ITEM 1. BUSINESS
COMPANY OVERVIEW
The Washington Water Power Company (WWP, the Company), which was incorporated in the State of Washington in 1889, primarily operates in the electric and natural gas utility businesses. As of January 1, 1995, the Company provides electricity and natural gas in a 26,000 square mile area in eastern Washington and northern Idaho with a population of approximately 765,000. The Company's electric service territory now includes Bonner County in northern Idaho as a result of the acquisition of electric properties from PacifiCorp, which was finalized on December 30, 1994. See Note 14 to Financial Statements for additional information. Through a separate operating division called WP Natural Gas (WPNG), the Company also provides natural gas service in northeast and southwest Oregon and in the South Lake Tahoe region of California with a population of approximately 460,000.
The Company's wholesale and retail utility businesses include the generation, purchase, transmission, distribution and sale of electric energy plus the purchase, transportation, distribution and sale of natural gas. In addition to its utility businesses, the Company owns Pentzer Corporation (Pentzer), parent company to the majority of the Company's non-utility businesses.
At December 31, 1994, the Company's employees included 1,420 people in its utility operations and 775 people in its majority-owned non-utility businesses. The Company's corporate headquarters are in Spokane, Washington (Spokane), which serves as the Inland Northwest's center for manufacturing, transportation, health care, education, communication, agricultural and service businesses.
For the twelve months ended December 31, 1994, 1993 and 1992, respectively, the Company derived operating revenues and income from operations in the following proportions:
MERGER AGREEMENT OVERVIEW
In June 1994, the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power Company (SPPC), a subsidiary of SPR, and Resources West Energy Corporation, a newly formed subsidiary of the Company (Resources West), entered into an Agreement and Plan of Reorganization and Merger, as subsequently amended (Merger Agreement), which provides for the merger of WWP, SPR and SPPC into Resources West. SPR and SPPC are both Nevada corporations with headquarters in Reno, Nevada (Reno). The Merger Agreement provides that after the effective date of the Merger, Resources West's corporate headquarters offices and principal executive offices will be located in Spokane and that the headquarters of its Washington Water Power and Sierra Pacific operating divisions will be in Spokane and Reno, respectively. As a result of the Merger Agreement, holders of WWP Common Stock would receive one share and holders of SPR Common Stock would receive 1.44 shares of Resources West Common Stock, respectively. Each outstanding share of Preferred Stock of WWP and SPPC, respectively, will be converted into the right to receive one share of Resources West Preferred Stock with equal stated value and dividends and like redemption provisions and rights upon liquidation.
WWP, SPR and SPPC believe that the proposed merger offers significant strategic and financial benefits to each of the companies and to their respective stakeholders including an enhanced competitive position, a larger and more diverse service territory, an expanded resource base, improved resource planning and coordination, and cost savings. The cost savings for the new company are estimated to approximate $450 million, net of merger transaction and transition costs, over the 10 years following the consummation of the merger. The cost savings should be achieved from, among other things, the integration of corporate management and administrative functions, the consolidation of distribution operations, the integration of gas purchasing requirements, the reduction of capacity requirements, the reduction of non-firm transmission expense, the avoidance of expenditures for operating systems, and the streamlining of inventories and purchasing economies.
See Item 4. Submission of Matters to a Vote of Security Holders, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations: Future Outlook and Note 15 to Financial Statements for additional information.
THE WASHINGTON WATER POWER COMPANY
UTILITY OPERATIONS OVERVIEW
The Company owns and operates nine hydroelectric projects in addition to a wood-waste fueled generating station. The Company also owns a 15% share in two coal-fired generating facilities, one in western Washington State and one in southeastern Montana. In addition the Company owns one natural gas combustion turbine (CT) peaking unit located near Spokane and completed the construction of two additional natural gas CT peaking units in northern Idaho in early January 1995. The Company contracts with five natural gas pipeline companies for access to domestic and Canadian natural gas supplies. With this diverse energy resource portfolio, the Company remains one of the nation's lowest-cost producers and sellers of energy services.
At December 31, 1994, electric service was supplied to approximately 275,000 customers in eastern Washington and northern Idaho. The Company's average hourly load for 1994 was 886 aMW. The Company's annual peak load, including firm contractual obligations, was 2,233 MW. This peak occurred on February 8, 1994, at which time the maximum capacity available from the Company's generating facilities, in addition to firm and non-firm purchases, was 2,468 MW.
At December 31, 1994, the Company's natural gas operations served approximately 212,000 customers in its natural gas service territory located in parts of four states. The peak load in 1994 occurred on February 7, 1994 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 is Pentzer, a wholly-owned private investment company whose current portfolio of investments includes companies involved in consumer product promotion, specialty tool manufacturing, financial services, industrial real estate development and electronic technology.
Pentzer's business strategy is to acquire controlling interest 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. Pentzer's objective is to produce current returns from its portfolio investments that are higher than that of the utility operations and to supplement these current returns by generating transactional gains through the sale of portfolio investments when appropriate.
As of December 31, 1994, Pentzer had approximately $167 million in total assets or about 8% of the Company's consolidated assets.
THE WASHINGTON WATER POWER COMPANY
ELECTRIC SERVICE
COMPETITION AND BUSINESS RISK
Regulatory, economic and technological changes have brought about the accelerating transformation of the electric utility industry from a vertically integrated monopoly to a business that is much more market driven in each segment of its business. The Company believes that it is well positioned to meet the challenges of increased competition due to its low production costs, close proximity to major transmission lines, active participation in wholesale power markets and its dedication to high levels of customer satisfaction, cost reduction and continuous improvement of work processes.
The Company continues to compete for new retail electric customers with various rural electric cooperatives and public utility districts in and adjacent to its service territories. Challenges facing the electric retail business include evolving technologies which provide alternate energy supplies, reduced energy consumption and the cost of the energy supplied, self-generation and fuel switching by commercial and industrial customers, the potential for retail wheeling (described below), the costs of increasingly stringent environmental laws and the potential for stranded or nonrecoverable utility assets. 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. Similarly the Company believes it faces minimal risk for stranded generation, transmission or distribution assets due to its low cost structure.
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 a new exception from the provisions of the Holding Company Act for Exempt Wholesale Generators (EWG). Subject to satisfying various regulatory requirements, EWGs may own generating facilities and make wholesale sales. 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 has filed for open access transmission tariffs with the FERC and is exploring options as a member of the newly forming Regional Transmission Groups, which are designed to enable the market for electric power to operate in a more competitive and efficient manner.
The Company continues to compete in the wholesale electric market with other western utilities, including the Bonneville Power Administration (BPA) which is forecasting significant price increases in the near future. Business challenges affecting the wholesale electric business include new entrants in the wholesale market, such as power brokers and marketers, competition from low cost generation being developed by independent power producers and declining margins. However, the Company's wholesale electric business remains an important part of the Company's overall business strategy. 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 electric wholesale business opportunities. In 1994, 29% of total KWH sales were to wholesale customers with 53% of these sales under firm contracts.
ELECTRIC SYSTEM
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 hydroelectric contracts in normal water years. The streamflows in the Company's drainage systems were 65%, 86% and 64% of normal in 1994, 1993 and 1992, respectively. For the years 1994, 1993 and 1992, respectively, 38%, 43% and 40% of the Company's total system requirements were met by these hydroelectric resources.
Thermal Resources. The Company has a 15% interest in two coal-fired facilities - - the Centralia Power Plant (Centralia) in western 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 Company also completed the construction of two additional natural gas CT units in northern Idaho in early January 1995. The CTs are primarily used for peaking needs. Company-owned thermal facilities provided 32%, 25% and 31% of the Company's total electricity requirements for the years 1994, 1993 and 1992, respectively.
