============================================================================= SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _______________________ FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 October 23, 1997 February 10, 1997 ___________________________________________________ (Date of earliest event reported) PUGET SOUND ENERGY, INC (Exact name of registrant as specified in its charter) Washington 1-4393 91-0374630 (State or other (Commission (I.R.S. Employer jurisdiction of File Number) Identification incorporation) Number) 411 108th Avenue N.E., Bellevue, Washington 98004-5515 (Address of principal executive offices, zip code) Registrant's telephone number, including area code: 425/454-6363 ============================================================================= 1 ITEM 5. OTHER EVENTS For information regarding periods subsequent to those periods contained in this report, please see the Company's quarterly reports on Form 10-Q for the periods ending March 31, 1997 and June 30, 1997. BUSINESS General Puget Sound Energy, Inc. (the "Company"), formerly Puget Sound Power & Light Company ("Puget Power"), is an investor-owned public utility incorporated in the State of Washington furnishing electric and, since February 10, 1997, gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of Washington state. On February 10, 1997, the Company completed a merger (the "Merger") with the Washington Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas Company ("WNG"). Seattle-based WNG provided natural gas distribution service to approximately 500,000 customers in an area east of Puget Sound that included Seattle, Tacoma, Everett, Bellevue and Olympia. Puget Power changed its name to Puget Sound Energy, Inc. effective with the Merger. Certain historical financial and statistical information contained herein has been restated to reflect the combined operations of the Company, WECo and WNG and all references to the Company include the combined entity. Effective with the merger, WECo's 1996 fiscal year-end was changed from September 30 to December 31 to conform to Puget Power's year-end. Accordingly, financial and statistical information contained herein reflects fiscal years ended December 31 for Puget Power and September 30 for WECo. (See "Merger With Washington Energy Company and Washington Natural Gas Company," below.) At year-end, the Company had approximately 857,300 electric customers, consisting of 761,000 residential, 90,500 commercial, 4,100 industrial and 1,400 other customers and approximately 492,700 gas customers, consisting of 448,700 residential, 41,000 commercial, 2,900 industrial and 100 other customers. For the year 1996, the Company added approximately 16,600 electric customers and approximately 22,200 gas customers, representing annualized growth rates of 2.0% and 4.7%, respectively. During 1996, the Company's billed revenues from electric utility operations were derived 47% from residential customers, 35% from commercial customers, 14% from industrial customers and 4% from sales to other utilities and others, and the Company's billed revenues from gas utility operations were derived 60% from residential customers, 23% from commercial customers, 11% from industrial customers and 6% from other customers. During this period, the largest single electric customer accounted for 3.3% of the Company's electric utility operating revenues, and the largest single gas customer accounted for .5% of the Company's gas utility operating revenues. 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 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 of electricity to other utilities also vary by quarters and years depending principally upon streamflow conditions for the generation of surplus hydro-electric power, customer usage and the energy requirements of other neighboring utilities. Under the electric Periodic Rate Adjustment Mechanism ("PRAM") approved by the Washington Utilities and Transportation Commission (the "Washington Commission") in October 1991, earnings were not significantly influenced, up or down, by sales of surplus electricity to other utilities or by variations in normal seasonal weather or hydro 2 conditions. The PRAM however, ended effective September 30, 1996, under a stipulated negotiated settlement approved by the Washington Commission. With the discontinuance of the PRAM, earnings now can be significantly influenced, up or down, by surplus sales and variations in weather and hydro conditions. Since 1971, the Washington Commission has permitted WNG, and now WNG to pass on to its customers, through changes in its rates, all changes in the price of gas purchased from nonaffiliated suppliers through the PGA mechanism. This mechanism allows the Company to pass these cost increases or decreases to its customers on a timely basis, resulting in no material impact on net income. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.") During the period from January 1, 1992 through December 31, 1996, the Company made gross electric utility plant additions of $915 million and retirements of $131 million. In the five year period ended September 30, 1996, the Company made gross gas utility plant additions of $424 million and retirements of $44 million. Gross electric utility plant at December 31, 1996, was approximately $3.5 billion which consisted of 47% distribution, 27% generation, 15% transmission and 11% general plant and other. Gross gas utility plant at September 30, 1996, was approximately $1.1 billion which consisted of 86% distribution, 4% transmission and 10% general plant and other. At year-end the Company and its subsidiaries had 3,261 aggregate full-time equivalent employees, down from 4,350 aggregate employees at the end of 1992. This represents a workforce reduction of 25% over the last four years. Industry Evolution The U.S. electric utility industry is facing an increasingly competitive environment, particularly in wholesale electric generation and industrial customer markets. The National Energy Policy Act of 1992 ("EPACT") intensified competition in the wholesale electric market by easing restrictions on wholesale power producers and by allowing the Federal Energy Regulatory Commission ("FERC") to order access for wholesale sellers to deliver electric power to wholesale buyers over transmission systems owned by others. In 1996, FERC issued its landmark Orders 888 and 889, which require jurisdictional utilities, including the Company, to file wholesale transmission tariffs providing pricing and terms for transmission access for wholesale purposes. The EPACT does not permit the FERC to order transmission access for retail purposes, but Congress now has pending bills that would require existing electric utilities to allow competitors to use utility property, including transmission and distribution facilities, to provide electric service to retail customers of the existing utilities. Several states, including California, New Hampshire, Pennsylvania and Rhode Island have enacted legislation to allow competitors to use utility property of electric utilities. Most other states, including Washington, are considering, or have adopted, legislative or regulatory proposals which would also allow competitors to sell to retail customers of the existing utilities. In its February 5, 1997 order approving the Merger, the Washington Commission required the Company to conduct a retail access pilot program. Any substantial change in utility regulation in Washington state, such as allowing use of utility property by competitors for retail purposes, would require legislative action. The major credit rating agencies have expressed the general view that increased competition is likely to increase business risks in the electric utility industry, with resulting pressures on utility credit quality and investor returns. 3 Since 1986, the Company has been offering gas transportation as a separate service to industrial and commercial customers who choose to purchase their gas supply directly from producers and gas marketers. The continued evolution of the natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the ability of large gas end-users to bypass the Company in obtaining gas supply and transportation services. Though the Company has not lost any substantial industrial or commercial load as a result of such bypass, in certain years up to 160 customers annually have taken advantage of unbundled transportation service; in 1996, approximately 106 commercial and industrial customers, on average, chose to use such service. (See "Gas Utility Operations - Natural Gas Pipeline Deregulation.") Merger With Washington Energy Company and Washington Natural Gas Company Puget Sound Power & Light Company, on February 10, 1997, completed its Merger with WECo and WNG and was renamed Puget Sound Energy The order approving the Merger, issued by the Washington Commission on February 5, 1997, contains a rate plan designed to provide a five-year period of rate certainty for customers and to provide the Company with an opportunity to achieve a reasonable return on investment. As required under the Merger order, the Company filed tariffs, effective February 8, 1997, that resulted in an average decrease of 5.6% related to the PRAM, and an increase in general electric rates of between 1.0% and 2.5%, depending on rate class. The general rate increase has a positive impact on earnings while the decrease, reflecting the discontinuation of the PRAM and collection of accrued revenues, does not affect earnings. The net impact was an average decrease in electric rates of 3.7%, including a decrease in residential rates of 3.2%. General rates for electric residential and industrial service will increase by 1.5% on January 1 of each of the four years beginning in 1998, while those for small commercial electric customers will increase by 1.0% in each of