentzer), parent company to the majority of the Company's non-energy businesses.
[1996 ORGANIZATIONAL STRUCTURE]
1996 Organizational Structure is a chart that depicts the Company's organizational structure during 1996. The top of the organizational chart shows "Washington Water Power". Under this are the three Lines of Business -- "Energy Delivery", "Energy Trading and Market Services", and "Non-Energy Business". Under Energy Delivery are the two business units -- "Electric and Natural Gas" and "Transmission Services". Under Energy Trading and Market Services are three business units -- "Generation and Production", "Commodity Trading" and "Energy Services". Under Non-Energy Business are two business units -- "Pentzer Corporation" and "Other".
For the twelve months ended December 31, 1996, 1995 and 1994, respectively, the Company derived operating revenues and income from operations in the following proportions:
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As previously reported, 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, which would have provided for the merger of the Company, SPR and SPPC with and into Altus.
In February 1997, the Company's Board of Directors approved creation of a new subsidiary, Avista Corp. (Avista), which will own all of the Company's non-regulated businesses (energy and non-energy). The non-regulated energy businesses include Avista Advantage, Inc. (formerly WWP Energy Solutions, Inc.) and Avista Energy, Inc. (formerly WWP Resource Services, Inc.). (See Item 1. Business - Energy Trading for additional information about these businesses). The non-energy business primarily consists of Pentzer which is the parent company to the majority of the Company's non-energy businesses. See Item 1. Business - Non-Energy Business and Note 15 to Financial Statements for additional information. Avista was formed to segregate the Company's non-regulated businesses from regulated businesses and support financing of the non-regulated businesses as they develop and expand. The Company will operate under this corporate structure prospectively; the remainder of these 10-K discussions focus on the corporate structure in place during 1996.
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ENERGY DELIVERY
GENERAL BUSINESS MATTERS
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 1996, retail electric service was supplied to approximately 297,000 customers in eastern Washington and northern Idaho; retail natural gas service was supplied to approximately 238,000 customers in parts of Washington, Idaho, Oregon and California.
ELECTRIC OPERATIONS
Regulatory, economic and technological changes have brought about the accelerating transformation of the electric utility industry from a vertically integrated monopoly to a market driven business. The Company is well-positioned to meet the challenges of increased competition due to its low production costs and close proximity to major transmission lines. To assess impacts of competition and customer choice, the Company has proposed and/or implemented experimental programs which include a Direct Access and Delivery Service Tariff (DADS) and a More Options for Power Services (MOPS) tariff. See Regulatory Issues below for additional information.
Challenges facing the retail electric business include reduced energy consumption and the cost of the energy supplied, 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. See Energy Trading - Regulatory Issues for additional information.
Bills have recently been introduced in the Washington State Legislature to move toward retail competition in the electric business. The major features of the proposed bills would allow consumers to choose a market-based rate alternative, allow for recovery of some stranded costs, and require electric utility companies to unbundle their services and rates; prices for local distribution and ancillary services would continue to be regulated. The Company cannot predict the timing or ultimate impact of these proposals if passed. However, the Company believes it is clear that competition will ultimately be introduced into the retail electric business.
IndeGO (Northwest Grid Operator) The Company signed a Memorandum of Understanding (MOU) on July 11, 1996 with various Northwest utilities for the purposes of jointly investigating the feasibility of transferring certain operating responsibilities associated with a regional transmission grid to an independent grid operator. It is conceivable that operation of the regional transmission grid by an independent grid operator may facilitate evolution to a competitive electric power market and potentially increase the efficiency of the Northwest transmission system, as well as provide non-discriminatory open access to the regional transmission grid consistent with FERC requirements. The Company is participating in various IndeGO committees addressing a number of issues (system operations, transmission pricing, regional planning, etc.) associated with the development of an independent grid operator. IndeGO parties are working cooperatively with all anticipated stakeholders during this initial development stage. The MOU is essentially non-binding in that any party to the MOU may withdraw at any time by providing written notice to each other party to the MOU. At such time as IndeGO may be formally proposed, the Company, pursuant to its ongoing internal evaluation of IndeGO, will determine whether it will participate in the formation of the Northwest independent grid operator.
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 or provides transportation service directly to large natural gas customers and non-retail sales to marketers and producers where points of delivery are outside the Company's retail distribution area.
The Company provides transportation service to customers who obtain their own natural gas supplies. Transportation service continued to be a significant component of the Company's total system deliveries in 1996. 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 was approximately 237.9 million therms in 1996. This volume represented approximately 40% of the Company's total system deliveries in 1996.
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While rate design changes have increased the costs of firm transportation to low load-factor pipeline customers such as the Company, flexible receipt and delivery points and capacity releases allow temporarily under-utilized transportation to be released to others when not needed to serve the Company's customers.
Challenges facing the Company's natural gas business include the continuing potential for customers to by-pass the Company's natural gas system. Since 1988, two of the Company's large industrial customers have built their own pipeline interconnections. However, these customers continue to purchase natural gas services from the Company. To reduce the potential for such by-pass, the Company prices its natural gas services, 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 also signed long-term transportation contracts with two of its largest industrial customers which reduces the chances of these customers by-passing the Company's system in the foreseeable future.
REGULATORY ISSUES
The Company, as a public utility, is currently subject to regulation by state utility commissions with respect to rates, 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) and the Idaho Public Utilities Commission (IPUC). The natural gas operations are subject to the jurisdiction of the WUTC, the IPUC, the Public Utility Commission of Oregon (OPUC) and the California Public Utilities Commission (CPUC).
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) is currently determined on a "cost of service" basis and is designed to provide, after recovery of allowable 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 to Financial Statements for additional information about depreciation and deferred taxes). Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirements of utility plant from service. As the energy business is restructured, traditional "cost of service" rate setting may be modified through performance-based (or "incentive") ratemaking. Rates for transmission services are based on the same principles and are set forth in tariffs on file with the FERC.
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%. The Company's last general natural gas rate cases were effective: in August 1990 for the State of Washington and allowed a return on equity of 12.90%; in October 1989 for the State of Idaho and allowed a return on equity of 12.75%.
Notice of Inquiry (NOI) The WUTC, after a notice of inquiry process, has examined potential structural changes in the electric utility industry with a focus on the implications of industry changes for Washington utility regulation and recommendations concerning specific rules and regulations currently used by the WUTC. The NOI process concluded in December 1995 with the issuance by the WUTC of eight guiding principles stating basically that future WUTC regulatory oversight will balance issues such as reliability, pricing responsive to customers needs and selected public policy concerns. Washington utilities were ordered to follow the eight guiding principles while the WUTC reviews other states' experience with restructuring to determine potential benefits for Washington customers. In January 1996, the IPUC initiated a similar NOI entitled, "Investigation into Changes Occurring in the Electric Industry." The IPUC issued an order in September 1996 indicating that, given the low electric rates provided by Idaho utilities, the IPUC will review other states' experience with restructuring to determine potential benefits for Idaho customers.
In August 1995, the WUTC initiated an NOI entitled, "Examining Regulation of Local Distribution Companies in the Face of Change in the Natural Gas Industry." The WUTC sought comments on the potential structural change in the natural gas industry, the implications of industry changes for utility regulation and recommendations concerning specific rules and regulations currently used by the WUTC. As a result of comments received, the WUTC is reviewing regulatory procedures and rules concerning such matters as least-cost planning, purchased gas adjustment (PGA) mechanisms and demand side management (DSM) incentives. The Company provided initial comments in September 1995 and reply comments in early February 1996, and has participated in a series of meetings pertaining to natural gas procurement incentives, DSM and unbundling issues.
Direct Access and Delivery Service Tariff (DADS) To proactively respond to the potential regulatory change of customer choice in the electric business, the Company filed a DADS tariff to better understand how customer choice could affect and benefit its large industrial customers. In May 1996, the Company filed with the WUTC and the IPUC an experimental DADS tariff to allow eligible customers to choose their supplier to serve up to one-third of their electric load. The only eligible customers are 30 of the Company's largest customers in Washington and Idaho. The WUTC and the IPUC approved the tariff effective in September 1996. This trial tariff is effective through August 31, 1998. As of January 1, 1997, 13 of the eligible customers were taking service under the tariff (eight Washington customers and five Idaho customers), representing 60% of the eligible load. Five different alternative suppliers are selling energy to those customers mostly with one-year terms at a fixed-price for the capacity and energy. The tariff will not affect the rates for other customer classes during or after the experimental period. The Company is absorbing any margin losses associated with
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loads served on the DADS tariff and the losses incurred are not having a material impact on the Company's financial condition or results of operation.