THE WASHINGTON WATER POWER COMPANY
Centralia, which is operated by PacifiCorp, is supplied with coal under both a fuel supply agreement in effect through December 2020 and various spot market purchases. In 1994, 1993 and 1992 Centralia provided approximately 42%, 46% 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 the operator of Colstrip. In 1994, 1993 and 1992 Colstrip provided approximately 48%, 43%, and 51% of the Company's thermal generation, respectively.
Kettle Falls' primary fuel is wood-waste generated as a by-product of forest industry operations within one hundred miles of the plant. Natural gas may be used as an alternate fuel. The cost of wood-waste fuel is heavily influenced by operations of the forest products industry as well as transportation costs and, therefore, is subject to significant price variations. Even with the increased competition for wood-waste, 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 1994, 1993 and 1992 Kettle Falls provided approximately 10%, 11% and 9% of the Company's thermal generation, respectively.
Purchases, Exchanges and Sales. In addition to the Company-owned hydroelectric projects, long-term hydroelectric contracts and thermal generating resources discussed above, total system requirements are met with other purchases and exchanges of power. Other power purchases and exchanges for the years 1994, 1993 and 1992 provided approximately 30%, 32% and 29%, 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, 1994 (1):
(1) Available capacity may vary pursuant to the provisions of the specific contracts. See Note 13 to Financial Statements for additional information.
Under PURPA, the Company is required to purchase generation from qualifying facilities, including small hydroelectric and cogeneration projects, at avoided cost rates adopted by the Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (IPUC). The Company purchased approximately 612 million KWH, or about 6% of the Company's total energy requirements, from these sources at a cost of approximately $25 million in 1994. Current avoided costs range from 2.2 to 5.5 cents per KWH in Washington, depending on the terms and length of the contract in addition to the period in which the project commences delivery of power to the Company. Avoided cost rates ranging from 1.9 to 3.7 cents per KWH in Idaho were proposed in an amended filing made to the IPUC in early March 1995.
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 provides 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 price the Company may charge for utility services (other than certain wholesale sales and specially negotiated retail rates for industrial or large commercial customers) is currently determined on a "cost of service" basis and is designed to provide, after recovery of allowable operating expenses, an opportunity to earn a reasonable return on "rate base" 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.
THE WASHINGTON WATER POWER COMPANY
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. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation and take-over of such projects after the expiration of the license upon payment of the lesser of "net investment" or "fair value" of the project, in either case plus severance damages. See 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 power rating under specified conditions. (2) Capability is the maximum generation of the plant without exceeding approved limits of temperature, stress and environmental conditions. (3) See Note 11 to Financial Statements for additional information. (4) The formal relicensing process will begin in mid-1995 for Cabinet Gorge and in 2000 for Noxon Rapids. (5) Jointly-owned; data above refers to Company's respective 15% interests. (6) Used primarily for peaking needs. (7) Construction completed in January 1995; see Note 9 to Financial Statements regarding long-term lease financing.
Distribution and Transmission Plant
The Company operates approximately 11,350 miles of primary and secondary distribution lines in its electric system in addition to a transmission system of approximately 550 miles of 230 KV line and 1,530 miles of 115 KV line. These electric system mileages do not yet include the properties recently acquired from PacifiCorp in Bonner County in northern Idaho. 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 hydroelectric generating stations to major load centers in the Company's service area. The 230 KV lines also transmit to points of
THE WASHINGTON WATER POWER COMPANY
interconnection with adjoining electric transmission systems for bulk power transfers. These lines interconnect with BPA at five locations and at one location each with PacifiCorp, Montana Power and Idaho Power Company. The BPA interconnections serve as points of delivery for power from the Colstrip and Centralia generating stations as well as for the interchange of power with the Southwest. The interconnection with PacifiCorp is the point of delivery for power purchased by the Company from Mid-Columbia projects' hydroelectric generating stations.
The 115 KV lines provide for transmission of energy as well as providing for the integration of the Spokane River hydroelectric and Kettle Falls wood-waste generating stations with service area load centers. These lines interconnect with BPA at nine locations, Grant County PUD, Seattle City Light and Tacoma City Light at two locations and one interconnect location each with Chelan County PUD, PacifiCorp, and Montana Power.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Future Outlook for additional information regarding the potential transmission interconnections between the Company and SPPC.
NATURAL GAS PROPERTIES
The WWP and WPNG service territories' natural gas properties have natural gas distribution mains of approximately 3,100 miles and 1,500 miles, respectively, as of December 31, 1994.
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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
A Special Meeting of Shareholders of the Company was held on November 18, 1994. The only matter voted upon at the meeting was the approval of the Agreement and Plan of Reorganization and Merger dated as of June 27, 1994, as amended October 4, 1994, by and among the Company, SPR, SPPC and Resources West, and the transactions contemplated thereby (Merger Proposal), pursuant to which, among other things, each of the Company, SPR and SPPC will be merged with and into Resources West.
As of September 22, 1994, the record date for determining shareholders entitled to notice of and to vote at the meeting, 54,017,035 shares of Common Stock of the Company and 850,500 shares of Preferred Stock of the Company were issued and outstanding, with 43,088,852 shares of Common Stock and 641,686 shares of Preferred Stock represented at said meeting. Approval of the Merger Proposal required the affirmative vote of (i) not less than two thirds of all votes entitled to be cast by all holders of Company Common Stock and (ii) not less than two-thirds of all votes entitled to be cast by all holders of Company Preferred Stock, in each case voting separately as a class. The Merger Proposal was approved by the requisite shareholder votes. The details of the voting are shown below:
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations: Future Outlook and Note 15 to Financial Statements for additional details relating to the terms of the proposed merger.
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 28, 1995, there were approximately 34,155 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.
Refer to Notes 1, 8 and 17 to Financial Statements for additional information.
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 was accounted for by the equity method and was included in Other Income-Net and its investment in ITRON was reflected on the balance sheet under Other Property and Investments. ITRON's initial public offering in November 1993 and Pentzer's sales of ITRON stock during 1993 and 1994 resulted in a reduction in Pentzer's ownership interest to approximately 14%. As a result, Pentzer's investment in ITRON, beginning in December 1994, is accounted for by the cost method. Therefore, income from ongoing ITRON operations will no longer be recorded by Pentzer.
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. Total assets for 1994 include the northern Idaho electric properties purchased by the Company from PacifiCorp on December 30, 1994.
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.
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 in the Southwest region. Other factors affecting the wholesale power market include new entrants in the wholesale market, such as power brokers and marketers, competition from low cost generation being developed by independent power producers and declining margins. Usage by retail customers varies from year to year primarily as a result of weather conditions, the economy in the Company's service area, customer growth, conservation, appliance efficiency and other technology.
The Company intends to 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 also intends to pursue resource opportunities through system upgrades, purchases, demand side management and other options that will result in obtaining electric power and natural gas supplies at the lowest possible cost.
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 1994 were $1.28, compared to $1.44 in 1993 and $1.37 in 1992. The 1994 results include $8.0 million of gains recorded by Pentzer Corporation (Pentzer) primarily as a result of the sale of stock in ITRON, Inc. (ITRON). The 1993 results include gains totaling $12.8 million recorded by 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 in November 1993. The 1992 results include gains of $4.4 million, or $0.09 per share, due to the issuance of common stock by ITRON in an acquisition and $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.
Utility income available for common stock decreased $6.3 million, or 10.2%, in 1994 after increasing $4.0 million, or 7.0%, in 1993. Utility income available for common stock contributed $1.03 to earnings per share in 1994, compared to $1.19 in 1993 and $1.15 in 1992. Non-utility income available for common stock from continuing operations increased $0.4 million in 1994 and $5.0 million in 1993 and contributed $0.25 to earnings per share in both 1994 and 1993 and $0.17 in 1992.