the following three years. General rates for all classes of natural gas customers will remain unchanged until January 1, 1999, when they will decrease sufficiently to reduce gas utility margins by 1%. On January 29, 1997, the Company and BPA signed a Residential Exchange Termination Agreement. The Agreement ends the Company's participation in the Residential Purchase and Sale Agreement with BPA. The Residential Purchase and Sale Agreement enabled the Company's residential and small farm customers to receive the benefits of lower-cost federal power. As part of the Termination Agreement, the Company will receive payments by the BPA of approximately $237 million over five years. Under the rate plan approved by the Washington Commission in its merger order, the Company will continue to reflect, in customers' bills, the current level of Residential Exchange benefits. Over the five year period, it is projected that the Company will credit customers approximately $250 million more than it will receive from BPA. The Company expects the difference will be made up through the general rate increases approved in the merger order and additional reductions in operating expenses. Regulation and Rates The Company is subject to the regulatory authority of (1) the Washington Commission as to rates, accounting, the issuance of securities and certain other matters and (2) the FERC with respect to the transmission of electric energy, the resale of electric energy at wholesale, and accounting and certain other matters. The Washington Commission consists of three Commissioners, each appointed for a six-year term by the Governor of Washington state. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.") 4 Electric Utility Operations Power Resources At December 31, 1996, the Company's peak electric power resources were approximately 5,109,200 KW. The Company's historical peak load of approximately 4,615,000 KW occurred on December 21, 1990. During 1996, the Company's total electric energy production was supplied 21% by its own resources, 32% through long-term contracts with several of the Washington Public Utility Districts ("PUDs") that own hydroelectric projects on the Columbia River, 34% from other firm purchases and 13% from non-firm purchases. Peak Power Resources at December 31, 1996 1996 Energy Production ----------------------- ---------------------- Kilowatts % Kilowatt-Hours % --------- ---- -------------- ---- (Thousands) Purchased Resources: Columbia River PUD Contracts (Hydro) 1,356,000 26.5 8,488,933 32.3 Other Hydro(a) 570,000 11.2 4,303,931 16.4 Thermal(a) 1,399,000 27.4 7,881,061 30.0 - ------------------------------------------------------------------------- Total Purchased 3,325,000 65.1 20,673,925 78.7 - ------------------------------------------------------------------------- Company-owned Resources: Hydro 309,950 6.1 1,346,434 5.1 Coal 771,900 15.1 4,217,543 16.1 Natural gas/oil 702,350 13.7 21,618 0.1 - ------------------------------------------------------------------------- Total Company-owned 1,784,200 34.9 5,585,595 21.3 - ------------------------------------------------------------------------- Total 5,109,200 100.0 26,259,520 100.0 ========================================================================= (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. Company-Owned Resources. 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 owners of the Colstrip Units purchase coal for the units from Western Energy Company ("Western Energy"), an affiliate of Montana Power Company ("Montana Power") (one of the joint owners), under the terms of long-term coal supply agreements. In 1996, under the Colstrip 3 and 4 Coal Supply Agreement, the owners, other than Montana Power, gave Western Energy written notice of the existence of an unusual condition and gross inequity concerning the coal price in accordance with contract provisions. Pursuant to a settlement agreement between the Company, Montana Power and Western Energy dated February 21, 1997, the coal 5 price has been reduced on an interim basis pending a restructuring of the Colstrip coal supply arrangements. Pursuant to its settlement agreement, the Company has withdrawn from participation in, and will forego any benefits from, the negotiations and potential arbitration regarding the notice of an unusual condition and a gross inequity. The Company owns a 7% interest (91,900 KW) in a coal-fired, steam-electric generating plant near Centralia, Washington, with a total 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 and other owners of the Centralia project are reviewing emissions compliance options that will need to be adopted to meet the Federal and State emission requirements by the year 2001. Legislation is pending in the Washington State Legislature which would provide certain tax relief to the owners of the Centralia Plant in order to help defray costs associated with emissions compliance. The Company also has the following plants with an aggregate net generating capability of 1,012,300 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 1911 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; 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 dual-fuel combustion turbine units (89,100 KW each) installed during 1981; and two dual-fuel combustion turbine units (123,600 KW each) installed during 1984. The Company's combustion turbines installed in 1981 and 1984 may be fueled with either natural gas or distillate oil. Short-term supplies of distillate fuel may be stored on-site. These plants are operated from time to time for peaking purposes and to produce energy for sales to other utilities, either directly or through tolling arrangements. The Company has applied to the FERC for an initial license for its existing and operating White River project which includes authorization to install an additional 14,000 KW generating unit. The initial license for the existing and operating Snoqualmie Falls project expired in December 1993, and the Company continues to operate this project under a temporary license. The Company is continuing the FERC application process to relicense this project and expects a license to be issued in 1997. The Company has also applied for a license to expand its existing 1,750 KW Nooksack Falls project which is currently unlicensed and not operating because of an electrical fire. Columbia River Projects. During 1996, approximately 32% of the Company's energy output was obtained at an average cost of approximately 8.7 mills per KWH through long-term contracts with several of the Washington PUDs owning hydroelectric projects on the Columbia River. The Company's purchases of power from the Columbia River projects is generally on a "cost of service" basis under which the Company pays a proportionate share of the annual debt service and operating and maintenance costs of each project in proportion to the amount of power annually purchased by the Company from such project. Such payments are not contingent upon the projects being operable. These projects are financed through substantially level debt service payments, and their annual costs may vary over the term of 6 the contracts as additional financing is required to meet the costs of major maintenance, repairs or replacements or license requirements. The Company has contracted to purchase from Chelan County PUD ("Chelan") a share of the output of the original units of the Rock Island Project which equaled 57.1% through June 30, 1997. This share decreases gradually to 50% of the output at July 1, 1999, and remains unchanged thereafter for the duration of the contract. The Company has also 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 up to 10% per year beginning July 1, 2000, subject to a maximum aggregate reduction of 50%, upon the exercise of rights of withdrawal by Chelan for use in its local service area. Chelan has given notice of withdrawal of 5% on July 1, 2000. As of December 31, 1996, the Company's aggregate annual capacity from all units of the Rock Island Project was 423,000 KW. The Company has contracted to purchase from Chelan 38.9% (482,750 KW as of December 31, 1996) of the annual output of the Rocky Reach Project, which percentage remains unchanged for the remainder of the contract. The Company's share of the annual output of the Wells Project purchased from Douglas County PUD is currently 31.5% (271,320 KW as of December 31, 1996) and can be ultimately reduced to 31.3% upon the additional exercise of withdrawal rights by Douglas County PUD. The Company has contracted to purchase from Grant County PUD 8.0% (72,320 KW as of December 31, 1996) of the annual output of the Priest Rapids project and 10.8% (106,380 KW as of December 31, 1996) of the annual output of the Wanapum project, which percentages remain unchanged for the remainder of the contracts. See Note 16 to the Company's Consolidated Financial Statements. 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 (the "Coordination Agreement"). This agreement provides for the coordinated operation of substantially all of the hydroelectric power plants and reservoirs in the Pacific Northwest. Negotiations are being conducted regarding a possible replacement of the Coordination Agreement. Various fishery enhancement measures, including most recently the 1995 "biological opinion" from the National Marine Fisheries Service ("NMFS"), have reduced the flexibility provided by the Coordination Agreement. (See "Environment - Federal Endangered Species Act.") Certain utilities in the northwest United States and Canada are obtaining the benefits of additional firm power as a result of the ratification of a 1961 treaty between the United States and Canada under which Canada is providing approximately 15,500,000 acre-feet of reservoir storage on the upper Columbia River. As a result of this storage, streamflow which would otherwise not be usable to serve firm regional load is stored and later released during periods when it is usable. Pursuant to the treaty, one-half of the firm power benefits produced by the additional storage accrue to Canada. The Company's benefits from this storage are based upon its percentage participation in the Columbia River projects and one half of those benefits must be returned to Canada. In turn, the Company has contracted to purchase 17.5% of Canada's share of the power to be returned resulting from such storage until the beginning of a phased expiration of the contract in 1998. The Company has also contracted to purchase from the Bonneville Power Administration ("BPA") supplemental capacity in amounts that decrease gradually until the beginning of a phased expiration of the contract in 1998. Negotiations are being conducted regarding replacement of the existing contracts. 