Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS
COMPANY OVERVIEW
Incorporated in 1889 under the laws of the State of Washington, The Washington Water Power Company (WWP, the Company) is an investor-owned company primarily engaged as a combination electric and natural gas utility serving a 26,000 square mile area known as the Inland Northwest in eastern Washington and northern Idaho with a population estimated to be in excess of 750,000. Also, WP Natural Gas (WPNG), an operating division, provides natural gas service in northeast and southwest Oregon and the South Lake Tahoe region in California with a population estimated to be in excess of 450,000. The Company's utility operations include the generation, purchase, transmission, distribution and sale of electric energy on both a retail and wholesale basis plus the purchase, transportation, distribution and sale of natural gas. In addition to its utility operations, the Company owns Pentzer Corporation, parent company to the majority of the Company's non-utility businesses. Pentzer's portfolio of investments includes companies involved in advertising display manufacturing, electronic technology, energy services, financial services, real estate development and telecommunications.
At December 31, 1993, the Company employed 1,696 people with 1,438 in its utility operations and 258 in its majority-owned non-utility operations. The Company headquarters are in Spokane, Washington, which with a population of about 480,000 in the Greater Spokane Area, serves as the Inland Northwest's center for business, transportation, health care, education, communication and agricultural interests.
For the twelve months ended December 31, 1993 and 1992, respectively, the Company derived operating revenues and income from operations in the following proportions:
UTILITY OVERVIEW
The Company owns and operates nine hydroelectric projects, a wood-waste fueled generating station and a natural gas combustion turbine. The Company also retains a 15% ownership in two coal-fired generating facilities, one in southwestern Washington and one in southeastern Montana. In addition the Company is in the process of constructing a natural gas combustion turbine peaking unit in northern Idaho. Four natural gas pipelines provide the Company access to both domestic and Canadian natural gas supplies. With this diverse resource portfolio, the Company remains one of the nation's lowest-cost producers and sellers of energy services.
At December 31, 1993, electric service was supplied to approximately 267,000 customers in eastern Washington and northern Idaho. The Company's average hourly load for 1993 was 900 aMW. The Company's annual peak load, including firm contractual obligations, was 2,126 MW. This peak occurred on January 13, 1993, at which time the maximum capacity available from the Company's generating facilities, contracts and non-firm purchases was 2,335 MW.
At December 31, 1993, the Company's natural gas operations served approximately 196,000 customers in four states. The Company's natural gas business has more than doubled since 1990 due primarily to the acquisition of the natural gas distribution properties of CP National in Oregon and South Lake Tahoe, California in September, 1991. The peak load in 1993 occurred on February 16, 1993 when 2.7 million therms were required. During that peak 3.5 million therms were available under firm transportation and storage contracts.
NON-UTILITY OVERVIEW
The Company's principal subsidiary, Pentzer, is the parent company of all the Company's non-utility subsidiaries except for three non-operating subsidiaries. Wholly-owned Pentzer is a company with approximately $130 million in total assets and about $86 million in shareholder equity. 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.
THE WASHINGTON WATER POWER COMPANY
ELECTRIC SERVICE
ELECTRIC COMPETITION AND BUSINESS OVERVIEW
The electric utility business is undergoing numerous changes and is becoming increasingly competitive as a result of economic, regulatory, and technological changes. The Company believes that it is well positioned to meet the challenges described below due to its low production costs, close proximity to major transmission lines, experience in the wholesale market and its commitment to high levels of customer satisfaction, cost reduction and continuous improvement of work processes.
The Company currently competes for new retail electric customers with various rural electric cooperatives and public utility districts. Challenges facing the electric retail business include changing technologies which reduce energy consumption, self- generation and fuel switching by industrial and other large retail customers, the potential for retail wheeling (described below) and the costs of increasingly stringent environmental laws. Cogeneration has had only a minor impact on the Company to date. See "Purchases, Exchanges and Sales" for additional detail on cogeneration purchases and sales. In addition, if electric utility companies are eventually required to provide retail wheeling service, which is the transmission by an electric utility 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.
The Company also competes in the wholesale electric market with other western utilities, including the BPA. Challenges facing the electric wholesale business include new entrants in the wholesale market and competition from lower cost generation being developed by independent power producers.
The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of issues affecting the wholesale electric business. NEPA gives the FERC expanded authority to order electric utilities (a) to transmit electric power to or for wholesale purchasers and sellers if the result would not unreasonably impair the continuing reliability of the affected electric systems and (b) to increase transmission capacity to provide access for wholesale purchasers and sellers of electric power at prices that permit the recovery by the utility of all costs incurred in connection with the transmission services. NEPA also created Exempt Wholesale Generators (EWG's), a new class of independent power plant owners who are able to sell generation only at the wholesale level. The Company believes NEPA provides future transmission, energy production and sales opportunities to the Company and complements the Company's commitment to the wholesale electric business.
The Company's wholesale electric business remains an important part of the Company's overall business. Since 1987 the Company has entered into a number of long-term firm power sales contracts that have increased its wholesale electric business and the Company intends to continue active pursuit of wholesale business opportunities. In 1993, 31% of total KWH sales were to wholesale customers with 55% of these sales under firm contracts.
ELECTRIC SYSTEM
The Company owns and operates nine hydroelectric projects, a wood-waste fueled generating station and a natural gas combustion turbine in addition to retaining a 15% ownership in two coal-fired generating facilities.
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 power costs. The Company expects to meet about 49% of its total system requirements with its own hydroelectric generation and long-term hydro contracts in normal water years. The streamflows in the Company's drainage systems were 86%, 64% and 116% of normal in 1993, 1992 and 1991, respectively. For the years 1993, 1992 and 1991, respectively, the Company's own hydroelectric generation facilities provided 33%, 28% and 38%, while long-term hydro contracts provided approximately 10%, 12% and 14% of the Company's total system requirements.
Thermal Resources The Company has a 15% interest in two coal-fired facilities - - the Centralia Power Plant (Centralia) in southwestern Washington and Units 3 and 4 of the Colstrip Generating Project (Colstrip) in southeastern Montana. In addition, the Company owns a woodwaste-fired facility known as the Kettle Falls Generating Station (Kettle Falls) in northeastern Washington and a natural gas-fired combustion turbine (CT) in Spokane. The CT is primarily used for peaking needs. In a normal water year about 32% of the Company's total system requirements are met by thermal sources. Company-owned thermal facilities provided 25%, 31% and 26% of the Company's total electricity requirements for the years 1993, 1992 and 1991, respectively.
THE WASHINGTON WATER POWER COMPANY
Centralia, which is operated by PacifiCorp, is supplied with coal under a fuel supply agreement in effect through December 31, 2020. In 1993, 1992 and 1991 Centralia provided approximately 46%, 40% and 40%, 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 owned and controlled by Entech, Inc. (Entech). Entech is a wholly-owned subsidiary of The Montana Power Company, which is also the operator of Colstrip. In 1993, 1992 and 1991 Colstrip provided approximately 43%, 51%, and 51% of the Company's thermal generation, respectively.
Kettle Falls' primary fuel is waste wood generated as a by-product of forest product processing facilities such as sawmills within an approximate one hundred mile radius of the plant. Natural gas may be used as an alternate fuel. The cost of waste wood fuel is heavily influenced by operations of the forest products industry as well as transportation costs and, therefore, is subject to significant price variations. Current fuel supplies are adequate through the remainder of 1994. A combination of long term contracts already in place plus spot purchases allow the Company the flexibility to meet all expected future fuel requirements for the plant. In 1993, 1992 and 1991 Kettle Falls provided approximately 11%, 9% and 9% of the Company's thermal generation, respectively.
Purchases, Exchanges and Sales In addition to the Company-owned hydro, long-term hydro contracts and thermal generating resources discussed above, total system requirements are met with other long-term purchases and exchanges of power. Other power purchases and exchanges for the years 1993, 1992 and 1991 provided approximately 32%, 29% and 22%, respectively, of the Company's total system requirements.
The following table summarizes the Company's major long-term wholesale power agreements as of December 31, 1993 (1):
(1) Available capacity may vary pursuant to the provisions of the specific contracts. See Notes 11 and 13 to Financial Statements for additional information
Under PURPA, the Company is required to purchase generation from qualifying facilities, including small hydro and cogeneration projects, at avoided cost rates adopted by the WUTC and IPUC. The Company purchased approximately 623 million KWH, or about 6% of the Company's total energy requirements, from these sources at a cost of approximately $26 million in 1993. The largest such contract is a ten-year power purchase contract between the Company and Potlatch, one of the Company's major industrial customers, which became effective on January 1, 1992. Under the terms of the agreement, the Company purchases 50-55 aMW of Potlatch's electric generation and makes available approximately 95 aMW of firm energy for sale. In addition, the Company makes available 25 aMW of interruptible energy and Potlatch must provide an equivalent amount of reserve generation capacity in case of interruption.
ELECTRIC 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 electric retail operations are subject to the jurisdiction of the WUTC and IPUC. The Company is also subject to the jurisdiction of the FERC for its accounting procedures and its wholesale transmission rates.
In each regulatory jurisdiction, the prices the Company may charge for utility services (other than certain wholesale sales and specially negotiated retail rates for industrial or large commercial customers) are determined on a "cost of service" basis and are designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return on "rate base" or assets employed in the business. "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. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirements of utility plant from service.
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. See "Properties - Electric Properties" for additional information. These provisions include payment for headwater
THE WASHINGTON WATER POWER COMPANY
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.
General Rate Cases
The Company does not currently plan to file for any general electric rate increases in 1994. The following table summarizes information for the Company's most recent general electric rate cases:
(1) Anticipated annual revenue effect. (2) Through June 30, 1994, the IPUC has approved a power cost adjustment (PCA) mechanism
Integrated Resource Planning (IRP) IRP is a process required by both the WUTC and IPUC and represents the Company's responsibility to meet customer demand for reliable energy services at the lowest total cost to both the Company and its customers. The process entails (1) the forecasting of future energy needs, (2) the assessment of energy supplies, conservation options, customer costs, and social and environmental impacts and (3) the development of action plans which support a least cost resource strategy. The Company's need for future electric resources to serve retail loads is very minimal. The electric integrated resource plan accepted by both the IPUC and the WUTC in 1993 showed that, through the year 1998, the Company's additional electric load requirements will be met for the most part by a combination of demand side management, including conversions to natural gas, and the redevelopment of existing hydro generating plants. The cost of these resources is generally competitive with the costs of resources being developed by independent power producers.