Weather that was 9% warmer than normal during 1994 reduced residential usage for both electric and natural gas customers. Income from electric operations decreased $0.6 million in 1994 over 1993 primarily as a result of a $12.9 million decline in revenues due to decreased KWh sales that was nearly offset by decreased purchased power expense. Income from natural gas operations decreased $0.2 million in 1994, as compared to 1993, due primarily to increased purchased gas costs that were offset substantially by increased revenues due to customer growth. Slightly colder-than-normal weather during 1993 affected both electric and natural gas operations as compared to 1992. Income from electric operations decreased $5.4 million in 1993, as compared to 1992, primarily as a result of increases in purchased power costs due to thermal plant outages, a significant short-term sale of wholesale energy, lower hydroelectric generation due to below normal streamflows and increases in other operating and maintenance expenses. Income from natural gas operations increased $6.7 million in 1993 over 1992 due primarily to increased customer usage from the colder weather and customer growth.
THE WASHINGTON WATER POWER COMPANY
Interest expense increased $2.9 million in 1994 after a decrease of $3.4 million in 1993. In 1994, $88.0 million in long-term debt was issued, while $7.5 million of long-term debt matured or was redeemed. At December 31, 1994, long-term debt outstanding was $73.9 million higher than at December 31, 1993. In 1993, $274.1 million of long-term debt matured or was redeemed, while only $254.1 million was issued.
Preferred stock dividend requirements increased $0.3 million in 1994, primarily due to higher dividend rates on the Company's Auction Preferred Stock, and $1.5 million, or 22.3%, in 1993 due to the issuance of preferred stock in late 1992. A redemption of preferred stock in early 1992, which was not replaced until an issuance later in the year was the primary reason for the reduced preferred dividend requirement in 1992.
UTILITY OPERATIONS
ELECTRIC OPERATIONS
(1) Does not include interest expense or other income.
Electric revenues decreased by 3% in 1994, as compared to 1993, due to a combination of decreased residential sales and wholesale sales, partially offset by increased commercial sales and higher wheeling revenues. Residential revenues decreased by $7.0 million, despite a 3% increase in customers, due to warm weather throughout most of 1994. Residential usage was also affected by new appliance efficiency and other technology which has decreased customers' base load requirements. Commercial revenues increased $5.0 million, or 4%, in 1994, as compared to 1993, due to 3% customer growth and the slightly warmer-than-normal weather which increased air conditioning load. Commercial customers tend to use air conditioning systems at much cooler temperatures than residential customers, with the result that air conditioning load can be up within the commercial sector and not within the residential sector, as during the fall of 1994. Wholesale revenues decreased $17.2 million during 1994, compared to 1993, primarily due to a significant short-term sale of wholesale energy in 1993 which increased wholesale revenues in that period, low streamflow conditions during 1994 which led to decreased KWh sales and lower wholesale prices.
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 have grown, the electric load has become 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 a sales agreement with a large customer. Wholesale revenues increased by $16.8 million, or 18%, due primarily to a significant sale of wholesale energy over a six-week period in the first quarter of 1993.
THE WASHINGTON WATER POWER COMPANY
Electric Revenues, KWh Sales, and Customers by Service Class
Warmer-than-normal weather and below-normal streamflow conditions affected 1994 electric operating results. Hydroelectric generation was 23% below normal, caused by streamflows which were 65% of normal in 1994. Fuel costs increased $4.9 million over 1993 due to increased thermal generation as a result of the low streamflows in 1994 and shutdowns at thermal plants during 1993 which decreased fuel expense for that year. Purchased power costs in 1994 decreased $12.5 million, or 11%, over levels incurred during 1993, primarily due to increased purchases during 1993 to complete a significant short-term sale of wholesale energy and to replace lost thermal generation due to plant outages. Transmission and distribution costs, which decreased $1.0 million and $2.3 million, respectively, contributed to the $7.3 million, or 11%, decrease in other operating and maintenance expenses. Transmission expenses decreased in 1994 over 1993 due to decreased wholesale KWh sales and the associated wheeling costs. Distribution expense was lower in 1994, compared to 1993, due to increased expenses during 1993 for repairs at thermal plants. 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, resulting from low hydroelectric conditions, accounted for $4.1 million of the decrease in other operating and maintenance expenses from 1993. Administrative and general expenses increased by $2.8 million in 1994, compared to 1993, primarily due to labor-related costs.
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 significant sale of wholesale energy in the first quarter and to replace lost thermal generation due to plant outages. 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.
THE WASHINGTON WATER POWER COMPANY
NATURAL GAS OPERATIONS
Natural Gas Operating Income Summary
(1) Does not include interest expense or other income.
The Company's natural gas business experienced the effects of weather on operating results in both 1994 and 1993. In 1994, weather in the Washington and Idaho service territory was 9% warmer than normal, compared to 5% colder than normal in 1993. The Oregon service territory experienced temperatures 6% warmer than normal in 1994, compared to 8% warmer in 1993. The 8% growth in customers in 1994 helped offset the impact of the weather. Substantial customer growth of 9% in 1993, along with colder weather, contributed to increased revenues.
Total natural gas revenues increased in all customer classes except industrial in 1994 from 1993. WPNG revenues accounted for an increase of $4.6 million in overall natural gas operating revenues, as compared to 1993. In 1994, natural gas revenues from WWP residential and commercial customers rose by $5.2 million and $5.9 million, respectively. The increased revenues were due to customer growth and higher average prices than in 1993, which were offset in part by lower usage per customer as a result of warm temperatures. Much of the customer growth in the WWP service area during the early part of 1994 was the result of the Company's emphasis on conversions from electric service to natural gas. Recent revisions in the Company's Demand Side Management programs may lessen the pace of conversions in the future. During 1994, the Company sold natural gas on an off-system sales basis. The revenues from these sales were offset by like increases in purchased gas expense. Margins from these transactions will be credited back to customers through rate changes for the cost of gas.
Total natural gas 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.
THE WASHINGTON WATER POWER COMPANY
Natural Gas Revenues, Therm Sales, and Customers by Service Class
A large portion of purchased gas expense is variable costs, with the result that increases in revenues are offset by like increases in purchased gas expense. Natural gas purchased expense increased $19.4 million in 1994 from 1993, primarily due to the increase in therm sales of 32.1 million, or 6%. Administrative and general expenses increased by $0.9 million in 1994, compared to 1993, primarily due to labor-related costs.
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.
NON-UTILITY OPERATIONS
Non-Utility Operations Summary
Non-utility operations include the results of Pentzer and three other subsidiary companies. Pentzer's business strategy is to acquire controlling interest 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. Pentzer's objective is to produce current returns from its portfolio investments that are higher than that of the utility operations and to supplement these current returns by generating transactional gains through the sale of portfolio investments when appropriate. From time to time, a significant portion of Pentzer's earnings
THE WASHINGTON WATER POWER COMPANY
contributions may be the result of transactional gains. Accordingly, although the income stream is expected to be positive, it may be uneven from year to year.
Non-utility net income for 1994 was $13.6 million, which was a 3% increase over 1993. The 1993 net income of $13.3 million was a 60% increase over 1992. The increase in 1993 over 1992 was primarily due to transactional gains recorded by Pentzer during 1993.
Transactional gains of $8.0 million in 1994 declined by $4.8 million as compared to 1993. The 1994 transactional gains were primarily the result of gains of $7.7 million from the sale of ITRON stock. The 1993 transactional gains included gains of $7.1 million from the sale of companies involved in telecommunications, technology and energy and a transactional gain of $5.7 million from the sale of ITRON stock.