7 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 Washington Public Power Supply System ("WPPSS") Nuclear Project No. 3, in which the Company has a 5% interest. Under the settlement agreement, the Company is receiving from BPA for approximately 30.5 years, beginning January 1, 1987, a certain amount of electric power 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. On April 4, 1988, the Company executed a 15-year contract, with provisions for early termination by the Company, 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, subject to certain price ceilings. 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. 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 February 27, 1995, the Company delivered to Montana Power notice of termination of the contract based on Montana Power's failure to arrange for firm contractual transmission rights for such energy as required by the contract. On February 21, 1997, the Company and Montana Power settled the dispute as fully described in the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission (the "SEC") on February 27, 1997. Pursuant to the settlement, the contract remains in effect and the price of power purchased by the Company is reduced. On February 21, 1997, the Company and Montana Power also agreed to settle their coal supply disputes in return for certain price reductions and restructuring activities in connection with the Colstrip coal supply arrangements. Montana Power has estimated that, beginning in 1997, these agreements will result in an annual reduction in Montana Power's revenues, before anticipated efficiency gains, of between $11 and $13 million. The Company expects to realize a reduction in its power supply costs of approximately the same amount. In addition, the Company expects reductions in coal taxes and royalties and anticipates efficiency gains through restructuring. 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 conservation power for the remaining term of the agreement. Annual power deliveries gradually 8 increased over the first five years of the agreement and will remain at 6 average MW of energy throughout the remaining 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 seasonally 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. As required by the Public Utility Regulatory Policies Act of 1978, P.L. 95- 617 ("PURPA"), the Company has contracted to purchase the net electrical output from a number of non-utility generators, of which the most significant are described below. Payments by the Company to owners of these non-utility generating resources are subject to the delivery of power. See Note 16 to the Company's Consolidated Financial Statements. A number of these agreements have escalation provisions providing for periodic increases in the cost of power, and most of these agreements provide for power purchases at prices that are now above market prices. These excess contract prices could become stranded costs in a deregulated electric industry environment. On February 21, 1985, the Company executed a 50-year contract to purchase 6 average MW of energy and 14 MW of capacity, beginning in December 1990, from Koma Kulshan Associates, which owns and operates a small hydroelectric project located near the Company's Upper Baker Dam. On January 4, 1988, the Company executed a 21-year contract to purchase 15 average MW of energy and 23 MW of capacity, beginning November 1991, from the City of Spokane, which owns and operates a regional solid waste incineration project located near Spokane, Washington. On June 29, 1989, the Company executed a 20-year contract to purchase 70 average MW of energy and 80 MW of capacity, beginning October 11, 1991, from the March Point Cogeneration Company ("March Point"), which owns and operates a natural gas-fired cogeneration facility known as March Point Phase I, located at a Texaco refinery in Anacortes, Washington. On December 27, 1990, the Company executed a second contract (having a term coextensive with the first contract) to purchase an additional 53 average MW of energy and 60 MW of capacity, beginning in January 1993, from another natural gas-fired cogeneration facility owned and operated by March Point, which facility is known as March Point Phase II and is located at the Texaco refinery in Anacortes, Washington. In November 1995, March 1996 and November 1996, the Company delivered notices of breach of contract to March Point based on, among other things, March Point's failure to maintain generation at agreed- upon limits, failure to displace generation pursuant to the parties' power purchase agreements, and failure to provide information essential to the parties' agreed-upon displacement arrangements. On November 29, 1995, March Point commenced litigation against the Company in federal court for the Western District of Washington. March Point requested a declaration of certain obligations of March Point and the Company under the contracts, injunctive relief preventing the Company from terminating its contracts with March Point and damages based on breach of contract. The Company has answered and filed a counterclaim contending that March Point has breached the contracts. The Company seeks declaratory relief regarding the parties' obligations and rights under the contracts, damages based on the breach and rescission. 9 On February 24, 1989, the Company executed a 20-year contract to purchase 108 average MW of energy and 123 MW of capacity, beginning in April 1993, from Sumas Cogeneration Company, L.P., which owns and operates a natural gas-fired cogeneration project located in Sumas, Washington. On September 26, 1990, the Company executed a 15-year contract to purchase 141 average MW of energy and 160 MW of capacity, beginning in July 1993, from Encogen Northwest L.P. ("Encogen") (a limited partnership having a general partner that is a subsidiary of Enserch Development Corp.), which owns and operates a natural-gas fired cogeneration facility located at the Georgia Pacific mill near Bellingham, Washington. In June 1995, the Company delivered notice of breach of contract to Encogen based on, among other things, Encogen's failure to provide information essential to the parties' agreed-upon displacement arrangements. On September 20, 1995, Encogen commenced litigation against the Company in Whatcom County Superior Court requesting a declaration of certain obligations of Encogen under the contract and seeking further relief. The Company has answered and filed a counterclaim, contending that Encogen has breached the contract and seeking declaratory relief regarding Encogen's duty to provide certain information. On March 20, 1991, the Company executed a 20-year contract to purchase 216 average MW of energy and 245 MW of capacity, beginning in April 1994, from Tenaska Washington Partners, L.P., which owns and operates a natural-gas fired cogeneration project located near Ferndale, Washington. Electric Energy Conservation The Company offers programs designed to help new and existing customers use electric energy efficiently. The primary emphasis is to provide information and technical services to enable customers to make energy-efficient choices with respect to building design, equipment and building systems, appliance purchases and O&M practices. The Company's electric energy conservation expenditures have historically been accumulated, included in rate base and amortized to expense over a ten year period at the direction of the Washington Commission. In June 1995 the Company sold approximately $202.5 million of its investment in customer-owned energy conservation measures to a grantor trust, which, in turn, issued securities backed by a Washington state statute enacted in 1994. On August 6, 1997, the Company sold its remaining $35.2 million of such conservation investments in a similarly structured transaction. (See Note 1 to the Company's Consolidated Financial Statements) Electric Rates and Regulation In the Washington Commission's September 21, 1993, general rate case order, the Company was allowed 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. On September 22, 1995, the Washington Commission issued a rate order relating to the Companys fifth annual rate adjustment under the PRAM. In addition to approval of the rate adjustment, the Commission also agreed, pursuant to a negotiated settlement, to discontinue the PRAM on September 30, 1996. PRAM accrued revenues of $40.5 million, recorded at December 31, 1996, were recovered in the first quarter of 1997. Over-collection of PRAM revenues were refunded to customers in the second quarter of 1997. 10 With the discontinuance of the PRAM, the annual regulatory adjustments for variations in weather and hydro conditions provided for in the PRAM were also discontinued. On September 30, 1996, the Washington Commission issued an order granting a joint motion by the Company and the Washington Commission Staff to transfer annual revenues of $165.5 million which were being collected in PRAM rates to the Company's permanent rate schedules. As a result of the order, the Company also wrote off $4.5 million in previously accrued revenues related to special industrial customer service contracts. 