Demand Side Management (DSM) Energy efficiency programs, which include residential space and water heat conversion programs, are material components of the Company's long-term resource strategy. In 1992 the Company filed a request with both the WUTC and IPUC for approval of new electric DSM tariffs which would provide for the implementation of new and revised energy efficiency programs including the "Energy Exchanger" program, which offers incentives to the Company's electric space and/or hot water heating customers to convert to natural gas. In conjunction with the request for tariff approval, DSM accounting treatment was requested which would allow the Company to defer the costs in new program investments until the next general rate case. With only minor modifications, the applications were approved and the effective dates for implementation were May 1 and July 17, 1992 in Washington and Idaho, respectively. Reductions in the DSM incentives were approved by both the IPUC and WUTC in 1993. Justification will be required for continuation of the programs beyond December 31, 1994. Approximately 18 aMW were saved in 1993 under these programs and over 23 aMW have been saved since the program's inception.
Power Cost Adjustment (PCA) The Company's PCA surcharge of $2.3 million in Idaho expired on November 1, 1993. The current balance in the account has not yet triggered either a surcharge or a refund. In June 1993 the IPUC approved an extension of the PCA to June 30, 1994. See Note 1 to Financial Statements for additional details.
THE WASHINGTON WATER POWER COMPANY
ELECTRIC OPERATING STATISTICS
(1) Includes firm contract obligations of 485 MW, 462 MW and 323 MW and 120 MW, 63 MW and 247 MW of non-firm sales in 1993, 1992 and 1991, respectively.
(2) Includes firm contract obligations of 610 MW, 468 MW and 474 MW in 1993, 1992 and 1991, respectively; 1991 results do not include 150 MW for non-firm sales. There were no non-firm sales in 1993 or 1992 during the summer system peak period.
THE WASHINGTON WATER POWER COMPANY
NATURAL GAS SERVICE
NATURAL GAS COMPETITION AND BUSINESS OVERVIEW
Natural gas is priced competitively compared to other alternative fuel sources for both residential and commercial customers. The Company provides programs that encourage electric customers to convert to natural gas. Significant growth has occurred in the Company's natural gas business in recent years due to these conversions. The Company also makes sales or provides transportation service directly to large natural gas customers.
Challenges facing the Company's natural gas business include the potential for customers to by-pass the Company and securing competitively priced natural gas supplies for the future. Since 1988 one of the Company's large industrial customers has built its own pipeline interconnection. However, this customer still purchases some natural gas services from the Company. 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 to assist in retaining potential by-pass customers. The Company has signed long-term transportation contracts with two of its largest industrial customers which minimizes the chances of these customers by-passing the Company's system.
Order 636B adopted by FERC in 1992 provides the Company more flexibility in optimizing its natural gas transportation and supply portfolios. 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.
NATURAL GAS SYSTEM
The Company's natural gas operations are operated as separate divisions, with the WWP service territory including the Washington and Idaho properties and the WPNG service territory including Oregon and California properties.
Natural Gas Supply The Company has access to four natural gas pipelines, Northwest Pipeline Company (NWP), Pacific Gas Transmission (PGT), Paiute Pipeline (Paiute) and Alberta Natural Gas Co. Ltd. (ANG), which provide the Company access to both domestic and Canadian natural gas supplies. Due to this resource portfolio, the Company remains one of the nation's lowest-cost local distribution companies. Both WWP and WPNG contract with (1) NWP for three types of firm service: transportation, liquefied natural gas storage and underground storage and (2) PGT and ANG for firm transportation. WPNG also contracts with Paiute for firm transportation and liquefied natural gas storage to deliver natural gas to its California customers.
Firm winter natural gas supplies are purchased by the Company through negotiated agreements having terms ranging between one month and eleven years with a variety of natural gas suppliers. As a result of FERC Order 636B, WWP has completed the process of converting its NWP natural gas sales to firm transportation and assuming its share of NWP's natural gas supply contracts.
In January 1993, the Company contracted with ANG, PGT, NWP and Paiute for additional transportation capacity to be available by November 1995 for service in the Oregon and California service territory of WPNG. The Company has also contracted with PGT and ANG for additional capacity for service beginning in 1995 for its Washington and Idaho properties.
Jackson Prairie Natural Gas Storage Project (Storage Project) The Company retains a one-third ownership interest in the Storage Project, which is an underground natural gas storage field located near Chehalis, Washington. Under FERC's open access policy the role of the Storage Project in providing flexible natural gas supplies is increasingly important to the Company's natural gas operations. The Storage Project enables the Company to place natural gas into storage when prices are low or to meet minimum natural gas purchasing requirements, as well as to withdraw natural gas from storage when spot prices are high or as needed to meet high demand periods. The Company has released some of its Storage Project capacity to two other utilities until 1995 and 1996 with a provision under one of the releases to partially recall the released capacity if the Company determines additional natural gas is required for its own system supply.
Natural Gas Transportation Services 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 1993. 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 197.5 million therms in 1993. This total volume represented approximately 40% of the Company's total system deliveries in 1993.
THE WASHINGTON WATER POWER COMPANY
NATURAL GAS REGULATORY ISSUES
The Company, as a public utility, is currently subject to regulation by several state utility commissions with respect to rates, accounting, the issuance of securities and other matters. The natural gas operations are subject to the jurisdiction of the WUTC, IPUC, OPUC and CPUC in addition to the FERC with respect to natural gas rates charged for the release of capacity from the Storage Project. Refer to Electric Regulatory Issues for additional details regarding the rate setting process.
General Rate Cases
The Company has no current plans to file for any natural gas general rate cases in 1994. The following table summarizes information for the Company's most recent general natural gas rate cases (1):
(1) In addition, the Company from time to time, upon request, receives regulatory approval from the WUTC, the IPUC, the OPUC and the CPUC to adjust rates to reflect changes in the cost of purchased natural gas between general rate cases. (2) Anticipated annual revenue effect.
In September 1991, the Company commenced operations in both California and Oregon upon the acquisition of the natural gas properties of CP National. The conditions of the CPUC order approving the acquisition included an exemption from filing a general rate case until January 1, 1994 and a rate "freeze" until January 1, 1995. On October 20, 1993, the CPUC granted a one year extension to January 1, 1995 before the Company is required to file a general rate case. As a result, the existing rate "freeze" will continue until at least January 1, 1996. The OPUC also authorized a general rate "freeze" which extends to December 31, 1995. Purchased natural gas costs will continue to be tracked through to customers in both jurisdictions during the rate "freeze" period.
Integrated Resource Planning (IRP) In 1993 biannual natural gas IRP reports were accepted by both the WUTC and OPUC. Refer to Electric Regulatory Issues for a description of the IRP process.
Demand Side Management (DSM) Included with the WUTC and IPUC electric DSM applications discussed above under Electric Regulatory Issues, the Company requested approval of new natural gas tariffs which would provide for the implementation of new and revised energy efficiency programs for the Company's residential, commercial and industrial natural gas customers. In conjunction with the request for tariff approval, the Company requested approval of associated natural gas DSM accounting treatment. With only minor modifications, the applications were approved. The effective dates for implementation were May 1 and July 17, 1992 in Washington and Idaho, respectively, with revisions made in July 1993 and future justification required for continuance of programs beyond December 31, 1994.
On December 21, 1993, the OPUC authorized the Company to defer revenue requirement amounts associated with its WPNG DSM investments, and established an annual rate adjustment mechanism to reflect the deferred costs on a timely basis. Under this authorization, each December 1 the Company will file a rate adjustment to recover DSM program costs and margin losses. This filing will be concurrent with the Company's annual natural gas tracker filing. The effective date for both the deferrals and the rate adjustment mechanism was January 1, 1994.
Natural Gas Trackers In the second quarter of 1993, the Company filed special natural gas trackers with the WUTC, IPUC, OPUC and CPUC due primarily to the increased costs from the pipelines related to the implementation of FERC Order 636B. The increases range from 3% to 25% but will result in no additional net income to the Company. The trackers were approved by all four state commissions.
In a separate proceeding, the annual Oregon natural gas tracker became effective on December 1, 1993. The tracker will increase overall revenue by about $3.1 million or 8.74% in Oregon but will result in no additional net income to the Company as it is only a passthrough of changes in the cost of purchased natural gas and amortization rates pursuant to the Company's natural gas tracker. The filing also included the acquisition of additional capacity over the PGT system.
THE WASHINGTON WATER POWER COMPANY
NATURAL GAS OPERATING STATISTICS
(1) Includes WPNG results from September 30 to December 31 except where otherwise noted; includes a three-month average of WPNG customers and a twelve-month average of WWP customers.
THE WASHINGTON WATER POWER COMPANY
ENVIRONMENTAL MATTERS
The Company is subject to environmental regulation by federal, state and local authorities. The generation, transmission, distribution, service and storage facilities in which the Company has an ownership interest have been designed to comply with all environmental laws presently applicable.
The Company was named a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 ("CERCLA" or "Superfund") at the Coal Creek site in Chehalis, Washington. The estimated cost of clean-up is $12,000,000, which is being shared by over 90 utilities. The Company is responsible for approximately $800,000 of this cost, the majority of which was spent in 1993.
In 1993 the EPA referred a matter to the U.S. Justice Department requesting the Company and other potentially responsible parties to enter into negotiations for the recovery of costs incurred by EPA and for initiation of action in connection with the clean-up at the Spokane Junk Yard Site located in Spokane, Washington. If an action is commenced, the claim is expected to be for $2.4 million in site stabilization costs plus additional costs including attorneys' fees and site rehabilitation costs. The Company has no records showing that any Company equipment was ever deposited at the Spokane Junk Yard Site or that PCB contaminated equipment was delivered to any company which disposed of materials at the site. Therefore, the Company has disclaimed any liability with respect to the Spokane Junk Yard Site. If an action is commenced, the Company will vigorously defend against such claim.
Refer to both Note 11 to Financial Statements: Commitments and Contingencies and Significant Trends in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations for additional information.