Excluding transactional gains, earnings of $5.7 million in 1994 from Pentzer operations exceeded 1993 earnings by $5.8 million. 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. Transactional gains during 1993 totalled $12.8 million compared to $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 and recognized an income tax benefit of $2.2 million due to tax loss carryforwards in a subsidiary. Pentzer's return on invested capital increased from 12% in 1992 to 17% in 1993 due, in part, to transactional gains.
Non-utility operating revenues and expenses increased substantially in 1994 as compared to 1993, and to a lesser degree in 1993 as compared to 1992. These increases in both revenues and expenses have been the result of the acquisitions by Pentzer in 1994 and 1993. Pentzer acquired two companies in 1994 and three companies in 1993. Income taxes also increased substantially in 1994 due to increased revenues and income.
THE WASHINGTON WATER POWER COMPANY
LIQUIDITY AND CAPITAL RESOURCES
UTILITY
The Company funds capital expenditures with a combination of internally-generated cash and external financing. The level of cash generated internally and the amount that is available for capital expenditures fluctuates annually. Cash provided by operating activities remains the Company's primary source of funds for operating needs, dividends and construction expenditures.
Operating Activities Cash from operating activities less cash dividends paid provided 66% of utility capital expenditures in 1994 as compared to 67% in 1993 and 82% in 1992. Cash available from operating activities in 1994 declined from 1993 primarily due to both a reduction in operating income related to warmer than normal weather and an increase in various working capital components. The decline was partially offset by the positive effect of the PCA mechanism in 1994. See Note 1 to Financial Statements for additional information.
Investing Activities Cash used in investing activities increased in 1994 over 1993, despite a 14% decrease in construction expenditures, primarily due to the acquisition of the northern Idaho properties of PacifiCorp for $33 million. See Note 14 to Financial Statements for additional information. 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 $356 million for the 1992-1994 period.
Financing Activities During the 1992-1994 period, $60 million of long-term debt matured and $352 million of higher-cost debt and preferred stock was redeemed and refinanced at lower cost. In January 1994, the Company received authorization to issue $250 million in First Mortgage Bonds which are being issued in the form of Secured Medium Term Notes, Series B (Series B Notes). During 1994, $7.5 million of long-term debt, with an average interest rate of 8.93% and an average maturity of 5 years, were redeemed and $88 million of secured long-term debt were issued at an average interest rate of 7.99% and an average maturity of 9 years. On March 6, 1995, $15 million of Series B Notes were issued with an average interest rate of 7.60% and an average maturity of 6 years. As of March 6, 1995, $157 million of Series B Notes remained to be issued.
Capital expenditures are financed on an interim basis with notes payable (due within one year). The Company has $160 million in committed lines of credit. In addition, the Company may borrow up to $60 million through other borrowing arrangements with banks. As of December 31, 1994, $25 million was outstanding under the committed lines of credit and $33 million was outstanding under other short-term borrowing arrangements. In the fourth quarter of 1994, the Company eliminated its commercial paper program.
From time to time the Company enters into sale/leaseback arrangements for various long-term assets which provide additional sources of funds. See Note 9 to Financial Statements for additional information.
The Company's total common equity increased by $29 million during the year to $663 million at the end of 1994. The 1994 increase was primarily due to the issuance of 1.7 million shares of common stock through both the Dividend Reinvestment Plan and the Investment and Employee Stock Ownership Plan for proceeds of $26 million. No shares were issued under the Company's Periodic Offering Program in 1994. The utility capital structure at December 31, 1994, was 50% debt, 10% preferred stock and 40% common equity as compared to 49% debt, 10% preferred stock and 41% common equity at year-end 1993.
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 $464 million of First Mortgage Bonds could be issued as of December 31, 1994. As of December 31, 1994, under its Restated Articles of Incorporation, approximately $469 million of additional preferred stock could be issued at an assumed dividend rate of 9.00%.
During the 1995-1997 period, utility capital expenditures are expected to be $228 million, and $132 million will be required for long-term debt maturities and preferred stock sinking fund requirements. During this three-year period, the Company estimates that internally-generated funds will average 90% of the funds needed for its capital expenditure program. External financing will be required to fund maturing long-term debt, preferred stock sinking fund requirements and the remaining portion of capital expenditures. These projections relate to the Company on a stand-alone basis and do not reflect any adjustment for the effects of the proposed merger of the Company, Sierra Pacific Resources (SPR) and Sierra Pacific Power Company (SPPC) with and into Resources West Energy Corporation (Resources West). See below for details.
THE WASHINGTON WATER POWER COMPANY
See Note 4, 5, 6, 7, 8 and 9 to Financial Statements for additional details related to financing activities.
NON-UTILITY
Capital expenditures for the non-utility operations were $16 million for the 1992-1994 period. During this period, $1 million of debt was repaid and capital expenditures were partially financed by the $9 million in proceeds from new long-term debt.
The non-utility operations have $43 million in borrowing arrangements ($22 million outstanding as of December 31, 1994) to fund corporate requirements on an interim basis. At December 31, 1994, the non-utility operations had $34 million in cash and marketable securities with $13 million in long-term debt outstanding.
The 1995-1997 non-utility capital expenditures are expected to be $5 million, and $7 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.
TOTAL COMPANY CASH REQUIREMENTS
(1) Excludes $66 million for the combustion turbine project located in Rathdrum, Idaho for which the Company has obtained separate long-term lease financing; see Note 9 to Financial Statements for additional information. Also excludes $33 million for the 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. (2) These projections relate to the Company on a stand-alone basis and do not reflect any adjustment for the effects of the proposed merger of the Company, SPR and SPPC with and into Resources West (see below). (3) Excludes AFUDC and AFUCE. (4) Excludes notes payable (due within one year).
FUTURE OUTLOOK
Merger
In June 1994, the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power Company (SPPC), a subsidiary of SPR, and Resources West Energy Corporation, a newly formed subsidiary of the Company (Resources West), entered into an Agreement and Plan of Reorganization and Merger, as subsequently amended (Merger Agreement), which provides for the merger of WWP, SPR and SPPC into Resources West. SPR and SPPC are both Nevada corporations with headquarters in Reno. The Merger Agreement provides that after the effective date of the merger, Resources West's corporate headquarters offices and principal executive offices will be located in Spokane and that the headquarters of its Washington Water Power and Sierra Pacific operating divisions will be in Spokane and Reno, respectively. As a result of the Merger Agreement, holders of WWP Common Stock would receive one share and holders of SPR Common Stock would receive 1.44 shares of Resources West Common Stock, respectively. Each outstanding share of Preferred Stock of WWP and SPPC, respectively, will be converted into the right to receive one share of Resources West Preferred Stock with equal stated value and dividends and like redemption provisions and rights upon liquidation.
Approval of the proposed merger was obtained from WWP, SPR and SPPC shareholders at meetings held on November 18, 1994. The Merger Agreement is also subject to certain customary closing conditions, including,
THE WASHINGTON WATER POWER COMPANY
without limitation, the receipt of all necessary governmental approvals, including approval of the Federal Energy Regulatory Commission (FERC) and the state utility commissions of California (CPUC), Idaho (IPUC), Montana (MPSC), Nevada (PSCN), Oregon (OPUC) and Washington (WUTC). Applications were filed with each of the state commissions and the FERC in the third quarter of 1994. An order was issued by the MPSC on October 17, 1994, stating that they would not exercise jurisdiction over the proposed merger. Each of the other five states has set a separate calendar for filings and hearings. The FERC has not yet established a procedural schedule for this proposed merger but it is expected to be within the same timeframes as the state commissions. A number of entities have intervened or expressed their intent to intervene either at the Federal level or before the various state commissions. However, the Company anticipates receiving final orders from all jurisdictions and closing the merger transaction by the end of 1995.