11 Energy Delivery Operating Statistics Electric Operations: Year Ended on December 31 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------- Operating revenues by classes: (thousands) Residential $ 554,318 $ 524,749 $ 532,124 $ 502,037 $ 443,490 Commercial 423,139 397,212 375,751 356,586 323,764 Industrial 170,596 168,501 163,574 150,063 138,416 Other consumers 44,125 38,730 38,759 28,189 35,779 - ------------------------------------------------------------------------------------------- Operating revenues billed to consumers (a) 1,192,178 1,129,192 1,110,208 1,036,875 941,449 Unbilled revenues - net increase (decrease) 13,201 (6,382) (2,522) 14,409 15,080 PRAM accrual (74,326) 3,953 25,835 42,100 42,119 - ------------------------------------------------------------------------------------------- Total operating revenues from consumers 1,131,053 1,126,763 1,133,521 1,093,384 998,648 Other utilities 67,716 52,567 60,537 19,494 26,322 - ------------------------------------------------------------------------------------------- Total operating revenues $1,198,769 $1,179,330 $1,194,058 $1,112,878 $1,024,970 - ------------------------------------------------------------------------------------------- Number of customers (average): Residential 754,097 739,173 723,566 708,123 692,100 Commercial 89,613 87,404 85,203 82,875 80,963 Industrial 3,993 3,908 3,851 3,715 3,659 Other 1,371 1,346 1,325 1,289 1,254 - ------------------------------------------------------------------------------------------- Total customers (average) 849,074 831,831 813,945 796,002 777,976 - ------------------------------------------------------------------------------------------- KWH generated, purchased and interchanged (thousands): Total Company generated 5,585,595 6,371,416 7,011,932 6,414,311 7,420,058 Purchased power 20,573,983 17,897,922 16,268,042 14,608,899 13,408,522 Interchanged power (net) 99,942 48,485 (87,771) 174,478 (118,346) - ------------------------------------------------------------------------------------------- Total energy output 26,259,520 24,317,823 23,192,203 21,197,688 20,710,234 Losses and company use (1,322,262) (1,235,457) (1,291,322) (1,096,599) (1,202,194) - ------------------------------------------------------------------------------------------- Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040 - ------------------------------------------------------------------------------------------- (a) Operating revenues in 1996 and 1995 were reduced by $41.0 million and $25.1 million, respectfully, as a result of the Company's sale of $202.5 million of its investment in customer-owned energy conservation measures. (See "Operating revenues" in Management's Discussion and Analysis and Note 1 to the Consolidated Financial Statements.) 12 Electric Operations (continued from previous page): Year Ended on December 31 1996 1995 1994 1993 1992 - -------------------------------------------------------------------------------------------- Electric energy sales, KWH: (thousands) Residential 9,350,292 8,972,498 8,913,903 8,974,787 8,297,293 Commercial 6,807,465 6,538,533 6,301,568 6,175,911 5,945,284 Industrial 3,793,966 3,720,641 3,724,931 3,690,473 3,704,450 Other consumers 205,066 205,232 200,622 196,246 193,563 - -------------------------------------------------------------------------------------------- Total energy billed to consumers 20,156,789 19,436,904 19,141,024 19,037,417 18,140,590 Unbilled energy sales - net increase (decrease) 224,412 (158,920) (72,352) 139,329 209,565 - -------------------------------------------------------------------------------------------- Total energy sales to consumers 20,381,201 19,277,984 19,068,672 19,176,746 18,350,155 Sales to other electric utilities 4,556,057 3,804,382 2,832,209 924,343 1,157,885 - -------------------------------------------------------------------------------------------- Total energy sales 24,937,258 23,082,366 21,900,881 20,101,089 19,508,040 - -------------------------------------------------------------------------------------------- Per residential customer: Annual use (KWH) 12,399 12,139 12,319 12,674 11,989 Annual billed revenue $762.35 $726.95 $735.42 $708.97 $640.79 Billed revenue per KWH $.0615 $.0599 $.0597 $.0559 $.0534 Company-owned generation capability - kilowatts: Hydro 309,950 309,950 309,950 309,950 309,950 Steam 771,900 771,900 771,900 857,700 857,700 Natural gas/oil 702,350 702,350 702,350 702,350 702,350 - -------------------------------------------------------------------------------------------- Total 1,784,200 1,784,200 1,784,200 1,870,000 1,870,000 - -------------------------------------------------------------------------------------------- Heating degree days 4,953 3,994 4,341 4,691 4,090 % of normal of 30 year average (4,908) 100.9% 81.4% 88.4% 95.6% 83.3% Load factor 55.5% 56.7% 54.7% 52.5% 57.0% Gas Utility Operations Gas Supply The Company currently purchases a blended portfolio of long-term firm, short- term firm, and spot gas supplies from a diverse group of major and independent producers and gas marketers in the United States and Canada. Prior to implementation of FERC Order No. 636 in 1993, WNG purchased a portion of its firm gas supply from the Northwest Pipeline Corporation ("NPC") under a firm sales agreement. All of the Company's gas supply is ultimately transported through NPC, the sole interstate pipeline directly supplying the western Washington area. For baseload and peak-shaving purposes, the Company supplements its portfolio of firm gas supply by purchasing natural gas at generally lower prices in summer, injecting it into underground storage facilities and withdrawing it during the winter heating season. Storage facilities at Jackson Prairie in Washington and at Clay Basin in Utah are used for this purpose. Peaking 13 needs are also met by using the Company's gas held in NPC's liquefied natural gas ("LNG") facility at Plymouth, Washington, and by producing propane air gas at two plants owned by the Company and located on its distribution system. The Company expects to meet its firm peak day requirements for residential, commercial and industrial markets through its firm gas purchase contracts, firm transportation capacity, firm storage capacity and other firm peaking resources. The Company believes that it will be able to acquire incremental firm gas supply resources, which are reliable and reasonably priced, to meet anticipated growth in the requirements of its firm customers for the foreseeable future. Natural Gas Pipeline Deregulation The implementation of FERC Order No. 636 by NPC in November 1993 completed the deregulation of its activities as an interstate natural gas pipeline and unbundled sales services formerly performed by NPC. The complete unbundling of NPC's services at that date finalized the Company's transition from purchasing all of its gas supply from NPC prior to 1986 to purchasing all such gas supplies directly from producers and gas marketers. As part of the transition, the Company was assigned certain long-term firm gas supply agreements of NPC effective November 1, 1992 and November 1, 1993. In order to deliver purchased gas supplies to its distribution system and to provide transportation service for customer-owned gas, the Company assumed long- term, firm transportation capacity on the transmission systems of NPC and Pacific Gas Transmission Company ("PGT"), together with associated demand charge obligations. The Company also acquired storage capacity with associated demand charge obligations at Clay Basin in two increments effective April 1991 and April 1993. Gas Supply Portfolio For the 1996-97 winter heating season, the Company has contracted for approximately 26% of its expected peak day gas supply requirement from sources originating in British Columbia under a combination of long-term and winter peaking purchase agreements and firm gas exchange arrangements. Long- term gas supplies from Alberta represent approximately 10% of the peak day requirement. Long-term and winter peaking arrangements with U.S. suppliers and gas stored at Clay Basin make up approximately 22% of the peak day portfolio. The balance of the peak day requirement is expected to be met with gas stored at Jackson Prairie, LNG held at NPC's Plymouth facility and propane air gas, each of which represents approximately 30%, 9% and 3%, respectively, of the expected peak requirements. The current firm, long-term gas supply portfolio consists of arrangements with 11 producers and gas marketers, with no single supplier representing more than 10% of the expected peak day requirement. The contracts have remaining terms that range from less than one year to seven years, with an average term of three years. All but one of the supply contracts originally assigned to the Company by NPC have expired. The one remaining contract, with an Alberta supplier, has a remaining term of seven years. All of the current gas supply contracts contain market-sensitive pricing provisions based on various published indices. The Company's firm gas supply portfolio is structured to take advantage of regional price differentials and to market gas and services outside the Company's service territory ("off-system sales") when market opportunities arise and customer demand requirements permit. The geographic mix of suppliers and daily, monthly and annual take requirements permit a high degree of flexibility in sourcing gas supplies in off-peak periods to 14 minimize costs. During the 12 months ended June 30, September 30, 1996, the Company's off-system sales totaled approximately 27 billion cubic feet ("BCF") of gas and generated $8.1 million of gross margin ("gross margin" being gas revenue less cost