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

ITEM 1. BUSINESS
THE COMPANY
The Company is an investor-owned public utility incorporated in the State of Washington furnishing electric service in a territory covering approximately 4,500 square miles, principally in the Puget Sound region of Washington State. The population of the Company's service area is over 1.8 million. In December 1993, the Company had approximately 804,600 total customers, consisting of 715,600 residential, 83,900 commercial, 3,800 industrial and 1,300 other customers. For the year 1993, the Company added approximately 17,500 customers, an annual growth rate of 2.2%. Growth in total kilowatt-hour sales to consumers increased 3.0% in 1993 over 1992, due to continuing growth in the number of customers in 1993 combined with unusually mild temperatures throughout 1992.
During 1993, the Company's billed revenues were derived 48% from residential customers, 34% from commercial customers, 14% from industrial customers and 4% from sales to other utilities and others. During this period, the largest single customer accounted for 3.1% of the Company's operating revenues. The average number of kilowatt-hours billed per residential customer served by the Company in 1993 was 12,674 kilowatt- hours. At December 31, 1993, the peak power resources of the Company were approximately 5,367,000 KW. The Company's historical peak load of approximately 4,615,000 KW occurred on December 21, 1990.
The Company is affected by various seasonal weather patterns throughout the year and, therefore, operating revenues and associated expenses are not generated evenly during the year. Variations in energy usage by consumers do occur from season to season and from month to month within a season, primarily as a result of weather conditions. The Company normally experiences its highest energy sales in the first and fourth quarters of the year. Sales to other utilities also vary by quarters and years depending principally upon water conditions for the generation of surplus hydro- electric power, customer usage and the energy requirements of other utilities. With the implementation of the Periodic Rate Adjustment Mechanism ("PRAM") in October 1991, earnings are no longer significantly influenced, up or down, by sales of surplus electricity to other utilities or by variations in normal seasonal weather or hydro conditions. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters")
The electric utility industry in general is experiencing intensifying competitive pressures, particularly in wholesale generation and industrial customer markets. The National Energy Policy Act of 1992 was designed to increase competition in the wholesale electric generation market by easing regulatory restrictions on producers of wholesale power and by authorizing the Federal Energy Regulatory Commission ("FERC") to mandate access to electric transmission systems by wholesale power generators. The potential for increased competition at the retail level in the electric utility industry through state-mandated retail wheeling has also been the subject of legislative and administrative interest in a number of states, including the state of Washington. Electric utilities, including the Company, now face greater potential competition for resources and customers from a variety of sources, including privately owned independent power producers, exempt wholesale power generators, industrial customers developing their own generation resources, suppliers of natural gas and other fuels, other investor-owned electric utilities and municipal generators. All four of the major credit rating agencies have expressed the view that competitive developments in the electric utility industry are likely to increase business risks, with resulting pressure on utility credit quality. One of the rating agencies has stated that it is revising its financial ratio guidelines for electric utilities to reflect the changing risk profiles within the industry. These rating agency actions may result in higher capital costs and more limited access to capital markets for electric utilities, including the Company.
Although the Company to date has not experienced any significant adverse impact on its business from these industry trends, the Company has taken a number of steps to prepare for a more competitive business environment. These include programs to become a lower-cost producer by improving productivity and reducing the work force. The Company is also reviewing the extent of its investment in regulatory assets that may not be readily marketable to others in a competitive marketplace. The Company is seeking state legislation to provide a firm statutory basis for recovery of demand-side management regulatory assets associated with the Company's conservation programs.
During the period from January 1, 1989 through December 31, 1993, the Company made gross utility plant additions of $752 million and retirements of $84 million. Gross electric utility plant at December 31, 1993 was approximately $3.1 billion.
The Company had 2,609 full-time equivalent employees on December 31, 1993.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the Washington Utilities and Transportation Commission (the "Washington Commission") as to rates, accounting, the issuance of securities and certain other matters, and (2) the FERC in the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale for resale, accounting and certain other matters. The Washington Commission consists of three Commissioners, each appointed for a six-year term by the Governor of the State of Washington.
On September 21, 1993, the Washington Commission issued two rate orders, one regarding the Company's request for an increase in general rates, the other related to an annual rate adjustment under the PRAM. In its revised general rate request, the Company had requested a $97 million increase and in its PRAM request it had requested a first year recovery of between $27.6 and $38.1 million.
The Washington Commission authorized a general rate increase of $21.9 million, reflecting increased costs of service, and collection of $35.7 million in the first year to recover previously deferred costs under the PRAM. The total increase in rates of $57.6 million was effective October 1, 1993. The Washington Commission also authorized the Company to increase rates by an additional $3.9 million effective October 1, 1993 to recognize, prospectively, the effect of the increase in the Federal corporate income tax rate from 34 to 35 percent.
The general rate order also required the Company to file a case by November 1, 1993, demonstrating the prudency of its eight new power purchase contracts acquired since its last general rate case. Pending the resolution of the prudency review case, the Washington Commission ordered that the Company's new rates which became effective October 1, 1993, would be collected subject to refund to the extent this proceeding demonstrates any of those contracts to be imprudent. The Washington Commission calculated the annual revenue requirement at risk to be up to $86.1 million.
The general rate case order allows a 10.5% return on common equity and 8.94% return on rate base, based on a capital structure of 47% debt, 8% preferred stock and 45% common equity. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.")
The decrease in allowed return on equity from 12.8 percent in the last general rate case to 10.5 percent approved in the present rate case has put downward pressure on earnings since the order became effective on October 1, 1993. In addition, it will be difficult for the Company to earn its full allowed rate of return because of changes made by the rate orders in the recovery methods of certain costs. Therefore, the Company continues to place strong emphasis on its ongoing improvement efforts designed to increase operating efficiencies.
POWER RESOURCES
During 1993, the Company's total energy production was supplied 30% by its own resources, 27% through long-term firm contracts with several of the PUDs that own hydroelectric projects on the Columbia River, 37% from other firm purchases and 6% from non-firm purchases.
The following table shows the Company's resources at December 31, 1993, and energy production during the year:
Peak Power Resources at December 31, 1993 1993 Energy Production ----------------------- ---------------------- Kilowatts % Kilowatt-Hours % --------- ----- -------------- ----- (Thousands) Hydro: Company resources 309,950 5.8 1,204,164 5.7 Purchased (Columbia River PUD Contracts) 1,474,282 27.5 5,681,522 26.8 Purchased (other)(a) 829,886 15.4 3,293,131 15.5 - ---------------------------------------------------------------------------- Total Hydro 2,614,118 48.7 10,178,817 48.0 - ---------------------------------------------------------------------------- Thermal: Company resources: Coal 771,900 14.4 4,790,625 22.6 Natural gas/oil 788,150 14.7 419,522 2.0 Purchased(a) 1,191,914 22.2 5,808,724 27.4 - ---------------------------------------------------------------------------- Total Thermal 2,751,964 51.3 11,018,871 52.0 - ---------------------------------------------------------------------------- Total Capability 5,366,082 100.0% 21,197,688 100.0% ============================================================================
(a) Power received from other utilities is classified between hydro and thermal based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource.
The Pacific Northwest depends on the accumulation of snow in the Rocky and Cascade mountain ranges to supply the region's Columbia River hydroelectric resources. The Company derives much of its power supply from the Columbia River projects. For the third consecutive winter, snowpack was substantially below normal due to dry weather.
Forecasts completed in early March 1994, indicate that the projected streamflow affecting the principal hydroelectric facilities from which the Company receives power is expected to be only 82 percent of normal for the period January through July, 1994. This reduction should not have a significant impact on the Company's ability to meet customer energy demands as it has recently entered into long term contracts to buy the output of four new cogeneration projects. The Company also owns 700 MW of installed combustion turbine capacity which can be used as an alternative energy supply under certain market conditions. Substantially all cost increases of combustion turbine operation or other alternative power supplies are expected to be recovered in rates through the PRAM mechanism.
Company Owned - -------------
The Company and other utilities are joint owners of four mine-mouth, coal-fired, steam-electric generating units at Colstrip, Montana, approximately 100 miles east of Billings. The Company owns a 50% interest (330,000 KW) in Units 1 and 2 and a 25% interest (350,000 KW) in Units 3 and 4. The Company's share of the output of all four Colstrip units is transmitted over two 500 KV transmission lines from Colstrip to a point of interconnection with the main Northwest transmission grid at Garrison, Montana.
The owners of the Colstrip Units purchase the coal requirements for the units from Western Energy Company, an affiliate of Montana Power - one of the joint owners, under the terms of long-term coal supply agreements, with escalation provisions to cover actual mining cost increases and inflationary factors. These contracts are expected to satisfy the majority of the requirements for the units over their anticipated useful life.
A contract price reopener for both the base price and adjustment provisions of the Colstrip 1 & 2 Coal Supply Agreement became effective July 30, 1991. A dispute exists between the buyers, including the Company, and the seller on this reopener. This dispute will be arbitrated in the 4th quarter of 1994, the outcome of which is not expected to have material adverse impact on the financial condition or results of operations of the Company.
The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-electric generating plant near Centralia, Washington, with a net capability of 1,313,000 KW. In 1991, the Company and other owners of the Centralia Project renegotiated a long-term coal supply agreement with Pacific Power & Light Company.
The Company also has the following plants with an aggregate net generating capability of 1,098,100 KW: Upper Baker River hydro project (103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400 KW) reconstructed in 1968; White River hydro plant (63,400 KW) constructed in 1912 with installation of the last unit in 1924; Snoqualmie Falls hydro plant (44,000 KW), half the capability of which was installed during the period 1898 to 1910 and half in 1957; two smaller hydro plants, Electron (26,400 KW) and Nooksack Falls (1,750 KW), constructed during the period 1904 to 1929; Shuffleton residual oil-fired steam-electric generating plant (85,800 KW) constructed in 1929-30; a standby internal combustion unit (2,750 KW) installed in 1969; two oil-fired combustion turbine units (28,500 KW and 67,500 KW) installed in 1972 and 1974, respectively; four combustion turbine units (89,100 KW each) installed during 1981; and two combustion turbine units (123,600 KW each) installed during 1984.
The Company's combustion turbines installed in 1981 and 1984 may be fueled with natural gas or distillate oil. The Company has not entered into contracts which assure a future long-term supply or price of fuel for the Company's combustion turbines, and the future availability and prices of fuel for the Company's combustion turbines are not assured.
The Company has applied to the FERC for an initial license for its existing and operating White River project and authorization to install an additional 14,000 KW generating unit. The Company also has applied for a license for a proposed 8,000 KW capacity project at Nooksack Falls to replace the existing 1,750 KW capacity unlicensed facility. The initial license for the Snoqualmie Falls project expired in December 1993, and the Company is continuing the FERC application process to relicense the project and increase its capacity from 44,000 KW to 73,000 KW. FERC has granted a license extension through December 1994, and under its present policies will continue to grant one year extensions until the relicensing process is completed.
Columbia River Projects - -----------------------
The purchase of power from the Columbia River projects is generally on a "cost of service" basis under which the Company pays a proportionate part of the annual debt service and operating and maintenance costs of each project in direct ratio to the amount of power annually allocated to it. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements or license requirements. The average cost of power purchased from these projects is approximately 11.9 mills per KWH.
As of December 31, 1993, the Company was entitled to purchase portions of the power output of the PUDs' projects as set forth in the following tabulation: Company's Annual Amount Bonds Purchasable (Approximate) Outstanding -------------------------- Contract License 12/31/93(a) % of Kilowatt Costs(b) Project Exp.Date Exp.Date (Millions) Output Capacity (Millions) - ------------------------------------------------------------------------------ Rock Island Original units(c) 2012 2029(d) $ 79.8 62.5 ) ) 507,000 $ 45.7 Additional units 2012 2029(d) 326.8 100.0 ) Rocky Reach 2011 2006(e) 186.0 38.9 504,922 15.0 Wells 2018 2012(e) 199.9 34.8 292,320 10.0 Priest Rapids 2005 2005(e) 141.2 8.0 71,760 2.1 Wanapum 2009 2005(e) 189.4 10.8 98,280 2.8 - ------------------------------------------------------------------------------ Total 1,474,282 $ 75.6 ============================================================================== (a) The contracts for purchases are generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration dates are: 69.3% at Rock Island; 20.1% at Rocky Reach; 59.8% at Priest Rapids; and 39.4% at Wanapum.
(b) Estimated debt service and operating costs for the year 1994. The components of 1994 costs associated with the interest portion of debt service are: Rock Island, $27.78 million for all units; Rocky Reach, $5.01 million; Wells, $3.42 million; Priest Rapids, $0.68 million; and Wanapum, $1.16 million.
(c) For the period July 1, 1994 through June 30, 1995, the Company will pay 76.4% of the debt service and operating costs of the original units. This percentage will decrease thereafter in approximate relationship to the Company's share of the output until it reaches 50% on July 1, 1999 (see below).
(d) Under a settlement agreement, FERC granted Chelan a license for 40 years beginning January 18, 1989.
(e) The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees or what effect the term of the licenses may have on the Company's contracts. - --------------------
The Company has contracted to purchase a share of the output of the original units of the Rock Island Project that equals 63.5% through June 30, 1994, decreases gradually to 50% of the output until July 1, 1999, and remains unchanged thereafter for the duration of the contract. The Company has contracted to purchase the entire output of the additional Rock Island units for the duration of the contract, except that the Company's share of output of the additional units may be reduced not in excess of 10% per year beginning July 1, 2000, to a minimum of 50% upon the exercise of rights of withdrawal by Chelan for use in its local service area. The Company has contracted to purchase a share of the output of the Rocky Reach Project that remains unchanged for the duration of the contract. Under terms of a withdrawal of power settlement, the Company's share of the output of the Wells Project is currently 34.8%. However, the Company's share of the output can be reduced to 31.3% at any time upon the exercise of withdrawal rights by Douglas County PUD. The Company has contracted to purchase a share of the output of the Priest Rapids and Wanapum projects that remains unchanged for the duration of the contracts.
Seven of the eleven turbines at Rocky Reach are in the process of being replaced. Studies are currently underway that are expected to lead to the replacement of the remaining four units. Turbine replacement is planned for all ten units at Wanapum. Also, as a result of FERC Settlements, it is anticipated that installation of fish screens will be required at Rocky Reach, Rock Island, Priest Rapids and Wanapum Dams. These multi-year capital projects are expected to result in increases in annual power costs as they progress.
In 1964, the Company and fifteen other utilities and agencies in the Pacific Northwest entered into a long-term coordination agreement extending until June 30, 2003. This agreement provides for the coordinated operation of substantially all of the hydroelectric power plants and reservoirs in the Pacific Northwest. Among other things, it increases the ability of the Company to meet its customers' requirements with existing resources during periods of insufficient stream flows or forced outages of equipment.
Certain utilities in the northwest United States and Canada are obtaining the benefits of over 1,000,000 KW of additional power as a result of the ratification of a treaty between the United States and Canada under which Canada is providing approximately 15,500,000 acre-feet of storage on the upper Columbia River. As a result of this storage, the Company obtains firm power based upon its percentage entitlement under its Columbia River contracts, currently approximately 163,800 KW. In addition, the Company has contracted to purchase 17.5% of Canada's share of the power resulting from such storage (132,100 KW capacity and 49,500 KW average energy in the 1993-94 contract year, April 1 to March 31, which amounts decrease gradually until expiration of the contract in 2003). The Company has also contracted to purchase from BPA supplemental capacity in amounts that decrease gradually until expiration of the contract in 2003. The amount of supplemental capacity currently purchased is approximately 43,900 KW.
See "ENVIRONMENT - Federal Endangered Species Act" for discussion of the fishery enhancement plan related to these projects. Contracts and Agreements with Other Utilities - ---------------------------------------------
On September 17, 1985, the Company and BPA entered into a settlement agreement settling the Company's claims against BPA resulting from BPA's action in halting construction on WPPSS Nuclear Project No. 3 in which the Company has a five percent interest. The settlement includes a Settlement Exchange Agreement ("Bonneville Exchange Power Contract") under which the Company is receiving from BPA for a period of approximately 30.5 years, beginning January 1, 1987, a certain amount of power determined by a formula and depending on the equivalent annual availability factors of several surrogate nuclear plants. The power is received during the months of November through April. Under the contract, the Company is guaranteed to receive not less than 191,667 MWH in each contract year until the Company has received total deliveries of 5,833,333 MWH. BPA may request energy at times not needed by the Company during the months of September through June of each contract year. The payment to the Company for such energy would be based on the actual costs to produce such energy up to the operating and maintenance costs of the Company's oil and natural gas fired combustion turbines.