WWP, SPR and SPPC believe that the proposed merger offers significant strategic and financial benefits to each of the companies and to their respective stakeholders including an enhanced competitive position, a larger and more diverse service territory, an expanded resource base, improved resource planning and coordination, and cost savings. Specifically, the Board of Directors of the Company believes that the merger would afford the following distinct benefits to the Company and its shareholders over the long term: (i) the potential for higher growth in revenues and earnings due to the higher load growth forecast in SPPC's retail electric service territory in comparison to the load growth forecast for the area now served by the Company, (ii) transmission access to additional western markets which would offer increased opportunities for wholesale power sales, (iii) moderation of future rate increases through estimated cost savings and increased retail and wholesale sales, (iv) a significant increase in the proportion of net income available for common stock represented by core utility cash earnings as opposed to non-utility earnings and non-cash items, and (v) a lower dividend payout ratio than the Company might be able to achieve on a stand-alone basis.
The cost savings are estimated to approximate $450 million, net of merger transaction and transition costs, over a 10 year period following the consummation of the merger. The cost savings should be achieved from, among other things, the integration of corporate management and administrative functions, the consolidation of distribution operations, the integration of natural gas purchasing requirements, the reduction of capacity requirements, the reduction of non-firm transmission expense, the avoidance of expenditures for operating systems, and the streamlining of inventories and purchasing economies. Since there will be an integration of corporate management and administrative functions, severance options and a voluntary early retirement plan are being offered to employees of the Company.
The analyses employed in order to develop estimates of specific amounts of savings to be achieved as a result of the merger were necessarily based upon various assumptions which involve judgments with respect to, among other things, future national and regional economic and competitive conditions, inflation rates, regulatory treatment, weather conditions, financial market conditions, interest rates, future business decisions, and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company, SPR, SPPC and Resources West. The Company believes that these assumptions are reasonable for the purpose of the development of estimates of cost savings but there is no assurance that such assumptions will approximate actual experience or that all such savings will be realized. Additionally, the treatment of the benefits and cost savings will depend on the terms of the regulatory approvals received in the various jurisdictions in which the Company and SPPC operate their businesses.
The regulatory plan proposed by the Company and SPPC includes a commitment to freeze base rates at their current levels in each jurisdiction until at least December 31, 1999, except for commodity cost increases and a small general increase in Nevada in 1997 for capital additions previously approved for SPPC by the PSCN. Ratemaking and regulation, in general, are anticipated to continue as before the merger with resources, costs and benefits allocated to each jurisdiction according to allocation methodologies agreed upon with each state commission. If the merger were consummated, the Company would avoid having to request retail rate increases effective between now and January 2000. These filings would otherwise be anticipated to request additional annual revenues of approximately $20 million. Resources West plans to develop, with its respective regulatory commissions, a longer-term regulatory plan for continued merger benefit savings commencing January 2000.
The service territories of WWP and SPPC are not physically connected. The only overlap in service territories is the South Lake Tahoe area in California where the Company provides natural gas service and SPPC provides the electric service. Both companies are jointly pursuing transmission access options and contracts, including Regional Transmission Groups, which will provide for the necessary interconnections to realize a portion of the expected merger-related savings. In February 1995, the Company and SPPC completed negotiations and have entered into letters of intent with the Idaho Power Company and Bonneville Power Administration (BPA) to acquire transmission rights between the two companies. The letters of intent contemplate new firm transmission purchases with Resources West having flexibility to exercise certain options in the future to expand its use of the transmission capabilities. The
THE WASHINGTON WATER POWER COMPANY
actual cost of the transmission rights will not vary significantly from that assumed in the original estimate of merger costs and benefits. Operational transmission interconnections are expected to be in place by the time the proposed merger is effective.
In the event that the merger is not completed due to circumstances beyond the Company's control, the Company would continue to operate as a separate utility and expense the merger costs that were incurred. The Merger Agreement does provide for the payment of a $25 million termination fee plus expenses to be made in certain circumstances where one party accepts another business combination proposal and, as a result, the Merger Agreement is terminated.
See Note 15 to Financial Statements for additional details.
Competition and Business Risk
The electric and natural gas utility businesses continue to undergo numerous transformations 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, active participation in the wholesale electric market and its commitment to high levels of customer satisfaction, cost reduction and continuous improvement of work processes. Additionally the Company continually evaluates merger and acquisition opportunities that will allow it to expand its economies of scale and diversify its risk posed by weather and economic conditions.
The Company continues to compete for new retail electric customers with various rural electric cooperatives and public utility districts in and adjacent to its service territories. Challenges facing the electric retail business include evolving technologies which provide alternate energy supplies, reduced energy consumption and the cost of the energy supplied, self-generation and fuel switching by commercial and industrial customers, the potential for retail wheeling, the costs of increasingly stringent environmental laws and the potential for stranded or nonrecoverable utility assets. 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. Similarly the Company does not believe it has much risk for stranded generation, transmission or distribution assets due to its low cost structure.
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.
The Company continues to compete in the wholesale electric market with other western utilities, including the BPA. Business challenges affecting the wholesale electric business include new entrants in the wholesale market, such as power brokers and marketers, competition from low cost generation being developed by independent power producers and declining margins. However, the Company's wholesale electric business remains an important part of the Company's overall business strategy.
Natural gas remains priced competitively compared to other alternative fuel sources for residential, commercial and industrial customers and is projected to remain so well into the future due to increasing supplies and competition. Challenges facing the Company's natural gas business include the potential for customers to by-pass the Company's natural gas system. Since 1988 two of the Company's large industrial customers have built their own pipeline interconnection. However, these customers continue to purchase natural gas services from the Company. To reduce the potential for such by-pass, the Company prices its natural gas services, including transportation contracts, competitively and has varying degrees of flexibility to price its transportation and delivery rates by means of special contracts. The Company has also signed long-term transportation contracts with two of its largest industrial customers which minimizes the risks of these customers by-passing the Company's system in the foreseeable future.
Order 636B adopted by FERC 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. The Company is also able to optimize its natural gas supply portfolio by engaging in some off-system sales.
Resource planning for both the electric and natural gas businesses has been integrated so that the Company's customers are provided the most efficient and cost-effective products possible for all their energy requirements. The
THE WASHINGTON WATER POWER COMPANY
Company's need for future electric resources to serve retail loads is expected to remain very minimal. The Company will be filing electric integrated resource plans with both the WUTC and IPUC in April 1995. 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. The 1995 natural gas integrated resource plan reports were submitted to the WUTC, IPUC and OPUC in January 1995 with acceptance anticipated by the end of 1995. The natural gas integrated resource plan is provided to the CPUC for informational purposes only.
Economic and Load Growth
The Company expects economic growth to increase in its eastern Washington and northern Idaho service area. 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 anticipates strong economic growth to continue in its Oregon and South Lake Tahoe, California service areas.
The Company anticipates electric retail load growth to average approximately 1.0% annually for the next five years primarily due to increases in both population and the number of businesses in its service territory. Although the number of electric customers is expected to increase, the average annual usage by residential customers is expected to 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 3.1% annually for the next five years. The Oregon and South Lake Tahoe, California service areas are anticipated to realize 5.1% growth annually during that same period. These growth forecasts have increased from the forecasts issued last year primarily due to fuel switching to natural gas necessitated by more stringent environmental laws that are being enacted.
Environmental Issues
Since December 1991, a number of species of fish in the Northwest, including the Snake River sockeye salmon and chinook salmon, the Kootenai River white sturgeon and the bull trout have either been added to the endangered species list under the Federal Endangered Species Act (ESA), listed as "threatened" under the ESA or been petitioned for listing under the ESA. Thus far, measures which have been adopted and implemented to save both the Snake River sockeye salmon and chinook salmon have not directly impacted generation levels at any of the Company's hydroelectric dams. The Company does, however, purchase power from four projects on the Columbia River that are being directly impacted by these ongoing mitigation measures. The reduction in generation at these projects is relatively minor, resulting in minimal economic impact on the Company at this time. Future actions to save these, and other as yet unidentified fish or wildlife species, could further impact the Company's operations or the operations of some of its major customers. However, it is currently impossible to predict likely economic costs to the Company resulting from these actions.