of gas sold). By way of comparison, the Company's on-system volumes during the same period totaled approximately 73 BCF. The Company also conducts exchanges of gas with other suppliers or marketers on different pipelines, which exchanges generated $1.4 million of gross margin during the 12 months ended September 30, 1996. The savings or gross margin from these off- system activities does not affect the Company's earnings, but is currently passed on to the Company's customers through the purchased gas adjustment ("PGA") mechanism approved by the Washington Commission. Gas Transportation Capacity The Company currently holds firm transportation capacity on pipelines owned by NPC and PGT. Accordingly, the Company pays fixed monthly demand charges for the right, but not the obligation, to transport a specified quantity of gas from a receipt point to a delivery point on such pipelines each day for the term or terms of the applicable agreements. The Company holds firm capacity on NPC's pipeline totaling 454,533 million British thermal units ("MMBtu") per day, acquired under seven agreements at various times. The Company has exchanged certain segments of its firm capacity with several parties to effectively lower transportation costs. In the aggregate, the Company's capacity provides for receipt of 204,761 MMBtu per day at Sumas on the Washington border with British Columbia, 173,836 MMBtu per day at various points in Wyoming, Colorado, and Utah and 75,936 MMBtu per day at several interconnections with PGT. The Company also holds seasonal firm capacity from NPC for receipt of 236,298 MMBtu per day at the Jackson Prairie storage field and 70,500 MMBtu per day at the Plymouth LNG facility. The latter capacity is available to deliver storage gas to the Company's distribution system during the heating season. The Company's firm transportation capacity contracts with NPC have remaining terms ranging from 8 to 19 years. However, the Company has either the unilateral right to extend the contracts under their current terms or the right of first refusal to extend such contracts under then current FERC orders. The Company holds firm transportation capacity on PGT's pipeline totaling 90,392 MMBtu per day from Kingsgate on the Idaho border with British Columbia to various interconnections with NPC. Gas originating in Alberta is transported to NPC utilizing this capacity for subsequent delivery by NPC to the Company's distribution system. The contract for this capacity has a remaining term of 27 years. Gas Storage Capacity The Company holds storage capacity in the Jackson Prairie and Clay Basin underground gas storage facilities. The Jackson Prairie facility, one-third owned and operated by the Company, is used primarily for intermediate peaking purposes as it is designed to deliver a large volume of gas over a relatively short time period. The Company has peak, firm delivery capacity of 236,298 MMBtu per day and total firm storage capacity of 6,341,660 MMBtu at the facility. The location of the Jackson Prairie facility in the Company's service area provides significant cost savings by reducing the amount of annual pipeline capacity required to meet peak day gas requirements. The Clay Basin storage facility is intended as a baseload gas supply source as well as a peaking supply source. The Company has a maximum firm withdrawal capacity of 111,300 MMBtu per day from the facility with total storage capacity of 13,419,000 MMBtu. The capacity is held under two contracts with remaining terms of 17 and 24 years. 15 LNG and Propane Air LNG and propane air gas provide gas supply on short notice for short periods of time. Due to their high cost, these sources are utilized as the supply of last resort in extreme peak demand periods lasting a few hours or days. The Company has long-term contracts for storage of 241,700 MMBtu of its gas as LNG at NPC's Plymouth facility, which equates to approximately three and one- half days' supply at maximum daily deliverability of 70,500 MMBtu. The Company owns storage capacity for approximately 1.4 million gallons of propane. The facilities are capable of delivering the equivalent of 30,000 MMBtu of gas per day for up to four days directly into the Company's distribution system. Capacity Release One of the most significant changes resulting from the deregulation of the natural gas industry is the advent of capacity release to counter the impact on pipeline customers of the straight fixed variable rate design used by interstate pipelines. Under this rate design, essentially all pipeline costs are recovered from customers through fixed monthly demand charges, rather than volumetrically as in the past. The FERC provided the capacity release mechanism as the means for holders of firm capacity to relinquish temporarily unutilized pipeline capacity to others in order to recoup all or a portion of the cost of such capacity. Capacity may be released through several methods including open bidding and by prearrangement. All capacity available for release is posted on the electronic bulletin boards of the pipelines. During the 12 months ended September 30, 1996, the Company utilized buy/sell and capacity release mechanisms to recoup $1.3 million out of approximately $28.3 million of demand charges for which the capacity was not utilized in off-peak periods. WNG CAP I and WNG CAP II, wholly owned subsidiaries of the Company, were formed to provide additional flexibility and benefits from capacity release. All savings from capacity release are currently passed on to the Company's customers through the PGA mechanism. In addition, off-system sales activities have often bundled the gas commodity or other commodity services with transportation, which has increased capacity utilization. In approving the Company's last PGA, effective May 15, 1995, the Washington Commission allowed all previously incurred and projected capacity related demand charges to be recovered in rates. Reallocation of NPC Transition Costs In May 1994, NPC was ordered by the FERC to modify the previous allocation of transition costs, totaling $34 million plus interest, incurred in "unbundling" interstate pipeline services. Under this order, the Company's share of these costs increased from $1.2 million, which amount had been previously paid, to $10.4 million, inclusive of interest. The Company and six other customers filed requests for rehearing. In December 1994, the FERC issued an order denying the rehearing requests and permitting NPC to bill customers under the modified allocation methodology. Pending the outcome of an appeal to the United States Court of Appeals, the Company paid a total of $9.8 million, inclusive of interest, in monthly installments in 1995 and 1996, representing its share of the reallocated costs. The court appeal is still pending. The Washington Commission has allowed the Company to recover the full amount of the increased transition costs as part of the PGA that went into effect on May 15, 1995. 16 Gas Rates and Regulation Since 1971, the Washington Commission has permitted WNG to pass on to its customers, through changes in its rates, all changes in the price of gas purchased from nonaffiliated suppliers through the PGA mechanism. This mechanism allows the Company to pass these cost increases or decreases to its customers on a timely basis, resulting in no material impact on net income. Since a 1991 order disallowing a portion of the cost of gas purchased from an affiliate, the Washington Commission has authorized three PGAs with no disallowance of purchased gas costs. Two of the adjustments, one in 1992 and one in 1993, substantially increased rates and were allowed on a timely basis. The most recent PGA was approved by the Washington Commission effective May 15, 1995. This PGA resulted in a pass-through to customers of an annual reduction of $46.5 million in the cost of purchased gas. March 1995 Rate Case. In March 1995, WNG filed a general rate case, (the "March 1995 Rate Case") Docket No. UG-950278, seeking to raise general gas service tariff rates by 8.5%, or $35.4 million, on an annual basis. The filing was requested in order to reflect the higher costs of capital and increased operating costs as a result of customer growth. As part of the filing, WNG petitioned that $17.8 million of the $35.4 million request be granted as interim rate relief. On May 11, 1995, WNG and the Washington Commission reached a negotiated settlement of the March 1995 Rate Case. The settlement provided a $17.7 million annual increase in revenue and margin. The increase reflected an allowed rate-of-return on common equity in the range of 11% - 11.25%, up from the previous level of 10.5%. The settlement accepted by the Washington Commission also stipulated that WNG be allowed to earn in excess of that range to the extent that it can do so by managing its cost of service. The new rates became effective May 15, 1995. As part of the settlement, WNG agreed not to make a general rate case filing prior to May 15, 1997. The agreement, however, did not preclude filing under the PGA mechanism or for interim emergency rate relief if conditions warrant. Rate Redesign. On May 11, 1995, the Washington Commission ordered the implementation of a cost-based gas tariff rate design effective May 15, 1995. The order, while revenue neutral in total, shifted rates and costs, and thus source of margin, among customer classes. The average margins on transportation service decreased by 26% and margins on sales to larger volume industrial sales customers decreased by 27%. The order also raised average residential margins 4.5%. Firm commercial and smaller industrial average margins were not materially affected. The changes in transportation and industrial margins made the utility economically indifferent to customer choices between transportation and sales service. The Company believes the order enhances