NON-UTILITY BUSINESS
As of December 31, 1993, the Company had an investment of approximately $93 million in non-utility operations, of which about $86 million was invested in Pentzer. The remainder was invested in three non-operating subsidiaries, the largest of which is WIDCo, which maintains a small investment portfolio. Substantially all of the non-utility operations are controlled by Pentzer, a wholly owned subsidiary of the Company.
As of December 31, 1993, Pentzer had approximately $130 million in total assets, or about 7% of the Company's consolidated assets. Pentzer's portfolio of investments includes companies involved in advertising display manufacturing, electronic technology, energy services, financial services, real estate development and telecommunications.
Pentzer's current investment profile focuses on manufacturers and distributors of industrial and consumer products as well as service businesses. The Company seeks businesses with above average records of earnings growth in industries that are not cyclical or dependent upon high levels of research and development. Emphasis is placed on leading companies with strong market franchises, dominant or proprietary product lines or other significant competitive advantages. Pentzer is particularly interested in companies serving niche markets. Total investment in any one company is generally limited to $15 million, and control of the acquired company's board of directors is generally required.
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 that of the utility 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.
THE WASHINGTON WATER POWER COMPANY
ITEM 2.



ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The Company's electric 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 rating under specified conditions. (2) Capability is the maximum generation of the plant without exceeding approved limits of temperature, stress and environmental conditions. (3) Due to the redevelopment project which was started during 1993, the actual plant capability at year end declined from 18 MW; upon completion of this project in mid-1994, the plant capability is expected to rise to 29 MW. (4) Reduced from 13 MW due to possible penstock enlargement; if completed, the plant capability is expected to return to 13 MW. (5) Due to the upgrade project started during 1993 on unit no. 1, the actual plant capability at year end declined from 230 MW; upon completion of this project in mid-1994, the plant capability is expected to rise to 240 MW. (6) Jointly-owned. Data above refers to Company's respective 15% interests. (7) Used primarily for peaking needs.
Distribution and Transmission Plant
The Company operates approximately 11,250 miles of distribution lines in its electric system. The Company's transmission system consists of approximately 550 miles of 230 KV line and 1,500 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 BPA interconnections.
The 230 KV lines are used primarily to transmit power from the Company's Noxon Rapids and Cabinet Gorge hydro 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
THE WASHINGTON WATER POWER COMPANY
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' hydro generating stations.
The 115 KV lines provide for transmission of energy as well as providing for the integration of the Spokane River hydro and Kettle Falls wood-waste generating stations with service area load centers. These lines interconnect with BPA at nine locations, Grant County PUD at three locations, Seattle City Light and Tacoma City Light at two locations and one each with Chelan County PUD, PacifiCorp, and Montana Power.
Electric Projects Under Construction
Rathdrum Combustion Turbine On October 5, 1993, the IPUC issued an order approving the combustion turbine project consisting of two 88 MW units. Construction has begun on the project, which is designed to meet the Company's peaking needs for both its retail and wholesale obligations. The air quality permit that has been issued, which allows for the operation of the project as scheduled, has been challenged and is currently under administrative review. Natural gas will be used as both the primary and back-up fuel. The Company has obtained separate construction and long-term lease financing for this project. The project is currently expected to be completed by early 1995 at an expected cost of $66 million, of which $29 million had been spent as of December 31, 1993.
Company Hydro The Company continues to study its hydroelectric facilities on both the Spokane and Clark Fork Rivers to identify additional economic hydroelectric generating potential. Turbine efficiency improvements are underway at the Nine Mile project that would increase generating capacity by 12 MW to a total of 29 MW by mid-1994 at an expected cost of $20 million. Similar improvements are underway at the Cabinet Gorge powerhouse that would increase capacity by approximately 10 MW to a total of 240 MW at an expected cost of $12 million; it is expected back on-line by the end of the first quarter 1994. Feasibility studies for upgrading the Company's other hydroelectric facilities are continuing.
Proposed Acquisition
On February 15, 1994, the Company announced it had reached agreement to acquire the northern Idaho electric properties of Pacific Power and Light Company, an operating division of PacifiCorp. The cash purchase price will be $26 million, subject to closing adjustments, and includes a premium above the book value of the net assets acquired. Pacific Power's northern Idaho electric system currently serves approximately 9,300 residential, commercial and industrial customers. The purchase is subject to regulatory approval by the IPUC and the FERC. Closing of the transaction is expected to occur during the summer of 1994. See Note 14 to Financial Statements for additional information related to this acquisition.
NATURAL GAS PROPERTIES
The WWP and WPNG service territories' natural gas properties have natural gas distribution mains of approximately 2,912 miles and 1,410 miles, respectively.
The Company, NWP and Washington Natural Gas Company each own a one-third undivided interest in the Storage Project. The Storage Project has a total peak day deliverability of 4.6 million therms, with a total working natural gas inventory of 155.2 million therms.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
Refer to Note 11 to Financial Statements: Commitments and Contingencies.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
THE WASHINGTON WATER POWER COMPANY
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 25, 1994, there were approximately 36,000 registered shareholders of the Company's no par value Common Stock.
It is the intention of the Board of Directors to continue to pay dividends quarterly on the Common Stock, but the amount of such dividends is dependent on future earnings, the financial position of the Company and other factors.
For further information, see Notes 8 and 15 to Financial Statements.
THE WASHINGTON WATER POWER COMPANY
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.
In 1992, Pentzer's common stock ownership in ITRON was reduced from approximately 60% to approximately 40% as a result of the issuance of common stock by ITRON in an acquisition. Accordingly, beginning in 1992, Pentzer's share of ITRON's earnings is accounted for by the equity method and is included in Other Income-Net and its investment in ITRON is reflected on the balance sheet under Other Property and Investments. ITRON's initial public offering in November 1993 and Pentzer's sale of a portion of its ITRON stock resulted in a reduction in Pentzer's ownership interest in ITRON to approximately 25%.
The Company purchased natural gas distribution properties in Oregon and California from CP National Corporation on September 30, 1991. The 1991 financial information reflects three months of operations of these properties.
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.
(Thousands of Dollars except Per Share Data and Ratios)
THE WASHINGTON WATER POWER COMPANY
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Company is primarily engaged as a utility in the generation, purchase, transmission, distribution and sale of electric energy and the purchase, transportation, distribution and sale of natural gas. Natural gas operations are affected to a significant degree by weather conditions and customer growth. The Company's electric operations are highly dependent upon hydroelectric generation for its power supply. As a result, the electric operations of the Company are significantly affected by weather and streamflow conditions and, to a lesser degree, by customer growth. Revenues from the sale of surplus energy to other utilities and the cost of power purchases vary from year to year depending on streamflow conditions and the wholesale power market. The wholesale power market in the Northwest region 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 from the Southwest region. 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 and conservation.
The Company will continue to emphasize the efficient use of energy by its customers, increase efforts to grow its customer base, especially natural gas, and continue to manage its operating costs, increase revenues and improve margins. The Company will also pursue resource opportunities through demand side management, system upgrades, purchases and other options that will result in obtaining electric power and natural gas supplies at the lowest possible cost.
The Company purchased natural gas distribution properties in Oregon and California from CP National Corporation on September 30, 1991. The 1991 financial statements reflect three months of operations of these properties. See Note 14 to Financial Statements for further information.
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.
RESULTS OF OPERATIONS
OVERALL OPERATIONS
Overall earnings per share for 1993 were $1.44, compared to $1.37 in 1992 and $1.34 in 1991. The 1993 results include transactional gains totaling $12.8 million recorded by Pentzer Corporation (Pentzer) as a result of the sale of several investments in its portfolio and the sale of stock in the initial public offering by ITRON, Inc. (ITRON) in November 1993. The 1992 results include an after-tax gain of $4.4 million, or $0.09 per share, due to the issuance of common stock by ITRON in an acquisition and a transactional gain of $1.2 million due to the sale of Pentzer's interest in a company involved in power plant maintenance. Discontinued coal mining operations contributed $2.4 million to net income, or $0.05 per share, in 1992 and $1.6 million, or $0.03 per share, in 1991.
Earnings per share from continuing operations were $1.44 for 1993, $1.32 for 1992 and $1.31 for 1991. Utility income available for common stock increased $4.0 million, or 7.0%, in 1993 after decreasing $2.8 million, or 4.6%, in 1992. Utility income available for common stock contributed $1.19 to earnings per share in 1993, compared to $1.15 in 1992 and $1.28 in 1991. Non-utility income available for common stock from continuing operations increased $5.0 million in 1993 and $6.9 million in 1992 and contributed $0.25 to earnings per share in 1993, compared to $0.17 in 1992 and $0.03 in 1991.
Slightly colder-than-normal weather during 1993 impacted both electric and natural gas operations as compared to 1992. Income from electric operations decreased $1.8 million in 1993, as compared to 1992, primarily as a result of increases in purchased power costs due to thermal plant outages, a large sale of wholesale energy and lower hydroelectric generation due to below normal streamflows, and increases in other operating and maintenance expenses. Income from natural gas operations increased $9.3 million in 1993 over 1992 due primarily to increased customer usage from the colder weather and customer growth. Warmer-than-normal weather throughout most of 1992 significantly impacted both electric and natural gas operations during the year. Increased purchased power and fuel costs, due to low hydroelectric generation and reduced streamflows, combined with decreased customer usage, were responsible for a decrease of $10.2 million in 1992 income from electric operations as compared to 1991. Income from natural gas operations decreased $2.3 million in 1992, as compared to 1991, due primarily to reduced revenues as a result of the warmer-than-normal temperatures.
THE WASHINGTON WATER POWER COMPANY
Electric revenues and expenses were both impacted by a ten-year power purchase contract, effective January 1992, with Potlatch Corporation (Potlatch), one of the Company's major industrial customers. Under terms of the agreement, the Company purchases 50-55 average MW of Potlatch's electric generation and makes available up to approximately 95 average MW of firm energy for sale. In addition, the Company makes available 25 average MW of interruptible energy and Potlatch must provide an equivalent amount of reserve generation capacity in case of interruption. The increased KWH sales to Potlatch result in increased industrial revenues to the Company, while the purchase of Potlatch's generating output increases purchased power expense.