More Options for Power Services (MOPS) A MOPS experimental tariff was filed on February 10, 1997 with the WUTC and IPUC to help the Company assess the potential benefits of direct access for its electric residential and commercial customers and to collect information that will assist in the transition to customer choice. The MOPS filing proposes a two-year pilot program that would allow approximately 2,500 residential and 300 commercial customers direct access to alternative energy providers. This pilot is proposed to begin in mid-1997 and end in mid-1999, assuming regulatory approval. The Company has proposed to recover one-half of the lost margins associated with the pilot through the energy delivery rate and absorb one-half of the margin losses. The program costs and margin losses are not expected to have a material impact on the Company's financial condition or results of operation.
Demand Side Management (DSM) The WUTC and IPUC approved as filed, effective January 1, 1997, the Company's proposed electric DSM programs and tariff rider for a three-year extension ending December 31, 1999. The Company's DSM programs focus on both the continuation of selected existing programs available to broad customer classes and the participation in the Northwest Energy Efficiency Alliance, a partnership of regional utilities offering specifically structured programs to influence market demand. The Company's programs, while maintaining a residential electric weatherization program and fuel efficiency awareness programs, now place a greater emphasis on commercial and industrial programs. The tariff rider is a separate revenue source and represents a 1.54% electric revenue surcharge. The revenues will be used to fund the Company's 1997 through 1999 DSM program surcharge expenditures.
The avoided cost of natural gas has decreased to a level which significantly reduces the cost-effectiveness of natural gas DSM programs. The WUTC and IPUC each approved the Company's reduction of the natural gas DSM tariff rider from a surcharge of 0.52% to zero effective January 1, 1997. The Company will continue to monitor the cost of natural gas to determine if there are any substantive changes in the natural gas commodity that would improve the cost-effectiveness of natural gas DSM programs.
In 1993, the OPUC authorized the Company to defer revenue requirements associated with its Oregon DSM investments and established an annual rate adjustment mechanism to reflect the deferred costs on a timely basis. Under this authorization, the Company files annually, concurrent with the Company's annual natural gas "tracker" filing, a rate adjustment to recover DSM program costs and margin losses.
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 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. See Note 1 to Financial Statements for additional details.
Purchased Gas Adjustment (Natural Gas Trackers) Natural gas trackers are designed to pass through changes in purchased natural gas costs and do not normally result in any changes in net income to the Company. In September 1996, the Company filed a natural gas tracker with the IPUC requesting a $2.34 million, or 8.5%, decrease which was approved, effective November 1, 1996. In October 1996, the Company filed a natural gas tracker with the OPUC requesting a $3.67 million, or 8.59%, decrease which was approved, effective December 1, 1996. The Oregon gas tracker includes a provision that specifies a sharing of benefits and risks associated with changes in gas prices. In November 1996, the Company filed a natural gas tracker with the WUTC requesting a $3.39 million, or 4.4%, decrease which was approved, effective January 1, 1997.
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(1) The transfer to Energy Trading represents the portion of revenues collected by Energy Delivery for the generation and resource costs to meet retail loads.
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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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ENERGY TRADING
GENERAL BUSINESS MATTERS
Energy Trading manages the Company's electric energy resource portfolio, which is used to serve Energy Delivery's retail electric customers and Energy Trading's wholesale electric customers. Energy Trading is also in the electric and natural gas commodity trading business where it is involved in both short-term trading and long-term contracts at the wholesale level. Other energy services are provided through Avista Advantage, a subsidiary of the Company.
In managing the electric energy resource portfolio, Energy Trading seeks to maximize availability and minimize cost of production of generation resources. The Company owns and operates nine hydroelectric projects, a wood-waste fueled generating station and two natural gas combustion turbine (CT) peaking units. The Company also owns a 15% share in two coal-fired generating facilities and leases two additional gas CT peaking units. With this diverse energy resource portfolio, the Company remains one of the nation's lowest-cost producers and sellers of electric energy services.
The commodity trading business consists of energy trading and wholesale marketing. 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.
The Company's wholesale marketing and commodity trading businesses are a growing and important part of the Company's overall business strategy. Since 1987, the Company has entered into a number of long-term power sales contracts that have increased its wholesale electric business and the Company is continuing to actively pursue electric wholesale business opportunities. Wholesale sales are affected by weather and streamflow conditions and may eventually be affected by the restructuring of the electric utility industry.
Challenges facing Energy Trading include evolving technologies which provide alternate energy supplies and deregulation of electric and natural gas markets. Energy Trading continues to compete in the wholesale electric market with other western 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 in 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 energy trading business include new entrants in the wholesale market, such as power brokers and marketers, competition from low-cost generation being developed by independent power producers and declining margins. In addition, the Energy Act confers expanded authority upon the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity to provide these services.
To meet the challenges of a changing marketplace, the Company formed two new non-regulated subsidiaries, Avista Advantage, Inc. and Avista Energy, Inc. Avista Advantage provides a variety of energy-related products and services to commercial and industrial customers on a national basis. The Avista Advantage product line includes real-time metering, consolidated billing, lighting and security systems, energy technology services and energy commodity management. Avista Energy will focus on commodity trading, energy marketing and other related businesses. In September 1996, the FERC approved Avista Energy's application for National Power Marketer certification. This will allow Avista Energy to buy electricity for resale to utilities and other customers throughout the United States. The national energy marketing effort will be operating from Spokane, WA.
In November 1996, an alliance was formed with Mock Energy Services, California's largest natural gas marketer, to provide integrated energy services to customers throughout the State of California. Under the terms of the agreement, the alliance will market natural gas and electric commodity service to industrial and large commercial customers throughout California. The alliance will also offer customers a wide variety of energy-related products and services through Avista Advantage.
REGULATORY ISSUES
The Company is subject to the jurisdiction of the FERC for its accounting procedures, its wholesale electric rates and its (wholesale) natural gas rates charged for the release of capacity from the Jackson Prairie Storage Project. Some wholesale electric rates are determined on a "cost-of-service" basis in a manner similar to retail rates. See Energy Delivery - Regulatory Issues for additional information. Also, the Company can enter into wholesale electric sales contracts with rates based on "cost-of-service" principles. Generally, rates for wholesale electric sales by the Company for terms up to five years are based on market prices.
FERC Orders No. 888 and No. 889 As previously reported, the FERC issued its final rule in Order No. 888 on April 24, 1996. The final rule requires public utilities operating under the Federal Power Act to provide access to their transmission systems to third parties pursuant to the terms and conditions of the FERC's pro-forma Open Access Transmission tariff. Utilities were required to file an Open Access tariff, allowing only limited variations to the pro-forma tariff to reflect regional operating practices. Utilities were also required to take transmission service under this same tariff. The Company filed its Open Access tariff with the FERC on July 8, 1996 and subsequently began providing transmission service under
the tariff. The FERC issued its initial order on the non-rate terms and conditions of the tariff on November 13, 1996, accepting the tariff for filing subject to the Company submitting three minor changes to the tariff.
In the FERC's Order No. 889, the companion rule to Order No. 888, the FERC required public utilities to establish an OASIS to provide transmission customers with information about available transmission capacity, prices and other information, by electronic means. This would enable such customers to obtain non-discriminatory transmission service. The final rule requires each public utility subject to the rule to functionally separate its transmission and wholesale power merchant functions and prescribed standards or conduct pursuant to which it is assured a utility's wholesale power merchant function obtains information about its transmission system in the same manner competitors do. The Company filed its "Procedures for Implementing Standards of Conduct under FERC Order No. 889" with the FERC on December 31, 1996 and adopted these Procedures effective January 3, 1997.
FERC Orders NO. 888 and No. 889 have not had a significant material effect on the operating results of the Company.
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ENERGY RESOURCES
ELECTRIC REQUIREMENTS
The Company's 1996 annual peak requirements, including long-term and short-term contractual obligations, was 3,180 MW. This peak occurred on January 31, 1996, at which time the maximum capacity available from the Company's generating facilities, including long-term and short-term purchases, was 3,340 MW. The electric requirements are affected by both Energy Delivery's and Energy Trading's electric needs.
ELECTRIC RESOURCES
The Company's diverse resource mix of hydroelectric projects, thermal generating facilities and power purchases and exchanges, combined with strategic access to regional electric transmission systems, enables the Company to remain one of the nation's lowest-cost producers and sellers of electric energy services. At December 31, 1996, the Company's total owned resources available were 58% hydroelectric and 42% thermal. See Energy Trading Operating Statistics on page 12 for the Company's energy resource statistics.