the Company's ability to offer rates that support cost-effective and responsible growth and customer choice. Line Extension and New Customer Addition Policy. In March 1995, the Washington Commission approved a new tariff for extending natural gas mains and services to new gas customers. Under the new policy, main and service extensions that meet or exceed the target rate-of-return, currently 9.15%, based on an analysis of estimated costs and gas usage, are provided without requiring economic support from customers. This new policy 17 helps ensure that new gas customer growth is profitable. If a new main or service extension is estimated to have a rate-of-return between 6.86% and 9.15%, the customer is required to either make a one-time contribution or pay a new customer rate, at the customer's choice. A contribution is an advance payment to cover a portion of the costs of construction. This advance payment may be refundable over a five-year period based on additional new customer load which has been added to the new main or service extension since it was initially installed. The other choice is payment of a nonrefundable new customer rate for five years. The new customer rate is essentially a surcharge of 11.5 cents per therm for new residential developments, or 17 cents per therm for single-family residential or small commercial conversions. If the main extension is estimated to have a rate-of-return of less than 6.86%, the customer must make a nonrefundable contribution in aid of construction in addition to either the refundable advance payment or the new customer rate discussed above. The Company is also engaged in the business of leasing gas water heaters and conversion burners for residential and commercial use. As of September 30, 1996, the Company had approximately 114,000 equipment leases with customers with original costs and net book value of approximately $71 million and $61 million, respectively. Lease revenues are included in the financial statements as part of Regulated Utility Sales since the rates charged are subject to the approval of the Washington Commission. Lease revenues for the 12 months ended September 30, 1996 and for the 12 months ended September 30, 1995 were $10,027,000, and $9,274,000, respectively. The number of equipment leases has been declining over the last several years because more customers choose to own rather than lease their gas equipment. However, lease revenues have increased due to rate increases of approximately $1 per month per lease for most residential customers in each of the last three years. The leases may be terminated on 30 days' written notice by the customer, in which case the Company removes the equipment at no charge to the customer. However, most customers elect to purchase the equipment at a price which approximates net book value of the equipment. 18 Gas Operations: Twelve Months Ended September 30 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------- Operating revenues by classes: (thousands): Regulated utility sales: Residential firm gas sales $ 238,560 $ 231,202 $ 206,602 $ 195,936 $ 152,015 Commercial firm gas sales 94,251 97,396 91,749 87,644 67,393 Industrial firm gas sales 20,024 25,860 28,827 23,967 17,226 Interruptible gas sales 23,376 44,511 51,425 44,160 29,593 Transportation services 12,812 10,762 8,399 8,434 11,231 Other 11,085 10,317 9,405 7,712 7,481 - ------------------------------------------------------------------------------------------- Total regulated utility sales $ 400,108 $ 420,048 $ 396,407 $ 367,853 $ 284,939 =========================================================================================== Customers, average number served: Residential firm 440,586 423,195 403,642 383,291 361,454 Commercial firm 39,651 38,378 37,112 35,951 34,503 Industrial firm 2,762 2,754 2,824 2,844 2,857 Interruptible 1,000 1,037 1,009 988 948 Transportation 106 55 36 68 130 - ------------------------------------------------------------------------------------------- Total average customers 484,105 465,419 444,623 423,142 399,892 =========================================================================================== Gas volumes (thousands of therms): Residential firm sales 421,727 398,283 371,472 382,118 301,887 Commercial firm sales 188,321 179,725 174,668 177,724 142,402 Industrial firm sales 46,640 55,365 62,698 54,096 52,019 Interruptible sales 72,229 132,316 151,175 127,678 78,645 Transportation volumes 242,299 156,941 119,590 159,765 199,143 - ------------------------------------------------------------------------------------------- Total gas volumes 971,216 922,630 879,603 901,381 774,096 =========================================================================================== Working gas volumes in storage at year end (thousands of therms) Jackson Prairie 65,834 65,834 65,834 65,834 65,834 Clay Basin 82,847 130,970 47,557 70,006 43,246 Average use per customer: (therms) Residential firm 957 941 921 998 835 Commercial firm 4,749 4,683 4,708 4,903 4,127 Industrial firm 16,886 20,103 22,035 24,618 18,208 Interruptible 72,229 127,595 147,315 129,231 82,959 Transportation 2,285,840 2,853,473 3,400,694 2,133,676 1,531,869 Average revenue per customer: Residential firm $ 541 $ 546 $ 512 $ 511 $ 421 Commercial firm 2,377 2,538 2,472 2,438 1,953 Industrial firm 7,250 9,390 10,208 8,427 6,029 Interruptible 23,376 42,923 50,966 44,695 31,216 Transportation 120,868 195,673 233,306 124,029 86,392 19 Gas Operations: (continued) Twelve Months Ended September 30 1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------- Average revenue per therm (cents): Residential firm 56.6 58.0 55.6 51.3 50.4 Commercial firm 50.0 54.2 52.5 49.3 47.3 Industrial firm 42.9 46.7 46.0 44.3 33.1 Interruptible 32.4 33.6 34.0 34.6 37.6 Total sales customers 51.6 52.1 49.8 47.4 46.3 Transportation 5.3 6.9 7.0 5.3 5.6 Average cost per therm of gas sold (cents) (1): 24.4 28.6 29.5 24.0 22.7 Weather - degree days 4,953 3,994 4,341 4,691 4,090 % of normal (30-yr avg) 100.9% 81.4% 88.4% 95.6% 83.3% (1) Average Cost Per Therm includes both fixed and variable elements, and it is not common gas industry practice to allocate these among classes of customers. Washington Natural does not sell or transport gas to any of its customers at a loss or on a break-even basis. Oil and Gas Exploration and Production The Company has participated in the oil and gas exploration and production business since 1974. In May 1994, the Company's subsidiary engaged in such business was merged in a tax-free exchange with a wholly owned subsidiary of Cabot Oil & Gas Corporation ("Cabot"), based in Houston, Texas. Through such merger the Company owns 16.4% of Cabot's outstanding voting securities, consisting of 2,133,000 shares of common stock representing 9.4% of total common shares outstanding, and 1,134,000 shares of convertible voting preferred stock. The Company is accounting for its investment in Cabot's common stock using the equity method, whereby the Company is recording its proportionate share of Cabot's earnings and losses available to common shareholders as "Other Income (Expense)." Detailed information regarding Cabot is available in Cabot's filings with the SEC. Construction Financing The Company estimates its combined electric and gas construction expenditures, excluding Allowance for Funds Used During Construction ("AFUDC"), for 1997 through 1999 will be approximately $247 million, $252 million and $226 million, respectively. The Company expects cash from operations (net of dividends and AFUDC) during the period 1997 through 1999 will, on average, be approximately 73% of average estimated construction expenditures (excluding AFUDC) during the same period. 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 market conditions and 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 Indentures, Articles of Incorporation and certain loan agreements. Under the most restrictive tests, at December 31, 1996, the Company could issue (i) approximately $1.118 billion of additional first mortgage bonds or (ii) approximately $645 million of additional preferred stock at an assumed dividend rate of 6.80% or (iii) a combination thereof. 20 Environment The Company's operations are subject to environmental regulation by federal, state and local authorities. Capital expenditures for environmental controls for Company facilities are estimated at $2.3 million for 1997. 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 (See Note 16 to the Consolidated Financial Statements for a discussion of these sites) 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). The Company and other owners of the Centralia Project, including Pacific Power & Light Company, which operates the Centralia Project, are reviewing emission compliance options which will need to be adopted to meet the Phase II limits in the year 2000. Montana Power, which operates the Colstrip 3 and 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 have sufficient allowances for Phase II requirements.The Company owns combustion turbine units, most of 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 1995 the NMFS issued a biological opinion which has significantly changed the operation of the Federal Columbia River Power System. 21 The 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 developed by NMFS shifts 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.Other species are also proposed for listing as endangered species and could further restrict regional hydro system flexibility and energy production. 