The Company is entitled to receive 80,000 KW of capacity and 68,000 KW of average energy from BPA under a WPPSS Nuclear Power Unit 1 Exchange Agreement through June 30, 1996. The calculation of the cost of the energy and capacity received by the Company has been in dispute, and the Company in 1990 entered into a settlement agreement with WPPSS and BPA as to prices for the July 1, 1990 through June 30, 1996 period. These prices range between 4.3 cents and 4.842 cents per KWH and are subject to certain increases or decreases as a result of settlement of or judgment on cost sharing claims with respect to the allocation of costs among WPPSS projects.
On April 14, 1983, the Company contracted to purchase the output of Grays Harbor PUD's 4% interest (52,520 KW) in the Centralia generating plant subject to withdrawal on at least 7 years' notice. Grays Harbor PUD issued such notice in 1990; therefore this contract will terminate on June 30, 1997.
On April 4, 1988, the Company executed a 15-year contract for the purchase of firm energy supply from Washington Water Power Company. This agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of energy from the Washington Water Power system annually (75 annual average MW). Minimum and maximum delivery rates are prescribed. Under this agreement, the energy is to be priced at Washington Water Power's average generation and transmission cost.
On October 27, 1988, the Company executed a 15-year contract for the purchase of firm power and energy from Pacific Power & Light Company. Under the terms of the agreement, the Company receives 120 average MW of energy and 200 MW of peak capacity.
On November 23, 1988, the Company executed an agreement to purchase surplus firm power from BPA. Under the agreement, the Company receives 150 average MW of energy and 300 MW of peak capacity from BPA between October 1 and March 31 of each contract year. The contract extends for 20 years, ending in 2008. The sale will convert to a power-for-power exchange on June 30, 2001, or earlier, if BPA provides the Company with a five-year notice that it no longer has surplus energy available to support the power sale.
On October 1, 1989, the Company signed a contract with Montana Power under which Montana Power provides, from its share of Colstrip Unit 4, to the Company 71 average MW of energy (94 MW of peak capacity) over a 21-year period.
On December 11, 1989, the Company executed a conservation transfer agreement with Snohomish County PUD. Snohomish County PUD, together with Mason and Lewis County PUDs, will install conservation measures in their service areas. The agreement calls for the Company to receive the power saved over the expected 20-year life of the measures. The agreement calls for BPA to deliver the conservation power to the Company from March 1, 1990 through June 30, 2001, and for Snohomish County PUD to deliver the conser- vation power for the remaining term of the agreement. Power deliveries gradually increase over the first five years of the agreement, roughly matching the installation of the conservation measures, and will reach six average MW of energy in the fifth year. Under the agreement, deliveries of conservation power will then remain at six average MW of energy throughout the term of the agreement.
The Company executed an exchange agreement with Pacific Gas & Electric Company which became effective on January 1, 1992. Under the agreement, 300 MW of capacity together with 413,000 MWH of energy are exchanged every year on a unit for unit basis. No payments are made under this agreement. Pacific Gas & Electric Company is a summer peaking utility and will provide power during the months of November through February. The Company is a winter peaking utility and will provide power during the months of June through September. By giving proper notice, either party may terminate the contract for various reasons.
Contracts and Agreements with Non-Utilities - -------------------------------------------
The Company has contracted to purchase the output from a number of non- utility generating resources. The Company currently has available 410 MW of capacity from gas cogeneration, 40.5 MW from small hydro generation and 28 MW from municipal solid waste and others.
In addition, the Company will add 245 MW of capacity in 1994 in the form of purchased power contracts with independent producers of gas-fired cogeneration. The Company's payments under these contracts are subject to the delivery of power. (See Note 14 to the Consolidated Financial Statements for further discussion.)
Other Resources - ---------------
The Company offers programs designed to help new and existing customers conserve electric energy. In the residential sector, free energy audits, cash grants, and on-site inspection of cost-effective energy conservation improvements generate a significant share of KWH savings. Further energy conservation savings are realized through electric water heater programs, energy efficient lighting rebates and special programs targeted at low-income customers. The commercial and industrial energy management programs offer customers engineering audits, computerized analyses, bid design criteria, cash grants and follow-up verification for a wide variety of electrical efficiency improvements. Energy conservation measures installed in 1993 are expected to result in annualized savings of approximately 260,400 MWH.
The Company's energy conservation expenditures are accumulated and amortized to expense over a ten year period at the direction of the Washington Commission. The Company's total unamortized conservation balance at December 31, 1993, was $234 million. The amount included in rate base by the Washington Commission in its September 1993 order based on expenditures through April 30, 1993, was $201 million. The Washington Commission has authorized the Company to accrue, as non-cash income, the carrying costs on energy conservation expenditures until such investments are reflected in rates. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.")
CONSTRUCTION FINANCING
The Company estimates its construction expenditures, which include energy conservation expenditures and exclude Allowance for Funds Used During Construction ("AFUDC") and Allowance for Funds Used to Conserve Energy ("AFUCE"), for 1994 and 1995 to be $261 million and $200 million, respectively. The estimate for 1994 includes a $72 million payment to BPA for capacity rights to the third AC transmission line. The Company expects to fund an average of 68% of its estimated construction expenditures (excluding AFUDC and AFUCE) in 1994 and 1995 from cash from operations (net of dividends and AFUDC), and to fund the balance through the sale of securities. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of the Company's construction program.) The Company's ability to finance its future construction program is dependent upon maintaining a level of earnings sufficient to permit the sale of additional securities. In determining the type and amount of future financings, the Company may be limited by restrictions contained in its Mortgage Indenture, Articles of Incorporation and certain loan agreements.
Under the most restrictive tests, at December 31, 1993, the Company could issue (i) approximately $709 million of additional first mortgage bonds or (ii) approximately $564 million of additional preferred stock at an assumed dividend rate of 7.00% or (iii) a combination thereof.
ENVIRONMENT
The Company's operations are subject to environmental regulation by federal, state and local authorities. Capital expenditures for environmental controls on all Company facilities are estimated at $29.4 million for the period 1994 through 1996. Due to the inherent uncertainties surrounding the development of federal and state environmental and energy laws and regulations, the Company cannot determine the impact such laws may have on its existing and future facilities.
Federal Comprehensive Environmental Response, Compensation and Liability Act, and the Washington State Model Toxics Control Act - ---------------------------------------------------------------- The federal Comprehensive Environmental Response, Compensation and Liability Act (commonly referred to as the "Superfund Act") subjects certain parties to liability for remedial action at contaminated disposal sites.
The Company has been named by the Environmental Protection Agency ("EPA") as a Potentially Responsible Party ("PRP") at four sites in Washington State, which are: two locations formerly operated by Northwest Transformer, Inc. at Mission-Pole and South Harkness in Whatcom County; a site formerly operated by Ross Electric, Inc. at Coal Creek in Lewis County; and a site formerly operated by Simon & Sons, Inc. in Pierce County. A settlement was reached in July 1991 with the EPA on the Simon & Sons site in which the Company paid approximately $442,000. A settlement was reached with the EPA on the Northwest Transformer/Mission-Pole site in a Consent Decree approved by Federal Court in January 1992. Current estimates of future remedial costs by the Company under that settlement are approximately $0.7 million. A settlement was reached with the EPA for the Ross Electric/Coal Creek site in a Consent Decree approved by Federal Court in February 1992. Based upon December 1993 estimates of future remedial costs, the Company's estimated share would be approximately $0.3 million. A settlement was reached with the EPA on June 7, 1992, for the Northwest Transformer/South Harkness site in an Administrative Order of Consent in which the PRPs agreed to conduct a Remedial Investigation & Feasibility Study. Based on a December 1993 estimate of future costs, the Company's share would be approximately $1.6 million.
The above sites represent all significant Superfund sites currently known to the Company. There is, however, no assurance that all contaminated sites and contaminants for which the Company may have a responsibility have been identified or that remedial actions planned to date at current sites, including actions pursuant to consent decrees, will be adequate.
The Company has remediated two locations at the Company's Electron Generating Station which had been contaminated with chemicals formerly used to treat wooden timbers. These sites had been listed as Priority 1 by the Washington State Department of Ecology ("WDOE") because of potential groundwater contamination. Remedial actions at these sites under provisions of the state's Model Toxics Control Act began in 1991 and were completed in 1992. A final remedial report has been filed with the WDOE.
The Company is also participating in a joint research project with the Electric Power Research Institute to clean up the Snoqualmie Railroad site in the town of Snoqualmie, Washington. The site has been leased from the Company since 1959 by the non-profit Puget Sound Railway Historical Association. The contamination consists of heavy petroleum hydrocarbons which were used as lubricants for railroad equipment. The purpose of the project is to provide a field demonstration of new technologies to treat heavy molecular weight petroleum hydrocarbons in soil. Remediation of the research project was completed in February 1994.
The Company has also commenced a program to test, replace and take remedial actions on certain underground storage tanks as required by federal and state laws. Remedial actions and testing of Company vehicle service facilities and storage yards have also been commenced. (See Note 14 to the Consolidated Financial Statements for further discussion of environmental obligations and the related regulatory treatment.)
Federal Clean Air Act Amendments of 1990 - ----------------------------------------
The Company has an ownership interest in coal-fired, steam-electric generating plants at Centralia, Washington and Colstrip, Montana which are subject to the federal Clean Air Act Amendments of 1990 ("CAAA") and other regulatory requirements.
The Centralia Project and the Colstrip Projects meet the sulfur dioxide limits of the CAAA in Phase I (1995). Pacific Power & Light Company, which operates the Centralia Project, is working on compliance plans to meet the Phase II limits in the year 2000.
Montana Power, which operates the Colstrip 3 & 4 Project, is working to meet the Phase II limits in the year 2000. Under the CAAA, allowances may be used to achieve compliance. It is believed that Units 1 and 2 may have an excess of allowances above what is currently set for Phase II requirements and that Units 3 and 4 appear to have enough allowances for Phase II requirements.
The Company owns combustion turbine units which are capable of being fueled by natural gas or oil. The nature of these units provides operational flexibility in meeting air emission standards.
There is no assurance that in the future environmental regulations affecting sulfur dioxide or nitrogen oxide emissions may not be further restricted, and there is no assurance that restrictions on emissions of carbon dioxide or other combustion by-products may not be imposed.
Federal Endangered Species Act - ------------------------------
In November 1991, the National Marine Fisheries Service ("NMFS") listed the Snake River Sockeye as an endangered species pursuant to the federal Endangered Species Act. Since the Sockeye listing, the Snake River fall and spring/summer Chinook have also been listed as threatened. In response to the listings, a team of experts was formed to develop a plan for the recovery needs of these species. In anticipation of the listings, the Northwest Power Planning Council ("NWPPC") previously developed a fishery enhancement plan which combines increased springtime flows with habitat enhancements, harvest reductions, and other measures. The spring flow augmentation portion of the plan began in 1991. The draft plan developed by the NMFS recovery team late in 1993 concludes that there is no scientific evidence that increased flows during the spring outmigration period enhance fish survival. The recovery team essentially advocates a continuation of the flows called for in the Council's program, unless or until scientific research dictates something different. When finalized, the recovery team's plan may be used by the NMFS as the recovery plan required pursuant to the Act, but there is no assurance NMFS will in fact use that plan instead of some other plan. Federal agencies which operate the Federal Columbia River Power System must consult with the NMFS to determine whether any action they undertake will unduly jeopardize the listed species. Measures recently announced by NMFS covering the period 1994 through 1998 are the result of the most recent of those consultations. In general, the measures require the federal agencies to release more water during the spring and summer for fish enhancement than is required by either the NWPPC Fish and Wildlife Program or that recommended by the draft recovery plan.
The NWPPC plan and plans developed by NMFS affect the Mid-Columbia projects from which the Company purchases power on a long-term basis, and will further reduce the flexibility of the regional hydroelectric system. Although the full impacts are unknown at this time, the plan ultimately developed by NMFS could shift an amount of the Company's generation from the Mid-Columbia projects from winter periods into the spring when it is not needed for system loads, and will increase the potential for spill and loss of generation at the Mid-Columbia projects. Under the Council's plan presently in effect, in years of critical water flows, the maximum amount of generation that the company would have to transfer to the spring is limited to approximately 275,000 MWH. The Company's share of energy production from the Mid-Columbia during 1993 was approximately 5,682,000 MWH and the total production from all resources was more than 21,198,000 MWH.
Other species are also proposed for listing and could further restrict system flexibility and energy production.
Puget Sound Power & Light Company
EXECUTIVE OFFICERS AT DECEMBER 31, 1993:
Name Age Offices - ---------------- --- ---------------------------------------------------
R. R. Sonstelie 48 President and Chief Executive Officer since 1992; President and Chief Operating Officer 1991-1992; President and Chief Financial Officer 1987-1991; Executive Vice President 1985-1987; Senior Vice President Finance 1983-1985; Vice President Engineering and Operations 1980-1983; Director since 1987.
W. S. Weaver 49 Executive Vice President and Chief Financial Officer and Director since 1991. For more than five years prior to that time, a Partner in the law firm Perkins Coie.
N. L. McReynolds 59 Senior Vice President Corporate Relations since 1987; Vice President Corporate Relations 1980-1987.
R. V. Myers 60 Senior Vice President Operations since 1985; Vice President Engineering and Operations 1983-1985; Vice President Generation Resources 1980-1983.
R. G. Bailey 54 Vice President Power Systems since 1980.
J. W. Eldredge 43 Corporate Secretary and Controller since 1993; Controller since 1988; Manager Budgets and Performance 1987-1988; Manager General Accounting 1984-1987.
W. J. Finnegan 61 Vice President since January 11, 1994; Vice President Engineering 1986-1994; Director Environmental and Resource Services 1981-1986.
J. L. Henry 48 Vice President Engineering and Operating Services since January 11, 1994; Vice President Operations Services 1991-1994; Director South Central Division 1990-1991; Director Division Operations 1984-1990.
C. A. Knutsen 47 Vice President Administration and Corporate Services since February 10, 1994; Vice President Corporate Planning 1989-1994; Director Strategic Planning 1987-1988; Manager Demand and Resource Evaluation Project 1986-1987.
J. R. Lauckhart 45 Vice President Power Planning since 1991; Director Power Planning 1986-1991.
R. E. Olson 62 Vice President Finance and Treasurer since 1987; Vice President Financial Control 1986; Vice President and Treasurer 1980-1986.
G. B. Swofford 52 Vice President Divisions and Customer Services since 1991; Vice President Rates and Customer Programs 1986-1991; Director Conservation and Division Services 1980-1986.
S. M. Vortman 48 Vice President Strategic Planning and Regulatory Affairs since February 10, 1994; Vice President Corporate Services 1992-1994; Director Real Estate 1990-1992; Manager Community and Economic Development 1986-1990.
Officers are elected for one-year terms.
ITEM 2.



ITEM 2. PROPERTIES
The principal generating plants owned by the Company are described under Item 1 - "Business - Power Resources." The Company owns its transmission and distribution facilities, and various other properties. Substantially all properties of the Company are subject to the lien of the Company's Mortgage Indenture.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
See Notes 8 and 14 to the Consolidated Financial Statements.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS - NONE
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's common stock is traded on the New York Stock Exchange (symbol PSD). The number of stockholders of record of the Company's common stock at December 31, 1993, was 64,622.
The Company has paid dividends on its common stock each year since 1943 when such stock first became publicly held. Future dividends will be dependent upon earnings, the financial condition of the Company and other factors.
Certain provisions relating to the Company's senior securities limit funds available for payment of dividends to net income available for dividends on common stock (as defined in the Company's Mortgage Indenture) accumulated after December 31, 1957, plus the sum of $7.5 million. As of December 31, 1993, the balance of earnings reinvested in the business that was not restricted as to dividends on common stock was approximately $266 million. (See Note 5 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the last two years were:
1993 1992 --------------------------- --------------------------- Price Range Price Range --------------- Dividends --------------- Dividends Quarter Ended High Low Paid High Low Paid - ------------- ------ ------ --------- ------ ------ --------- March 31 28-3/4 26-1/8 $.45 26-3/4 23-7/8 $.44 June 30 29-3/8 26-1/4 $.46 26-3/8 24-1/2 $.45 September 30 29-3/4 25-5/8 $.46 27-7/8 25-7/8 $.45 December 31 26-7/8 23-1/2 $.46 27-3/8 25-7/8 $.45
ITEM 7.