Non-recurring adjustments were made in 1991 to establish reserves for potential write-offs related to the recovery of costs associated with the Creston Project, a proposed 2,000 MW coal-fired generating station located near Creston, Washington, and related transmission. The reserves were calculated assuming regulators would allow the Company to recover its investment, but would not allow the Company to earn a return on the investment during a recovery period. Through December 31, 1993, the Company had invested $11.0 million in the Creston Project. These adjustments decreased Other Income net of taxes in 1991 by $3.2 million. A non-recurring adjustment was also made during 1991 to adjust previous accruals of deferred federal income tax related to electric operations. This adjustment decreased income taxes by $4.0 million in 1991.
Interest expense decreased $3.4 million in 1993 and $1.0 million in 1992. From 1991 through 1993, $69 million of long-term debt matured and $344 million of higher-cost debt was redeemed and refinanced at lower interest rates.
Preferred stock dividend requirements increased $1.5 million, or 22.3%, in 1993 due to the issuance of preferred stock in late 1992. Preferred stock dividend requirements decreased $2.5 million, or 26.6%, in 1992. The redemption of preferred stock in early 1992, combined with an issuance later in the year at a lower dividend rate and lower rates on variable rate preferred stock were the primary reasons for the 1992 decrease.
UTILITY OPERATIONS
Electric Operating Income Summary
(1) Does not include interest expense or other income.
Electric revenues increased in all classes for 1993, as compared to 1992, as a result of customer growth, increased wholesale sales and a slight increase in customer usage due to colder than normal weather. As the Company's Demand Side Management programs grow, the electric load is becoming less weather-sensitive as a result of the shifting of a greater portion of the heat load to natural gas. Residential and commercial revenues increased by $12.8 million, primarily as a result of a 3% growth in customers in 1993. Industrial sales during 1993 increased by $6.2 million, or 12%, primarily due to increased KWH sales under the Potlatch agreement discussed earlier. Wholesale revenues increased by $16.8 million, or 18%, due primarily to a large sale of wholesale energy over a six-week period in the first quarter of 1993.
THE WASHINGTON WATER POWER COMPANY
Electric revenues increased by 3% in 1992, compared to 1991, due to a combination of increased industrial sales and customer growth, which offset the decrease in residential usage due to warm weather. The Company's electric customer base grew by 2% in 1992, in both the residential and commercial sectors, which helped to reduce the weather-related impact on revenues. Industrial sales increased by $11.5 million, or 29%, primarily due to increased KWH sales under the Potlatch agreement discussed earlier. Commercial sales increased $4.7 million, or 4%, in 1992, as compared to 1991, due to customer growth. Residential revenues decreased by $3.1 million, despite a 2% increase in customers, due to warm weather throughout most of 1992. Wholesale KWH sales were down 23% in 1992, reflecting low streamflow conditions during the year. However, increased prices in the secondary market resulted in decreased wholesale revenues of only $0.6 million, or 1%, in 1992 from 1991.
Electric Revenues, KWH Sales, and Customers by Service Class
Below-normal streamflow conditions and thermal plant outages significantly affected 1993 electric operating results. Hydroelectric generation was 11% below normal, caused by streamflows which were 86% of normal. Purchased power increased by $27.1 million, or 30%, in 1993 primarily due to reduced hydroelectric generation early in the year, a large sale of wholesale energy in the first quarter and to replace lost thermal generation due to plant outages. In October 1989, the Idaho Public Utilities Commission (IPUC) approved the Company's filing for a Power Cost Adjustment (PCA) designed to allow the Company to change rates to recover or rebate a portion of the difference between actual and allowed net power supply costs. Net PCA adjustments accounted for $4.6 million of the increase in other operating and maintenance expenses from 1992. Higher levels of purchased power resulted in higher transmission costs which also contributed to the increase in other operating and maintenance expenses in 1993 over 1992. Shutdowns at thermal generation plants and improved streamflows in the latter part of 1993 were the primary reasons for the $2.9 million decrease in fuel costs, and repairs at the plants resulted in an increase of nearly $2.0 million in other operating and maintenance expenses.
Warmer-than-normal weather and below-normal streamflow conditions significantly affected 1992 electric operating results. Hydroelectric generation was 22% below normal, caused by streamflows which were 64% of normal in 1992. In 1991, streamflows were 116% of normal. Fuel costs and purchased power costs in 1992 were a combined $27.6 million, or 27%, over levels incurred during 1991, due to low hydroelectric generation and the Potlatch agreement previously discussed. Transmission and distribution costs, which decreased $2.2 million and $1.5 million, respectively, contributed to the $7.9 million, or 12%, decrease in other operating and maintenance expenses. Transmission expenses decreased in 1992 over 1991 due to decreased wholesale KWH sales. Distribution expense was lower in 1992, compared to 1991, due to mild weather and fewer storm-related damages. Net PCA adjustments, resulting from low hydroelectric conditions and prices of secondary energy, accounted for $3.3 million of the decrease in other operating and maintenance expenses from 1991.
THE WASHINGTON WATER POWER COMPANY
NATURAL GAS OPERATIONS
Natural Gas Operating Income Summary
(1) Does not include interest expense or other income.
On September 30, 1991, the Company purchased the Oregon and South Lake Tahoe, California, natural gas distribution assets of CP National Corporation. The Company's natural gas operations are operated as separate divisions, with the WWP service territory including the Washington and Idaho properties and the WP Natural Gas (WPNG) service territory including the Oregon and California properties. As of December 31, 1993, there were approximately 73,300 WPNG natural gas customers and 122,500 WWP natural gas customers.
The Company's natural gas business experienced weather-related impacts on operating results in both 1993 and 1992. In 1993, weather in the Washington and Idaho service territory was 5% colder than normal, compared to 11% warmer than normal in 1992. The Oregon service territory experienced temperatures only 8% warmer than normal in 1993, compared to 24% warmer in 1992. Substantial customer growth of 9% in 1993, along with colder weather, contributed to increased revenues. The 7% growth in customers in 1992 helped offset the impact of the weather.
Total natural gas operating revenues increased $37.0 million, or 37%, in 1993. WPNG revenues accounted for an increase of $10.1 million, while WWP revenues increased $26.9 million. Total therm sales increased by 18% in 1993 due to customer growth in all service classes except transportation and higher customer usage due to colder weather in 1993 as compared to 1992. Approximately 40% of the customer growth in the WWP service area during 1993 was the result of the Company's emphasis on conversion from electric space and water heating to natural gas through Demand Side Management programs.
Total natural gas revenues increased in all customer classes in 1992 from 1991 due to the WPNG acquisition. WPNG revenues accounted for an increase of $24.5 million in overall natural gas operating revenues, as compared to 1991. In 1992, natural gas revenues from WWP residential and commercial customers rose by $2.0 million and $0.5 million, respectively, due to growth in the number of customers, as usage per customer decreased as a result of warm temperatures.
THE WASHINGTON WATER POWER COMPANY
Natural Gas Revenues, Therm Sales, and Customers by Service Class
Natural gas purchased expense increased $23.7 million, or 49%, in 1993 as compared to 1992, primarily as a result of an increase in therm sales of 76.3 million, or 18%, across all customer classes due to customer growth and colder weather. Taxes other than income and income taxes also increased substantially in 1993 due to increased revenues and income.
Natural gas purchased expense and other operating and maintenance expenses increased $17.4 million and $5.1 million, respectively, in 1992 from 1991. All other expenses also increased substantially over 1991, primarily as a result of the operation of the WPNG properties, combined with the Company's continued emphasis on conversions from electric energy to natural gas.
NON-UTILITY OPERATIONS
Non-Utility Operations Summary
Non-utility operations include the results of Pentzer and three non-operating subsidiary companies. 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 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 that of the utility 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.
THE WASHINGTON WATER POWER COMPANY
For the year ended December 31, 1993, Pentzer had consolidated earnings of $19.7 million before provision for possible losses. At the end of the year, Pentzer established a $7.0 million provision for possible write-off of a portion of its investment portfolio. The provision was recorded based on the determination that future cashflows may be lower than expected, impairing the value of certain investments. After deducting this provision, Pentzer reported consolidated earnings of $12.7 million, which represents a 50% increase over Pentzer's 1992 earnings of $8.5 million. Pentzer's return on invested capital increased from 12% in 1992 to 17% in 1993 due, in part, to transactional gains.
Pentzer earnings for 1993 were significantly impacted by transactional gains of $7.1 million as a result of the sale of companies involved in telecommunications, technology and energy and by a transactional gain of $5.7 million resulting from the successful completion by ITRON, a company in which Pentzer is the largest shareholder, of an initial public offering which also resulted in the sale of a portion of the ITRON shares owned by Pentzer. This transaction reduced Pentzer's investment in ITRON from approximately 40% to approximately 25%. Included in other income, total 1993 transactional gains of $12.8 million compares with transactional gains of $5.6 million in 1992.
In addition to the transactional gains from ITRON in 1993, Pentzer also recorded a $3.0 million increase in net income as a result of improved earnings at ITRON.
Pentzer's earnings increase from 1991 to 1992 was primarily attributable to the 1992 transactional gains of $5.6 million relating to ITRON's issuance of common stock in an acquisition and the sale of Pentzer's interest in a company involved in power plant maintenance. This issuance of common stock reduced Pentzer's ownership from approximately 60% to approximately 40%. Accordingly, Pentzer's investment in ITRON after 1991 is accounted for by the equity method. The 1991 results presented include ITRON on a fully consolidated basis. The decrease in revenues and expenses from 1991 to 1992 was primarily due to the change to the equity method of accounting for ITRON.
THE WASHINGTON WATER POWER COMPANY
LIQUIDITY AND CAPITAL RESOURCES
UTILITY
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 $378 million for the 1991-1993 period. In addition, $69 million of long-term debt matured and $344 million of higher-cost debt and preferred stock was redeemed and refinanced at lower cost during the 1991-1993 period.
Capital expenditures are funded with internally-generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates from year to year.
During 1993, $274 million of long-term debt, with an average interest rate of 8.67% and 13.6 years remaining to maturity, was redeemed or matured and $250 million of long-term debt was issued at an average interest rate of 6.59% and with 16.1 years remaining to maturity. In January 1994, authorization was received for $250 million of Secured Medium Term Notes, Series B, which brings the total authorized but unissued Secured Medium Term Notes to $275 million as of February 28, 1994.