Electro-magnetic field (EMF) exposure, and its potential health hazards, continues to be an evolving issue facing electrical utilities. Studies are continuing by dozens of governmental and scientific agencies but the results to date are at best conflicting. Public concerns regarding EMF may cause the siting and construction of new power lines and substations to be more expensive. The Company is unable to determine at this time whether its operations may be adversely impacted by EMF issues.
See Note 11 to Financial Statements for additional information.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Independent Auditor's Report and Financial Statements begin on the next page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
INDEPENDENT AUDITORS' REPORT
The Washington Water Power Company Spokane, Washington
We have audited the accompanying consolidated balance sheets and statements of capitalization of The Washington Water Power Company and subsidiaries (the Company) as of December 31, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, 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 LLP
Seattle, Washington January 27, 1995 (February 2, 1995 as to Note 11)
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 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. As discussed in Note 14, the 1993 and 1994 operating results for ITRON are no longer consolidated and were accounted for on the equity method, and as of December 31, 1994 are now accounted for on the cost method.
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 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.
RECLASSIFICATIONS Certain prior year amounts related to segment information have been reclassified due to a current year change in the allocation method for common plant, plant-related costs and administrative and general expenses.
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 1994, 1993 and 1992. 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 or amortized into rates. 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.
THE WASHINGTON WATER POWER COMPANY
DEFERRED CHARGES AND CREDITS The Company prepares its financial statements in accordance with the provisions of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation." FAS No. 71 requires a cost-based, rate-regulated company to reflect the impact of regulatory decisions in its financial statements. In certain circumstances, certain costs and obligations, such as incurred costs not currently recovered through rates but expected to be recovered in the future, must be reflected in a deferred account in the balance sheet and not be reflected in income until matching revenues are recognized.
The primary regulatory assets include Investment in Exchange Power, Demand Side Management costs, the FAS 109 income tax deferral, the provision for FAS 106, and unrecovered purchased gas costs. Included in Deferred Charges, Other are debt issuance and redemption costs, which are amortized over the terms of the respective debt issues. Deferred credits include the gain on the general office building sale/leaseback being amortized over the life of the lease.
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 2.56% in 1994, 2.68% in 1993 and 2.37% in 1992.
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 1994 and 1992, the Company deferred $4.1 million and $3.3 million, respectively, of net power supply costs, which resulted in like decreases in electric operating expenses. In 1993, the Company deferred $4.6 million of net power supply cost savings, which resulted in like increases in electric operating expenses. Rate changes are triggered when the deferred balance reaches $2.2 million. On January 1, 1995, a $2.2 million surcharge was implemented for the next twelve months to recover costs resulting from low streamflow conditions during 1994. A rate increase was also implemented in November 1992 to pass through accumulated costs. As of December 31, 1994, $1.4 million of costs not yet subject to a rate increase had accumulated in the PCA deferral account. On July 18, 1994, the IPUC approved an indefinite extension of the PCA.
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 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 SHARE Earnings per 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
DERIVATIVE FINANCIAL INSTRUMENTS The Company's one involvement with derivative financial instruments is an interest rate cap agreement effective January 1995, for a three-year period, that sets a ceiling on the interest rate associated with a lease. Payments made under this agreement are being amortized to rent expense.
OTHER INCOME -- NET Other income-net is composed of the following items:
NEW ACCOUNTING STANDARDS Effective January 1, 1994, the Company adopted FAS No. 115, entitled "Accounting for Certain Investments in Debt and Equity Securities." Under FAS No. 115, investments in debt and marketable equity securities are classified as "available for sale" and are recorded at fair value. Investments totalling $34.1 million and $27.9 million are included on the Consolidated Balance Sheets as other property and investments and current assets, respectively. Unrealized investment gains, net of taxes, added $14.3 million to the Consolidated Statements of Capitalization as of December 31, 1994 as a separate component of shareholders' equity.
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 elected to amortize this obligation of approximately $34,500,000 over a period of twenty years.
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 and income from operations 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 1994, 1993 and 1992, the Company recognized $1,270,000, $1,250,000 and $1,290,000, 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, 1994 and 1993.
THE WASHINGTON WATER POWER COMPANY
Accumulated postretirement benefit obligation (thousands of dollars):
Net postretirement benefit cost for 1994 and 1993 consisted of the following components (thousands of dollars):
The currently assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation is 12% for 1994, decreasing linearly each successive year until it reaches 7% in 1998. 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, 1994 and net postretirement health care cost by approximately $1,552,000. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 8.5%.
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. The Company also has another plan which covers the executive officers.
THE WASHINGTON WATER POWER COMPANY
The funded status of the Plan and the pension liability at December 31, 1994, 1993 and 1992, are 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.
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 December 31, 1994 and 1993, respectively, the Company had recorded net regulatory assets of $174,349,000 and $177,786,000 related to the probable recovery of FAS No. 109 deferred tax liabilities from customers through future rates. Such net regulatory assets will be adjusted by amounts recovered through rates.
Deferred income taxes reflect the net tax effects of (a) temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes, and (b) tax credit carryforwards. The net deferred federal income tax liability consists of the following (thousands of dollars):
THE WASHINGTON WATER POWER COMPANY
A reconciliation of federal income taxes derived from statutory tax rates applied to income from continuing operations and federal income tax as set forth in the accompanying Consolidated Statements of Income and Retained Earnings is as follows (the current and deferred effective tax rates are approximately the same during all periods):
THE WASHINGTON WATER POWER COMPANY
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, 1994 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 and 1992, $25,000,000 and $113,000,000, respectively, of unsecured Medium-Term Notes, Series A and B were issued. At December 31, 1994, the Company had outstanding $242,500,000 of such notes with maturities between 1 and 29 years and with interest rates varying between 5.50% and 9.58%.
In 1994 and 1993, $88,000,000 and $225,000,000, respectively, of Secured Medium-Term Notes, Series A and B were issued. At December 31, 1994, the Company had outstanding $313,000,000 of such notes with maturities between 2 and 29 years and with interest rates varying between 4.72% and 8.25%. As of December 31, 1994, the Company had remaining authorization to issue up to $187,000,000 of such notes of the $250,000,000 originally authorized.
At December 31, 1994, the Company had $58,000,000 outstanding under borrowing arrangements which will be refinanced in 1995. 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, 1994 and 1993 is estimated to be $673.0 million, or 93% of the carrying value and $690.0 million, or 107% 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, 1994, 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, 1997, 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 0.1875% 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. In December 1994, the Company terminated its commercial paper program.
Balances and interest rates of bank borrowings under these arrangements were as follows:
Non-utility operations have $43 million of credit arrangements available. At December 31, 1994 and 1993, $22.3 million and $19.7 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, 1994 and 1993, $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 1994, the dividend rate varied from 3.000% to 4.950% and at December 31, 1994, was 4.950%. 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 $40 million in mandatory redemption requirements during the 1995-1999 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, 1994 and 1993 is estimated to be $135.1 million, or 100% of the carrying value and $93.8 million, or 110% 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 ($12,266,750 at December 31, 1994) 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 1994, the cost recorded for the Plan was $2,724,000. This included the cost for an additional 272,278 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 $1,195,000, $2,264,000 and $1,224,000, respectively.