Hydroelectric Resources Hydroelectric generation is the Company's lowest cost source of electricity and the availability of hydroelectric generation has a significant effect on the Company's total energy costs. Under normal operating conditions, the Company meets about 49% of its total energy requirements (both retail and wholesale), with its own hydroelectric generation and long-term hydroelectric contracts. The streamflows to Company-owned hydroelectric projects were 145%, 120% and 65% of normal in 1996, 1995 and 1994, respectively.
Thermal Resources The Company has a 15% interest in each of two twin-unit coal-fired facilities - the Centralia Power Plant in western Washington and Units 3 and 4 of the Colstrip Generating Project in southeastern Montana. In addition, the Company owns a wood-waste-fired facility known as the Kettle Falls Generating Station in northeastern Washington and two natural gas-fired CTs, located in Spokane, used for peaking needs. The Company also leases two natural gas-fired CTs, both in northern Idaho, used for peaking needs.
Centralia, which is operated by PacifiCorp, is supplied with coal under both a fuel supply agreement in effect through December 2020 and various spot market purchases. In 1996, 1995 and 1994, Centralia provided approximately 46%, 30% and 42%, respectively, of the Company's thermal generation.
Colstrip is supplied with fuel under coal supply and transportation agreements in effect through December 2019 from adjacent coal reserves. The Montana Power Company is the operator of Colstrip. In 1996, 1995 and 1994, Colstrip provided approximately 34%, 47% and 48% of the Company's thermal generation, respectively.
Kettle Falls' primary fuel is wood-waste generated as a by-product from forest industry operations within one hundred miles of the plant. Natural gas may be used as an alternate fuel. A combination of long-term contracts plus spot purchases provides the Company the flexibility to meet expected future fuel requirements for the plant. In 1996, 1995 and 1994, Kettle Falls provided approximately 10%, 8% and 10% of the Company's thermal generation, respectively.
The CTs are natural gas-fired units, primarily used for peaking needs. The Rathdrum CTs have access to domestic and Canadian natural gas supplied through Pacific Gas Transmission (PGT). In 1996 and 1995, these units provided approximately 10% and 15%, respectively, of the Company's thermal generation primarily due to the low cost of natural gas during the two years. Thermal generation provided by the Spokane CT in prior years was immaterial.
Purchases, Exchanges and Sales In 1996, the Company had various purchase contracts equating to a non-coincident peak of 669 MW, with an average remaining life of 4.9 years. Additionally, long-term hydro purchase contracts of 197 MW were available with an average remaining contract life of 12.6 years. The Company also enters into a significant amount of short-term sales and purchases with durations of up to one year. Energy purchases and exchanges for the years 1996, 1995 and 1994 provided approximately 54%, 36% and 30%, respectively, of the Company's total electric energy requirements, including wholesale obligations.
Under the Public Utility Regulatory Policies Act of 1978 (PURPA), the Company is required to purchase generation from qualifying facilities, including small hydroelectric and cogeneration projects, at avoided cost rates adopted by the WUTC and the IPUC. The Company purchased approximately 574,000 MWH, or about 3% of the Company's total energy requirements, from these sources at a cost of approximately $25 million in 1996.
HYDROELECTRIC RELICENSING
The Company is a licensee under the Federal Power Act and its licensed projects are subject to the provisions of Part I of that Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation and take-over of such projects after the expiration of the license upon payment of the lesser of "net investment" or "fair value" of the project, in either case plus severance damages.
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All but one of the Company's hydroelectric plants are regulated by the FERC through project licenses issued for a 30-50 year period. The Cabinet Gorge and Noxon Rapids plants are currently in the process of relicensing with an expiration date of February 2001. The Company filed a Notice of Intent to relicense in 1996 and has undertaken consultation with resource agencies, Native American tribes, special interest groups and the general public. The Company's goal in consultation is to develop settlement agreements with all parties, which will form the basis for the license application in February 1999. Natural resource and engineering studies as defined by the consultation process will be the focus in 1997 with the objective to obtain information necessary for decisions regarding future protection, mitigation and enhancement measures. An Environmental Impact Statement (EIS) will be written in the period between application filing and issuance of a new license.
The Company's approach to relicensing is unique because it departs from the conventional FERC process. Early FERC involvement and EIS scoping has occurred prior to application and the consultation process has been expanded to include all stakeholders. The Company signed an agreement inviting Trout Unlimited to become a partner at the onset of the process. See Item 2.
ITEM 2. PROPERTIES
ENERGY DELIVERY
Electric Distribution and Transmission Plant
The Company operates approximately 12,110 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 1550 miles of 115 kV line. The Company also owns a 10% interest in 495 miles of a 500 kV line from Colstrip, Montana and a 15% interest in 3 miles of a 500 kV line from Centralia, Washington to the nearest Bonneville Power Administration (BPA) interconnections.
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. The 230 kV lines also transmit to points of interconnection with adjoining electric transmission systems for bulk power transfers. These lines interconnect with BPA at five locations and at one location each with PacifiCorp, Montana Power and Idaho Power Company. The BPA interconnections serve as points of delivery for power from the Colstrip and Centralia generating stations as well as for the interchange of power with the Southwest. The interconnection with PacifiCorp is the point of delivery for power purchased by the Company from Mid-Columbia projects' hydroelectric generating stations.
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 the BPA at nine locations, Grant County Public Utility District (PUD), Seattle City Light and Tacoma City Light at two locations and one interconnect location each with Chelan County PUD, PacifiCorp and Montana Power.
Natural Gas Plant
The Company has natural gas distribution mains of approximately 3,420 miles in Washington and Idaho and 1,630 miles in Oregon and California, as of December 31, 1996.
The Company, NWP and Washington Natural Gas Company each own a one-third undivided interest in the Storage Project, which has a total peak day deliverability of 4.6 million therms, with a total working natural gas inventory of 155.2 million therms.
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ENERGY TRADING
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. (4) Jointly owned; data above refers to Company's respective 15% interests. (5) Used primarily for peaking needs. (6) Construction completed in January 1995; see Note 9 to Financial Statements regarding long-term arrangement.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is pursuing recovery from insurers, including filing suit against Underwriters at Lloyds (Lloyds) for $16 million in Spokane County Superior Court. The action is to recover the costs associated with the oil spill in downtown Spokane at the site of the Company's steam heat plant and other environmental remediation efforts. The Company's policies with Lloyds were in effect through 1979; thereafter, its policies were maintained with another underwriter, Aegis. Overlapping or unknown time periods when damages occurred necessitates seeking recovery from both insurers. Refer to Note 14 to Financial Statements.
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 28, 1997, there were approximately 31,566 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, 5 and 17 to Financial Statements for additional information.
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ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
On November 9, 1993, the Company distributed, to shareholders of record on October 25, 1993, shares of its common stock, without par value, under a two-for-one stock split effected in the form of a 100% stock dividend. All references to number of shares and per share information have been adjusted to reflect the common stock split on a retroactive basis.
On July 31, 1990, WIDCo sold its 50% interest in its coal mining properties. The consolidated financial statements, notes and selected financial data have been reclassified to reflect the continuing operations of the Company. The revenues, expenses, assets and liabilities of the discontinued operations have been reclassified from those categories and netted into single line items in the income statements and balance sheets.
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ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Company is primarily engaged as a utility providing electric and natural gas sales and services. The Energy Delivery business includes retail electric and natural gas distribution and transmission services. Usage by retail customers varies from year to year primarily as a result of weather conditions, the economy in the Company's service area, customer growth, conservation, appliance efficiency and other technology. The Energy Trading and Market Services (Energy Trading) business includes generation and production, electric and natural gas commodity trading and energy services. Revenues from the sale of energy to other utilities 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 and the demand for power in other areas of the country. Other factors affecting the wholesale power market include an increasing number of power brokers and marketers and competition from low cost generation being developed by independent power producers.
RESULTS OF OPERATIONS
OVERALL OPERATIONS
Overall earnings per share for 1996 were $1.35, compared to $1.41 in 1995 and $1.28 in 1994. 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 16 to the Financial Statements for additional information about the merger termination). The 1996 results also reflect improved energy earnings, primarily from wholesale electric activities, and transactional gains totaling $15.1 million recorded by Pentzer Corporation (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). The 1995 results include improved earnings from the Company's electric operations and $6.1 million in transactional gains from Pentzer, primarily due to the sale of ITRON stock. The 1994 earnings include $8.0 million of transactional gains recorded by Pentzer primarily as a result of the sale of ITRON stock.