Capital expenditures are financed on an interim basis with short-term debt. The Company has $160 million in committed lines of credit, a portion of which backs up a $50 million commercial paper facility. In addition, the Company may borrow up to $60 million through other borrowing arrangements with banks. As of December 31, 1993, $20 million in commercial paper was outstanding, $4 million was outstanding under the committed lines of credit and $44 million was outstanding under other short-term borrowing arrangements.
The Company's total common equity increased by $47 million to $634 million at the end of 1993. The 1993 increase was primarily due to the issuance of approximately 1,900,000 shares of common stock through the Periodic Offering Program, the Dividend Reinvestment Plan and the Investment and Employee Stock Ownership Plan for proceeds of $36 million. The utility capital structure at December 31, 1993, was 49% debt, 10% preferred stock and 41% common equity as compared to 48% debt, 11% preferred stock and 41% common equity at year-end 1992.
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 $431 million of First Mortgage Bonds could be issued as of December 31, 1993. As of December 31, 1993, under its Restated Articles of Incorporation, approximately $670 million of additional preferred stock could be issued at an assumed dividend rate of 7.00%.
During the 1994-1996 period, capital expenditures are expected to be $334 million, and $90 million will be required for long-term debt maturities and preferred stock sinking fund requirements. During this three-year period, the Company expects that internally- generated funds will provide approximately 50% of the funds for its capital expenditures. External financing will be required to fund maturing long-term debt, preferred stock sinking fund requirements and the remaining portion of capital expenditures.
See Notes 4 through 8 to Financial Statements, inclusive, for additional details related to financing activities.
NON-UTILITY
Capital expenditures for the non-utility operations were $15 million for the 1991-1993 period. These capital expenditure requirements were financed primarily with internally-generated funds. In addition, $2 million of debt either matured or was redeemed during that same period. The non-utility operations have $26 million in borrowing arrangements ($20 million outstanding as of December 31, 1993) to fund capital expenditures and other corporate requirements on an interim basis. At December 31, 1993, the non-utility operations had $32 million in cash and marketable securities.
The 1994-1996 non-utility capital expenditures are expected to be $8 million, and $1 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-utility capital expenditure requirements.
THE WASHINGTON WATER POWER COMPANY
TOTAL COMPANY CASH REQUIREMENTS (Millions of Dollars)
(1) Excludes $66 million for the combustion turbine project under construction in Rathdrum, Idaho; the Company has obtained separate construction and long-term lease financing for this project. Also excludes $26 million for the proposed acquisition of the northern Idaho electric properties of Pacific Power and Light, an operating division of PacifiCorp; see Note 14 to Financial Statements for additional information related to this proposed acquisition. (2) Excludes AFUDC and AFUCE. (3) Demand Side Management programs. (4) Includes $68 million for the acquisition of the CP National Corporation's natural gas distribution properties in Oregon and California.
SIGNIFICANT TRENDS
Competition
The electric and natural gas utility businesses are undergoing numerous changes and are becoming 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, experience in the wholesale electric market and its commitment to high levels of customer satisfaction, cost reduction and continuous improvement of work processes.
The Company currently competes for new retail electric customers with various rural electric cooperatives and public utility districts. Challenges facing the electric retail business include changing technologies which reduce energy consumption, self-generation and fuel switching by industrial and other large retail customers, the potential for retail wheeling and the costs of increasingly stringent environmental laws. In addition, if electric utility companies are eventually required to provide retail wheeling service, which is the transmission by an electric utility 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.
The Company also competes in the wholesale electric market with other Western utilities, including the Bonneville Power Administration. Challenges facing the electric wholesale business include new entrants in the wholesale market and competition from lower cost generation being developed by independent power producers.
The National Energy Policy Act (NEPA) enacted in 1992 addresses a wide range of issues affecting the wholesale electric business. The Company believes NEPA provides future transmission, energy production and sales opportunities to the Company and complements the Company's commitment to the wholesale electric business.
Natural gas is priced competitively compared to other alternative fuel sources for both residential and commercial customers. Challenges facing the Company's natural gas business include the potential for customers to by-pass the Company and securing competitively priced natural gas supplies for the future. Since 1988 one of the Company's large industrial customers has built its own pipeline interconnection. However, this customer still purchases some
THE WASHINGTON WATER POWER COMPANY
natural gas services from the Company. 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 to assist in retaining potential by-pass customers. The Company has signed long-term transportation contracts with two of its largest industrial customers which minimizes the risks of these customers by-passing the Company's system.
Order 636B adopted by FERC in 1992 provides the Company more flexibility in optimizing its natural gas transportation and supply portfolios. 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.
Least cost 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 future electric resources to serve retail loads is very minimal. The electric integrated resource plan accepted by both the IPUC and the Washington Utility and Transportation Commission (WUTC) in 1993 showed that, through the year 1998, the Company's additional electric load requirements will be met for the most part by a combination of demand side management, including conversions to natural gas, and the redevelopment of existing hydro generating plants. The cost of these resources is generally less than costs of resources being developed by independent power producers and other exempt wholesale generators. The Company's natural gas integrated resource plan was accepted by both the WUTC and Public Utility Commission of Oregon (OPUC) in 1993 and insures adequate supplies of natural gas are available at the least possible cost. 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, although at a slower pace than seen in the past couple of years. The Company, along with others in the service area, continues its efforts to expand existing businesses and attract new businesses to the Inland Northwest. In the past, agriculture, mining and lumber have been the primary industries. However, health care, electronic and other manufacturing, tourism and the service sectors have become increasingly important industries that operate in the Company's service area. In addition, the Company also expects economic growth to continue in its Oregon and California service areas.
The Company anticipates electric retail load growth to average approximately 0.4% annually for the next five years. Although the number of electric customers is expected to increase, the average annual usage by residential customers is expected to continue to decline on a weather-adjusted basis due to newer technologies, construction and appliance efficiency standards and continued conversions to natural gas where available. The Company anticipates natural gas load growth, including transportation volumes, in its Washington and Idaho service area to average approximately 2.7% annually for the next five years. The Oregon and South Lake Tahoe, California service area is anticipated to realize 2.6% growth annually during that same period.
Environmental Matters
The Company continues to assess both the potential and actual impact of the 1990 Clean Air Act Amendments (CAAA) on its thermal generating plants. The Centralia Power Plant (Centralia), which is operated by PacifiCorp, is classified as a "Phase II" coal-fired plant under the CAAA and as such, will be required to reduce sulfur dioxide (SO2) emissions by approximately 40% by the year 2000. Several methods to meet CAAA compliance by reducing SO2 are being evaluated and a plan is expected to be completed by early 1995. The alternatives most likely to be used in meeting the compliance standards will be some combination of lower sulfur coal, SO2 reduction through clean coal technology and SO2 allowances either purchased or pooled, if available, among the Centralia owners. The Colstrip Generating Project (Colstrip), which is also a "Phase II" coal-fired plant operated by Montana Power, is not expected to be required to implement any additional SO2 mitigation in the foreseeable future in order to continue operations. Reduction in nitrogen oxides (NOX) will be required at both Centralia and Colstrip prior to the year 2000. The anticipated costs for NOX compliance will have a minor economic impact on the Company.
THE WASHINGTON WATER POWER COMPANY
Since December 1991, a number of species of fish, 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 River sockeye 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 this operation. The reduction in generation is relatively small resulting in minimal economic impact on the Company. Future actions to save the Snake River salmon, Kootenai River white sturgeon and bull trout could further impact the Company's hydroelectric resources. However, it is unknown at this time what impact, if any, will occur from the processes discussed above on the Company's operations.
See Note 11 to Financial Statements for discussion of additional environmental matters.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Independent Auditor's Report and Financial Statements begin on page 24.
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 as of December 31, 1993 and 1992, 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, 1993. 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, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, 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 Notes 2 and 3 to the financial statements, the Company changed its methods of accounting for other post-employment benefits and income taxes effective January 1, 1993, to conform with Statements of Financial Accounting Standards No. 106 and 109.
Deloitte & Touche
Seattle, Washington January 28, 1994 (February 15, 1994 as to Note 14)
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.
THE WASHINGTON WATER POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEM OF ACCOUNTS The accounting records of The Washington Water Power Company (Company) 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.
BASIS OF REPORTING 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 12).
The financial statements are presented on a consolidated basis and, as such, include the assets, liabilities, revenues and expenses of the Company and its wholly owned subsidiaries, Pentzer Corporation (Pentzer), Washington Irrigation and Development Company (WIDCo), The Limestone Company and WP Finance Company. All material intercompany transactions that are not allowed recovery under regulation have been eliminated in the consolidation. On July 31, 1990, WIDCo sold its 50% interest in the Centralia coal mining properties for $40.8 million. As discussed in Note 14, operating results for ITRON are no longer consolidated and are accounted for on the equity method.
The financial activity of each of the Company's segments is reported in the "Schedule of Information by Business Segments." Such information is an integral part of these financial statements.
UTILITY PLANT The cost of additions to utility plant, including internally developed information systems, an allowance for funds used during construction and replacements of units of property and betterments, is capitalized. Maintenance and repairs of property and replacements determined to be less than units of property are charged to operating expenses. 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 (Interest Capitalized) 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 and Interest Capitalized (see Other Income below). 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 is placed in service.
The effective AFUDC rate was 10.67% in 1993, 1992 and 1991. The Company's AFUDC rates do not exceed the maximum allowable rates as determined in accordance with the requirements of regulatory authorities.
ALLOWANCE FOR FUNDS USED TO CONSERVE ENERGY The Allowance for Funds Used to Conserve Energy (AFUCE) rate recovers carrying costs associated with Demand Side Management (DSM) program expenditures until such investment is included in rate base. AFUCE is capitalized as a part of the cost of the DSM investment and is credited currently as a noncash item to Other Income and Interest Capitalized. The AFUCE rate in effect is the last authorized, or otherwise stipulated, rate of return from the Company's proceeding for natural gas or electric operations. The rate for Washington is adjusted for the tax effect of interest. Cash inflow related to AFUCE does not occur until the related DSM investment is placed in service.