22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Financial Condition and Results Of Operations Financial Condition and Results of Operations reflect combined results for the fiscal years ended December 31 for Puget Power and September 30 for WECo. Net income in 1996 was $165.5 million on operating revenues of $1.649 billion, compared to $101.8 million on operating revenues of $1.631 billion in 1995 and $78.4 million on operating revenues of $1.632 billion in 1994. Income for common stock was $143.3 million in 1996, compared to $79.1 million in 1995 and $58.0 million in 1994. Income for common stock for all periods presented includes losses from discontinued operations consisting of carrying and development costs for undeveloped coal reserves and a related railroad. The 1994 loss from discontinued operations also includes a loss on disposition of a biowaste business. Earnings per share in 1996 were $1.70 on 84.4 million weighted average common shares outstanding including a $.02 loss per share from discontinued operations compared to $.94 on 84.2 million weighted average common shares outstanding in 1995 including a $.32 loss per share from discontinued operations and $.69 on 83.8 million weighted average common shares outstanding in 1994 including a $.01 loss per share from discontinued operations. In 1996, WECo decided to seek a buyer for its undeveloped coal properties and to cease development efforts on the associated railroad. Accordingly, WECo's financial statements reflect these businesses as discontinued operations. The 1996 loss from discontinued operations includes an after- tax charge of $.4 million to establish a reserve for estimated operating losses through disposition. In 1995, WECo wrote down the carrying value of its coal properties by $34.7 million ($22.6 million after tax) and wrote off its entire railroad investment of $6.0 million ($3.9 million after tax) with adoption of SFAS No. 121. Results for 1995 also include special charges of $22.7 million which resulted from: 1) adoption of SFAS No. 121 by Cabot and WECo required a large write down of Cabot's oil and gas properties and a permanent impairment in the carrying value of the Company's investment in Cabot ($16.1 million after tax); 2) increased losses projected in the future from certain gas transportation and storage arrangements excluded from the merger of WECo's former oil and gas exploration subsidiary with Cabot ($3.3 million after tax); 3) employee severance costs ($2.0 million after tax); and 4) deferred income taxes relating to tax contingencies ($1.3 million). Results for 1994 include special charges of $55.3 million which resulted from: 1) the merger of WECo's oil and gas exploration and production subsidiary with Cabot and reserves established for certain gas transportation and storage arrangements excluded from the merger ($30.0 million after tax); 2) restructuring and down sizing utility operations ($18.2 million after tax); and 3) other write-offs and reserves established in connection with gas operations ($7.1 million after tax). Total kilowatt-hour sales to ultimate consumers in 1996 were 20.4 billion, compared with 19.3 billion in 1995 and 19.1 billion in 1994. Kilowatt-hour sales to other utilities were 4.6 billion in 1996, 3.8 billion in 1995 and 2.8 billion in 1994. 23 Regulated gas utility sales in 1996 decreased by $19.9 million, or 5%, from 1995 on a 5% decrease in gas volumes sold. Total gas volumes, including transported gas, increased 5% in 1996. Regulated gas sales increased $23.6 million or 6% in 1995 compared to 1994, primarily as a result of two general rate increases and customer growth, partially offset by the impact of the May 1995 PGA, which reduced rates for a portion of the year. The preferred stock dividend accrual decreased $0.5 million in 1996 compared to 1995 due to lower dividend rates on the Adjustable Rate Cumulative Preferred Stock (OARPSO), Series B ($100 par value). The preferred stock dividend accrual increased $2.3 million in 1995 compared to 1994 due primarily to the issuance of the 8.50%, Series III Preferred ($25 par value) in September 1994. The preferred stock dividend accrual increased $1.2 million in 1994 compared to 1993 due primarily to the issuance of the 7.45% Series II Preferred ($25 par value) in November 1993. The increase from this issue was partially offset by a combination of the redemptions of the $50 million Flexible Dutch Auction Rate Transferable Securities $100 Par Value Preferred Stock ("FLEX DARTS"), Series B in July 1993 and the $40 million ARPS, Series A in February 1994 and the issuance in February 1994 of the $50 million ARPS, Series B ($25 par value). 24 Increase (Decrease) Over Preceding Year Years Ended December 31 (Dollars in Millions) 1996 1995 1994 - --------------------------------------------------------------------- Operating revenues General rate increase $ -- $ -- $ 27.0 PRAM revenues (37.1) 31.6 13.3 BPA Residential Purchase and Sale Agreement (15.8) (25.3) 2.3 Sales to other utilities 15.1 (8.0) 41.0 Revenue sold to conservation trust (15.9) (25.1) -- Load and other changes 91.8 1.8 (66.6) Gas revenue change (19.9) 23.6 28.6 - --------------------------------------------------------------------- Total operating revenue changes 18.2 (1.4) 45.6 - --------------------------------------------------------------------- Operating expenses Purchased electricity 18.6 14.8 77.1 Purchased gas (41.3) (4.5) 42.6 Utility operations and maintenance (2.6) (73.3) (13.0) Other operations and maintenance 3.9 0.7 1.8 Depreciation and amortization 3.7 (6.0) (7.2) Taxes other than federal income taxes 5.5 4.6 6.4 Federal income taxes 16.2 16.7 (18.5) - --------------------------------------------------------------------- Total operating expense changes 4.0 (47.0) 89.2 - --------------------------------------------------------------------- Other income 16.4 7.7 (35.7) Interest charges (8.3) 4.2 4.4 Discontinued operations 24.8 (25.7) 11.5 - --------------------------------------------------------------------- Net income changes $ 63.7 $ 23.4 $(72.2) ===================================================================== The following information pertains to the changes outlined in the table above: Operating Revenues - Electric Electric revenues since October 1, 1995, increased as a result of rates authorized by the Washington Utilities and Transportation Commission (the "Washington Commission") under the fifth Periodic Rate Adjustment Mechanism ("PRAM") filing. Revenues since October 1, 1994, increased as a result of rates authorized by the Washington Commission under the fourth PRAM filing. Revenues since October 1, 1993, increased as a result of rates authorized by the Washington Commission in its general rate order issued on September 21, 1993. The PRAM was terminated effective September 30, 1996. (See "Rate Matters.") Electric revenues have been reduced by virtue of the credit that 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 corresponding reduction is included in purchased and interchanged power expenses. On January 29, 1997, the Company and the BPA signed a Residential Exchange Termination Agreement. The Agreement effectively ends the Company's participation in the Residential Purchase and Sale Agreement in exchange for settlement payments by the BPA 25 of approximately $237 million over five years. (See "Other" for a discussion of the Residential Exchange Termination Agreement.) Electric revenues in 1996 and 1995 have been reduced by $41.0 million and $25.1 million as a result of the Company's sale of revenues associated with $202.5 million of its investment in conservation assets to a grantor trust. The revenue decrease represents the portion of rate revenues that were sold and forwarded to the trust. The impact of this revenue decrease, however, was offset by related reductions in other operation and interest expenses. (See "Other" for a discussion of the sale of conservation assets.) To meet customer demand, the Company's power supply portfolio includes net purchases of power under long-term supply contracts. However, depending principally upon streamflow available for hydroelectric generation and weather effects on customer demand, from time to time the Company may have surplus power available for sale at wholesale to other utilities. In addition, the Company intends to increase its wholesale surplus power business through short and intermediate term purchase, sale, arbitrage and other trading and marketing techniques. Operating Revenues - Gas Regulated gas utility sales in 1996 decreased by $19.9 million, or 5%, from the prior year on a 5% decrease in gas volumes sold. Total gas volumes, including transported gas, increased 5% in 1996. The PGA implemented in May 1995, which reduced rates, and customers switching from gas sales service to transportation, combined to more than offset the impact of the May 1995 general rate increase and increases in gas sales due to customer growth and colder weather. Utility margin increased by $21.4 million, or 11%, due primarily to: the full-year impact of the $17.7 million general rate increase in May 1995; a 4%, or 19,000 increase in customers; and additional heating load due to weather that was 3% warmer than normal in 1996 versus 12% warmer than normal in 1995. The May 1995 PGA reduced revenues but did not impact utility margin. The shifting of customers from sales service to transportation did not materially impact utility margin, as most were switching from large volume, interruptible gas sales. Due to the rate redesign implemented in May 1995, the Company generally earns the same margin on transportation service as it does on large volume, interruptible gas sales. The $23.6 million, or 6%, increase in regulated gas sales in 1995 was largely the result of two general rate increases and customer growth, partially offset by the impact of the May 1995 PGA, which reduced rates for a portion of the year. Gas utility margin increased by $28.1 million, or 16%, due primarily to the rate increases and customer growth, and was not impacted by the PGA. The general rate orders increased gas utility margin by approximately $18 million in 1995. The impact on gas utility margin in 1995 was less than the full annualized impact of the two rate orders because of warmer weather and the timing of the May 1995 increase, which was implemented after the heating season. The Company's rate of growth in new gas customers remained at approximately 4%, or 21,000 customers, during 1995, increasing firm gas sales volumes by 5% and adding an estimated $6 million in gas utility margin. During 1995, weather did not have a significant impact on gas utility margin due to the fact that much of the winter of 1995 was colder than in 1994, while the rest of 1995, when heating load was lower, was significantly warmer than 1994. 