Energy operating income available for common stock decreased $8.8 million, or 14%, in 1996 after increasing $8.3 million, or 15%, in 1995. Energy operating income contributed $0.97 to earnings per share in 1996, compared to $1.14 in 1995 and $1.03 in 1994. 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. Non-energy operating income available for common stock increased $6.2 million, or 42%, in 1996 and $1.2 million in 1995 and contributed $0.38 to earnings per share in 1996, compared to $0.27 in 1995 and $0.25 in 1994.
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. However, the Company estimates that approximately 75% of those customers had their electric service fully restored within 72 hours of the first storm. 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. No increase in rates will occur as a result of these costs.
Income from Energy Delivery operations decreased $19.1 million, or 18%, in 1996 from 1995, primarily due to $17.1 million in pre-tax expenses associated with the storm damage on the electric distribution system. Income from Energy Delivery operations decreased $5.4 million, or 5%, in 1995 from 1994, primarily due to increased operating expenses. Income from Energy Trading operations increased $14.6 million, or 21%, in 1996 over 1995, and $32.7 million, or 90%, in 1995 over 1994, primarily due to increased wholesale electric revenues, resulting from both new power contracts and improved streamflow conditions. In 1995, purchased power and fuel expense decreased from 1994, both a result of the improved streamflows.
Interest expense increased $4.2 million in 1996, as compared to 1995, and $6.0 million in 1995, as compared to 1994, with both increases primarily due to higher levels of outstanding debt. In 1996, $20 million in preferred stock was redeemed, which increased short-term borrowings. During 1996 and 1995, $38.0 million and $45.0 million, respectively, of long-term debt matured or was redeemed, while $78.0 million in long-term debt was issued in 1995. At December 31, 1996, long-term debt outstanding was $26.2 million higher than at December 31, 1995, due to increased borrowings from banks. Long-term debt outstanding at December 31, 1995, was $17.1 million higher than at the end of 1994.
Preferred stock dividend requirements decreased $1.1 million, or 13%, in 1996 from 1995 due to the redemption of $20 million of Preferred Stock, Series I in June 1996. Preferred stock dividend requirements increased $0.5 million in 1995 over 1994 due to higher interest rates in 1995.
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ENERGY OPERATIONS
REVENUES
Total Energy Delivery revenues increased $5.4 million in 1996 over 1995. Electric Energy Delivery revenues increased $8.3 million in 1996 as compared to 1995. Electric residential and commercial revenues increased by a combined $8.1 million, primarily as a result of weather 9% colder than normal in 1996, as compared to 7% warmer than normal in 1995, and a 2.4% growth in these two classes of customers during 1996. Transmission revenues increased $3.6 million in 1996 over 1995 due to increased wholesale electric sales. Total natural gas revenues decreased $2.9 million in 1996 from 1995. Natural gas therm sales to residential and commercial customers increased 13% during 1996, primarily as a result of 6% customer growth in those sectors, due in large part to population growth and new construction, and as a result of colder than normal weather. However, in spite of the increased sales volumes, residential and commercial revenues decreased slightly due to decreases in natural gas prices. Purchased gas cost adjustments effective in Washington, Idaho and Oregon during December 1995 decreased the rates paid by customers in 1996 by 13.58%, 16.68% and 5.82%, respectively.
Total Energy Delivery revenues increased $26.8 million in 1995 over 1994. Electric Energy Delivery revenues increased $9.4 million in 1995 as compared to 1994. Electric residential and commercial revenues increased by a combined $18.8 million, primarily as a result of an increase of nearly 16,500 customers, or 6%, during 1995. Approximately 10,000 residential and commercial customers were added through the acquisition of PacifiCorp's electric properties in northern Idaho in late December 1994. Total natural gas revenues increased $17.5 million, or 11%, in 1995 over 1994, as retail therm sales increased 24%. Residential and commercial natural gas revenues increased by a combined $9.5 million in 1995 as compared to 1994, primarily as a result of 7% customer growth in those sectors, due to conversions from electric service to natural gas, population growth and new construction. Transportation sales increased by 13% in 1995 over 1994, leading to a $1.2 million increase in revenues. Non-retail natural gas sales accounted for a $5.4 million increase in revenues in 1995 over 1994. The revenues from these sales were offset by like increases in purchased gas expense. Margins from these transactions are credited back to retail customers through rate changes for the cost of gas.
Energy Trading revenues increased $132.6 million, or 46%, in 1996 over 1995, primarily due to new power contracts for firm wholesale electric service and increased spot market sales as a result of improved streamflow conditions which led to increased availability of hydroelectric generation in the region. Firm wholesale (long-term) revenues increased $54.9 million in 1996 over 1995, while revenues from short-term (spot market) sales increased $66.4 million during the same period. Streamflows were 145% of normal for 1996. Wholesale kWh sales were nearly three times greater in 1996 than 1995, which offset a 26% decline in average prices.
Energy Trading revenues increased $26.3 million, or 10%, in 1995 over 1994, primarily due to new power contracts for firm wholesale electric service and increased spot market sales as a result of improved streamflow conditions which led to increased availability of hydroelectric generation in the region and generation from the Rathdrum combustion turbine, which went into service in January 1995. Firm wholesale (long-term) revenues increased $19.3 million in 1995 over 1994, while revenues from short-term sales decreased $1.5 million during the same period. Hydroelectric generation was 105% above normal, due to streamflows which were 120% of normal in 1995.
OPERATING EXPENSES
Total operating expenses increased by $24.5 million for Energy Delivery operations and $117.9 million for Energy Trading operations during 1996 compared to 1995. Total operating expenses increased by $32.2 million for Energy Delivery operations and decreased $6.4 million for Energy Trading operations during 1995 compared to 1994.
Commitments under new firm wholesale contracts and increased spot market sales resulted in a $92.4 million, or 95%, increase in electric purchased power expense in 1996 over 1995, which accounts for the majority of the increase in Energy Trading's operating expenses. Improved streamflow conditions, which resulted in increased hydroelectric generation, caused purchased power expense for 1995 to decline by $8.6 million from 1994.
Fuel costs increased $8.3 million in 1996 compared to 1995 as a result of higher generation at thermal plants during the year. The increase in generation was primarily due to increased wholesale sales during 1996. Fuel costs decreased $6.9 million in 1995 compared to 1994 as a result of the increased availability of hydroelectric generation during 1995.
Natural gas purchased expense decreased $5.8 million, or 6%, in 1996 as compared to 1995, primarily due to lower natural gas prices, which offset an increase in therm sales volumes of 4.2 million, or 1%. Natural gas purchased expense increased $11.1 million, or 12%, in 1995 as compared to 1994, primarily as the result of an increase in therm sales volumes of 125.8 million, or 24%. A large portion of purchased gas expense is variable costs, with the result that increases or decreases in revenues are generally offset by like changes in purchased gas expense.
Other operating and maintenance expenses increased $29.6 million in 1996 over 1995 primarily due to the $17.1 million in expenses related to the storm damage on the Company's electric distribution system. Transmission expenses associated with increased wholesale sales increased $2.1 million in 1996 over 1995. The Idaho Power
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Cost Adjustment (PCA), which allows the Company to change rates to recover or rebate a portion of the difference between actual and allowed net power supply costs, also increased during 1996. Net PCA adjustments, resulting from improved streamflow conditions, accounted for $1.9 million of the increase in other operating and maintenance expenses for 1996 over 1995. Increased amortization of conservation programs and a higher accrual for uncollectible accounts were also partially responsible for the increase in other operating and maintenance expenses during 1996 over 1995. Other operating and maintenance expenses increased $20.9 million in 1995 over 1994 due to net PCA adjustments, resulting from improved streamflow conditions, which accounted for $5.8 million of the increase, as well as lease payments and operating expenses related to the Rathdrum combustion turbine, which went into service in 1995, increased amortization of conservation programs, a higher accrual for uncollectible accounts and environmental remediation reserves (see Note 14 to Financial Statements for additional information).
Administrative and general expenses increased by $13.4 million in 1996, compared to 1995, primarily due to $4.2 million in accruals related to postretirement and pension benefits, a $1.6 million write-off of regulatory deferrals of pension expenses, development of a financial information system, increased FERC fees due to higher levels of generation and increases in labor and benefits costs. Administrative and general expenses increased by $5.3 million in 1995, compared to 1994, primarily due to lease payments for computer software systems, labor expenses resulting from merger activities and other labor-related costs.