In February 1990, the Company adopted a shareholder rights plan, which was subsequently amended, pursuant to which holders of Common Stock outstanding on March 2, 1990, or issued thereafter, have been granted one preferred share purchase right ("Right") on each outstanding share of Common Stock. Each Right, initially evidenced by and traded with the shares of Common Stock, entitles the registered holder to purchase one two-hundredth of a share of Preferred Stock of the Company, without par value, at an exercise price of $40, subject to certain adjustments, regulatory approval and other specified conditions. The Rights will be exercisable only if a person or group acquires 10% or more of the Common Stock or announces a tender offer, the consummation of which would result in the beneficial ownership by a person or group of 10% or more of the Common Stock. The Rights may be redeemed, at a redemption price of $0.005 per Right, by the Board of Directors of the Company at any time until any person or group has acquired 10% or more of the Common Stock. The Rights will expire on the earlier of February 16, 2000 and the effective time of the merger with SPR, SPPC and Resources West.
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, 1994, 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 1994 and 1993 are summarized below (in thousands of dollars):
NOTE 9. LEASES
The Company has entered into several lease arrangements involving various assets, with minimum terms ranging from eleven months to seventeen years and expiration dates from 1995 to 2011. The lease provisions obligate the Company to sell on behalf of the lessor or purchase the associated asset at a specified percentage of the asset's fair value if the lease is not renewed. Rent expense for the years ended December 31, 1994, 1993 and 1992 was $2.3 million, $1.9 million and $1.8 million, respectively. Future minimum lease payments (thousands of dollars) required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1994 are estimated as follows:
The Company also has various other operating leases, which are charged to operating expense, consisting of a large number of small, relatively short-term, renewable agreements for various items, such as office equipment and office space.
NOTE 10. 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. 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 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 only material claim against the Company arising out of the Company's involvement in Project 3, which has been pending since October 1982 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 was seeking a reallocation of $495 million in costs (plus interest since commencement of construction in 1976) originally allocated to Projects 4 and 5.
On January 24, 1995, the Company executed a Memorandum of Understanding (MOU) which is intended to settle all remaining claims in the "cost sharing" litigation. The other parties to the MOU are expected to include Chemical Bank, as trustee for the holder of Supply System Projects 4 and 5 bonds; the Supply System; BPA; certain public utility participants in those projects; and Puget Sound Power & Light Company (Puget), and Portland General Electric Company (PGE), Puget and PGE being two of the other three investor-owned utilities which held minority ownership interests in Project 3.
The MOU provides for the Company to pay $500,000 in settlement of all claims, and as part of a total $55,000,000 payment to Chemical Bank. In the MOU, the Company also agrees to give up any claims relating to the Company's bridge loans made to the Supply System in 1981. In exchange, the Company would be released from all pending cost-sharing litigation claims. The MOU contemplates and provides agreement on consolidation of the Project 5 and Project 3 sites for site restoration purposes, if BPA and the Supply System decide to thus consolidate the site. In the event that occurs, the Company would be completely indemnified from any additional costs by a separate agreement with BPA. Under the MOU, the Company's payment to Chemical Bank is due in July, 1995, and it is expected that a final settlement agreement and dismissal of the litigation will occur before or contemporaneously with that payment.
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 had been stayed pending a decision by the Court on a case involving some similar issues brought by the Tribe against Idaho Power Company. The Court has since decided these issues and has dismissed all claims against Idaho Power. The Idaho Power case has now been appealed by the Nez Perce Tribe to the Ninth Circuit Court of Appeals. On November 21, 1994, the Company filed its Motion and Brief in Support of Summary Judgment of Dismissal. The Nez Perce Tribe has filed a reply brief, and has requested oral argument. No hearing on the Company's Motion for Summary Judgment has been scheduled by the Court and the matter is not set for trial. The Company is presently unable to assess the likelihood of an adverse outcome in this litigation, or estimate an amount or range of potential loss in the event of an adverse outcome.
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, which was filed in 1982. 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 claimed the Company's dam interfered with Indian fishing rights and sought a declaratory judgment and quiet title to part of the property comprising the Little Falls Hydroelectric Development. However, the Company, the Tribe and the Bureau of Indian Affairs signed a settlement agreement on September 9, 1994. The Secretary of the Interior and the Tribe have executed an irrevocable easement and license to WWP to the property comprising the Little Falls Hydroelectric Development. The lawsuit has been dismissed with prejudice. The settlement agreement provides for an initial payment of $1.0 million to the Tribe plus an additional $3.2 million to be paid over the next five years for fish and wildlife enhancement projects. An accrual of $4.2 million was made during June 1994 and is reflected in the Company's financial statements. Annual payments will also be made to the Tribe, which will be tied to generation at the Little Falls Project and escalate at the rate of 4.1 percent per year, with the first installment of $375,000 expected to be paid by mid-April 1995.
OIL SPILL
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 spill. 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 approximately one city block beyond the steam plant property. On December 6, 1993, the Company asked the DOE to enter into negotiations for a Consent Decree which will provide for additional remedial investigation and a feasibility study. The Consent Decree, entered on November 8, 1994, provided for 22 additional soil borings to be made around the site, which have been completed. In December 1993, the Company established a reserve of $2.0 million, and in December 1994 increased it to $3.1 million based on more current estimates.
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. Four separate class action lawsuits were filed against the Company by private individuals in the Superior Court of Spokane County on October 13, 1993. These suits concern fires identified as Midway, Golden Cirrus, Nine Mile and Chattaroy. All of these suits were certified as class actions on September 16, 1994, and bifurcated for trial of liability and damage issues by order of the same date. The Company's Motion for Reconsideration was denied on October 21, 1994, and a Motion for Discretionary Review of the Court's decision on certification of class actions was timely filed with the Washington Court of Appeals (Division III) on November 14, 1994.
The Company was also served with two suits in Spokane County Superior Court filed on April 20, 1994 and on September 15, 1994, both of which sought individual damages from separate fires within the Chattaroy Fire complex. Five additional and separate suits were brought by Grange Insurance Company, and were filed in Spokane County Superior Court on October 10, 1994, for approximately $2.2 million paid to Grange insureds for the same fire areas. Two additional class action suits were also filed - one in Lincoln County Superior Court, filed on October 14, 1994, for a fire known as "Nine Mile West" (previously included in the Spokane County Nine Mile suit certified as a class action), and the second in Spokane County Superior Court, filed on October 14, 1994, for the Ponderosa Fire area (which had not been the subject of previous suit). Neither of these suits has yet been certified as a class action, although the Lincoln County suit has been transferred to Spokane County pursuant to decision of the Lincoln County Superior Court on February 21, 1995.
Complainants in all cases allege various theories of tortious conduct, including negligence, creation of a public nuisance, strict liability and trespass; in most cases, complainants allege that fires were caused by electric distribution lines downed by the wind. 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. Since little discovery has been conducted and the classes are not yet formed, the Company is presently unable to assess the
THE WASHINGTON WATER POWER COMPANY
likelihood of an adverse outcome or estimate an amount or range of potential loss in the event of an adverse outcome. The Company was previously presented with a claim from the Washington State Department of Natural Resources (DNR) for fire suppression costs associated with five of these fires in eastern Washington. The total of the DNR claim was $1.0 million. On July 22, 1993, the Company entered into a settlement with the DNR whereby the Company agreed to pay $200,000 to DNR in full settlement of any and all DNR claims; however, there was no admission of liability on the part of the Company.