DEPRECIATION For utility operations, depreciation provisions are computed by a method of depreciation accounting utilizing unit rates for hydroelectric plants and composite rates for other properties. Such rates are designed to provide for retirements of properties at the expiration of their service lives. The rates for hydroelectric plants include annuity and interest components, in which the interest component is 6%. For utility operations, the ratio of depreciation provisions to average depreciable property was 2.68% in 1993, 2.37% in 1992 and 2.44% in 1991.
THE WASHINGTON WATER POWER COMPANY
AMORTIZATION Deferred charges include regulatory assets which are amortized primarily over periods allowed by regulators. Also included in Deferred Charges, Other are debt issuance and redemption costs which are amortized over the terms of the respective debt issues.
POWER AND NATURAL GAS COST ADJUSTMENT PROVISIONS In 1989, the Idaho Public Utilities Commission (IPUC) approved the Company's filing for a power cost adjustment mechanism (PCA). The PCA is designed to allow the Company to change electric rates to recover or rebate a portion of the difference between actual and allowed net power supply costs. In 1993 and 1991, the Company deferred $4.6 million and $1.8 million, respectively, of net power supply cost savings, which resulted in like increases in electric operating expenses. In 1992, the Company deferred $3.3 million of net power supply costs, which resulted in like decreases in electric operating expenses. Rate changes are triggered when the deferred balance reaches $2.2 million. A rate increase was implemented in November 1992 to pass through accumulated costs. A rate reduction was implemented in May 1991 to pass through accumulated cost savings. As of December 31, 1993, $0.6 million of costs not yet subject to a rate increase had accumulated in the PCA deferral account. The PCA is currently scheduled to end on June 30, 1994.
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.
OPERATING REVENUES The Company accrues estimated unbilled revenues for services provided through month-end.
INCOME TAXES Provisions for income taxes are based generally on income and expense as reported for financial statement purposes adjusted principally for the excess of tax depreciation over book depreciation.
Beginning with 1981 property additions, deferred income taxes are provided for the tax effect of Accelerated Cost Recovery System (ACRS) depreciation over straight-line depreciation. Investment tax credits (ITC) are amortized over the period established by regulators.
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 1990 return.
EARNINGS PER COMMON SHARE Earnings per common share have been computed based on the weighted average number of common shares outstanding during the period. 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.
CASH 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.
THE WASHINGTON WATER POWER COMPANY
OTHER INCOME--NET Other income-net is composed of the following items:
Non-recurring adjustments were made in 1991 to establish reserves for a potential write-off related to the recovery of costs associated with the Creston Project and related transmission. The reserves were calculated assuming regulators would not allow the Company to earn a return during a recovery period. These adjustments decreased other income by $4.8 million before income taxes and decreased income net of taxes by $3.2 million. The Company's costs of $10,990,000 less a reserve for a potential write-off of $3,967,000 related to this project as of December 31, 1993, are included in Other Deferred Charges on the Balance Sheet.
NEW ACCOUNTING STANDARDS
FAS No. 112, entitled "Employers' Accounting for Postemployment Benefits," was issued by the Financial Accounting Standards Board in November 1992 and is effective for fiscal years beginning after December 15, 1993. This Statement requires the accrual of the expected cost of providing benefits to former or inactive employees after employment but before retirement. It has been determined that the liabilities related to the Company's Long-Term Disability and Workers' Compensation programs are affected by this Statement. The Company does not expect FAS No. 112 to have a material effect on the Company's financial position or results of operations.
NOTE 2. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
Effective January 1, 1993, the Company adopted FAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." FAS No. 106 requires the Company to accrue the estimated cost of postretirement benefit payments during the years the employee provides services. The Company previously expensed the cost of these benefits, which are principally health care, as claims were incurred. FAS No. 106 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 has elected to amortize this obligation of approximately $39,600,000 over a period of twenty years. Income from continuing operations during 1993 was not changed by the implementation of this Statement.
The Company has received accounting orders from the Washington Utilities and Transportation Commission (WUTC) and the IPUC allowing the current deferral of expense accruals under this Statement as a regulatory asset for future recovery. At such time that rate recovery is requested and allowed, cumulative deferrals will be amortized over the remainder of the twenty-year amortization period. The Company expects to be able to recover the amortized amounts. Therefore, the Company's cash flows are not affected by implementation of this Statement.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. In 1993, 1992 and 1991, the Company recognized $1,250,000, $1,290,000 and $1,233,000, 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, 1993.
THE WASHINGTON WATER POWER COMPANY
Accumulated postretirement benefit obligation:
Net postretirement benefit cost for 1993 consisted of the following components:
The currently assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation is 12.0% for 1993, decreasing linearly each successive year until it reaches 6.0% in 1997. 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, 1993 and net postretirement health care cost by approximately $3,079,000. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.5%.
The Company has a pension plan covering substantially all of its regular full-time employees. Some 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.
Net pension credit for 1993, 1992 and 1991 is summarized as follows:
(1) The Company has received accounting orders from regulatory authorities requiring the Company to defer the difference between pension cost as determined under FAS 87 and that determined for ratemaking purposes.
THE WASHINGTON WATER POWER COMPANY
The funded status of the Plan and the pension liability at December 31, 1993, 1992 and 1991, are as follows:
NOTE 3. ACCOUNTING FOR INCOME TAXES
The Company adopted Statement of Financial Accounting Standards (FAS) No. 109, "Accounting for Income Taxes," effective January 1, 1993, which supersedes Accounting Principles Board Opinion 11 previously adopted by the Company. FAS No. 109 establishes revised financial accounting and reporting standards for the effects of income taxes.
As of January 1, 1993, the Company accrued net regulatory assets of $171,365,000 related to the probable recovery of FAS No. 109 deferred tax liabilities from customers through future rates. In the third quarter, the balance was adjusted to account for the 35% federal income tax rate, which brought the accrued net regulatory assets balance to $182,196,000. As such, the Company's adoption of FAS No. 109 has no effect on income for 1993. The regulatory assets and deferred tax liabilities are being amortized over the estimated remaining life of the associated assets.
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 tax effects of significant items comprising the Company's net deferred tax liability as of January 1, 1993, restated to reflect the 35% federal income tax rate, are as follows:
THE WASHINGTON WATER POWER COMPANY
The provision for income tax expense for 1993 was $42,503,000, of which $35,443,000 and $7,060,000 is current and deferred tax expense, respectively. The provision for income tax expense for 1992 was $41,330,000, of which $24,148,000 and $17,182,000 was current and deferred tax expense, respectively. The provision for income tax expense for 1991 was $38,086,000, of which $31,853,000 and $6,233,000 was current and deferred tax expense, respectively. The current and deferred effective tax rates are approximately the same during all periods.
NOTE 4. LONG-TERM DEBT
The annual sinking fund requirements and maturities for the next five years for First Mortgage Bonds and Medium-Term Notes outstanding at December 31, 1993 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 1993, 1992 and 1991, $25,000,000, $113,000,000 and $37,000,000, respectively, of unsecured Medium-Term Notes, Series A and B (Notes) were issued. At December 31, 1993, the Company had outstanding $250,000,000 of the Notes with maturities between 1 and 29 years and with interest rates varying between 5.50% and 9.58%.
As of December 31, 1993, the Company had authorization to issue up to $25,000,000 of the $250,000,000 originally authorized in aggregate principal amount of new First Mortgage Bonds issued in the form of Secured Medium-Term Notes, Series A (Secured MTNs). The Secured MTNs may be issued from time to time and may vary in term from 9 months to 30 years. At December 31, 1993, the Company had outstanding $225,000,000 of the Secured MTNs with maturities between 2 and 30 years and with interest rates varying between 4.72% and 7.54%. In January 1994, authorization was received for an additional $250,000,000 of Secured Medium-Term Notes, Series B, which may vary in term from 9 months to 40 years.
At December 31, 1993, the Company had $68,000,749 outstanding under borrowing arrangements which will be refinanced in 1994. See Note 5 for details of credit agreements.
Included in other long-term debt are the following items related to non-utility operations:
In accordance with FAS No. 107 "Disclosures About Fair Value of Financial Instruments," the fair value of the Company's long-term debt at December 31, 1993 and 1992 is estimated to be $690.0 million, or 107% of the carrying value, and $612.1 million, or 103% of the carrying value, respectively. These estimates are based on available market information and appropriate valuation methodologies.
THE WASHINGTON WATER POWER COMPANY
NOTE 5. BANK BORROWINGS AND COMMERCIAL PAPER
At December 31, 1993, the Company maintained total lines of credit with various banks under two separate credit agreements amounting to $160,000,000. The Company has a revolving line of credit expiring December 9, 1995, which provides a total credit commitment of $70,000,000. The second revolving credit agreement is composed of two tranches totaling $90,000,000. The one-year tranche is renewable each year through 1995 and provides for up to $50,000,000 of notes to be outstanding at any one time. The three-year tranche expires September 30, 1995, and provides for up to $40,000,000 of notes to be outstanding at any one time. The Company pays commitment fees of up to 1/5% 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.
Balances and interest rates of bank borrowings under these arrangements were as follows:
Non-utility operations have $26 million of credit arrangements available. At December 31, 1993, 1992 and 1991, $19.7 million, $7.8 million and $9.3 million, respectively, were outstanding.
NOTE 6. ACCOUNTS RECEIVABLE SALE
The Company has entered into an agreement whereby it can sell, 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, 1993 and 1992, $40,000,000 in receivables had been sold pursuant to the agreement.
THE WASHINGTON WATER POWER COMPANY
NOTE 7. 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 1993, the dividend rate varied from 3.00% to 3.27% and at December 31, 1993, was 3.14%. 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, 1996, 1997, 1998, 1999 and 2000, 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 1994-1998 period.
In accordance with FAS No. 107 "Disclosures About Fair Value of Financial Instruments," the fair value of the Company's preferred stock at December 31, 1993 and 1992 is estimated to be $93.8 million, or 110% of the carrying value, and $89.4 million, or 105% of the carrying value, respectively. These estimates are based on available market information and appropriate valuation methodologies.
NOTE 8. COMMON STOCK
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.