Income taxes decreased $3.3 million, or 7%, in 1996 over 1995 primarily due to the effects of the expenses associated with the storm damage on the Company's electric distribution system and the merger-related expenses written off during the year, partially offset by increased income from operations. Income taxes increased by $9.9 million, or 26%, in 1995 over 1994, as a result of increased income from operations.
NON-ENERGY OPERATIONS
Non-energy operations primarily include the results of Pentzer. Pentzer's business strategy is to acquire controlling interests in a broad range of middle-market companies, to help these companies grow through internal development and strategic acquisitions and to sell the portfolio investments either to the public or to strategic buyers when it becomes most advantageous in meeting Pentzer's return on invested capital objectives. Pentzer's goal is to produce financial returns for the Company's shareholders that, over the long-term, should be higher than those of the energy operations. From time to time, a significant portion of Pentzer's earnings contributions may be the result of transactional gains. Accordingly, although the income stream is expected to be positive, it may be uneven from year to year.
Non-energy operating revenues and expenses increased by $52.0 million and $50.5 million, respectively, in 1996 as compared to 1995 primarily as a result of acquisitions. Non-energy net income for 1996 was $21.0 million, which represents a $6.2 million, or 42%, increase over 1995 earnings. The increase in 1996 earnings primarily resulted from transactional gains totaling $10.8 million, net of taxes and other adjustments, recorded by Pentzer as a result of the sale of property by one of its subsidiary companies. Transactional gains in 1996 also included $4.7 million from the sale of stock in ITRON, a decrease of $1.3 million from the amount recorded in 1995 from the sale of ITRON stock.
Non-energy operating revenues and expenses increased by $31.1 million and $24.0 million, respectively, in 1995 as compared to 1994, also primarily as a result of acquisitions. Non-energy net income for 1995 was $14.8 million, which represents a $1.2 million, or 9%, increase over 1994 earnings. The increase in 1995 earnings primarily resulted from a $2.2 million increase in non-transactional earnings over 1994 as a result of improved earnings from companies in Pentzer's investment portfolio, including earnings from two companies newly acquired in 1995, partially offset by a decline in transactional gains of $1.1 million as compared to 1994. The 1995 and 1994 transactional gains were primarily the result of gains recorded from the sale of ITRON stock.
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LIQUIDITY AND CAPITAL RESOURCES
OVERALL OPERATIONS
Operating Activities Cash from operating activities less cash dividends paid provided 100% of energy operations capital expenditures in 1996 as compared to 83% in 1995 and 66% in 1994. Cash available from operating activities in 1996 increased from 1995 primarily due to increases in the deferred income tax provision and changes in various working capital components, such as increased receivables, and decreased materials and supplies, fuel stock and natural gas stored and prepayments on power contracts, partially offset by the negative effect of power and purchased gas deferrals. However, construction expenditures have declined from 1994 levels so that cash from operating activities provided a higher percentage of the funds for construction than in previous years. See Note 1 to Financial Statements for additional information.
Investing Activities Cash used in investing activities increased in 1996 over 1995 primarily due to the acquisition of a new company by Pentzer and the Company's purchase of common stock in newly formed WWP subsidiaries. Cash used in investing activities also increased as a result of establishment of trusts for postretirement medical benefits and coal mining reclamation costs and the net effect on cash flows of transactions related to the sale of property by Pentzer. Pentzer received a promissory note for a portion of the sale price of Spokane Industrial Park. Energy 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 $292 million for the 1994-1996 period.
Financing Activities During the 1994-1996 period, $110.5 million of long-term debt and preferred stock matured, was mandatorily redeemed, or was optionally redeemed and refinanced at a lower cost. During 1996, $38.0 million of long-term debt, with an average interest rate of 5.22%, matured or was repurchased.
In November 1996, the Company and three newly formed Trusts filed a Registration Statement with the SEC for up to and including $150 million of Subordinated Debt Securities of the Company and Preferred Trust Securities of the Trusts (guaranteed by the Company), in one or more series and at prices and on terms to be determined at the time of the offering. In January 1997, Subordinated Debt Securities of the Company were issued to one of the Trusts, and that Trust, in turn, issued to the public $60 million of Preferred Securities having a distribution rate of 7 7/8%. On the Company's consolidated balance sheet, this will appear as $60 million of new preferred trust securities. Proceeds of the issuance were used to reimburse the Company's treasury for funds previously expended for the maturity and redemption of preferred stock and long-term debt and to fund a portion of the Company's capital expenditures.
ENERGY 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 construction expenditures.
Capital expenditures are financed on an interim basis with notes payable (due within one year). The Company has $160 million in committed lines of credit. In addition, the Company may currently borrow up to $60 million through other borrowing arrangements with banks. As of December 31, 1996, $35.0 million was outstanding under the committed lines of credit and $50.0 million was outstanding under other short-term borrowing arrangements.
From time to time the Company enters into sale/leaseback arrangements for various long-term assets which provide additional sources of funds. See Note 9 to Financial Statements for additional information.
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 $543 million of First Mortgage Bonds could be issued as of December 31, 1996. As of December 31, 1996, under its Restated Articles of Incorporation, approximately $788 million of additional preferred stock could be issued at an assumed dividend rate of 6.17%.
During the 1997-1999 period, energy capital expenditures are expected to be $239 million, and $132 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 103% of the funds needed for its capital expenditure program. Minimal amounts of external financing will be required to fund maturing long-term debt and preferred stock sinking fund requirements. 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 4, 5, 6, 7, 8 and 9 to Financial Statements for additional details related to financing activities.
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NON-ENERGY OPERATIONS
Capital expenditures for the non-energy operations were $16 million for the 1994-1996 period. During this period, $18.9 million of debt was repaid and capital expenditures were partially financed by the $28.2 million in proceeds from new long-term debt.
The non-energy operations have $45.0 million in short-term borrowing arrangements ($29.6 million outstanding as of December 31, 1996) to fund corporate requirements on an interim basis. At December 31, 1996, the non-energy operations had $28.2 million in cash and marketable securities with $44.0 million in long-term debt outstanding.
The 1997-1999 non-energy capital expenditures are expected to be $11.6 million, and $29.6 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.
TOTAL COMPANY CASH REQUIREMENTS (Millions of Dollars)
(1) Excludes $62 million in 1994 for the combustion turbine project located in Rathdrum, Idaho for which the Company obtained separate long-term lease financing; see Note 9 to Financial Statements for additional information. Also excludes $33 million in 1994 for the acquisition of the northern Idaho electric properties of PacifiCorp. (2) Excludes AFUDC and AFUCE. (3) Excludes notes payable (due within one year).
The Company's total common equity decreased by $6.4 million to $710.7 million at the end of 1996. The 1996 decrease was primarily due to a $13.5 million decrease in unrealized investment gains, due to sales of investments and decreased prices from the prior year, partially offset by a $6.3 million increase in retained earnings. The Company's consolidated capital structure at December 31, 1996, was 48% debt, 7% preferred stock and 45% common equity as compared to 46% debt, 9% preferred stock and 45% common equity at year-end 1995.
FUTURE OUTLOOK
Competition and Business Risk
The electric and natural gas businesses continue to undergo transformation and have become increasingly competitive as a result of economic, regulatory and technological changes. The Company believes that it is well positioned to meet future challenges due to its low production costs, close proximity to major transmission lines and natural gas pipelines, active participation in the wholesale electric market and its commitment to customer satisfaction, customer choice, cost reduction and continuous improvement of work processes. In addition, the Company evaluates business opportunities that will allow it to expand its economies of scale and diversify its risk posed by weather and economic conditions.
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 which provide alternate energy supplies, reduced energy consumption, the cost of the energy supplied, the potential for retail wheeling, self-generation and fuel switching by commercial and industrial customers, increasingly stringent environmental laws and the potential for stranded or nonrecoverable utility assets. 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 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.
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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, 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 also signed long-term transportation contracts with two of its largest industrial customers which reduces the risks of these customers by-passing the Company's system in the foreseeable future.
In 1996, the FERC issued Order No. 888 which requires public utilities operating under the Federal Power Act to provide access to their transmission systems to third parties. The Company filed its Open Access tariff with the FERC in July 1996, and subsequently began providing transmission service under the tariff. In the FERC's Order No. 889, the companion rule to Order No. 888, the FERC requires public utilities to establish an Open Access Same-time Information System (OASIS) to provide transmission customers with information about transmission capacity, prices and other information, by electronic means. These FERC orders have not had a material effect on the Company's operating results and are not expected to in the future.