WILLIAMS LAKE LAWSUIT
On February 2, 1995, a lawsuit was commenced in Spokane County Superior Court against the Company and its subsidiary, Pentzer, by Tondu Energy Systems, Inc. and T.E.S. Williams Lake Partnership alleging contract violations, conspiracy, misrepresentation and breach of fiduciary duties in regard to the 1993 sale of Pentzer Energy Services, Inc. to B.C. Gas, Inc. The suit claims damages in excess of $10 million, plus exemplary damages, prejudgment interest, costs and attorneys' fees. Also named as defendants are B.C. Gas, Inc., Inland Pacific Energy (Williams Lake) Corp. and the former Pentzer Energy Services, Inc., subsidiaries involved in the sale, WP Energy Company, WP Energy Canada, Ltd. and WP Energy Canada (Williams Lake) Ltd. The claims involve an alleged first right to purchase interests in the Williams Lake, British Columbia wood-fired generating station. Discovery with regard to the lawsuit has not yet commenced. The Company and Pentzer intend to vigorously defend against all of the claims.
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.
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, 1994:
THE WASHINGTON WATER POWER COMPANY
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, 1994, 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 1994. (3) Included in annual costs.
Actual expenses for payments made under the above contracts for the years 1994, 1993 and 1992, were $8,717,000 $8,721,000 and $8,433,000, 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 $3,829,000 in 1995, $3,750,000 in 1996, $3,616,000 in 1997, $5,355,000 in 1998 and $5,392,000 in 1999 (minimum payments thereafter are dependent on then market conditions). In addition, the Company will be required to pay its proportionate share of the variable operating expenses of these projects.
NOTE 14. ACQUISITIONS AND DISPOSITIONS
During 1994, Pentzer acquired two companies, one involved in bindery services for the advertising, printing, publishing and direct mail industries and the other in the design and manufacture of panel saws, panel routers and accessories. 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 in 1993. At December 31, 1994, Pentzer had approximately $167 million in assets compared to $130 million at the end of 1993.
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 was accounted for by the equity method and was included in Other Income-Net and its investment in ITRON was reflected on the balance sheet under Other Property and Investments. ITRON's initial public offering in November 1993 and Pentzer's sales of ITRON stock during 1993 and 1994 resulted in a reduction in Pentzer's ownership interest to approximately 14%. As a result, Pentzer's investment in ITRON, beginning in December 1994, is accounted for by the cost method.
THE WASHINGTON WATER POWER COMPANY
On December 30, 1994, the IPUC approved the transfer of ownership of all PacifiCorp's electric properties in northern Idaho to the Company. The cash purchase price was approximately $33 million. The Company commenced operations of the properties on January 1, 1995. The purchase adds approximately 9,800 customers. The Company reduced most customers' rates to 1% below PacifiCorp's current rates and instituted a four-year rate freeze. At the end of the rate freeze, rates will be adjusted to the levels then in effect in the Company's other service areas in northern Idaho. The Company believes this acquisition will not have a material impact on its operating revenues or its results of operations.
NOTE 15. PROPOSED MERGER
In June 1994, the Company, Sierra Pacific Resources (SPR), Sierra Pacific Power Company, a subsidiary of SPR (SPPC), and Resources West Energy Corporation, a newly formed subsidiary of the Company (Resources West) entered into an Agreement and Plan of Reorganization and Merger, dated as of June 27, 1994, as amended October 4, 1994 which provides for the merger of the Company, SPR and SPPC with and into Resources West. The merger is designed to qualify as a pooling-of-interests for accounting and financial reporting purposes. Under this method of accounting, the recorded assets and liabilities of WWP, SPR and SPPC will be carried forward to the consolidated financial statements of Resources West at their recorded amounts; income of Resources West will include income of WWP, SPR and SPPC for the entire fiscal year in which the merger occurs; and the reported income of the separate corporations for prior periods will be combined and restated as income of Resources West.
The cost savings from the merger are estimated to approximate $450 million, net of merger transaction and transition costs, over a 10 year period following the consummation of the merger.
The following pro forma condensed financial information combines the historical consolidated balance sheets and statements of income of WWP and SPR after giving effect to the merger. The unaudited pro forma condensed consolidated balance sheet at December 31, 1994 gives effect to the merger as if it had occurred at December 31, 1994. The unaudited pro forma condensed consolidated statements of income for each of the three years in the period ended December 31, 1994 give effect to the merger as if it had occurred at January 1, 1992. These statements are prepared on the basis of accounting for the merger as a pooling-of-interests and are based on the assumptions set forth in the paragraph below. The pro forma condensed financial information has been prepared from, and should be read in conjunction with the Company's historical consolidated audited financial statements and related notes thereto of which this note is a part and SPR's historical consolidated audited financial statements and related notes thereto included in reports filed by SPR pursuant to the Securities Exchange Act, as amended. The information contained herein with respect to SPR and its subsidiaries has been supplied by SPR. The information is not necessarily indicative of the financial position or operating results that would have occurred had the merger been consummated on the date, or at the beginning of the periods, for which the merger is being given effect, nor is it necessarily indicative of future operating results or financial position.
Intercompany transactions (including purchased and exchanged power transactions) between WWP and SPR during the periods presented were not material and, accordingly, no pro forma adjustments were made to eliminate such transactions. For comparative purposes, certain historical amounts have been reclassified to conform to the pro forma condensed financial statement format. The $450 million net cost savings estimated to be achieved by the merger are not reflected in the pro forma financial statements. All references to per share information for WWP have been adjusted to reflect the two-for-one common stock split which became effective on November 9, 1993. Pro forma per share data and common shares outstanding for Resources West give effect to the conversion of each share of WWP Common Stock into one share of Resources West Common Stock and the conversion of each share of SPR Common Stock into 1.44 shares of Resources West Common Stock.
THE WASHINGTON WATER POWER COMPANY
Pro Forma Condensed Consolidated Balance Sheet (in thousands of dollars):
At December 31, 1994 --------------------
Pro Forma Condensed Consolidated Statements of Income (in thousands of dollars, except per share amounts):
----
----
THE WASHINGTON WATER POWER COMPANY
NOTE 16. PROPERTY, PLANT AND EQUIPMENT
The year-end balances of the major classifications of property, plant and equipment are detailed in the following table (dollars in thousands):
THE WASHINGTON WATER POWER COMPANY
NOTE 17. 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 1994 and 1993 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 11, 1995.
Executive Officers of the Registrant
All of the Company's executive officers, with the exception of Messrs. Bryan, Ely, and Buergel and Ms. Racicot, were officers or directors of one or more of the Company's subsidiaries in 1994.
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 11, 1995.
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 11, 1995.
(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 11, 1995.
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, 1994, 1993 and 1992
Consolidated Balance Sheets, December 31, 1994 and 1993
Consolidated Statements of Capitalization, December 31, 1994 and
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994, 1993 and 1992
Schedule of Information by Business Segments for the Years Ended December 31, 1994, 1993 and 1992
Notes to Financial Statements
(a) 2. Financial Statement Schedules:
None
(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 June 27, 1994, regarding the Merger Agreement between the Company, Sierra Pacific Resources and Sierra Pacific Power Company.
Dated November 18, 1994 regarding the approval of the Merger Proposal by the shareholders of the Company.
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.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No. 2-81697 on Form S-8, in Registration Statement No. 2-94816 on Form S-8, in Registration Statement No. 33-49662 on Form S-3, in Registration Statement No. 33-51669 on Form S-3, in Registration Statement No. 33- 53655 on Form S-3 and in Registration Statement No. 33-54791 on Form S-8 of our report dated January 27, 1995 (February 2, 1995 as to Note 11) appearing in this Annual Report on Form 10-K of The Washington Water Power Company for the year ended December 31, 1994.
Deloitte & Touche LLP
Seattle, Washington March 7, 1995
EXHIBIT INDEX
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*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
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*Incorporated herein by reference. **Filed herewith.
EXHIBIT INDEX (continued)
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* Incorporated herein by reference. ** Filed herewith. *** Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.
EXHIBIT INDEX (continued)
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* Incorporated herein by reference. ** Filed herewith. *** Management contracts or compensatory plans filed as exhibits by reference per Item 601(10)(iii) of Regulation S-K.