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Net income in 1993 was $138.3 million on operating revenues of $1.113 billion, compared to $135.7 million on operating revenues of $1.025 billion in 1992 and $132.8 million on operating revenues of $956.8 million in 1991. Income for common stock was $121.9 million, $121.8 million and $122.7 million for 1993, 1992 and 1991, respectively.
Earnings per share in 1993 were $2.00 on 60.9 million weighted average common shares outstanding during the period compared to $2.16 on 56.3 million weighted average common shares in 1992 and $2.21 on 55.6 million weighted average common shares in 1991.
Return on the average book value of the Company's common equity in 1993 was 11.0%, compared to 12.6% in 1992 and 13.2% in 1991. The dividend payout ratio was 91.5% in 1993, compared to 82.9% in 1992 and 79.6% in 1991.
Total kilowatt-hour sales to ultimate consumers in 1993 were 19.2 billion, compared with 18.4 billion in 1992 and 18.3 billion in 1991. Kilowatt-hour sales to other utilities were 0.9 billion in 1993, 1.2 billion in 1992 and 1.9 billion in 1991.
The preferred stock dividend accrual increased $2.6 million in 1993 and $3.8 million in 1992 compared to 1991 primarily due to the issuance of the 7.75% Series Preferred Stock in March 1992 and the 7.875% Series Preferred Stock in July 1992. This was partially offset by the reacquisition of the Series A Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred Stock ("FLEX DARTS") in April 1992. The 1993 increase was also partially offset by the reacquisition of the Series B FLEX DARTS in July 1993. Lower dividend rates associated with the FLEX DARTS were also an offsetting factor during 1992. In 1991, the preferred stock dividend accrual decreased $2.4 million compared to 1990 levels. A decrease of $1.8 million was due to lower dividend rates associated with the FLEX DARTS and a decrease of $0.7 million was attributed to the reacquisition of shares of the 9.36% Series Preferred Stock. The Company reacquired 162,000 shares of its 9.36% Series Preferred Stock in March 1990 and the remaining 324,000 shares over the subsequent twelve months.
Years Ending December 31 Increase (Decrease) Over Preceding Year (Dollars in Millions)
1993 1992 1991 - ----------------------------------------------------------------------- Operating revenues General rate increase $ 14.2 $ -- $ 9.1 PRAM surcharge billed 48.8 44.8 9.6 Accrual of Revenue under the PRAM - Net -- 41.5 0.7 BPA Residential Purchase and Sale Agreement (15.0) (25.1) (10.6) Sales to other utilities (6.8) (0.8) 0.4 Load and other changes 46.7 7.8 12.3 - ----------------------------------------------------------------------- Total operating revenue changes 87.9 68.2 21.5 - ----------------------------------------------------------------------- Operating expenses Purchased and interchanged power 81.5 18.2 4.0 Fuel (4.4) 11.9 0.9 Other operation expenses 5.9 9.9 16.3 Maintenance (1.8) (0.4) 5.0 Depreciation and amortization (7.2) 6.6 5.1 Taxes other than federal income taxes 6.1 4.8 (0.3) Federal income taxes 11.5 16.3 (7.9) - ----------------------------------------------------------------------- Total operating expense changes 91.6 67.3 23.1 - ------------------------------------------------------------------------ Allowance for funds used during construction ("AFUDC") 1.5 (1.0) (0.4) Other income (5.5) 12.3 3.4 Interest charges (10.3) 9.3 1.0 - ----------------------------------------------------------------------- Net income changes $ 2.6 $ 2.9 $ 0.4 =======================================================================
The following information pertains to the changes outlined in the table above:
OPERATING REVENUES
Revenues since October 1, 1993 increased as a result of rates authorized by the Washington Utilities and Transportation Commission (the "Washington Commission") in its general rate order issued on September 21, 1993. Revenues since October 1, 1992, increased as a result of rates authorized by the Washington Commission under the second Periodic Rate Adjustment Mechanism ("PRAM") filing. Revenues since October 1, 1991, increased as a result of rates authorized under the first PRAM filing. (See "Rate Matters.")
Revenues have been reduced by virtue of the credit which the Company received through the Residential Purchase and Sale Agreement with the Bonneville Power Administration ("BPA"). This agreement enables the Company's residential and small farm customers to receive the benefits of lower-cost federal power. A related reduction is included in purchased and interchanged power expenses.
Revenues in 1992 were higher as a result of the recognition of $6.7 million of revenues in September 1992 related to incentive payments authorized by the Washington Commission for meeting energy conservation targets during 1991. These revenues were collected in rates beginning October 1, 1992. Revenues from the PRAM rate adjustments and continuing load growth contributed to higher revenues in 1991.
Although the Company is dependent on purchased power to meet customer demand, it may, from time to time, have energy available for sale to other utilities, depending principally upon water conditions for the generation of hydroelectric power, customer usage and the energy requirements of other utilities.
OPERATING EXPENSES
Purchased and interchanged power expenses increased $81.5 million in 1993. Higher purchased power expenses of $95.8 million were due to new firm power purchase contracts with PURPA (Public Utility Regulatory Policies Act) qualifying facilities and higher secondary power purchases from other utilities. This increase was partially offset by the Residential Purchase and Sale Agreement with BPA, which resulted in a reduction of $14.4 million. (See discussion of the Residential Purchase and Sale Agreement under "Operating revenues.")
Purchased and interchanged power expenses increased $18.2 million in 1992. Higher purchased power expenses of $42.3 million were influenced by new firm power purchase contracts with PURPA qualifying facilities and higher costs on certain firm power purchase contracts with other utilities. The Residential Purchase and Sale Agreement with BPA resulted in a reduction of $23.9 million.
Purchased and interchanged power expenses increased $4.0 million in 1991. Higher levels of purchased power accounted for a $14.3 million increase. The Residential Purchase and Sale Agreement with BPA resulted in a reduction of $10.1 million.
Fuel expense decreased $4.4 million in 1993 due to decreased use of the coal-fired plants. Fuel expense increased $11.9 million in 1992 over the previous year due to increased usage of the coal-fired and gas turbine plants.
Other operation expenses increased $5.9 million in 1993 due primarily to a $5.1 million increase in the amortization of conservation expenditures. Also influencing 1993 expenses was an increase of $1.8 million in steam generation expenses and a decrease of $2.3 million in administration and general expenses.
Other operation expenses increased $9.9 million in 1992. Transmission expense accounted for $5.3 million of the increase. Also contributing was a $2.2 million rise in customer service expenses and a $1.5 million increase in administration and general expenses.
Other operation expenses increased $16.3 million in 1991. Contributing to this increase was a $8.1 million rise in administrative and general expenses; a $3.9 million increase in customer service expenses; and a $2.2 million increase in transmission and distribution expenses.
Maintenance expense in 1993 declined $1.8 million compared to 1992 due primarily to a $2.2 million decrease in distribution maintenance expense. Maintenance expense in 1992 fell $0.4 million from 1991 levels due primarily to a decrease of $2.8 million in administration and general maintenance expenses. This was partially offset by a $2.0 million increase in steam plant expense. Maintenance expense in 1991 increased $5.0 million due primarily to $2.7 million for remedial action of Company owned facilities and a $1.5 million rise in transmission and distribution maintenance expenses.
Depreciation and amortization expense declined $7.2 million in 1993 compared to the prior year. This decrease was due in part to a change in depreciation rates approved by the Washington Commission staff in the second quarter of 1993 which was made retroactive to the beginning of 1993. This adjustment had the effect of decreasing depreciation expense by $10.5 million during 1993. This adjustment was partially offset by the effects of additional plant being placed into service. Depreciation and amortization expense increased $6.6 million in 1992 and $5.1 million in 1991 as a result of additional plant being placed into service.
Taxes other than federal income taxes increased $6.1 million in 1993 compared to 1992. Excise and municipal taxes, which are primarily revenue- based, increased $6.1 million.
Taxes other than federal income taxes increased $4.8 million in 1992. An increase in Washington State property taxes of $2.2 million accounted for much of the increase. Taxes other than federal income taxes decreased $0.3 million in 1991. Contributing to the decrease was a $1.1 million decrease in property taxes. Excise and municipal taxes contributed increases of $2.1 million and $1.1 million in 1992 and 1991, respectively.
Federal income taxes on operations increased $11.5 million in 1993. The increase was due in part to higher pre-tax operating income in 1993 and an increase in the corporate tax rate from 34 to 35 percent, retroactive to January 1, 1993. Federal income taxes on operations increased $16.3 million in 1992 due to an increase in pre-tax operating income and a change in the method in which energy conservation expenditures are deducted for federal tax purposes. (See Note 11 to the Consolidated Financial Statements.) Federal income taxes on operations decreased $7.9 million in 1991 due to tax benefits associated with energy conservation expenditures and lower taxable income.
AFUDC
(See Note 1 to the Consolidated Financial Statements.)
OTHER INCOME
Other income decreased $5.5 million in 1993. The decrease was due in part to a charge totaling $1.4 million as a result of the Washington Commission's September 1993 general rate case ruling and a $1.4 million decrease in excess AFUDC over the FERC maximum allowed by the Washington Commission. Also contributing to the 1993 decrease was a non-recurring $2.3 million decrease in non-operating federal income taxes in the second quarter of 1992 as a result of an IRS settlement.
Other income increased $12.3 million in 1992 over 1991 levels. This increase was due in part to an increase of $4.2 million in Allowance for Funds Used to Conserve Energy ("AFUCE"). The Washington Commission, in its April 1, 1991 order authorizing the PRAM, ordered the Company to start accruing carrying costs on energy conservation expenditures until such investments are included in ratebase. These accruals commenced in May 1991 but did not become significant until the third quarter of 1991. The AFUDC allowed by the Washington Commission in excess of the FERC maximum contributed $2.0 million to the increase over 1991. In addition, other income increased $3.8 million because of net income from subsidiaries of $1.0 million in 1992 versus losses of $2.8 million in 1991 and $1.1 million from lower non-operating federal income taxes.
Other income, which increased $3.4 million in 1991, included $2.0 million due to capitalized interest expense relating to construction activities of a subsidiary. Also contributing to the increase were lower non-operating federal income taxes of $1.6 million.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term debt and other interest, decreased $10.3 million in 1993 compared to the prior year. Interest and amortization on long-term debt decreased $3.5 million. Contributing $29.1 million in reduced interest expense were 11 issues of First Mortgage Bonds totaling $510 million redeemed or retired over the previous 21 months. Partially offsetting this was $23.7 million in new interest expense associated with 22 issues of Secured Medium-Term Notes totaling $549 million issued over the previous 23 months.
Other interest expense decreased $6.8 million in 1993 compared to the prior year. Much of the decrease was the result of a $5.3 million non-recurring interest charge in 1992 relating to a federal income tax assessment. Also contributing were lower average daily short-term borrowings and lower weighted average interest rates in 1993.
Interest charges increased $9.3 million in 1992 compared to the prior year. Interest and amortization on long-term debt increased $4.7 million. Contributing $24.0 million of new interest expense were 19 issues of Secured Medium-Term Notes totaling $645 million issued over the previous 19 months. Partially offsetting this were $21.1 million in interest reductions from First Mortgage Bond retirements or redemptions of $451 million over the same period. Also contributing an increase of $1.5 million were the effects of three issues of fixed rate pollution control bonds that were used to refund floating rate pollution control bonds of identical amounts. Other interest expense increased $4.6 million in 1992 compared to 1991. An interest charge of $5.3 million relating to a federal income tax assessment was partially offset by lower short-term interest rates in 1992.
Interest charges increased $1.0 million in 1991 compared to 1990. Interest and amortization on long-term debt increased $3.0 million. This increase included $3.9 million attributable to a First Mortgage Bond issue in October 1990. Also contributing to the increase were four issues of Secured Medium-Term Notes that added $4.6 million of interest in 1991. Partially offsetting these increases was a decrease of $1.4 million due in part to lower interest rates on pollution control bonds. In addition, the effects of bond retirements decreased interest expense by $4.2 million in 1991. Other interest expense decreased $2.0 million in 1991 compared to the prior year due to lower weighted average interest rates and lower average daily short-term borrowings.
CONSTRUCTION AND FINANCING PROGRAM
Current construction expenditures are primarily transmission and distribution-related, designed to meet continuing customer growth. Expenditures on energy conservation resources have also taken on increased importance in recent years as the Company seeks to manage the growth in demand for electricity. Construction expenditures, which include energy conservation expenditures and exclude AFUDC and AFUCE, were $211.5 million in 1993 and are expected to be $261 million in 1994 and $200 million in 1995. The ratio of cash from operations (net of dividends, AFUDC and AFUCE) to construction expenditures (excluding AFUDC and AFUCE) was 59.1% in 1993. The Company expects to fund an average of 68% of its total 1994 and 1995 estimated construction expenditures (excluding AFUDC and AFUCE) from cash from operations (net of dividends, AFUDC and AFUCE) and the balance through the sale of securities, the nature, amount and timing of which will be subject to market and other relevant factors. The Company made an initial payment of $8.0 million in 1993 for capacity rights to BPA's third A.C. transmission line to the southwestern United States and expects to pay the remaining cost of $72 million in 1994. Construction expenditure estimates are subject to periodic review and adjustment.
In April 1991, the Company filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $450 million principal amount of First Mortgage Bonds. The First Mortgage Bonds were issued as Secured Medium-Term Notes, Series A, in 14 separate issues. The Company issued the last of the $450 million of Secured Medium-Term Notes, Series A, in September 1992. The weighted average coupon rate of the Series A Notes was 7.84%.
In October 1992, the Company filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to an additional $450 million principal amount of First Mortgage Bonds. The First Mortgage Bonds can be issued as Secured Medium-Term Notes, through underwritten offerings, pursuant to delayed delivery contracts or any combination thereof. These Secured Medium-Term Notes were designated Series B. As of February 28, 1994, the Company has issued $334 million Series B Notes having an average coupon rate of 6.82%.
On February 9, 1993, the Company issued a total of $50 million principal amount of Secured Medium-Term Notes which included the following: $10 million principal amount of Secured Medium-Term Notes, Series B, due February 9, 1998, bearing interest at 6.17% per annum; $10 million principal amount of Secured Medium-Term Notes, Series B, due February 9, 2000, bearing interest at 6.61% per annum; and $30 million principal amount of Secured Medium-Term Notes, Series B, due February 10, 2003, bearing interest at 7.02% per annum. Proceeds of these issues were used to redeem $20 million principal amount of First Mortgage Bonds, 7.50% Series due 1999 and $30 million principal amount of First Mortgage Bonds, 7.75% Series due 2002, on March 8, 1993.
On March 5, 1993, the Company issued a total of $20 million principal amount of Secured Medium-Term Notes which consisted of $15 million principal amount of Secured Medium-Term Notes, Series B, due March 5, 1996, bearing interest at 4.85% per annum and $5 million principal amount of Secured Medium-Term Notes, Series B, due March 5, 1998, bearing interest at 5.70% per annum. Proceeds of these issues were used to redeem $20 million principal amount of First Mortgage Bonds, 6.625% Series due 1997, on April 2, 1993.
On November 29, 1993, the Company issued a total of $14 million principal amount of Secured Medium-Term Notes which consisted of $3 million principal amount of Secured Medium-Term Notes, Series B, due December 1, 2003, bearing interest at 6.20% per annum and $11 million principal amount of Secured Medium-Term Notes, Series B, due December 2, 2003, bearing interest at 6.40% per annum. Proceeds of these issues were used to pay down short-term debt.
On February 1, 1994, the Company issued $55 million principal amount of Secured Medium-Term Notes, Series B, due February 1, 2024, bearing interest at 7.35% per annum. Proceeds of this issue were used to extinguish $50 million principal amount of the Company's First Mortgage Bonds, 9.625% Series due 1997. The Company redeemed $24.5 million through a tender offer completed February 7, 1994. A portfolio of U.S. Government Treasury Securities was purchased to defease the remaining $25.5 million of the bonds.
On April 29, 1993, the Company issued $23.46 million principal amount of Pollution Control Revenue Refunding Bonds, 5.875% Series due 2020. The proceeds were used to refund, on April 29, 1993, $16.46 million principal amount of Pollution Control Revenue Bonds, 5.90% 1973 Series and $7.0 million principal amount of Pollution Control Revenue Bonds, 6.30% 1977 Series.