The Company continues 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 wholesale electric business include an increasing number of power brokers and marketers, competition from low-cost generation being developed by independent power producers and declining margins. Other challenges facing wholesale electric marketing include evolving technologies which provide alternate energy supplies and deregulation of electric and natural gas markets. In addition, the Energy Act confers expanded authority upon the FERC to issue orders requiring electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and to require electric utilities to enlarge or construct additional transmission capacity to provide these services.
Resource planning for both the electric and natural gas businesses has been integrated so that the Company's customers are provided the most efficient and cost-effective products possible for all their energy requirements. The Company's need for new future electric resources to serve retail loads is expected to remain very minimal. The switching of electric heating customers to natural gas requires increased efforts on the Company's part in negotiating and securing competitively-priced natural gas supplies for the future.
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 expand existing businesses and attract new businesses to the Inland Northwest. Agriculture, mining and lumber were the primary industries for many years, but health care, 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 strong economic growth to continue in its Oregon service area.
The Company anticipates retail electric load growth to average approximately 2.0% annually for the next five years primarily due to increases in both population and the number of businesses in its service territory. Although the number of electric customers is expected to increase, the average annual usage by residential customers is expected to decrease slightly 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 1.5% annually for the next five years. The Oregon and South Lake Tahoe, California service areas are anticipated to realize 2.0% 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 and the bull trout have either been added to the endangered species list under the Federal Endangered Species Act (ESA), listed as "threatened" under the ESA or been petitioned for listing under the ESA. Thus far, measures which have been adopted and implemented to save both the Snake
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River sockeye salmon and chinook salmon have not directly impacted generation levels at any of the Company's hydroelectric dams. The Company does, however, purchase power from four projects on the Columbia River that are being directly impacted by these ongoing mitigation measures. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on the Company at this time. Future actions to save these, and other as yet unidentified fish or wildlife species, could further impact the Company's operations or the operations of some of its major customers. It is currently not possible to predict the likely economic costs to the Company resulting from these 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. Bull trout are native to this area and are again being considered for listing under the ESA following a recent court decision. The relicensing process includes a cooperative program for recovery with the two states. It is currently not possible to predict the likely economic costs to the Company resulting from bull trout recovery whether or not a listing occurs.
See Note 14 to Financial Statements for additional information.
Other
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 are derived from its retail electric and natural gas energy operations and, increasingly, from its growing wholesale electric operations and Pentzer's non-energy investment operations.
In February 1997, the Company's Board of Directors approved creation of a new subsidiary, Avista Corp. (Avista), which will own all of the Company's non-regulated energy and non-energy businesses. The non-regulated energy businesses include Avista Advantage, Inc. (formerly WWP Energy Solutions, Inc.) and Avista Energy, Inc. (formerly WWP Resource Services, Inc.). The non-energy business primarily consists of Pentzer which is the parent company to the majority of the Company's non-energy businesses. Avista was formed to segregate the Company's non-regulated businesses from regulated businesses and support financing of the non-regulated businesses as they develop and expand. The Company will operate under this corporate structure prospectively.
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 other statements which are other than statements of historical facts. 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 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 operations to differ materially from those discussed in forward-looking statements include prevailing 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 of plant facilities, and acquisition and disposal of assets or facilities.
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Non-Energy Operations -
Certain important factors which could cause actual results or outcomes for the Company and all or certain of its 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, and the availability of economic expansion or development opportunities.
Factors Common to Energy and Non-Energy 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 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
The Washington Water Power Company Spokane, Washington
We have audited the accompanying consolidated balance sheets and statements of capitalization of The Washington Water Power Company and subsidiaries (the Company) as of December 31, 1996 and 1995, and the related consolidated statements of income and retained earnings, cash flows, and the schedules of information by business segments for each of the three years in the period ended December 31, 1996. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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 and schedules are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements and schedules. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement and schedule presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements and schedules present fairly, in all material respects, the financial position of the Company and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. In addition, the schedules referred to above present fairly, in all material respects the segment information of the Company and its subsidiaries in accordance with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, in 1996 the Company changed its method of grouping products and services into new industry segments to conform to a restructuring of the Company's business operations. The Company retroactively restated the 1995 and 1994 financial statements for the change.
Deloitte & Touche LLP
Seattle, Washington January 31, 1997
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS The Washington Water Power Company - - -------------------------------------------------------------------------------- For the Years Ended December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CONSOLIDATED BALANCE SHEETS The Washington Water Power Company - - -------------------------------------------------------------------------------- At December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CONSOLIDATED STATEMENTS OF CAPITALIZATION The Washington Water Power Company - - -------------------------------------------------------------------------------- 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 The Washington Water Power Company - - -------------------------------------------------------------------------------- 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 The Washington Water Power Company - - -------------------------------------------------------------------------------- For the Years Ended December 31 Thousands of Dollars
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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NOTES TO FINANCIAL STATEMENTS - - --------------------------------------------------------------------------------
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS The Company was incorporated in the State of Washington in 1889, and is primarily engaged as a utility providing electric and natural gas sales and services. The Energy Delivery business includes retail electric and natural gas distribution and transmission services. Usage by retail customers varies from year to year primarily as a result of weather conditions, the economy in the Company's service area, customer growth, conservation, appliance efficiency and other technology. The Energy Trading and Market Services (Energy Trading) business includes generation and production, electric and natural gas commodity trading and energy services. Revenues from the sale of energy to other utilities 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 and the demand for power in other areas of the country. Other factors affecting the wholesale power market include an increasing number of power brokers and marketers and competition from low cost generation being developed by independent power producers.
BASIS OF REPORTING The financial statements are presented on a consolidated basis and, as such, include the assets, liabilities, revenues and expenses of The Washington Water Power Company (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 3). The financial activity of each of the Company's lines of business is reported in the "Schedule of Information by Business Segments." Such information is an integral part of these financial statements. In 1996, the Company changed its method of grouping products and services into new industry segments. Information that was previously reported as electric, natural gas and non-utility operations is now being reported by the new business lines of Energy Delivery, Energy Trading and Non-Energy operations. The Company retroactively restated the 1995 and 1994 financial statements for the change.
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.
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 services provided through month-end.
OTHER INCOME (DEDUCTIONS)--NET Other income (deductions)-net is composed of the following items:
EARNINGS PER SHARE Earnings per share have been computed based on the weighted average number of common shares outstanding during the period.
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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.
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 1996, 1995 and 1994. 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 energy operations, the ratio of depreciation provisions to average depreciable property was 2.58% in 1996, 2.57% in 1995 and 2.56% in 1994.
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 $14.2 million and $19.7 million are included on the Consolidated Balance Sheets at December 31, 1996 as other property and investments and current assets, respectively. Investments totaling $37.1 million and $27.4 million are included on the Consolidated Balance Sheets at December 31, 1995 as other property and investments and current assets, respectively. Unrealized investment gains, as of December 31, 1996 and 1995, of $5.7 million and $19.2 million, respectively, net of taxes, are reflected as a separate component of shareholders' equity in the Consolidated Statements of Capitalization.
DERIVATIVE FINANCIAL INSTRUMENTS The Company has used derivative instruments, primarily commodity price swaps, to a limited extent as a means of hedging its costs and preserving margins in the wholesale power business. The differential to be paid or received on a commodity price swap agreement is recognized over the life of the agreement as an adjustment to operating costs. The market and credit risk were determined to be immaterial to the financial statements as of December 31, 1996, and over the term of the agreements in effect at year-end. The Company will continue to use derivative instruments for hedging and risk mitigation purposes, but has adopted a policy not to trade in derivatives for speculative reasons. The Company's policy established procedures for monitoring open positions and requires review and approval of derivative instrument transactions.
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 would be required to write off its regulatory assets and would 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.
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The Company's primary regulatory assets include Investment in Exchange Power, conservation programs, deferred income taxes, the provision for postretirement benefits, unrecovered purchased gas costs and debt issuance and redemption costs. Deferred credits include natural gas deferrals and the gain on the general office building sale/leaseback being amortized over the life of the lease.
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 PURPA contracts. Rate changes are triggered when the deferred balance reaches $2.2 million. The following surcharges were in effect during the past three years: a $2.5 million (2.3%) rebate effective September 1, 1996, which will expire August 31, 1997; $2.3 million (2.4%) surcharge effective September 1, 1995, which expired August 31, 1996; and a $2.2 million (2.5%) surcharge effective January 1, 1995, which expired December 31, 1995.