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 ($12,755,500 at December 31, 1993) 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 1993, the cost recorded for the Plan was $2,216,000. This included the cost for an additional 165,335 shares which were issued for ongoing employee and Company contributions to the Plan. Interest on the note payable, cash and stock contributions to the Plan and dividends on the shares held by the Trustee were $1,238,000, $1,776,000 and $1,231,000, respectively.
In February 1990, the Company adopted a shareholder rights plan 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 one-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 $0.01 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.
THE WASHINGTON WATER POWER COMPANY
In November 1991, the Company received authorization to issue from time to time 1,500,000 shares of Common Stock under a Periodic Offering Program (POP). During 1992, the remaining 1,107,600 shares of the first POP were issued under this program for net proceeds of $18.0 million. In the second half of 1992, the Company received authorization to issue a second 1,500,000 shares of common stock under the POP. Through December 31, 1993, 927,600 shares of the second POP were issued for net proceeds of $17.3 million.
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.
Sales of Common Stock for 1993, 1992 and 1991, are summarized below (dollar amounts in thousands):
THE WASHINGTON WATER POWER COMPANY
NOTE 9. FEDERAL INCOME TAXES
A reconciliation of federal income taxes derived from statutory tax rates applied to income from continuing operations for accounting purposes and such taxes charged to expense for the consolidated Company is as follows:
NOTE 10. DISCONTINUED COAL MINING OPERATIONS
Washington Irrigation & Development Company (WIDCo) owned an undivided one-half interest in coal mining properties near Centralia, Washington, which it operated and which supplied coal to the Centralia Steam Electric Generating Plant owned 15% by the Company. On July 31, 1990, WIDCo sold its 50% interest in the Centralia coal mining properties for $40.8 million. A tax adjustment of $1.6 million related to the sale was recorded in 1991. Net income of $2.4 million in 1992 resulted from accounting adjustments and a refund of federal income taxes for years prior to the sale. The consolidated financial statements 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 for discontinued operations in the Balance Sheets and Income Statements.
THE WASHINGTON WATER POWER COMPANY
NOTE 11. COMMITMENTS AND CONTINGENCIES
SUPPLY SYSTEM PROJECT 3
In 1985, the Company and the Bonneville Power Administration (BPA) reached a settlement surrounding litigation related to the suspension of construction of Washington Public Power Supply System (Supply System) Project 3. Project 3 is a partially constructed 1,240 MW nuclear generating plant in which the Company has a 5% interest. Under the settlement agreement, the Company receives power deliveries from BPA from 1987 to 2017 in proportion to the Company's investment in Project 3.
The settlement with BPA and other parties does not affect the Company's obligations under the Ownership Agreement among the owners of Project 3. In connection with its 1993 rate proceedings, BPA has proposed termination of Project 1 and 3. Termination of Project 3 will require proposal of a termination budget and approval by BPA and the Project 3 Owners under the Ownership Agreement. The Company would be reimbursed for the cost of termination under the settlement with BPA.
The only material claim against the Company arising out of the Company's involvement in Project 3, which is still pending in the United States District Court for the Western District of Washington (District Court), is the claim of Chemical Bank, as bond fund trustee for Supply System Projects 4 and 5, against all owners of Projects 1, 2 and 3 for unjust enrichment in the allocation of certain costs of common services and facilities among the Supply System's five nuclear projects. Projects 4 and 5 were being constructed adjacent to Projects 1 and 3, respectively, under a plan to share certain costs. Chemical Bank is seeking a reallocation of $495 million in costs (plus interest since commencement of construction in 1976) originally allocated to Projects 4 and 5.
On October 7, 1992, the District Court issued an order ruling in favor of the defendants, including the Company, that the "proportional" allocation methodology actually employed by the Supply System was permitted by the Projects 4 and 5 bond resolution. This ruling does not resolve all cost reallocation claims pending in the District Court, including whether the Supply System correctly followed its methodology. Chemical Bank has indicated its intent to assert claims for cost reallocations based upon other theories which have not been litigated. The case is now in the discovery phase on those claims, as settlement talks were not successful.
The Company cannot predict whether Chemical Bank will ultimately be successful in its claim for reallocation of any of the costs of Supply System projects, nor can the Company predict any amounts which might be reallocated to Project 3 or to the Company due to its 5% ownership interest therein. The Company also has claims pending against the Supply System and Chemical Bank with respect to a subordinated loan made by the Company to Projects 4 and 5 in 1981, in the amount of approximately $11 million including interest. The District Court has deferred ruling on the Company's motion to set-off the amount due on the loan, including interest, against any recovery by Chemical Bank on its cost reallocation claims. The Company intends to continue to defend this suit vigorously. Since the discovery is not yet complete, the Company is 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.
NEZ PERCE TRIBE
On December 6, 1991, the Nez Perce Tribe filed an action against the Company in U. S. District Court for the District of Idaho alleging, among other things, that two dams formerly operated by the Company, the Lewiston Dam on the Clearwater River and the Grangeville Dam on the South Fork of the Clearwater River, provided inadequate passage to migrating anadromous fish in violation of rights under treaties between the Tribe and the United States made in 1855 and 1863. The Lewiston and Grangeville Dams, which had been owned and operated by other utilities under hydroelectric licenses from the Federal Power Commission (the "FPC", predecessor of the FERC) prior to acquisition by the Company, were acquired by the Company in 1937 with the approval of the FPC, but were dismantled and removed in 1973 and 1963, respectively. The Tribe initially indicated through expert opinion disclosures that they were seeking actual and punitive damages of $208 million. However, supplemental disclosures reflect allegations of actual loss under different assumptions of between $425 million and $650 million. Discovery in this case has been stayed pending a decision by the Court on a case involving some similar issues between Idaho Power Company and the Nez Perce Tribe. The case is not yet set for trial. The Company intends to vigorously defend against the Tribe's claims. Since the discovery is not yet complete, the Company is 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.
THE WASHINGTON WATER POWER COMPANY
LITTLE FALLS PROJECT
Pending before the U. S. District Court in the Eastern District of Washington is the case of Spokane Tribe of Indians v. WWP. This matter involves a claim of the Spokane Tribe of Indians for damages arising out of the Company's Little Falls Hydroelectric Development that was constructed on the Spokane River pursuant to a 1905 Act of Congress. The Tribe is claiming the Company's dam interfered with Indian fishing rights. The Tribe is also seeking a declaratory judgment and quiet title to part of the property comprising the Little Falls Hydroelectric Development. Discovery conducted by the Company revealed that the Tribe may seek damages in the range of $100 million to $1.4 billion, to compensate them for the alleged loss of fishing rights, alleged lost opportunity to develop the properties, and alleged damage to the Tribe's cultural heritage. The trial of these matters is currently scheduled for April 1994 in the United States District Court for the Eastern District of Washington, in Spokane, Washington. On the merits, the Company claims that it has all of the right, title and interest necessary for the construction, operation and maintenance of the Little Falls Development, which rights, title and interest were duly acquired from the United States pursuant to a 1905 Act of Congress. The Company intends to vigorously defend against the Tribe's claims. The Company is 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.
STEAM HEAT PLANT
The Company recently completed an updated investigation of an oil spill that occurred several years ago in downtown Spokane at the site of the Company's steam heat plant. The Company purchased the plant in 1916 and operated it as a non-regulated plant until it was deactivated in 1986 in a business decision unrelated to the leak. After the Bunker C fuel oil spill, initial studies suggested that the oil was being adequately contained by both geological features and man-made structures. The Washington State Department of Ecology (DOE) concurred with these findings. However, more recent tests confirm that the oil has migrated beyond the steam plant property. On December 6, 1993, the Company asked the DOE to approve a voluntary proposal to begin extracting the underground oil. The extraction process is intended to remove quantities of the oil and relieve any pressure on the deposit which might cause it to move. In December 1993, the Company established a reserve of $2.0 million, which is the current best estimate of mitigation costs.
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. On October 13, 1993, three separate class action lawsuits were filed by private individuals in the Superior Court of Spokane County in connection with fires occurring in the Midway, Nine Mile and Chattaroy regions of eastern Washington. Service of these suits, together with a fourth suit, occurred on January 7, 1994. Complainants allege various theories of tortious conduct, including negligence, creation of a public nuisance, strict liability and trespass. 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. The Superior Court has yet to certify these lawsuits as class actions. The Company intends to vigorously defend against all such pending claims. Since the discovery is not yet complete, the Company is 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.
OTHER CONTINGENCIES
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 power with other utilities, cogenerators, small power producers and government agencies. For information relating to certain long-term purchased power contracts, see Note 13.
THE WASHINGTON WATER POWER COMPANY
NOTE 12. JOINTLY-OWNED ELECTRIC FACILITIES
The Company is involved 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, 1993:
NOTE 13. LONG-TERM PURCHASED POWER CONTRACTS WITH REQUIRED MINIMUM PAYMENTS
Under fixed contracts with Public Utility Districts, 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, 1993, pertaining to these contracts is summarized in the following table:
(1) The Company purchases 100% of the Lake Chelan Project output and sells back to the PUD about 40% of the output to supply local service area requirements. (2) 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 1993. (3) Included in annual costs.
Actual expenses for payments made under the above contracts for the years 1993, 1992 and 1991, were $8,721,000, $8,433,000 and $7,589,000, 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 $4,338,000 in 1994, $4,775,000 in 1995, $3,830,000 in 1996, $4,300,000 in 1997 and $4,684,000 in 1998 (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.
THE WASHINGTON WATER POWER COMPANY
NOTE 14. ACQUISITIONS AND DISPOSITIONS
During 1993, Pentzer acquired three companies, two involved in financial services and one in point-of-purchase display manufacturing. Sales of companies involved in telecommunications, technology and energy services resulted in transactional gains of $7.1 million. At December 31, 1993, Pentzer had approximately $130 million in assets compared to $103 million at the end of 1992.
In 1992, Pentzer's common stock ownership in ITRON was reduced from approximately 60% to approximately 40% as a result of the issuance of common stock by ITRON in an acquisition. Accordingly, beginning in 1992, Pentzer's share of ITRON's earnings is accounted for by the equity method and is included in Other Income-Net and its investment in ITRON is reflected on the balance sheet under Other Property and Investments. As a result of ITRON's initial public offering in November 1993 and Pentzer's sale of a portion of its ITRON stock, Pentzer's ownership interest in ITRON was reduced to approximately 25%.