In February 1992, the Company filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $200 million of preferred stock. Either $25 par value or $100 par value preferred stock may be issued. In 1992, the Company issued an aggregate of $150 million of preferred stock from this shelf. On February 3, 1994, the Company issued $50 million, Adjustable Rate Cumulative Preferred Stock, Series B ($25 par value). The proceeds were used to retire the $40 million principal amount of its Adjustable Rate Cumulative Preferred Stock, Series A ($100 par value)and to pay down short-term debt.
On July 1, 1993, the Company sold 3.45 million shares of common stock. The stock was priced at $27.875 per share and resulted in proceeds to the Company of approximately $93 million. The proceeds were used to redeem the $50 million principal amount FLEX DARTS Series B Preferred Stock on July 6, 1993 with the balance used to pay down short-term debt.
Short-term borrowings from banks and the sale of commercial paper are used to provide working capital for the construction program. At December 31, 1993, the Company had in place $152 million in lines of credit with several banks, which provide liquidity support for outstanding commercial paper of $70.0 million, effectively reducing the available borrowing capacity under these lines of credit to $82.0 million. (See Note 7 to the Consolidated Financial Statements.)
RATE MATTERS
On September 21, 1993, the Washington Commission issued two rate orders, one regarding the Company's request for an increase in general rates, the other relating to an annual rate adjustment under the Company's Periodic Rate Adjustment Mechanism ("PRAM"). In its revised general rate request, the Company had requested a $97 million increase and in its $76.3 million PRAM request it had requested a first year recovery of between $27.6 and $38.1 million of previously deferred costs under the PRAM.
The Washington Commission authorized a general rate increase of $21.9 million, reflecting increased costs of service, and collection of $35.7 million in the first year to recover previously deferred costs under the PRAM. The Washington Commission authorized full recovery of the Company's PRAM request within two years from the end of the year in which the costs were deferred. The total increase in rates of $57.6 million was effective October 1, 1993. The Washington Commission also authorized the Company to increase rates by an additional $3.9 million effective October 1, 1993 to recognize, prospectively, the effect of the increase in the Federal corporate income tax rate from 34 to 35 percent.
While the Washington Commission's order allowed only $57.6 million of the total requested rate relief, an additional amount of approximately $33.1 million remains eligible for deferral and future recovery through the continued operation of the PRAM. This amount includes such items as the Tenaska purchase power contract (a 245 megawatt cogeneration facility scheduled for operation in April of 1994), costs associated with the impact of hydro conditions and costs associated with fuel costs at the Colstrip plant in Montana.
The Washington Commission authorized a 10.5 percent return on common equity and a common equity component of 45 percent, compared to the Company's request for a 12.25 percent return on common equity and a 45 percent common equity component. This lower return on equity reduced the amount the Washington Commission granted by approximately $30 million.
Prior to October 1, 1993, provision was made for uninsured storm damage, with the approval of the Washington Commission, on the basis of the amount of outside insurance in effect and historical losses. To the extent actual costs varied from the provision, the difference was deferred for incorporation into future rates. The general rate order terminated, prospectively, the provision for deferral of uninsured storm damage except for certain losses associated with major catastrophic events. At December 31, 1993, the Company had no insurance coverage for storm damage.
The general rate order also required the Company to file a case by November 1, 1993, demonstrating the prudency of its eight new power purchase contracts acquired since its last general rate case. Pending the resolution of the prudency review case, the Washington Commission ordered that the Company's new rates, effective October 1, 1993, would be collected subject to refund to the extent this proceeding demonstrates any of those contracts to be imprudent. The Washington Commission calculated the annual revenue requirement at risk to be up to $86.1 million. This amount is the difference between the Company's power costs under the new power purchase contracts and the Washington Commission's estimated cost of purchasing equivalent power on the secondary market. The Company filed its prudency case on October 18, 1993, and expects the Washington Commission to enter a final order before October 1, 1994.
The decrease in allowed return on equity from 12.8 percent in the last general rate case to 10.5 percent approved in the present rate case has put downward pressure on earnings since the order became effective on October 1, 1993. In addition, it will be difficult for the Company to earn its full allowed rate of return because of changes made by the rate orders in the recovery methods of certain costs. Therefore, the Company continues to place strong emphasis on its ongoing improvement efforts designed to increase operating efficiencies.
As a regulated electric utility, the Company's financial condition is largely dependent on continued cost-recovery regulation by the Washington Commission. Adverse action by the Washington Commission in regulatory matters involving the Company, including the pending prudency review case, could adversely impact the Company's financial condition and threaten its ability to maintain the dividend on its common stock at current levels.
OTHER
The Company and BPA have entered into a letter of intent, subject to various conditions, regarding pursuit of construction of a joint transmission project in Whatcom and Skagit counties in northern Washington state, the northernmost portion of the Company's service territory. The joint project is intended to provide the Company and BPA with certain transfer capacity with Canadian utilities and is intended to relieve certain transmission constraints on the respective systems of BPA and the Company. The joint project would involve a combination of existing facility upgrades and new construction and is currently under environmental review. The Company's efforts in this project are preliminary in nature and, as such, the Company cannot give assurance that any construction will result.
The Company also continues to seek reasonable terms for acquiring capacity rights to BPA's planned third A.C. line, which would provide additional transmission capacity between the Pacific Northwest and the Southwestern states. The Company expects to receive 371 MW of southbound capacity on the line from BPA and 284 MW of northbound capacity. The price of participation is expected to be $215 per KW for each KW of rated southbound capacity or a total capital cost of $80 million.
The Company is in the process of replacing the High Molecular Weight ("HMW") underground distribution cable installed during the 1960s and 1970s. The Company installed about 4,800 miles of industrial standard HMW cable between 1964 and 1979, but the Company and other utilities have experienced increasing cable failures in recent years. The Company is continuing to analyze cable failure trends to find ways to mitigate the long term effect of cable failures on customer service, within budgetary constraints. To minimize the impact of increasing cable failures, the Company replaces an increasing amount of HMW cable each year. The Company estimates that the total cost of replacing all 4,800 miles of cable will be about $550 million over a 15 to 20-year period. With 310 miles of cable replaced to date, the Company expects to spend $66 million during the period 1994-1997 for replacement of this cable.
The Company presently has no plans for major diversification outside of the electric utility field and expects revenues in the near future to be generated almost entirely by electric utility operations. Investments in and advances to subsidiaries increased $14.2 million in 1993 primarily as a result of advances to a subsidiary developing small hydro projects.
The electric utility industry in general is experiencing intensifying competitive pressures, particularly in wholesale generation and industrial customer markets. The National Energy Policy Act of 1992 was designed to increase competition in the wholesale electric generation market by easing regulatory restrictions on producers of wholesale power and by authorizing the FERC to mandate access to electric transmission systems by wholesale power generators. The potential for increased competition at the retail level in the electric utility industry through state-mandated retail wheeling has also been the subject of legislative and administrative interest in a number of states, including the state of Washington. Electric utilities, including the Company, now face greater potential competition for resources and customers from a variety of sources, including privately owned independent power producers, exempt wholesale power generators, industrial customers developing their own generation resources, suppliers of natural gas and other fuels, other investor-owned electric utilities and municipal generators. All four of the major credit rating agencies have expressed the view that competitive developments in the electric utility industry are likely to increase business risks, with resulting pressure on utility credit quality. One of the rating agencies has stated that it is revising its financial ratio guidelines for electric utilities to reflect the changing risk profiles within the industry. These rating agency actions may result in higher capital costs and more limited access to capital markets for electric utilities, including the Company.
Although the Company to date has not experienced any significant adverse impact on its business from these industry trends, the Company has taken a number of steps to prepare for a more competitive business environment. These include programs to become a lower-cost producer by improving productivity and reducing the work force.
The Company decided in January 1994 to offer an early separation plan to all officers, senior and middle managers and eligible professional staff. Benefits offered to those electing the program include a severance package based on years of service and enhanced retirement benefits for employees over 55 years of age. The number of employees that will accept the offer is presently not known. The Company has not set any specific job reduction targets.
The Company, based on studies performed, currently estimates the total severance cost will not exceed $10 million. However, the total severance cost is dependent on the number of employees ultimately accepting the plan. The accrual for costs of this program will be recognized in the first quarter of 1994. Subsequent periods' expense will benefit from the savings associated with the reduced workforce. While the program will result in a net cost to the Company in 1994, the Company expects to see net savings in 1995 and beyond.
The Company is also reviewing the extent of its investment in regulatory assets that may not be readily marketable to others in a competitive marketplace. The Company is seeking state legislation to provide a firm statutory basis for recovery of demand-side management regulatory assets associated with the Company's conservation programs.
For a discussion of Environmental obligations, see Note 14 to the Consolidated Financial Statements.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 35.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE - NONE.
PART III
Part III is incorporated by reference from the Company's definitive proxy statement issued in connection with the 1993 Annual Meeting of Shareholders. Certain information regarding executive officers is set forth in Part I.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1) Financial statement schedules - see index on page 35.
2) Exhibits - see index on page 67.
(b) Reports on Form 8-K: None
SIGNATURES
Pursuant to the requirements of Section 13 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.
PUGET SOUND POWER & LIGHT COMPANY
By /s/ R. R. Sonstelie -------------------------------------- R. R. Sonstelie President and Chief Executive Officer
Date: March 1, 1994
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.
Signature Title Date - --------------------------- -------------------------- ---------
/s/ R. R. Sonstelie President and - --------------------------- Chief Executive Officer (R. R. Sonstelie) and Director
/s/ William S. Weaver Executive Vice President and - --------------------------- Chief Financial Officer (William S. Weaver) and Director March 1, /s/ R. E. Olson Vice President Finance - --------------------------- and Treasurer (R. E. Olson) (Principal Accounting Officer)
/s/ Douglas P. Beighle Director - --------------------------- (Douglas P. Beighle)
/s/ Charles W. Bingham Director - --------------------------- (Charles W. Bingham)
/s/ Phyllis J. Campbell Director - --------------------------- (Phyllis J. Campbell)
/s/ John H. Dunkak Director - --------------------------- (John H. Dunkak III)
/s/ John D. Durbin Director - --------------------------- (John D. Durbin)
/s/ John W. Ellis Director - --------------------------- (John W. Ellis)
/s/ Daniel J. Evans Director - --------------------------- (Daniel J. Evans)
/s/ Nancy L. Jacob Director - --------------------------- (Nancy L. Jacob)
Director - --------------------------- (R. Kirk Wilson)
Puget Sound Power & Light Company
Report of Management: March 2, 1994
The accompanying consolidated financial statements of Puget Sound Power & Light Company have been prepared under the direction of management, which is responsible for their integrity and objectivity. The statements have been prepared in accordance with generally accepted accounting principles and include amounts based on judgments and estimates by management where necessary. Management also has prepared the other information in the Form 10-K and is responsible for its accuracy and consistency with the financial statements.
The Company maintains a system of internal control which, in management's opinion, provides reasonable assurance that assets are properly safeguarded and transactions are executed in accordance with management's authorization and properly recorded to produce reliable financial records and reports. The system of internal control provides for appropriate division of responsibility and is documented by written policy and updated as necessary. The Company's internal audit staff assesses the effectiveness and adequacy of the internal controls on a regular basis and recommends improvements when appropriate. Management considers the internal auditor's and independent auditor's recommendations concerning the Company's internal controls and takes steps to implement those that they believe are appropriate in the circumstances.
In addition, Coopers & Lybrand, the independent auditors, have performed audit procedures deemed appropriate to obtain reasonable assurance about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed solely of outside Directors. The audit committee meets regularly with management, the internal auditors and Coopers & Lybrand, jointly and separately, to review management's process of implementation and maintenance of internal accounting controls and auditing and financial reporting matters. The internal and independent auditors have unrestricted access to the audit committee.
R. R. Sonstelie William S. Weaver Russel E. Olson ___________________ _______________________ ______________________ R. R. Sonstelie William S. Weaver Russel E. Olson
President and Executive Vice President Vice President Finance Chief Executive and Chief Financial and Treasurer (Principal Officer Officer Accounting Officer)
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders of Puget Sound Power & Light Company
We have audited the consolidated financial statements and the financial statement schedules of Puget Sound Power & Light Company listed on page 35 of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement 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 are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As more fully discussed in Note 14 to the financial statements, the Washington Commission, in its September 21, 1993 rate orders, authorized an increase in the Company's rates effective October 1, 1993 and required the Company to file another case demonstrating the prudency of certain power purchase contracts. Pending its decision in the prudency review case, the Washington Commission ordered that the new rates would be collected subject to refund to the extent any of the contract amounts were found to be imprudent. Management of the Company believes that the power purchase contracts are prudent. The Washington Commission's decision on the case is expected in September 1994.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Puget Sound Power & Light Company as of December 31, 1993 and 1992, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
As discussed in Notes 11 and 12, effective January 1, 1993, the Company changed its method of accounting for income taxes and postretirement benefits other than pensions.
Coopers & Lybrand
Seattle, Washington February 10, 1994
PUGET SOUND POWER & LIGHT COMPANY
CONSOLIDATED FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES COVERED BY THE FOREGOING REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED FINANCIAL STATEMENTS: Page
Consolidated Statements of Income for the years ended December 31, 1993, 1992 and 1991........................................36
Consolidated Balance Sheets, December 31, 1993 and 1992...................37
Consolidated Statements of Capitalization, December 31, 1993 and 1992.....39
Consolidated Statements of Earnings Reinvested in the Business for the years ended December 31, 1993, 1992 and 1991....................40
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991..................................41
Notes to Consolidated Financial Statements................................42
SCHEDULES:
II. Amounts Receivable From Related Parties and Underwriters, Promoters and Employees Other Than Related Parties for the years ended December 31, 1993, 1992 and 1991........................63
V. Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991....................................64
VI. Accumulated Depreciation and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991....................................65
VIII. Valuation and Qualifying Accounts and Reserves for the years ended December 31, 1993, 1992 and 1991........................66
All other schedules have been omitted because of the absence of the conditions under which they are required, or because the information required is included in the financial statements or the notes thereto.
Financial statements of the Company's subsidiaries are not filed herewith inasmuch as the assets, revenues, earnings and earnings reinvested in the business of the subsidiaries are not material in relation to those of the Company.
Puget Sound Power & Light Company Notes To Consolidated Financial Statements - -------------------------------------------------------------------------
1) Summary of Accounting Policies
Significant accounting policies are described below.
Utility Plant:
The costs of additions to utility plant, including renewals and betterments, are capitalized at original cost. Costs include indirect costs such as engineering, supervision, certain taxes and pension and other benefits, and an allowance for funds used during construction. Replacements of minor items of property are included in maintenance expense. The original cost of operating property together with removal cost, less salvage, is charged to accumulated depreciation when the property is retired and removed from service.
Consolidation and Investment in Subsidiaries:
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Puget Energy, Inc. ("Puget Energy"). Guaranteed Collateralized Bonds were issued by Puget Energy and the net proceeds from the sale of bonds were advanced to the Company (see Note 6). Puget Energy has no independent operations. Investments in all other subsidiaries are stated on an equity basis.
Operating Revenues:
Operating revenues are recorded on the basis of service rendered, which includes estimated unbilled revenue and revenue accrued under the Periodic Rate Adjustment Mechanism ("PRAM").
Energy Conservation:
The Company accumulates energy conservation expenditures which are amortized to expense over a ten-year period when authorized by the Washington Utilities and Transportation Commission ("Washington Commission"). The Washington Commission allows an additional overall rate of return of .90% on the Company's unamortized energy conservation expenditures and on energy conservation loans to customers made prior to January 1, 1991.
Self-Insurance:
Prior to October 1, 1993, provision was made for uninsured storm damage, comprehensive liability, industrial accidents and catastrophic property losses, with the approval of the Washington Commission, on the basis of the amount of outside insurance in effect and historical losses. To the extent actual costs varied from the provision, the difference was deferred for incorporation into future rates. The amount deferred and included in other long-term assets at December 31, 1993, was approximately $26.8 million. In its September 21, 1993 order, the Washington Commission terminated, prospectively, the provision for deferral of uninsured storm damage except for certain losses associated with major catastrophic events. The Washington Commission in its order did provide for recovery annually of $2.8 million in deferred storm damage costs in retail rates, beginning October 1, 1993. The order also terminated the provision for deferral of other uninsured losses retroactively, resulting in an after-tax writeoff in 1993 of $2.0 million. At December 31, 1993, the Company had no insurance coverage for storm damage.