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.
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 1992 return.
NEW ACCOUNTING STANDARDS FAS No. 121, entitled "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," was issued by the Financial Accounting Standards Board (FASB), and is effective for fiscal years beginning after December 15, 1995. FAS No. 121 requires the review of certain assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If an asset is determined to be impaired, a loss is recognized. The Company will continue to periodically review its assets to determine whether any assets meet the requirements for impairment recognition under this standard. The Company adopted the standard on January 1, 1996, but does not expect any material impact on the Company's financial position or results of operations.
FAS No. 125, entitled "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," which is effective after December 31, 1996, provides accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities which focuses on control of the assets. The statement provides standards for distinguishing transfers of financial assets that are sales from transfers that are secured borrowings. The Company has determined that its accounts receivable sale meets the qualifications to be accounted for as a sale of assets under this standard (see Note 4 to Financial Statements for additional information).
In October 1996, the American Institute of Certified Public Accountants issued Statement of Position (SOP) 96-1, entitled "Environmental Remediation Liabilities," which provides authoritative guidance for the recognition, measurement, display and disclosure of environmental remediation liabilities in financial statements. The Company's policy is to immediately accrue and charge to current expense identified exposure related to environmental remediation sites based on estimates of investigations, cleanup and monitoring costs to be incurred. These accruals are then adjusted as further information develops or circumstances change. Cost of future expenditures for environmental remediation obligations are not discounted to their present value. The Company adopted SOP 96-1 on January 1, 1997, but it is not expected to have a material effect on the Company's financial position or 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.
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NOTE 2. 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):
NOTE 3. JOINTLY OWNED ELECTRIC FACILITIES
The Company has invested in several 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. The following table indicates the Company's percentage ownership and the extent of the Company's investment in such plants at December 31, 1996:
NOTE 4. ACCOUNTS RECEIVABLE SALE
The Company has entered into an agreement whereby it can sell without recourse, on a revolving basis, up to $40,000,000 of interests in certain accounts receivable, both billed and unbilled. The Company is obligated to pay fees which approximate the purchaser's cost of issuing commercial paper equal in value to the interests in receivables sold. The amount of such fees is included in operating expenses. At both December 31, 1996 and 1995, $40,000,000 in receivables had been sold pursuant to the agreement. The agreement qualifies as a sale of assets under FAS No. 125 (see Note 1 to Financial Statements for additional information).
NOTE 5. 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 ($11,009,000 at December 31, 1996) 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 1996, the cost recorded for the Plan was $3,139,000. 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 $1,087,000, $2,569,000 and $1,198,000, respectively.
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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. 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 1994, 1995 or 1996. At December 31, 1996, 572,400 shares remained authorized but unissued.
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.
Beginning in 1996, shares were purchased on the open market to fulfill obligations of the 401(K) and Dividend Reinvestment Plans. Sales of Common Stock for 1996, 1995 and 1994 are summarized below (thousands of dollars):
NOTE 6. PREFERRED STOCK
CUMULATIVE PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION: The dividend rate on Flexible Auction Preferred Stock, Series J is reset every 49 days based on an auction. During 1996, the dividend rate varied from 4.03% to 4.24% and at December 31, 1996, was 4.20%. Series J is subject to redemption at the Company's option at a redemption price of 100% per share plus accrued dividends.
CUMULATIVE PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION:
Redemption requirements: $8.625, Series I - On June 15, 1997, 1998 and 1999, the Company must redeem 100,000 shares at $100 per share plus accumulated dividends. The Company may, at its option, redeem up to 100,000 shares in addition to the required redemption on any redemption date.
$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 $30 million in mandatory redemption requirements during the 1997-2001 period.
In June 1996, the Company had a mandatory redemption of $10 million, or 100,000 shares, and also completed an optional redemption of an additional 100,000 shares, or $10 million, of its $8.625 Series I.
The fair value of the Company's preferred stock at December 31, 1996 and 1995 is estimated to be $118.3 million, or 103% of the carrying value and $139.8 million, or 104% of the carrying value, respectively. These estimates are based on available market information.
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NOTE 7. LONG-TERM DEBT
The annual sinking fund requirements and maturities for the next five years for long-term debt outstanding at December 31, 1996 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 1995 and 1994, $78.0 million and $88.0 million, respectively, of First Mortgage Bonds in the form of Secured Medium-Term Notes were issued. As of December 31, 1996, the Company had remaining authorization to issue up to $109.0 million.
At December 31, 1996, the Company had $85.0 million outstanding under borrowing arrangements which will be refinanced in 1997. See Note 8 for details of credit agreements.
Included in other long-term debt are the following related to non-energy operations (thousands of dollars):
The fair value of the Company's long-term debt at December 31, 1996 and 1995 is estimated to be $658.7 million, or 102% of the carrying value and $733.2 million, or 107% of the carrying value, respectively. These estimates are based on available market information.
NOTE 8. BANK BORROWINGS
At December 31, 1996, the Company maintained total lines of credit with various banks under two separate credit agreements amounting to $160,000,000. The Company has one revolving line of credit, expiring December 10, 1999, which provides a total credit commitment of $70,000,000. The second revolving credit agreement is composed of two tranches totaling $90,000,000. One tranche provides for up to $50,000,000 of notes to be outstanding at any one time, while the other provides for up to $40,000,000 of notes to be outstanding at any one time. Both tranches of this agreement expire on July 23, 1997. The Company pays commitment fees of up to 0.10% 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 $60,000,000 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.
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Balances and interest rates of bank borrowings under these arrangements were as follows:
Non-energy operations have $45.0 million in short-term borrowing arrangements available. At December 31, 1996 and 1995, $29.6 million and $26.6 million, respectively, were outstanding.
NOTE 9. LEASES
The Company has entered into several lease arrangements involving various assets, with minimum terms ranging from one to fifteen years and expiration dates from 1998 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, 1996, 1995 and 1994 was $11.8 million, $10.7 million and $2.3 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, 1996 are estimated as follows:
The Company also has various other operating leases, which are charged to operating expense, consisting of a large number of small, relatively short-term, renewable agreements for various items, such as office equipment and office space.
NOTE 10. PENSION 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 another plan which covers the executive officers.
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Net pension cost (income) for 1996, 1995 and 1994 is summarized as follows:
The funded status of the Plans and the pension liability at December 31, 1996, 1995 and 1994, are as follows:
NOTE 11. OTHER POSTRETIREMENT BENEFITS
FAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," requires the Company to accrue 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.
The Company received accounting orders from the Washington Utilities and Transportation Commission (WUTC) and the IPUC allowing the deferral of expense accruals under this Statement as a regulatory asset for future recovery. The Company discontinued deferring expenses, began amortizing prior deferrals already recorded and began recognition of current expenses in 1996.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. In 1996, 1995 and 1994, the Company recognized $1,330,000, $1,800,000 and $1,270,000, respectively, as an expense for postretirement health care and life insurance benefits. The following table sets forth the health care plan's funded status at December 31, 1996, 1995 and 1994.
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Accumulated postretirement benefit obligation (thousands of dollars):
Net postretirement benefit cost for 1996, 1995 and 1994 (thousands of dollars):
The currently assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation is 5% for 1996. The assumed rate of future medical cost increases has been gradually decreased since the adoption of FAS 106 in response to the actual leveling off of cost increases in the plan. 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, 1996 and net postretirement health care cost by approximately $211,000. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.5%.
NOTE 12. ACCOUNTING FOR INCOME TAXES
As of December 31, 1996 and 1995, the Company had recorded net regulatory assets of $164,753,000 and $169,432,000, respectively, related to the probable recovery of FAS No. 109, "Accounting for Income Taxes," deferred tax liabilities from customers through future rates. Such net 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):
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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):
NOTE 13. 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, 1996, 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 1996. (2) Included in annual costs. (3) The Lake Chelan Project contract expired in 1995. The negative costs in 1996 represent final adjustments.
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Actual expenses for payments made under the above contracts for the years 1996, 1995 and 1994, were $5,435,000, $8,080,000 and $8,717,000, 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 $4,041,000 in 1997, $5,605,000 in 1998, $5,574,000 in 1999, $6,814,000 in 2000 and $6,677,000 in 2001 (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.