In December 1992, the Company completed the purchase of the northern Idaho electric distribution assets of Citizens Utilities. The cash purchase price of $1.2 million included a premium above the book value of the net assets acquired. The premium will be amortized over a 19-month period. The purchase provided approximately 2,100 additional electric customers. The Company believes that this acquisition will not have a material impact on its revenues or its operations.
On September 30, 1991, the Company completed the purchase of the Oregon and South Lake Tahoe, California, natural gas assets of CP National Corporation, a subsidiary of ALLTEL Corporation, for approximately $67.9 million. The cash purchase included a premium of approximately $24.9 million above the book value of the net assets acquired. The premium and other costs associated with acquiring the properties will be amortized under a straight-line method over 20 years and the amortization may be accelerated depending upon earnings. The California and Oregon Commissions have agreed to a general rate "freeze" which extends to January 1, 1996, in California and to December 31, 1995, in Oregon. Purchased natural gas costs will continue to be tracked through to customers during the rate "freeze" period.
On February 15, 1994, the Company announced it had reached agreement to acquire the northern Idaho electric properties of Pacific Power & Light Company, an operating division of PacifiCorp. The cash purchase price will be $26 million, subject to adjustments upon closing. The approximate book value of the assets is $19 million. The purchase agreement is subject to approval by the IPUC and FERC. It is anticipated the acquisition will be completed mid-year 1994. Pacific Power's northern Idaho electric system currently serves approximately 9,300 customers. The Company believes this acquisition will not have a material impact on its revenues or its operations.
THE WASHINGTON WATER POWER COMPANY
NOTE 15. SELECTED QUARTERLY INFORMATION (UNAUDITED)
The Company's electric and natural gas 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 for per share amounts) for 1993 and 1992 follows. All references to number of shares and per share information have been adjusted to reflect the common stock split on a retroactive basis.
THE WASHINGTON WATER POWER COMPANY
PART III
ITEM 10.



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding the directors of the Registrant has been omitted pursuant to General Instruction G to Form 10-K. Reference is made to the Registrant's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Registrant's annual meeting of shareholders to be held on May 12, 1994.
Executive Officers of the Registrant
All of the Company's executive officers, with the exception of Messrs. Harvey, Bryan, Ely, Fukai and Buergel and Ms. Racicot, were officers or directors of one or more of the Company's subsidiaries in 1993.
Executive officers are elected annually by the Board of Directors.
THE WASHINGTON WATER POWER COMPANY
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 12, 1994.
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 12, 1994.
(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 12, 1994.
THE WASHINGTON WATER POWER COMPANY
PART IV
ITEM 14.

ITEM 14. FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K
(a) 1. Financial Statements (Included in Part II of this report):
Independent Auditors' Report
Consolidated Statements of Income and Retained Earnings for the Years Ended December 31, 1993, 1992 and 1991
Consolidated Balance Sheets, December 31, 1993 and 1992
Consolidated Statements of Capitalization, December 31, 1993 and
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1992 and 1991
Schedule of Information by Business Segments for the Years Ended December 31, 1993, 1992 and 1991
Notes to Financial Statements
(a) 2. Financial Statement Schedules (Included in Part IV of this report):
Independent Auditors' Report (Relating to Supplemental Schedules)
Supplemental Schedules for the Years Ended December 31, 1993, 1992 and 1991:
Schedule V(a), (b), (c) - Property, Plant and Equipment
Schedule VI(a),(b), (c) - Accumulated Depreciation and Amortization of Property, Plant and Equipment
Schedule X - Supplementary Income Statement Information
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
(a) 3. Exhibits:
Reference is made to the Exhibit Index commencing on page 58. 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 November 9, 1993 regarding the two-for-one stock split in the form of a 100% stock dividend.
INDEPENDENT AUDITORS' REPORT
The Washington Water Power Company Spokane, Washington
We have audited the consolidated financial statement of The Washington Water Power Company and subsidiaries as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993, and have issued our report thereon dated January 28, 1994 (February 15, 1994 as to Note 14); such financial statement and report are included in Part II of this Annual Report on Form 10-K. Our audits also comprehended the financial statement schedules of The Washington Water Power Company, listed in Item 14(a)2. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects, the information shown therein.
Deloitte & Touche
Seattle, Washington January 28, 1994 (February 15, 1994 as to Note 14)
SCHEDULE V(a)
THE WASHINGTON WATER POWER COMPANY
Property, Plant and Equipment For the Year Ended December 31, 1993 (Thousands of Dollars)
The cost of additions includes completed projects transferred from CWIP. The Company's 1993 construction program was financed with internally-generated funds, bank borrowings and commercial paper, and proceeds from the sales of preferred and common stock and long-term debt.
(1) Represents balance of Citizen Utility acquisition adjustment. (2) Amortization of reserve for nonrecovery of a portion of the Kettle Falls project in accordance with FAS 90. (3) Represents the redistribution of Citizen Utility Electric Plant to appropriate category. (4) Represents $110,796,000 spent on construction less $88,344,000 closed to plant in service from CWIP.
SCHEDULE V(b)
THE WASHINGTON WATER POWER COMPANY
Property, Plant and Equipment For the Year Ended December 31, 1992 (Thousands of Dollars)
The cost of additions includes completed projects transferred from CWIP. The Company's 1992 construction program was financed with internally-generated funds, bank borrowings and commercial paper, and proceeds from the sales of preferred and common stock and long-term debt.
(1) Amortization of reserve for nonrecovery of a portion of the Kettle Falls project in accordance with FAS 90. (2) Represents the purchase of Citizen Utility Electric Plant. (3) Acquisition adjustment related to purchase of natural gas assets from CP National Corporation. (4) Represents $89,748,000 spent on construction less $96,829,000 closed to plant in service from CWIP. (5) Deconsolidation of ITRON, Inc.
SCHEDULE V(c)
THE WASHINGTON WATER POWER COMPANY
Property, Plant and Equipment For the Year Ended December 31, 1991 (Thousands of Dollars)
NOTE: All balances have been restated to exclude the assets of the Company's discontinued coal mining operations. These properties were sold in 1990. The amount of WP Natural Gas assets in Column F is $73,828,000.
The cost of additions includes completed projects transferred from CWIP. The Company's 1991 construction program was financed with internally-generated funds, bank borrowings and commercial paper, and proceeds from the sales of preferred and common stock and long-term debt.
(1) Amortization of reserve for non-recovery of a portion of the Kettle Falls project in accordance with FAS 90. (2) Amortization of adjustment related to City of Worley acquisition. (3) Acquisition adjustment related to purchase of natural gas assets from CP National Corporation. (4) Reclassification of software development costs. (5) Includes $234,237 of computer software transferred from general plant to intangible plant. (6) Represents $143,915,000 spent on construction less $123,869,000 closed to plant in service from CWIP.
SCHEDULE VI(a)
THE WASHINGTON WATER POWER COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Year Ended December 31, 1993 (Thousands of Dollars)
(1) Retirements are reported net of cost of removal and salvage. (2) Reference is made to Note 1 to Financial Statements for depreciation method. (3) Pertains to adjustment resulting from sale of equipment, transfers to non-utility, acquisition premium for Citizens Utility of ($340,298) and $838,911 accumulated depreciation acquired at the time of the purchase of Citizens Utility. (4) Represents a transfer relating to the accrued liability for Steam Heat Environmental clean-up.
SCHEDULE VI(b)
THE WASHINGTON WATER POWER COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Year Ended December 31, 1992 (Thousands of Dollars)
NOTE: All balances have been restated to exclude the accumulated depreciation and amortization on the Company's discontinued coal mining operations. These properties were sold in 1990. The amount in Column F related to WP Natural Gas is $31,460.
(1) Retirements are reported net of cost of removal and salvage. (2) Reference is made to Note 1 to Financial Statements for depreciation method. (3) Pertains to adjustment resulting from sale of equipment. (4) Deconsolidation of ITRON.
SCHEDULE VI(c)
THE WASHINGTON WATER POWER COMPANY
Accumulated Depreciation and Amortization of Property, Plant and Equipment for the Year Ended December 31, 1991 (Thousands of Dollars)
- --------- NOTE: All balances have been restated to exclude the accumulated depreciation and amortization on the Company's discontinued coal mining operations. These properties were sold in 1990. The amount in Column F related to WP Natural Gas is $29,404.
(1) Retirements are reported net of cost of removal and salvage. (2) Reference is made to Note 1 to Financial Statements for depreciation method. (3) Represents balance of accumulated depreciation & amortization for WP Natural Gas at time of purchase. (4) Reclassification related to intangibles and software development costs.
SCHEDULE X
THE WASHINGTON WATER POWER COMPANY
Supplementary Income Statement Information for the Years Ended December 31, 1993, 1992 and 1991 (Thousands of Dollars)
Amounts of maintenance and repairs, and depreciation, other than as set out separately in the Consolidated Statements of Income and Retained Earnings, are not material.
Amounts of advertising costs are not material.
THE WASHINGTON WATER POWER COMPANY
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
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.
THE WASHINGTON WATER POWER COMPANY
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. 33-10040 on Form S-3, in Registration Statement No. 33-32148 on Form S-8, in Registration Statement No. 33-40333 on Form S-3, in Registration Statement No. 33-49662 on Form S-3, in Registration Statement No. 33-60136 on Form S-3, and in Registration Statement No. 33-51669 on Form S-3 of our report dated January 28, 1994 (February 15, 1994 as to Note 14), appearing in this Annual Report on Form 10-K of The Washington Water Power Company for the year ended December 31, 1993.
Deloitte & Touche
Seattle, Washington March 4, 1994
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX
*Incorporated herein by reference. **Filed herewith.
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX (continued)
*Incorporated herein by reference. **Filed herewith.
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX (continued)
* Incorporated herein by reference. ** Filed herewith.
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX (continued)
* Incorporated herein by reference. ** Filed herewith.
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX (continued)
* Incorporated herein by reference. ** Filed herewith.
THE WASHINGTON WATER POWER COMPANY
EXHIBIT INDEX (continued)
* Incorporated herein by reference. ** Filed herewith.
THE WASHINGTON WATER POWER COMPANY
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.
THE WASHINGTON WATER POWER COMPANY
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.