Depreciation and Amortization:
For financial statement purposes, the Company provides for depreciation on a straight-line basis. The depreciation of automobiles, trucks, power operated equipment and tools is allocated to asset and expense accounts based on usage.
With the Washington Commission's approval, the Company reduced its depreciation rates in 1993. This adjustment had the effect of reducing depreciation expense by $10.5 million during 1993. The annual depreciation provision stated as a percent of average original cost of depreciable utility plant was 3.1% in 1993 and 3.4% for 1992 and 1991.
The Company's investments in terminated generating projects are being amortized on a straight-line basis over ten years for regulatory purposes (included in operating income as "Depreciation and amortization").
Amounts recoverable through rates related to investments in terminated generating projects and the Bonneville Exchange Power Contract were adjusted to their present value in prior years in accordance with Statement of Financial Accounting Standards No. 90. These adjustments result in reduced net amortization expense over the recovery periods, the effect of which is included in miscellaneous income in the amount, net of federal income tax expense, of $2.7 million, $3.6 million and $4.5 million for 1993, 1992 and 1991, respectively.
Federal Income Taxes:
The Company normalizes, with the approval of the Washington Commission, certain items. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109. (See Note 11.)
Allowance for Funds Used During Construction:
The Allowance for Funds Used During Construction ("AFUDC") represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used. AFUDC is capitalized as a part of the cost of utility plant and is credited as a non-cash item to other income and interest charges currently. Cash inflow related to AFUDC does not occur until these charges are reflected in rates.
The AFUDC rate allowed by the Washington Commission is the Company's authorized rate of return, which was 10.22% effective January 30, 1990, 10.16% effective October 1, 1991 and 8.94% effective October 1, 1993. To the extent this rate exceeds the maximum AFUDC rate calculated using the Federal Energy Regulatory Commission ("FERC") formula, the Company capitalizes the excess as a deferred asset, crediting miscellaneous income. The amounts included in income were: $2,309,000 for 1993; $3,680,000 for 1992 and $1,686,000 for 1991.
Allowance For Funds Used to Conserve Energy:
Beginning in April 1991, the Washington Commission authorized the Company to capitalize, as part of energy conservation costs, related carrying costs calculated at a rate established by the Washington Commission. This Allowance for Funds Used to Conserve Energy ("AFUCE") has been credited as a non-cash item to miscellaneous income in the amount of $4,276,000 in 1993, $4,454,000 in 1992 and $767,000 in 1991. Cash inflow related to AFUCE occurs when these charges are reflected in rates.
Periodic Rate Adjustment Mechanism:
In April 1991, the Washington Commission issued an order establishing a PRAM designed to operate as an interim rate adjustment mechanism between tri-annual general rate cases. Under the PRAM, the Company is allowed to request annual rate adjustments, on a prospective basis, to reflect changes in certain costs as set forth in the PRAM order. Also, under terms of the order, recovery of certain costs is decoupled from levels of electricity sales.
Rates established for the PRAM period are subject to future adjustment based on actual customer growth and variations in certain costs, principally those affected by hydro and weather conditions. To the extent revenue billed to customers varies from amounts allowed under the methodology established in the PRAM order, the difference is accumulated, without interest, for rate recovery which will be established in the next PRAM hearing. In its September 21, 1993 order, the Washington Commission approved the Company's latest PRAM filing. A receivable of approximately $85.0 million was recorded at December 31, 1993 under this methodology. Amounts expected to be collected within one year have been included in current assets.
Other:
The carrying amount of cash, which includes temporary investments with maturities of 3 months or less, is considered to be a reasonable estimate of fair value.
Debt premium, discount and expenses are amortized over the life of the related debt.
Certain costs have been deferred for amortization in subsequent years, as it is considered probable that such costs will be recovered through future rates.
Earnings Per Common Share:
Earnings per common share have been computed based on the weighted average number of common shares outstanding.
On January 15, 1991, the Board of Directors declared a dividend of one preference share purchase right (a "Right") on each outstanding common share of the Company. The dividend was distributed on January 25, 1991, to shareholders of record on that date. The Rights will be exercisable only if a person or group acquires 10 percent or more of the Company's common stock or announces a tender offer which, if consummated, would result in ownership by a person or group of 10 percent or more of the common stock. Each Right entitles the registered holder to purchase from the Company one one-thousandth of a share of Preference Stock, $50 par value per share, at an exercise price of $45, subject to adjustments. The description and terms of the Rights are set forth in a Rights Agreement between the Company and The Chase Manhattan Bank, N.A., as Rights Agent. The Rights expire on January 25, 2001, unless earlier redeemed by the Company.
In February 1992, the Company filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $200 million of preferred stock. Either $25 par value or $100 par value preferred stock may be issued. On March 25, 1992, the Company issued $75 million, 7.75% Series, $100 par value Preferred Stock. The proceeds were used to retire $50 million principal amount of its Flexible Dutch Auction Rate Transferable Securities, $100 par value Preferred Stock ("FLEX DARTS"), Series A and to pay down short-term debt. On July 21, 1992, the Company issued $75 million, 7.875% Series, $25 par value Preferred Stock. The proceeds of this issue were used to pay down short-term debt. The 7.875% Series may be redeemed after July 14, 1997 at $25 per share plus accrued dividends. On July 1, 1993, the FLEX DARTS Series B were redeemed with the proceeds from the sale of the Company's common stock. The weighted average dividend rate for Series B was 3.30% for 1993, 3.60% for 1992 and 5.49% for 1991. The weighted average dividend rate for Series A was 4.18% in the first three months of 1992 and 5.28% for 1991.
On February 3, 1994, the Company issued $50 million, Adjustable Rate Cumulative Preferred Stock ("ARPS"), Series B ($25 par value). The proceeds were used to retire the $40 million principal amount of its ARPS Series A ($100 par value). The weighted average dividend rate for the ARPS Series A was 7.00% for 1993, 7.17% for 1992 and 7.59% for 1991.
For each quarterly period, dividends on the ARPS Series B, determined in advance of such period, will be set at 83% of the highest of three interest rates as defined in the Statement of Relative Rights and Preferences for ARPS Series B. The dividend rate for any dividend period will in no event be less than 4% per annum or greater than 10% per annum. Dividends from the date of issuance through May 14, 1994 will be payable at the rate of 5.24% per annum. The Company may redeem the ARPS Series B at any time on not less than 30 days notice at $27.50 per share on or prior to February 1, 1999, and at $25 per share thereafter, plus in each case accrued dividends to the date of redemption; provided however, that no shares shall be redeemed prior to February 1, 1999, if such redemption is for the purpose or in anticipation of refunding such share at an effective interest or dividend cost to the Company of less than 5.37% per annum.
3) Preferred Stock Subject to Mandatory Redemption
The Company is required to deposit funds annually in a sinking fund sufficient to redeem the following number of shares of each series at $100 per share plus accrued dividends: 4.84% Series and 4.70% Series, 3,000 shares each; 8% Series, 6,000 and 1,000 shares through 2003 and 2004, respectively; and 7.75% Series, 37,500 shares on each February 15, commencing on February 15, 1998. Previous requirements have been satisfied by delivery of reacquired shares. At December 31, 1993, there were 13,939 shares of the 4.84% Series, 2,594 shares of the 4.70% Series and 704 shares of the 8% Series acquired by the Company and available for future sinking fund requirements. Upon involuntary liquidation, all preferred shares are entitled to their par value plus accrued dividends.
The preferred stock subject to mandatory redemption (see Note 2) may also be redeemed by the Company at the following redemption prices per share plus accrued dividends: 4.84% Series, $102; 4.70% Series, $101; and 8% Series, $101. The 7.75% Series may be redeemed by the Company, subject to certain restrictions, at $106.72 per share plus accrued dividends through February 15, 1995 and at per share amounts which decline annually to a price of $100 after February 15, 2007.
The preferred stock subject to mandatory redemption is estimated to have a fair value of $93.7 million or 100.6% of face value as of December 31, 1993. The fair value of preferred stock subject to mandatory redemption is estimated based on dealer quotes.
4) Additional Paid-in Capital 1993 1992 1991 - ----------------------------------------------------------------------------- (Dollars in Thousands)
Balance at beginning of year $243,874 $198,733 $198,819 Excess of proceeds over stated values of: Common stock issued to trustee of employee investment plan 2,234 1,046 -- Common stock issued under the stock purchase and dividend reinvestment plan 24,584 10,841 -- Common stock sold to the public 61,669 37,950 -- Par value over(under) cost of reacquired preferred stock 612 579 (86) Issue costs of common stock (3,035) (1,950) -- Issue costs of preferred stock (16) (3,325) -- - ----------------------------------------------------------------------------- Balance at end of year $329,922 $ 243,874 $198,733 =============================================================================
5) Earnings Reinvested in the Business
Earnings reinvested in the business unrestricted as to payment of cash dividends on common stock approximated $266 million at December 31, 1993, under the provisions of the most restrictive covenants applicable to preferred stock and long-term debt contained in the Company's Articles of Incorporation and indentures. The adjustments made to the carrying value of costs associated with the terminated generating projects and Bonneville Exchange Power as a result of Statement of Financial Accounting Standards No. 90 and the disallowance of certain terminated generating project costs by the Washington Commission do not impact the amount of earnings reinvested in the business for purposes of payment of dividends on common stock under the terms of the aforementioned Articles and indentures. (See Note 1.)
6) Long-Term Debt First Mortgage Bonds and Guaranteed Collateralized Bonds - -------------------------------------------------------- First Mortgage Bonds at December 31: Series Due 1993 1992 Series Due 1993 1992 - --------------------------------------------------------------------------- (Dollars in Thousands) (Dollars in Thousands)
4.00% 1993 $ -- $ 40,000 9.14% 2001 $ 30,000 $ 30,000 4.75% 1994 15,000 15,000 7.75% 2002 -- 30,000 8.25% 1995 100,000 100,000 7.85% 2002 30,000 30,000 5.25% 1996 20,000 20,000 7.07% 2002 27,000 27,000 4.85% 1996 15,000 -- 7.15% 2002 5,000 5,000 6.625% 1997 -- 20,000 7.625% 2002 25,000 25,000 7.875% 1997 100,000 100,000 7.02% 2003 30,000 -- 9.625% 1997 50,000 50,000 6.20% 2003 3,000 -- 6.17% 1998 10,000 -- 6.40% 2003 11,000 -- 5.70% 1998 5,000 -- 7.70% 2004 50,000 50,000 8.83% 1998 25,000 25,000 8.06% 2006 46,000 46,000 7.50% 1999 -- 20,000 8.14% 2006 25,000 25,000 6.50% 1999 16,500 16,500 7.75% 2007 100,000 100,000 6.65% 1999 10,000 10,000 8.40% 2007 10,000 10,000 6.41% 1999 20,500 20,500 8.59% 2012 5,000 5,000 7.25% 1999 50,000 50,000 8.20% 2012 30,000 30,000 6.61% 2000 10,000 -- - --------------------------------------------------------------------------- Total First Mortgage Bonds $874,000 $900,000 ===========================================================================
Guaranteed Collateralized Bonds at December 31:
Series Due 1993 1992 Series Due 1993 1992 (Dollars in Thousands) (Dollars in Thousands) 8.05% 1993 $ -- $ 8,000 8.45% 1996 $ 8,000 $ 8,000 8.15% 1994 8,000 8,000 9.375% 2017 -- 114,000 8.30% 1995 8,000 8,000 - --------------------------------------------------------------------------- Total Guaranteed Collateralized Bonds $ 24,000 $146,000 ===========================================================================
The Company has unconditionally guaranteed all payments of principal and premium, if any, and interest on each series of the Guaranteed Collateralized Bonds of Puget Energy issued in 1986. The guarantee of the Company with respect to each series of the Guaranteed Collateralized Bonds is backed by a related series of the Company's First Mortgage Bonds. Each related series of First Mortgage Bonds has been issued to the trustee for the Guaranteed Collateralized Bonds and so long as payment is made on the Guaranteed Collateralized Bonds no payment is due with respect to the related series of First Mortgage Bonds.
Substantially all properties owned by the Company are subject to the lien of the First Mortgage Bonds. In February 1994, the Company extinguished $50 million principal amount of First Mortgage Bonds, 9.625% Series due 1997. The Company redeemed $24.5 million through a tender offer. A portfolio of U.S. Government Treasury Securities was purchased to defease the remaining $25.5 million of the bonds. The defeased bonds will be called on October 15, 1995.
Pollution Control Revenue Bonds
In June 1986, the Company entered into an agreement with the City of Forsyth, Montana, (the "City") borrowing $115 million obtained by the City from the sale of Customized Purchase Pollution Control Revenue Refunding Bonds due in 2012 (1986 Series) issued to finance the pollution control facilities of Colstrip Units 3 and 4.
In April 1987, the Company entered into an agreement with the City, borrowing $23.4 million obtained by the City from the sale of Customized Purchase Pollution Control Revenue Refunding Bonds due December 1, 2016, (1987 Series) issued to finance additional pollution control facilities of Colstrip Unit 4.
On August 7, 1991, the Company refunded $27.5 million of the 1986 Series and the entire $23.4 million of the 1987 Series with two new series of bonds, consisting of $27.5 million principal amount of a 7.05% Series due 2021 and $23.4 million principal amount of a 7.25% Series due 2021. In March 1992, the Company refunded the remaining $87.5 million of the 1986 Series with a new series at a rate of 6.80%, maturing in 2022. Each new series of bonds is collateralized by a pledge of the Company's First Mortgage Bonds, the terms of which match those of the pollution control bonds. No payment is due with respect to the related series of First Mortgage Bonds, so long as payment is made on the pollution control bonds.
On April 29, 1993, the Company issued $23.46 million Pollution Control Revenue Refunding Bonds, 5.875% 1993 Series due 2020. The proceeds were used to refund $16.46 million Pollution Control Revenue Bonds, 5.90% 1973 Series and $7 million Pollution Control Revenue Bonds, 6.30% 1977 Series.
Long-Term Debt Maturities and Sinking Fund Requirements - --------------------------------------------------------
The principal amounts of long-term debt maturities and sinking fund require- ments for the next five years are as follows:
1994 1995 1996 1997 1998 (Dollars in Thousands)
Maturities of long-term debt $ 23,000 $108,000 $ 43,000 $150,000 $ 40,000 - ---------------------------------------------------------------------------- Sinking fund requirements $ 200 $ 200 $ -- $ -- $ -- - ----------------------------------------------------------------------------
The sinking fund requirement for the First Mortgage Bonds may be met by substitution of certain credits as provided in the indentures.
The fair value of outstanding bonds including current maturities is estimated to be $1.126 billion or 106.2% of face value as of December 31, 1993. The fair value of long-term bonds is estimated based on quoted market prices. 7) Short-Term Debt
The Company has short-term borrowing arrangements which include a $100 million line of credit with six major banks, a $50 million line of credit with four banks and a $2 million line with another three banks. The agreements provide the Company with the ability to borrow at different interest rate options. For the $100 million and $50 million lines of credit, the options are: (1) the higher of the prime rate or the Federal Funds rate plus 1/2 of 1 percent or (2) the bank Certificate of Deposit rate plus 1/2 of 1 percent or (3) the Eurodollar rate plus 3/8 of 1 percent. These Credit Agreements require an availability fee of 1/5 of 1% per annum on the unused loan commitment. Borrowings on the $2 million credit line are at the prime rate and compensating balances of 2-1/2% are required.
In addition, the Company has agreements with several banks to borrow on an uncommitted, as available, basis at money-market rates quoted by the banks. There are no costs, other than interest, for these arrangements. The Company also uses commercial paper to fund its short-term borrowing requirements.
At December 31: 1993 1992 1991 - ------------------------------------------------------------------------ (Dollars in Thousands) Short-term borrowings outstanding Bank notes $ 79,300 $ 69,800 $ 40,500 Commercial paper notes $ 70,006 $ 20,650 $ 71,289 Weighted average interest rate 3.49% 4.37% 5.49% Unused lines of credit (a) $152,000 $152,000 $153,000 During the year ended December 31: Maximum aggregate short-term borrowings $149,306 $146,158 $111,789 Average daily short-term borrowings (b) $ 55,244 $ 81,509 $ 59,931 Weighted average interest rate (c) 3.40% 4.15% 6.35% - ------------------------------------------------------------------------
(a) Provides liquidity support for outstanding commercial paper in the amount of $70.0 million, $20.7 million and $71.3 million for 1993, 1992 and 1991, respectively, effectively reducing the available borrowing capacity under these credit lines to $82.0 million, $131.3 million and $81.7 million, respectively. (b) The sum of dollar days of outstanding borrowings divided by actual days in period. (c) Actual accrued interest during the period divided by average daily borrowings.