NOTE 14. COMMITMENTS AND CONTINGENCIES
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 Federal Energy Regulatory Commission (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 range 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. The parties are in the process of selection of a mediator and a further status conference with the Ninth Circuit Mediator will be held on May 13, 1997. The Company is presently unable to assess the likelihood of an adverse outcome in this litigation, or estimate an amount or range of potential loss in the event of an adverse outcome.
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. On December 6, 1993, the Company asked the Department of Ecology (DOE) to enter into negotiations for a Consent Decree. The Consent Decree, entered on November 8, 1994, provided for an extensive Remedial Investigation (RI) and Feasibility Study (FS) to determine the appropriate cleanup action. The RI and FS were completed in 1995 and an RI/FS report was approved by the DOE in 1996. A Cleanup Action Plan (CAP) was determined by DOE in 1996. The 1994 Consent Decree was amended to include the CAP with court approval on December 2, 1996. The Company is now implementing the CAP. The Company presently estimates that the total cleanup cost, including costs incurred to-date, will approximate $10 million. As of December 31, 1996, an accrual of $3.1 million is reflected on the Company's financial statements, which represents the Company's best estimate of its uninsured liability.
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 alleges that the oil released from the Company's Central Steamplant trespassed on property owned by the plaintiff. In addition, the plaintiff claims 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. If the settlement agreement fails or is terminated, the Company is presently unable to assess the likelihood of an adverse outcome in this litigation, or estimate an amount or range of potential loss in the event of an adverse outcome.
FIRESTORM
On October 16, 1991, gale-force winds struck a five-county area in eastern Washington and a seven-county area in northern Idaho. These winds were responsible for causing 92 separate wildland fires, resulting in two deaths and the loss of 114 homes and other structures, some of which were located in the Company's service territory. Five separate class action lawsuits have been filed against the Company by private individuals in the Superior Court for Spokane County. All of these suits were certified as class actions on September 16, 1994, and bifurcated for trial of liability and damage issues by order of the same date.
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The Company was also served with two suits in Spokane County Superior Court filed on April 20, 1994 and on September 15, 1994, both of which sought individual damages from separate and for alleged wrongful death of two persons. Five additional and separate suits were brought by Grange Insurance Company, and were filed in Spokane County Superior Court on October 10, 1994, for approximately $2.2 million paid to Grange insureds for the same fire areas.
Complainants in all cases allege various theories of tortious conduct, including negligence, creation of a public nuisance, strict liability and trespass; in most cases, complainants allege that fires were caused by electric distribution and/or transmission lines downed by wind-downed trees. The lawsuits seek recovery for property damage, emotional and mental distress, lost income and punitive damages, but do not specify the amount of damages being sought. All cases are in a discovery phase. Plaintiffs' motion for consolidation of all liability trials was denied without prejudice. Plaintiffs also filed a Motion to Decertify all cases on damage issues, which motion was denied following a hearing held on January 27, 1997. Still pending is a WWP Motion for Discretionary Review before the Washington Court of Appeals (Div. III) on class certification issues, which was heard by the Court on February 4, 1997. Trial date(s) are anticipated in late 1997 or early 1998. The Company has received a settlement demand for settlement of class action litigation which is within the Company's insurance coverage limits. The Company is presently unable to assess the likelihood of an adverse outcome or estimate an amount or range of potential loss in the event of an adverse outcome.
WILLIAMS LAKE LAWSUIT
On December 21, 1995, a lawsuit was commenced in Vancouver, British Columbia against the Company's subsidiary, Pentzer Corporation (Pentzer), by Tondu Energy Systems, Inc. and T.E.S. Williams Lake Partnership alleging contract violations, conspiracy, misrepresentation and breach of fiduciary duties in regard to the 1993 sale of assets of Pentzer Energy Services, Inc. to B.C. Gas, Inc. and a U.S. subsidiary of B.C. Gas. The claims involve an alleged first right to purchase interests in the Williams Lake, British Columbia wood-fired generating station. The suit seeks damages in excess of $10 million, plus exemplary damages, prejudgment interest, costs and attorneys' fees. Also named as defendants are B.C. Gas, Inc., Inland Pacific Energy (Williams Lake) Corp., Pentzer Energy Services, Inc. and WP Energy Company. The Company is presently unable to assess the likelihood of an adverse outcome or estimate an amount or range of potential loss in the event of an adverse outcome.
At this time, management believes that the ultimate outcome of all the claims and actions discussed in this note should not have a material adverse effect on the Company's consolidated operations or financial position.
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 Centralia and Colstrip thermal generating plants, in which the Company maintains an ownership interest. The Company is presently unable to determine the financial impact of these requirements.
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, 1996, the Company's collective bargaining agreement with the International Brotherhood of Electrical Workers represented approximately 48% of employees. The current agreement with the union local representing the majority of the bargaining unit employees expires on March 25, 1997. Negotiations are taking place between bargaining unit employees and Company management. A local agreement in the South Lake Tahoe area, which represents 7 employees, expires on March 25, 1999.
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NOTE 15. ACQUISITIONS AND DISPOSITIONS
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. During 1996, Pentzer acquired a company that provides point-of-purchase and in-store merchandising services. In 1995 and 1994, Pentzer acquired two companies in each year.
NOTE 16. 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 will occur as a result of these costs being expensed.
NOTE 17. COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED TRUST SECURITIES
In November 1996, the Company and three newly formed Trusts filed a Registration Statement with the SEC for up to and including $150 million of Subordinated Debt Securities of the Company and Preferred Trust Securities of the Trusts (guaranteed by the Company). In January 1997, Subordinated Debt Securities of the Company were issued to one of the Trusts, and that Trust, in turn, issued to the public $60 million of Preferred Securities having a distribution rate of 7 7/8%. On the Company's consolidated balance sheet, this will appear as $60 million of new preferred trust securities.
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NOTE 18. 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 1996 and 1995 follows:
* The amount reported above for Operating Income in the second quarter of 1996 differs from the amount reported in the second quarter Form 10-Q because the merger expenses were retroactively reclassified from operating expenses to non-operating expenses during the third quarter of 1996.
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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 20, 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
All of the Company's executive officers, with the exception of Messr. Fukai, were officers or directors of one or more of the Company's subsidiaries in 1996.
Executive officers are elected annually by the Board of Directors.
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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 20, 1997.
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 20, 1997.
(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 20, 1997.
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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 Auditor's Report
Consolidated Statements of Income and Retained Earnings for the Years Ended December 31, 1996, 1995 and 1994
Consolidated Balance Sheets, December 31, 1996 and 1995
Consolidated Statements of Capitalization, December 31, 1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995, and 1994
Schedule of Information by Business Segments for the Years Ended December 31, 1996, 1995 and 1994
Notes to Financial Statements
(a) 2. Financial Statement Schedules:
None
(a) 3. Exhibits: Reference is made to the Exhibit Index commencing on page 52. 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 28, 1996, regarding the termination of the Merger Agreement between the Company, Sierra pacific Resources, Sierra Pacific Power Company and Altus Corporation.
Dated December 1, 1996, regarding the storm damage to the Company's electric transmission and distribution system resulting from an ice storm.
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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 20, 1997 By /s/ PAUL A. REDMOND - - -------------------------- -------------------------------------- Date Paul A. Redmond 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 No. 2-81697 on Form S-8, in Registration Statement No. 2-94816 on Form S-8, in Registration Statement No. 33-49662 on Form S-3, in Registration Statement No. 33-51669 on Form S-3, in Registration Statement No. 33-53655 on Form S-3, in Registration Statement No. 33-54791 on Form S-8, in Registration Statement No. 333-16353, in Registration Statement No. 333-16353-01, in Registration Statement No. 333-16353-02, and in Registration Statement No. 333-16353-03 of our report dated January 31, 1997, appearing in this Annual Report on Form 10-K of The Washington Water Power Company for the year ended December 31, 1996.
Deloitte & Touche LLP
Seattle, Washington March 20, 1997
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EXHIBIT INDEX
*Incorporated herein by reference. **Filed herewith.
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EXHIBIT INDEX (continued)
- - ------------- *Incorporated herein by reference. **Filed herewith.
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EXHIBIT INDEX (continued)
*Incorporated herein by reference. **Filed herewith.
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EXHIBIT INDEX (continued)
*Incorporated herein by reference. **Filed herewith.
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EXHIBIT INDEX (continued)
*Incorporated herein by reference. **Filed herewith.
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EXHIBIT INDEX (continued)
* 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.
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EXHIBIT INDEX (continued)
* 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.