The carrying value of short-term debt is considered to be a reasonable estimate of fair value.
8) Investment in Bonneville Exchange Power Contract
The Company has a five percent interest, as a tenant in common with three other investor-owned utilities and Washington Public Power Supply System ("WPPSS"), in the WPPSS Unit 3 project. Unit 3 is a partially constructed 1,240,000 kilowatt nuclear generating plant at Satsop, Washington, which is in a state of extended construction delay instituted by the Bonneville Power Administration ("BPA") and WPPSS in 1983. Under the terms of a settlement agreement (the "Settlement Agreement"), which includes a Settlement Exchange Agreement ("Bonneville Exchange Power Contract") between the Company and BPA dated September 17, 1985, the Company is receiving electric power (the "Bonneville Exchange Power") from the federal power system resources marketed by the BPA for a period of approximately 30.5 years which commenced January 1, 1987. The Settlement Agreement settled the claims of the Company against WPPSS and BPA relating to the construction delay of the WPPSS Unit 3 project.
In its general rate case order issued on January 17, 1990, the Washington Commission found that all WPPSS Unit 3/Bonneville Exchange Power costs had been prudently incurred. Under terms of the order, approximately two-thirds or $97 million of the investment in Bonneville Exchange Power is included in rate base and amortized on a straight-line basis over the remaining life of the contract (amortization is included in "Purchased and interchanged power"). The remainder of the Company's investment is being recovered in rates over ten years, without a return during the recovery period. The related amortization is included in "Depreciation and amortization," pursuant to a FERC accounting order.
Several issues in the litigation relating to WPPSS Unit 3, including claims on behalf of WPPSS Unit 5 against the Company and the other Unit 3 owners seeking recovery of certain common costs, have not been settled by the Settlement Agreement. The claims with respect to WPPSS Unit 3 and Unit 5 common costs, made in the United States District Court for the Western District of Washington, arise out of the fact that Unit 3 and Unit 5 were being constructed adjacent to each other and were planned to share certain costs. Unit 3 is in a state of extended construction delay and Unit 5 was terminated prior to completion. In 1989, the Company and other parties submitted arguments and affidavits to the United States District Court, in response to an order of the court, on the proper basis or bases upon which costs should have been allocated between Unit 3 and Unit 5 under the WPPSS Unit 4 and 5 Bond Resolution. On October 5, 1990, the District Court ruled that certain cost allocations between Unit 3 and Unit 5 (and between WPPSS Unit 1 and Unit 4) were improper. The District Court determined that principles of incremental cost sharing were not applied and, as a result, Unit 4 and Unit 5 apparently bore more than their fair and equitable share of construction costs. The District Court granted the motion by the trustee for WPPSS Unit 4 and Unit 5 bondholders for an accounting of all uses of WPPSS Unit 4 and Unit 5 bond proceeds to determine, among other things, the extent of improper allocation of such costs. In January 1991, the United States Court of Appeals for the Ninth Circuit granted the Company and others permission to appeal on an interlocutory basis from the District Court's orders. In February 1992, the Court of Appeals ruled on the District Court's October 5, 1990 order and held that principles of incremental cost sharing were not required and remanded the matter to the District Court for further proceedings. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition or operations of the Company.
9) Supplementary Income Statement Information
1993 1992 1991 - ---------------------------------------------------------------------- (Dollars in Thousands) Taxes: Real estate and personal property $ 29,354 $ 30,839 $29,023 State business 40,102 35,798 33,709 Municipal, occupational and other 23,064 21,136 20,887 Payroll 9,664 9,517 8,933 Other 3,462 5,300 4,316 - ---------------------------------------------------------------------- Total taxes $105,646 $102,590 $96,868 - ----------------------------------------------------------------------
Charged to: Tax expense $100,598 $ 94,466 $89,640 Other accounts, including construction work in progress 5,048 8,124 7,228 - ---------------------------------------------------------------------- Total taxes $105,646 $102,590 $96,868 ======================================================================
See "Consolidated Statements of Income" for maintenance and depreciation expense.
Advertising, research and development expenses and amortization of intangibles are not significant. The Company pays no royalties.
10) Leases
The Company classifies leases as operating or capital leases. Capitalized leases are not material. The Company treats all leases as operating leases for ratemaking purposes as required by the Washington Commission.
Rental and lease payments for the years ended December 31, 1993, 1992 and 1991 were approximately $14,016,000, $13,773,000 and $12,945,000, respectively. At December 31, 1993, future minimum lease payments for noncancelable leases are $8,279,000 for 1994, $8,211,000 for 1995, $8,158,000 for 1996, $8,194,000 for 1997, $7,934,000 for 1998 and in the aggregate $39,225,000 thereafter.
11) Federal Income Taxes
The details of federal income taxes ("FIT") are as follows:
1993 1992 1991 - --------------------------------------------------------------------------- Charged to Operating Expense: (Dollars in Thousands)
Current $56,908 $67,762 $54,004 Deferred investment tax credits - net (2,118) (4,018) (4,258) Deferred - net 29,180 8,705 6,434 - --------------------------------------------------------------------------- Total FIT charged to operations $83,970 $72,449 $56,180 =========================================================================== Charged to Miscellaneous Income: Current $(3,665) $(5,207) $(2,985) Deferred 3,087 2,596 2,175 - --------------------------------------------------------------------------- Total FIT charged to miscellaneous income $ (578) $(2,611) $ (810) =========================================================================== Total FIT $83,392 $69,838 $55,370 ===========================================================================
The following is a reconciliation of the difference between the amount of FIT computed by multiplying pre-tax book income by the statutory tax rate, and the amount of FIT in the Consolidated Statements of Income:
1993 1992 1991 - --------------------------------------------------------------------------- (Dollars in Thousands) - --------------------------------------------------------------------------- FIT at the statutory rate $77,602 $69,890 $63,970 - --------------------------------------------------------------------------- Increase (Decrease): Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation treated as a temporary difference 4,698 5,295 4,754 AFUDC included in income in the financial statements but excluded from taxable income (2,563) (2,438) (2,112) Investment tax credit amortization (2,118) (4,018) (4,264) Amortization of Pebble Springs and Skagit/ Hanford projects, deducted for financial statements but not deducted for income tax purposes, net of amount treated as a temporary difference 1,465 1,748 1,748 Energy conservation expenditures, net 5,608 (1,245) (11,635) Other (1,300) 606 2,909 - --------------------------------------------------------------------------- Total FIT $83,392 $69,838 $55,370 =========================================================================== Effective tax rate 37.6% 34.0% 29.4% ===========================================================================
The following are the principal components of FIT as reported:
1993 1992 1991 - --------------------------------------------------------------------------- (Dollars in Thousands) - --------------------------------------------------------------------------- Current FIT $53,243 $62,555 $51,019 =========================================================================== Deferred FIT - other: Conservation tax settlement (257) (22,645) -- Periodic rate adjustment mechanism (PRAM) 14,959 14,321 228 Deferred taxes related to insurance reserves 1,409 596 4,282 Terminated generating projects (5,735) (6,647) (6,647) Reversal of Statement No. 90 present value adjustments 1,477 2,374 3,096 Residential Purchase and Sale Agreement, net 4,136 2,491 (1,008) Normalized tax benefits of the accelerated cost recovery system 19,839 21,237 15,693 Energy conservation program (2,938) (3,360) (3,662) Other (623) 2,934 (3,373) - --------------------------------------------------------------------------- Total deferred FIT - other $32,267 $11,301 $ 8,609 ===========================================================================
Deferred investment tax credits - net of amortization $(2,118) $(4,018) $(4,258) - ---------------------------------------------------------------------------- Total FIT $83,392 $69,838 $55,370 ===========================================================================
Deferred tax amounts shown above result from temporary differences for tax and financial statement purposes. Deferred tax provisions are not recorded in the income statement on certain temporary differences for tax and financial statement purposes because they are not allowed for ratemaking purposes.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement No. 109"). Statement No. 109 requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow- through tax accounting for rate-making purposes. Under the provision of Statement No. 109, the Company recorded at the date of adoption an additional deferred tax liability of approximately $272 million. Because of prior, and expected future, ratemaking treatment for differences resulting from flow- through tax accounting, a corresponding regulatory asset for income taxes recoverable through future rates of $272 million was also established at the date of adoption. At December 31, 1993, the balance of this asset is $281 million. The cumulative effect on net income for the current period from adoption of Statement No. 109 was not significant. Adoption is not expected to significantly impact income tax expense in the future.
The Company has reclassified as liabilities deferred income taxes previously netted with plant and other property and investments of $196 million in 1992.
The deferred tax liability at December 31, 1993 is comprised of amounts related to the following types of temporary differences (thousands of dollars):
Utility plant $425,210 PRAM 29,885 Energy conservation charges 44,548 Contributions in aid of construction (21,814) Bonneville Exchange Power 18,968 Other 31,868 ------- Total $528,665 ========
The total of $529 million consists of deferred tax liabilities of $559 million net of deferred tax assets of $30 million.
In 1992, the Company reached an agreement with the Internal Revenue Service (the "Service") settling a number of issues. As part of the agreement, the Company agreed to accept the Service's position that energy conservation expenditures should be capitalized for tax purposes and deducted over the book life of the asset. Acceptance of the Service's position had no effect on net income because the Company obtained an accounting order from the Washington Commission with respect to additional tax expense associated with the settlement. The net income impact of other elements of the settlement was approximately $1.4 million.
12) Retirement Benefits
The Company has a noncontributory defined benefit pension plan covering substantially all of its employees. The benefit formula is a function of both years of service and the average of the five highest consecutive years of basic earnings within the last ten years of employment. The Company funds pension cost using the "frozen entry-age" actuarial cost method.
Through September 30, 1993, in accordance with the methodology confirmed in the January 17, 1990 general rate order from the Washington Commission, the Company has recognized pension costs for ratemaking and financial statement purposes using a formula based on a multi-year average of actual contributions to the plan. Effective October 1, 1993, because of a change in methodology made by the Washington Commission in its September 21, 1993 rate order, the Company's pension costs for financial statement purposes are determined in accordance with the provisions of Statement of Financial Accounting Standards No. 87, "Accounting for Pensions."
Net pension costs for 1993, 1992 and 1991, including $1,440,000 for 1993, $811,000 for 1992 and $741,000 for 1991 which were charged to construction and other asset accounts, were comprised of the following components:
1993 1992 1991 - --------------------------------------------------------------------------- (Dollars in Thousands) Service cost (benefits earned during the period) $ 6,952 $ 6,492 $ 5,919 Interest cost on projected benefit obligation 14,676 13,743 12,510 Actual return on plan assets (21,786) (9,426) (31,492) Net amortization and deferral 5,121 (5,470) 17,826 - --------------------------------------------------------------------------- Net pension costs under FASB Statement No. 87 4,963 5,339 4,763 - --------------------------------------------------------------------------- Regulatory adjustment (2,083) (3,575) (2,999) - --------------------------------------------------------------------------- Net pension costs $ 2,880 $ 1,764 $ 1,764 ===========================================================================
Funded Status of Plan At December 31: 1993 1992 - --------------------------------------------------------------------------- (Dollars in Thousands) Actuarial present value of benefit obligations: Vested $(151,399) $(125,019) Nonvested (1,090) (616) - ---------------------------------------------------------------------------- Accumulated benefit obligation (152,489) (125,635) Effect of future compensation levels (53,998) (51,072) - --------------------------------------------------------------------------- Total projected benefit obligation (206,487) (176,707) Plan assets at market value 214,580 191,776 - --------------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 8,093 15,069 Unrecognized net gain due to variance between assumptions and experience (14,344) (26,145) Prior service cost 11,232 12,249 Transition asset as of January 1, 1986, being amortized on a straight-line basis over 18 years (4,194) (4,614) Regulatory adjustment, cumulative 7,453 5,370 - --------------------------------------------------------------------------- Prepaid pension cost recognized in long-term assets on balance sheet $ 8,240 $ 1,929 ===========================================================================
Assumptions used for the above calculations are as follows: settlement (discount) rate for 1993 - 7.5%, for 1992 and 1991 - 8.5%; rate of annual compensation increase for 1993 - 5.5%, for 1992 and 1991 - 6%; and long-term rate of return on assets for 1993 - 8.5%, for 1992 and 1991 - 9%.
Plan assets consist primarily of U.S. Government securities, corporate debt and equity securities.
Effective October 1, 1991, the Company's Board of Directors approved supplemental retirement plans for officer and director level employees. Expenses for this plan for 1993, 1992 and 1991 were $651,000, $606,000 and $148,500, respectively. At December 31, 1993, a minimum liability and an intangible asset of $1,732,000 related to this plan are included in the financial statements.
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees. Substantially all of the Company's employees may become eligible for those benefits if they reach normal retirement age while working for the Company. These benefits are provided through an insurance company whose premiums are based on the benefits paid during the year. The Company recognized the cost of providing those benefits by expensing $2,025,000 and $2,095,000 for the years 1992 and 1991, respectively.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("Statement No. 106") which requires the costs associated with postretirement benefits to be accrued during the working careers of active employees. The Company is recognizing the impact of Statement No. 106 by amortizing its transition obligation of $24.9 million to expense over 20 years. The resulting 1993 annual cost under Statement No. 106 is approximately $3.8 million.
In the rate order issued by the Washington Commission on September 21, 1993, the Washington Commission approved adoption of accrual accounting for postretirement benefits. For rate purposes, the difference between accrual and pay-as-you-go accounting will be phased in over five years. The Washington Commission's calculation of Statement No. 106 costs for rate purposes is lower than the Company's cost. In 1993, the expense recognized for postretirement benefits was $2.8 million, including $.5 million disallowed by the Washington Commission which was expensed. An additional $1.0 million was deferred under provisions of the Washington Commission's five year phase-in plan.
13) Employee Investment Plan
The Company has a qualified employee Investment Plan under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. The Company makes a monthly contribution equal to 55% of the basic contribution of each participating employee. The basic contribution is limited to 6% of the employee's eligible earnings. All Company contributions are used to purchase Company common stock on the open market or directly from the Company.
The Company contributions to the plan were $3,520,000, $3,317,000 and $3,129,000 for the years 1993, 1992 and 1991, respectively. The shareholders have authorized the issuance of up to 1,000,000 shares of common stock under the plan, of which 959,142 were issued through December 31, 1993. The employee Investment Plan eligibility requirements are set forth in the plan documents.
14) Commitments and Contingencies
Commitments
For the twelve months ended December 31, 1993, approximately 27% of the Company's energy output was obtained at an average cost of approximately 11.9 mills per KWH through long-term contracts with several of the Washington public utility districts ("PUDs") owning hydroelectric projects on the Columbia River.
The purchase of power from the Columbia River projects is generally on a "cost-of-service" basis under which the Company pays a proportionate part of the annual cost of each project in direct ratio to the amount of power allocated to it. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs should not vary significantly over the term of the contracts unless additional financing is required to meet the costs of major maintenance, repairs or replacements or license requirements. The Company's share of the costs and the output of the projects is subject to reduction due to various withdrawal rights of the districts and others over the lives of the contracts.
As of December 31, 1993, the Company was entitled to purchase portions of the power output of the PUDs' projects as set forth in the following tabulation:
Company's Annual Amount Bonds Purchasable (Approximate) Outstanding -------------------------- Contract License 12/31/93(a) % of Kilowatt Costs(b) Project Exp.Date Exp.Date (Millions) Output Capacity (Millions) - ----------------------------------------------------------------------------- Rock Island Original units 2012 2029 $79.8 62.5 ) ) 507,000 $ 45.7 Additional units 2012 2029 326.8 100.0 ) Rocky Reach 2011 2006(c) 186.0 38.9 504,922 15.0 Wells 2018 2012(c) 199.9 34.8 292,320 10.0 Priest Rapids 2005 2005(c) 141.2 8.0 71,760 2.1 Wanapum 2009 2005(c) 189.4 10.8 98,280 2.8 - ----------------------------------------------------------------------------- Total 1,474,282 $ 75.6 =============================================================================
(a) The contracts for purchases are generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings, however, long-term bonds were sold to finance certain assets whose estimated useful lives extend beyond the expiration date of the power sales contracts. Of the total outstanding bonds sold for each project, the percentage of principal amount of bonds which mature beyond the contract expiration dates are: 69.3% at Rock Island; 20.1% at Rocky Reach; 59.8% at Priest Rapids; and 39.4% at Wanapum.
(b) Estimated debt service and operating costs for the year 1994. The components of 1994 costs associated with the interest portion of debt service are: Rock Island, $27.78 million for all units; Rocky Reach, $5.01 million; Wells, $3.42 million; Priest Rapids, $0.68 million; and Wanapum, $1.16 million.
(c) The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees or what effect the term of the licenses may have on the Company's contracts.
The Company's estimated payments for power purchases from the Columbia River projects are $75.6 million for 1994, $77.0 million for 1995, $77.7 million for 1996, $80.5 million for 1997, $84.3 million for 1998 and in the aggregate $1.044 billion thereafter through 2012.
The Company also has numerous long-term firm purchased power contracts with other utilities and non-utility generators in the region. These contracts have varying terms and may include escalation and termination provisions. The Company is not obligated to make payments under these contracts unless power is delivered. The Company's estimated payments for firm power purchases from other utilities and non-utility generators, which includes the expected addition of 245 MW of capacity during 1994 in the form of a purchased power contract with an independent producer of gas-fired cogeneration, are $361.5 million for 1994, $409.6 million for 1995, $424.0 million for 1996, $427.7 million for 1997, $446.3 million for 1998 and in the aggregate $6.885 billion thereafter through 2012.
Total purchased power contracts provided the Company with approximately 13.5 million, 12.7 million and 13.7 million MWH of firm energy at a cost of approximately $353.5 million, $274.6 million and $230.6 million for the years 1993, 1992 and 1991, respectively.
The following table indicates the Company's percentage ownership and the extent of the Company's investment in jointly-owned generating plants in service at December 31, 1993:
Energy Company's Plant in Accumulated Source Ownership Service Depreciation Project (Fuel) Share (%) (Millions) (Millions)
Centralia Coal 7 $ 25.7 $ 15.3 Colstrip 1 & 2 Coal 50 177.4 81.0 Colstrip 3 & 4 Coal 25 440.3 119.2
Financing for a participant's ownership share in the projects is provided for by such participant. The Company's share of related operating and maintenance expenses is included in corresponding accounts in the Consolidated Statements of Income.
Certain purchase commitments have been made in connection with the Company's construction program.
Contingencies
The Company is subject to environmental regulation by federal, state and local authorities. The Company has been named a Potentially Responsible Party by the Environmental Protection Agency at four sites. The Company is participating along with others in remedial action at various sites in the Pacific Northwest at which it is an alleged contributor of certain wastes. Based on the best estimates available at this time, the Company anticipates future costs for environmental remediation at all sites will approximate $4.4 million which was recorded as an accrued liability at December 31, 1993.
On April 1, 1992, the Washington Commission issued an order regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The order authorizes the Company to accumulate and defer prudently incurred cleanup costs paid to third parties for recovery in rates established in future rate proceedings.
The Company believes a significant portion of its past and future environmental remediation costs are recoverable from either insurance companies, third parties, or under the Washington Commission's order. At December 31, 1993, the recoverable amount for these costs is approximately $11.3 million.
In its September 21, 1993 general rate order, the Washington Commission required the Company to file a case by November 1, 1993, demonstrating the prudency of its eight new power purchase contracts acquired since its last general rate case. Pending the resolution of the prudency review case, the Washington Commission ordered that the Company's new rates, effective October 1, 1993, would be collected subject to refund to the extent this proceeding demonstrates any of those contracts to be imprudent. The Washington Commission calculated the annual revenue requirement at risk to be up to $86.1 million. This amount is the difference between the Company's power costs under the new power purchase contracts and the Washington Commission's estimated cost of purchasing equivalent power on the secondary market. The Company filed its prudency case on October 18, 1993, and expects the Washington Commission to enter a final order before October 1, 1994. Revenues reported as of December 31, 1993 which are at risk under the prudency review case are approximately $19.7 million. The extent to which refunds, if any, are necessary is subject to the determination of the Washington Commission. However, based on the nature and terms of the contracts and existing regulatory precedents, management believes that these contracts are prudent and that the ultimate resolution of the review will not have a material adverse impact on the financial condition or results of operations of the Company.
Other contingencies, arising out of the normal course of the Company's business, exist at December 31, 1993. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition or results of operations of the Company.
15) Supplemental Quarterly Financial Data (Unaudited)
The following amounts are unaudited but, in the opinion of the Company, include all adjustments necessary for a fair presentation of the results of operations for the interim periods. Annual amounts are not generated evenly by quarter during the year due to the seasonal nature of the utility business.
1993 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------ (Dollars in Thousands except per share amounts)
Operating revenues $323,974 $237,617 $230,178 $321,109 Operating income $ 72,922 $ 43,039 $ 35,505 $ 59,514 Other income $ 3,718 $ 4,614 $ 3,536 $ 1,712 Net income $ 54,682 $ 26,213 $ 18,071 $ 39,361 Earnings per common share $ 0.86 $ 0.37 $ 0.23 $ 0.56 - ------------------------------------------------------------------------
1992 Quarter Ended March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------ (Dollars in Thousands except per share amounts)
Operating revenues $280,202 $240,643 $219,221 $284,904 Operating income $ 67,818 $ 51,557 $ 35,717 $ 59,579 Other income $ 3,765 $ 6,294 $ 4,627 $ 2,517 Net income $ 48,032 $ 29,538 $ 17,987 $ 40,163 Earnings per common share $ 0.83 $ 0.47 $ 0.25 $ 0.62 - ------------------------------------------------------------------------
16) Consolidated Statement of Cash Flows
For purposes of the Statement of Cash Flows, the Company considers all temporary investments to be cash equivalents. These temporary cash investments are securities held for cash management purposes, having maturities of three months or less. The net change in current assets and current liabilities for purposes of the Statement of Cash Flows excludes short-term debt, current maturities of long-term debt and the current portion of PRAM accrued revenues.
The following provides additional information concerning cash flow activities:
Year Ended December 31: 1993 1992 1991 - --------------------------------------------------------------------------- (Dollars in Thousands) Changes in certain current assets and current liabilities: Accounts receivable $ (5,050) $(13,848) $12,474 Deferred energy costs -- (20) 119 Unbilled revenues (14,410) (15,081) 16,217 Materials and supplies 1,054 (1,338) (2,840) Prepayments and Other 5,809 (6,346) (677) Accounts payable 10,731 (5,948) 9,624 Accrued expenses and Other 11,511 3,274 (9,018) - --------------------------------------------------------------------------- Net change in certain current assets and current liabilities $ 9,645 $(39,307) $25,899 =========================================================================== Cash payments: Interest (net of capitalized interest) $80,646 $97,242 $86,114 Income taxes $32,585 $76,050 $61,256 - ---------------------------------------------------------------------------
17) Subsequent Event
In furtherance of its ongoing program to manage costs effectively and remain competitive with other energy providers, the Company decided in January 1994 to offer an early separation plan to all officers, senior and middle managers and eligible professional staff. Benefits offered to those electing the program include a severance package based on years of service and enhanced retirement benefits for employees over 55 years of age. The number of employees that will accept the offer is presently not known. The Company has not set any specific job reduction targets.
The Company, based on studies performed, currently estimates the total severance cost will not exceed $10 million. However, the total severance cost is dependent on the number of employees ultimately accepting the plan. The accrual for costs of this program will be recognized in the first quarter of 1994.
PUGET SOUND POWER & LIGHT COMPANY SCHEDULE II. Amounts Receivable From Related Parties and Underwriters, Promoters and Employees Other Than Related Parties - ---------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Ending Beginning Balance Name of Debtor Balance Additions Deletions Non-Current - ---------------------------- --------- --------- --------- ----------- Year Ended December 31, 1993 Bill E. Covin (a) $262,000 $ 21,000 -- $283,000 - --------------------------------------------------------------------------- Year Ended December 31, 1992 Bill E. Covin (a) $589,000 $ 23,000 $350,000 $262,000 - --------------------------------------------------------------------------- Year Ended December 31, 1991 Bill E. Covin (a) $545,000 $ 44,000 -- $589,000 - ---------------------------------------------------------------------------
(a) Note receivable at 8.06% interest, due March 31, 1995.
Puget Sound Power & Light Company Schedule VIII. Valuation and Qualifying Accounts and Reserves - ----------------------------------------------------------------------------- (Dollars in Thousands) - ----------------------------------------------------------------------------- Column A Column B Column C Column D Column E - ----------------------------------------------------------------------------- Additions Balance at Charged to Balance Beginning Costs and at End of Period Expenses Deductions of Period
Year Ended December 31, 1993 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 488 $ 2,799 $ 2,764 $ 523 - ----------------------------------------------------------------------------- Reserves: Accumulated provision for self-insurance $ 87 $13,634(A) $13,721(A) $ -- =============================================================================
Year Ended December 31, 1992 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 531 $ 1,981 $ 2,024 $ 488 - ----------------------------------------------------------------------------- Reserves: Accumulated provision for self-insurance $ 792 $ 4,610(A) $ 5,315(A) $ 87 =============================================================================
Year Ended December 31, 1991 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 569 $ 2,954 $ 2,992 $ 531
Reserves: Accumulated provision for self-insurance $ 900 $16,047(A) $16,155(A) $ 792 =============================================================================
Note (A): Includes charges of $10.3 million in 1993, $1.8 million in 1992 and $12.5 million in 1991 which were transferred to a deferred asset account.
EXHIBIT INDEX
Certain of the following exhibits are filed herewith. Certain other of the following exhibits have heretofore been filed with the Commission and are incorporated herein by reference.
3-a Restated Articles of Incorporation of the Company. (Exhibit 1.2 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
3-b Restated Bylaws of the Company. (Exhibit 4-b to Registration No. 33-18506)
4.1 Fortieth through Seventy-fifth Supplemental Indentures defining the rights of the holders of the Company's First Mortgage Bonds. (Exhibit 2- d to Registration No. 2-60200; Exhibit 4-c to Registration No. 2-13347; Exhibits 2-e through and including 2-k to Registration No. 2-60200; Exhibit 4- h to Registration No. 2-17465; Exhibits 2-l, 2-m and 2-n to Registration No. 2-60200; Exhibits 2-m to Registration No. 2-37645; Exhibit 2-o through and including 2-s to Registration No. 2-60200; Exhibit 5-b to Registration No. 2- 62883; Exhibit 2-h to Registration No. 2-65831; Exhibit (4)-j-1 to Registration No. 2-72061; Exhibit (4)-a to Registration No. 2-91516; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393; Exhibits (4)(a) and (4)(b) to Company's Current Report on Form 8-K, dated April 22, 1986; Exhibit (4)a to Company's Current Report on Form 8-K, dated September 5, 1986; Exhibit (4)-b to Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393; Exhibit (4)-c to Registration No. 33-18506; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393; Exhibit (4)-b to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393; Exhibits (4)-b and (4)-c to Registration No. 33-45916; Exhibit (4)-c to Registration No. 33-50788; Exhibit (4)-a to Registration No. 33-53056; and Exhibit 4.3 to Registration No. 33-63278.)
4.2 Credit Agreement dated as of December 1, 1991, among the Company and various banks named therein, Seattle-First National Bank as Agent. (Exhibit (4)-d to Registration No. 33-45916)
4.3 Credit Agreement dated as of December 1, 1991, among the Company and various banks named therein, Bank of New York as Agent. (Exhibit (4)-e to Registration No. 33-45916)
4.4 Final form of Indenture dated as of November 1, 1986, among Puget Energy, the Company, and The First National Bank of Boston, as Trustee. (Exhibit 4-a to Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393)
4.5 Final form of Pledge Agreement dated November 1, 1986, between the Company and The First National Bank of Boston, as Trustee. (Exhibit 4-c to Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1986, Commission File No. 1-4393)
4.6 Rights Agreement, dated as of January 15, 1991, between the Company and The Chase Manhattan Bank, N.A., as Rights Agent. (Exhibit 2.1 to Registration Statement on Form 8-A filed on January 17, 1991, Commission File No. 1-4393)
4.7 Pledge Agreement dated August 1, 1991, between the Company and The First National Bank of Chicago, as Trustee. (Exhibit (4)-j to Registration No. 33-45916)
4.8 Loan Agreement dated August 1, 1991, between the City of Forsyth, Rosebud County, Montana and the Company. (Exhibit (4)-k to Registration No. 33-45916)
4.9 Statement of Relative Rights and Preferences for the Adjustable Rate Cumulative Preferred Stock, Series B ($25 Par Value). (Exhibit 1.1 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.10 Statement of Relative Rights and Preferences for the Series A Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred Stock. (Exhibit 1.3 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.11 Statement of Relative Rights and Preferences for the Series B Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred Stock. (Exhibit 1.4 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.12 Statement of Relative rights and Preferences for the Preference Stock, Series R, $50 Par Value. (Exhibit 1.5 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.13 Statement of Relative Rights and Preferences for the 7 3/4% Series Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.14 Statement of Relative Rights and Preferences for the 7 7/8% Series Preferred Stock Cumulative, $25 Par Value. (Exhibit 1.7 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
*4.15 Pledge Agreement, dated as of March 1, 1992, by and between the Company and and Chemical Bank relating to a series of first mortgage bonds.
*4.16 Pledge Agreement, dated as of April 1, 1993, by and between the Company and The First National Bank of Chicago, relating to a series of first mortgage bonds.
10.1 Assignment and Agreement, dated as of August 13, 1964, between Public Utility District No. 1 of Chelan County, Washington and the Company, relating to the Rock Island Project. (Exhibit 13-b to Registration No. 2-24262) 10.2 First Amendment, dated as of October 4, 1961, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and the Company, relating to the Rocky Reach Project. (Exhibit 13-d to Registration No. 2-24252)
10.3 Assignment and Agreement, dated as of August 13, 1964, between Public Utility District No. 1 of Chelan County, Washington and the Company, relating to the Rocky Reach Project. (Exhibit 13-e to Registration No. 2-24252)
10.4 Assignment and Agreement, dated as of August 13, 1964, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Priest Rapids Development. (Exhibit 13-j to Registration No. 2-24252)
10.5 Assignment and Agreement, dated as of August 13, 1964, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Wanapum Development. (Exhibit 13-n to Registration No. 2-24252)
10.6 First Amendment, dated February 9, 1965, to Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13-p to Registration No. 2-24252)
10.7 First Amendment, executed as of February 9, 1965, to Reserved Share Power Sales Contract between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13-r to Registration No. 2-24252)
10.8 Assignment and Agreement, dated as of August 13, 1964, between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13-u to Registration No. 2-24252)
10.9 Pacific Northwest Coordination Agreement, executed as of September 15, 1964, among the United States of America, the Company and most of the other major electrical utilities in the Pacific Northwest. (Exhibit 13-gg to Registration No. 2-24252)
10.10 Contract dated November 14, 1957, between Public Utility District No. 1 of Chelan County, Washington and the Company, relating to the Rocky Reach Project. (Exhibit 4-1-a to Registration No. 2-13979)
10.11 Power Sales Contract, dated as of November 14, 1957, between Public Utility District No. 1 of Chelan County, Washington and the Company, relating to the Rocky Reach Project. (Exhibit 4-c-1 to Registration No. 2-13979)
10.12 Power Sales Contract, dated May 21, 1956, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Priest Rapids Project. (Exhibit 4-d to Registration No. 2-13347)
10.13 First Amendment to Power Sales Contract dated as of August 5, 1958, between the Company and Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development. (Exhibit 13-h to Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Wanapum Development. (Exhibit 13-j to Registration No. 2- 15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Priest Rapids Project. (Exhibit 13-k to Registration No. 2- 15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Wanapum Development. (Exhibit 13-1 to Registration No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13-r to Registration No. 2- 21824)
10.18 Reserved Share Power Sales Contract executed as of September 18, 1963, between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13- s to Registration No. 2-21824)
10.19 Exchange Agreement dated April 12, 1963, between the United States of America, Department of the Interior, acting through the Bonneville Power Administrator and Washington Public Power Supply System and the Company, relating to the Hanford Project. (Exhibit 13-u to Registration 2- 21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between the United States of America, Department of the Interior, acting through the Bonneville Power Administrator and the Company, relating to the Hanford Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971, between The Montana Power Company and the Company. (Exhibit 5-b to Registration No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971, between The Montana Power Company and the Company. (Exhibit 5-c to Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d to Registration No. 2-45702) 10.25 Power Purchase Agreement with Washington Public Power Supply System and the Bonneville Power Administration dated February 6, 1973. (Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D. No. 1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974
10.28 Restated Financing Agreement among the Company, lessee, Chrysler Financial Corporation, owner, Nevada National Bank and Bank of Montreal (California), trustee, dated December 12, 1974 pertaining to a combustion turbine generating unit trust. (Exhibit 5-a-35 to Registration No. 2-60200)
10.29 Restated Lease Agreement between the Company, lessee, and the Bank of California, and National Association, lessor, dated December 12, 1974 for one combustion generating unit. (Exhibit 5-a-36 to Registration No. 2-60200)
10.30 Financing Agreement Supplement and Amendment among the Company, lessee, Chrysler Financial Corporation, owner, The Bank of California, National Association, trustee, Pacific Mutual Life Insurance Company, Bankers Life Company, and The Franklin Life Insurance Company, lenders, dated as of March 26, 1975, pertaining to a combustion turbine generating unit trust. (Exhibit 5-a-37 to Registration No. 2-60200)
10.31 Lease Agreement Supplement and Amendment between the Company, lessee, and The Bank of California, National Association, lessor, dated as of March 26, 1975 for one combustion turbine generating unit. (Exhibit 5-a- 38 to Registration No. 2-60200)
10.32 Exchange Agreement executed August 13, 1964, between the United States of America, Columbia Storage Power Exchange and the Company, relating to Canadian Entitlement. (Exhibit 13-ff to Registration No. 2-24252)
10.33 Loan Agreement dated as of December 1, 1980 and related documents pertaining to Whitehorn turbine construction trust financing. (Exhibit 10.52 to Annual Report on Form 10-K for the fiscal year ended December 31, 1980, Commission File No. 1-4393)
10.34 Letter Agreement dated March 31, 1980, between the Company and Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No. 2-68498)
10.35 Coal Supply Agreement for Colstrip 3 and 4, dated as of July 2, 1980; Amendment No. 1 to Coal Supply Agreement, dated as of July 10, 1981; and Coal Transportation Agreement dated as of July 10, 1981. (Exhibit 20-a to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393) 10.36 Residential Purchase and Sale Agreement between the Company and the Bonneville Power Administration, effective as of October 1, 1981. (Exhibit 20-b to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393)
10.37 Letter of Agreement to Participate in Licensing of Creston Generating Station, dated September 30, 1981. (Exhibit 20-c to Quarterly Report on Form 10-Q for the quarter ended September 30, 1981, Commission File No. 1-4393)
10.38 Power sales contract dated August 27, 1982 between the Company and Bonneville Power Administration. (Exhibit 10-a to Quarterly Report on Form 10-Q for the quarter ended September 30, 1982, Commission File No. 1- 4393)
10.39 Agreement executed as of April 17, 1984, between the United States of America, Department of the Interior, acting through the Bonneville Power Administration, and other utilities relating to extension energy from the Hanford Atomic Power Plant No. 1. (Exhibit (10)-47 to Annual Report on Form 10-K for the fiscal year ended December 31, 1984, Commission File No. 1- 4393)
10.40 Agreement for the Assignment of Output from the Centralia Thermal Project, dated as of April 14, 1983, between the Company and Public Utility District No. 1 of Grays Harbor. (Exhibit (10)-48 to Annual Report on Form 10-K for the fiscal year ended December 31, 1984, Commission File No. 1-4393)
10.41 Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company dated September 17, 1985. (Exhibit (10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.42 Agreement to Dismiss Claims and Covenant Not to Sue dated September 17, 1985 between Washington Public Power Supply System and the Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.43 Irrevocable Offer of Washington Public Power Supply System Nuclear Project No. 3 Capability for Acquisition executed by the Company, dated September 17, 1985. (Exhibit A of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1- 4393)
10.44 Settlement Exchange Agreement ("Bonneville Exchange Power Contract") executed by the United States of America Department of Energy acting by and through the Bonneville Power Administration and the Company, dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1- 4393)
10.45 Settlement Agreement and Covenant Not to Sue between the Company and Northern Wasco County People's Utility District, dated October 16, 1985. (Exhibit (10)-53 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.46 Settlement Agreement and Covenant Not to Sue between the Company and Tillamook People's Utility District, dated October 16, 1985. (Exhibit (10)-54 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.47 Settlement Agreement and Covenent Not to Sue between the Company and Clatskanie People's Utility District, dated September 30, 1985. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.48 Stipulation and Settlement Agreement between the Company and Muckleshoot Tribe of the Muckleshoot Indian Reservation, dated October 31, 1986. (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1986, Commission File No. 1-4393)
10.49 Transmission Agreement dated April 17, 1981, between the Bonneville Power Administration and the Company (Colstrip Project). (Exhibit (10)-55 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.50 Transmission Agreement dated April 17, 1981, between the Bonneville Power Administration and Montana Intertie Users (Colstrip Project). (Exhibit (10)-56 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.51 Ownership and Operation Agreement dated as of May 6, 1981, between the Company and other Owners of the Colstrip Project (Colstrip 3 and 4). (Exhibit (10)-57 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.52 Colstrip Project Transmission Agreement dated as of May 6, 1981, between the Company and Owners of the Colstrip Project. (Exhibit (10)-58 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.53 Common Facilities Agreement dated as of May 6, 1981, between the Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.54 Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork II, Inc. and the Company (Weeks Falls Hydroelectric Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.55 Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork Resources, Inc. and the Company (Twin Falls Hydroelectric Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.56 Agreement for Firm Purchase Power dated as of January 4, 1988, between the City of Spokane, Washington, and the Company (Spokane Waste Combustion Project). (Exhibit (10)-62 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.57 Agreement for Evaluating, Planning and Licensing dated as of February 21, 1985 and Agreement for Purchase of Power dated as of February 21, 1985 between Pacific Hydropower Associates and the Company (Koma Kulshan Hydroelectric Project). (Exhibit (10)-63 to Annual Report on Form 10- K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.58 Power Sales Agreement dated as of August 1, 1986, between Pacific Power & Light Company and the Company. (Exhibit (10)-64 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.59 Agreement for Purchase and Sale of Firm Capacity and Energy dated as of August 1, 1986 between The Washington Water Power Company and the Company. (Exhibit (10)-65 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.60 Amendment dated as of June 1, 1968, to Power Sales Contract between Public Utility District No. 1 of Chelan County, Washington and the Company (Rocky Reach Project). (Exhibit (10)-66 to Annual Report on Form 10- K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 Coal Supply Agreement dated as of October 30, 1970, between the Washington Irrigation & Development Company and the Company and other Owners of the Centralia Thermal Project (Centralia Generating Plant). (Exhibit (10)- 67 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.62 Interruptible Natural Gas Service Agreement dated as of May 14, 1980, between Cascade Natural Gas Corporation and the Company (Whitehorn Combustion Turbine). (Exhibit (10)-68 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Interruptible Natural Gas Service Agreement dated as of January 31, 1983, between Cascade Natural Gas Corporation and the Company (Fredonia Generating Station). (Exhibit (10)-69 to Annual Report on Form 10- K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Interruptible Gas Service Agreement dated May 14, 1981, between Washington Natural Gas Company and the Company (Fredrickson Generating Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.65 Settlement Agreement dated April 24, 1987, between Public Utility District No. 1 of Chelan County, the National Marine Fisheries Service, the State of Washington, the State of Oregon, the Confederated Tribes and Bands of the Yakima Indian Nation, Colville Indian Reservation, Umatilla Indian Reservation, the National Wildlife Federation and the Company (Rock Island Project). (Exhibit (10)-71 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.66 Amendment No. 2 dated as of September 1, 1981, and Amendment No. 3 dated September 14, 1987, to Coal Supply Agreement between Western Energy Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit (10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.67 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between the Company and the Bonneville Power Administration dated August 27, 1982. (Exhibit (10)-73 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.68 Transmission Agreement dated as of December 30, 1987, between the Bonneville Power Administration and the Company (Rock Island Project). (Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.69 Agreement for Purchase and Sale of Firm Capacity and Energy between The Washington Water Power Company and the Company dated as of January 1, 1988. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1988, Commission File No. 1-4393)
10.70 Amendment dated as of August 10, 1988, to Agreement for Firm Purchase Power dated as of January 4, 1988, between the City of Spokane, Washington, and the Company (Spokane Waste Combustion Project).(Exhibit (10)- 76 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.71 Agreement for Firm Power Purchase dated October 24, 1988, between Northern Wasco People's Utility District and the Company (The Dalles Dam North Fishway). (Exhibit (10)-77 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.72 Agreement for the Purchase of Power dated as of October 27, 1988, between Pacific Power & Light Company (PacifiCorp) and the Company. (Exhibit (10)-78 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.73 Agreement for Sale and Exchange of Firm Power dated as of November 23, 1988, between the Bonneville Power Administration and the Company. (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No. 1-4393)
10.74 Agreement for Firm Power Purchase, dated as of February 24, 1989, between Sumas Energy, Inc. and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1989, Commission File No. 1-4393)
10.75 Settlement Agreement, dated as of April 27, 1989, between Public Utility District No. 1 of Douglas County, Washington, Portland General Electric Company, PacifiCorp, The Washington Water Power Company and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q the for quarter ended September 30, 1989, Commission File No. 1-4393)
10.76 Agreement for Firm Power Purchase (Thermal Project), dated as of June 29, 1989, between San Juan Energy Company and the Company. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.77 Agreement for Verification of Transfer, Assignment and Assumption, dated as of September 15, 1989, between San Juan Energy Company, March Point Cogeneration Company and the Company. (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.78 Power Sales Agreement between The Montana Power Company and the Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1- 4393)
10.79 Conservation Power Sales Agreement dated as of December 11, 1989, between Public Utility District No. 1 of Snohomish County and the Company. (Exhibit (10)-87 to Annual Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393)
10.80 Memorandum of Understanding dated as of January 24, 1990, between the Bonneville Power Administrator and The Washington Public Power Supply System, Portland General Electric Company, Pacific Power & Light Company, The Montana Power Company, and the Company. (Exhibit (10)-88 to Annual Report on Form 10-K for the fiscal year ended December 31, 1989, Commission File No. 1-4393)
10.81 Amendment No. 1 to Agreement for the Assignment of Power from the Centralia Thermal Project dated as of January 1, 1990, between Public Utility District No. 1 of Grays Harbor County, Washington, and the Company. (Exhibit (10)-89 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.82 Preliminary Materials and Equipment Acquisition Agreement dated as of February 9, 1990, between Northwest Pipeline Corporation and the Company. (Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.83 Amendment No. 1 to the Colstrip Project Transmission Agreement dated as of February 14, 1990, among the Montana Power Company, The Washington Water Power Company, Portland General Electric Company, PacifiCorp and the Company. (Exhibit (10)-91 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.84 Settlement Agreement dated as of February 27, 1990, among United States of America Department of Energy acting by and through the Bonneville Power Administrator, the Washington Public Power Supply System, and the Company. (Exhibit (10)-92 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.85 Amendment No. 1 to the Fifteen-Year Power Sales Agreement dated as of April 18, 1990, between Pacificorp and the Company. (Exhibit (10)-93 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.86 Settlement Agreement dated as of October 1, 1990, among Public Utility District No. 1 of Douglas County, Washington, the Company, Pacific Power and Light Company, The Washington Water Power Company, Portland General Electric Company, the Washington Department of Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of the Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.87 Agreement for Firm Power Purchase dated July 23, 1990, between Trans-Pacific Geothermal Corporation, a Nevada corporation, and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393)
10.88 Agreement for Firm Power Purchase dated July 18, 1990, between Wheelabrator Pierce, Inc., a Delaware corporation, and the Company. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393)
10.89 Agreement for Firm Power Purchase dated September 26, 1990, between Encogen Northwest, L.P., A Delaware Corporation and the Company. (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393)
10.90 Agreement for Firm Power Purchase (Thermal Project) dated December 27, 1990, among March Point Cogeneration Company, a California general partnership comprising San Juan Energy Company, a California corporation; Texas-Anacortes Cogeneration Company, a Delaware corporation; and the Company. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended March 31, 1991, Commission File No. 1-4393)
10.91 Agreement for Firm Power Purchase dated March 20, 1991, between Tenaska Washington, Inc. a Delaware corporation, and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.92 Letter Agreement dated April 25, 1991, between Sumas Energy, Inc., and the Company, to amend the Agreement for Firm Power Purchase dated as of February 24, 1989. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.93 Amendment dated June 7, 1991, to Letter Agreement dated April 25, 1991, between Sumas Energy, Inc., and the Company. (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.94 Amendatory Agreement No. 3, dated August 1, 1991, to the Pacific Northwest Coordination Agreement, executed September 15, 1964, among the United States of America, the Company and most of the other major electrical utilities in the Pacific Northwest. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended June 30, 1991, Commission File No. 1-4393)
10.95 Amendment dated July 11, 1991, to the Agreement for Firm Power Purchase dated September 26, 1990, between Encogen Northwest, L.P., a Delaware limited partnership and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393)
10.96 Agreement between the 40 parties to the Western Systems Power Pool (the Company being one party) dated July 27, 1991. (Exhibit (10)-2 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393)
10.97 Memorandum of Understanding between the Company and the Bonneville Po wer Administration dated September 18, 1991. (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1991, Commission File No. 1-4393)
10.98 Amendment of Seasonal Exchange Agreement, dated December 4, 1991, between Pacific Gas and Electric Company and the Company. (Exhibit (10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.99 Capacity and Energy Exchange Agreement, dated as of October 4, 1991, between Pacific Gas and Electric Company and the Company. (Exhibit (10)-108 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.100 Intertie and Network Transmission Agreement, dated as of October 4, 1991, between Bonneville Power Administration and the Company. (Exhibit (10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.101 Amendatory Agreement No. 4, executed June 17, 1991, to the Power Sales Agreement dated August 27, 1982, between the Bonneville Power Administration and the Company. (Exhibit (10)-110 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.102 Amendment to Agreement for Firm Power Purchase, dated as of September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit (10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.103 Centralia Fuel Supply Agreement, dated as of January 1, 1991, between Pacificorp Electric Operations and the Company and other Owners of the Centralia Steam-Electric Power Plant. (Exhibit (10)-113 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.104 Agreement for Firm Power Purchase dated August 10, 1992, between Pyrowaste Corporation, Puget Sound Pyroenergy Corporation and the Company. (Exhibit (10)-114 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.105 Memorandum of Termination dated August 31, 1992, between Encogen Northwest, L.P. and the Company. (Exhibit (10)-115 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.106 Agreement Regarding Security dated August 31, 1992, between Encogen Northwest, L.P. and the Company. (Exhibit (10)-116 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.107 Consent and Agreement dated December 15, 1992, between the Company, Encogen Northwest, L.P. and The First National Bank of Chicago, as collateral agent. (Exhibit (10)-117 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.108 Subordination Agreement dated December 17, 1992, between the Company, Encogen Northwest, L.P., Rolls-Royce & Partners Finance Limited and The First National Bank of Chicago. (Exhibit (10)-118 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1- 4393)
10.109 Letter Agreement dated December 18, 1992, between Encogen Northwest, L.P. and the Company regarding arrangements for the application of insurance proceeds. (Exhibit (10)-119 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.110 Guaranty of Ensearch Corporation in favor of the Company dated December 15, 1992. (Exhibit (10)-120 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.111 Letter Agreement dated October 12, 1992, between Tenaska Washington Partners, L.P. and the Company regarding clarification of issues under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.112 Consent and Agreement dated October 12, 1992, between the Company, and The Chase Manhattan Bank, N.A., as agent. (Exhibit (10)-122 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.113 Settlement Agreement dated December 29, 1992, between the Company and the Bonneville Power Administration (BPA) providing for power purchase by BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
*10-114 Contract with W. S. Weaver, Executive Vice President & Chief Financial Officer, dated April 24, 1991.
*(12)-a Statement setting forth computation of ratios of earnings to fixed charges (1989 through 1993).
*(12)-b Statement setting forth computation of ratios of earnings to combined fixed charges and preferred stock dividends (1989 through 1993).
(21) List of subsidiaries. (Exhibit 22 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
*(23) Consent of accountants.
_________________________________ *Filed herewith.