26 The Company's merchandise sales revenues increased $2.0 million, or 8%, in 1996 compared to a $12 million, or 34%, decline in 1995. The 1996 revenue increase was due primarily to certain actions taken late in 1995, such as the major fall marketing campaign, an extensive sales training program and restructuring of the sales force. Merchandise revenues have been negatively impacted by the absence of joint marketing, installation and service activities with the Company since the bulk of the business, consisting of gas appliance sales, was transferred from the Company to Washington Energy Services on October 1, 1993. Operating Expenses Purchased electricity expenses increased $18.6 million in 1996 when compared to 1995. Higher payments for firm power purchases from non-utility generators and increased secondary power purchases from other utilities contributed an increase of $34.5 million. This increase was partially offset by increased credits associated with the Residential Purchase and Sale Agreement with BPA of $15.2 million. (See discussion of the Residential Purchase and Sale Agreement under "Operating revenues.") Purchased electricity expenses increased $14.8 million in 1995 when compared to 1994. Higher payments for firm power purchases from non-utility generators and increased secondary power purchases from other utilities contributed an increase of $35.4 million. This increase was partially offset by increased credits associated with the Residential Purchase and Sale Agreement with BPA of $24.1 million. Purchased electricity expenses increased $77.1 million in 1994 when compared to 1993. Higher payments related to new firm power purchase contracts from non-utility generators contributed an increase of $89.3 million. Also contributing to the increase was a reduction in credits associated with the Residential Purchase and Sale Agreements with BPA of $2.2 million. Partially offsetting these increases were lower secondary power purchases from other utilities of $15.6 million. Purchased gas expenses decreased $41.3 million in 1996 when compared to 1995. The decrease resulted from lower average per-therm cost of gas established in the May 1995 PGA and the 5% reduction in gas volumes sold. Purchased gas expenses decreased $4.5 million in 1995 when compared to 1994. The decrease was due to the PGA implemented in May 1995. Purchased gas expenses increased $42.6 million in 1994 when compared to 1993 due to higher gas prices during 1994. Operations and maintenance expenses increased $1.3 million in 1996 compared to 1995. Contributing to the increase was a $5 million increase in fuel expense and a $7.8 million increase in transmission and distribution expenses, caused in part by a severe wind storm in November 1996. These increases were partially offset by an $11.6 million decrease in amortization expense associated with the Company's conservation program. In June 1995, the Company sold, to a grantor trust, approximately $202.5 million of its investment in customer-owned energy conservation measures. Operations and maintenance expenses decreased $72.6 million in 1995 compared to 1994. The reduction was the result of several factors. $24.8 million of the decrease was due to decreased charges in 1995 compared to 1994 associated with the Company's restructuring including employee separation programs and related business office and service facility consolidations. Also contributing to the decrease was lower amortization expense of $14.3 million associated with the Company's sale, in June 1995, of $202.5 million of its investment in customer-owned energy conservation measures. $11.5 27 million of the decrease related to lower fuel expense in 1995 compared to 1994 as the Company generated less electricity at company-owned coal plants while purchasing more power on the secondary market. Additionally, an Arbitration Panel's decision of a dispute involving the coal supply agreement at the Company's fifty percent-owned Colstrip 1 and 2 plants resulted in a $4.6 million decrease to fuel expense in the first quarter of 1995 pertaining to coal deliveries from August, 1 1991, through March 31, 1995. Operations and maintenance expenses decreased $11.2 million in 1994 compared to 1993. Reduced merchandise sales expenses and the deconsolidation of a subsidiary in the merger with Cabot contributed decreases of $26.6 million and $23.9 million, respectively. These decreases were partially offset by increased transmission and distribution expenses, charges related to voluntary retirement and separation programs and related facility consolidation expenses. Depreciation and amortization expense increased $3.7 million in 1996 from 1995 levels due primarily to capital spending to take on more customers, reinforce the gas distribution system, and add electric plant. Depreciation and amortization expense decreased $6.0 million in 1995 from 1994 levels. A decrease of $12.9 million was attributable to the completion in September 1994, of the 10 year amortization period related to two terminated generating projects. This decrease was partially offset by the effects of new plant placed into service. Depreciation and amortization expense decreased $7.2 million in 1994 compared to the prior year. Decreased expenses in 1994 as a result of the sale of Washington Energy Resources Company to Cabot was partially offset by increased depreciation expense related to additional plant placed into service. Taxes other than federal income taxes increased $5.5 million in 1996 compared to 1995. The increase was primarily due to higher Washington state property tax payments of $2.1 million and higher revenue-based municipal and state excise tax payments of $2.1 million. Taxes other than federal income taxes increased $4.6 million in 1995 compared to 1994. The increase was primarily the result of increased municipal and state excise tax payments of $4.5 million and increased property tax payments of $1.0 million. These increases were partially offset by lower payroll taxes. Taxes other than federal taxes increased $6.4 million in 1994 compared to the prior year. The increase was due primarily to higher municipal and state excise taxes, which are revenue- based, and higher Washington and Montana state property tax payments. Federal income taxes on operations increased by $16.2 million in 1996 over 1995. The increase was primarily due to higher pre-tax utility earnings. Also, there was a decrease in energy conservation expenditures in 1996 which are deducted for federal income taxes. Federal income taxes on operations increased $16.7 million in 1995 over 1994 due primarily to higher pre-tax operating income during 1995. Federal income taxes on operations decreased $18.5 million over the prior year due primarily to lower pre-tax operating income during 1994. 28 Other Income Total other income increased $16.4 million in 1996 as compared to 1995. The increase is due primarily to pre-tax charges in 1995 related to Cabot totaling $24.8 million, partially offset by a $8.7 million deferred tax benefit of write downs. Other income increased $7.7 million in 1995. The increase is primarily due to an $8.7 million deferred tax benefit of write downs in 1995, and lower special charges in 1995 as compared to 1994. Included in other income in 1995 were pretax charges related to Cabot of $24.8 million, while charges in 1994 included a pretax loss and related federal income taxes on the merger of Cabot of $30.0 million. These increases were partially offset by lower energy conservation expenditures resulting in a $2.2 million decline in Allowance for Funds Used to Conserve Energy ("AFUCE") and a $1.4 million decrease in excess AFUDC over the Federal Energy Regulatory Commission ("FERC") maximum allowed by the Washington Commission. Other income decreased $35.7 million in 1994. The decrease is primarily due to Federal income taxes on the merger of Cabot of $23.7 million and a pre- tax loss on the merger of $6.3 million. Interest Charges Interest Charges, which consists of interest and amortization on long-term debt and other interest, decreased $8.3 million in 1996 compared to 1995. Interest and amortization on long-term debt decreased $8.8 million. Contributing to the reduced interest expense were five First Mortgage Bond retirements or redemptions totaling $151 million over the previous 17 months. Other interest expense increased in 1996 over 1995 due primarily to increased interest on PGA balances. Interest Charges increased $4.2 million in 1995 compared to 1994. Interest and amortization on long-term debt decreased $4.4 million due primarily to the maturity of $100 million in First Mortgage Bonds in August 1995. Other interest expense increased $8.6 million in 1995 over 1994. The increase was primarily due to higher weighted-average interest rates and higher average daily short-term borrowings in 1995 as compared to 1994. Interest Charges increased $4.4 million in 1994. Interest and amortization on long-term debt increased $0.7 million. Other interest expense increased $3.7 million in 1994 over the prior year. The increase was primarily due to higher weighted-average interest rates and higher average daily short-term borrowings in 1994 as compared to 1993. For a discussion of discontinued operations see Note 17 to the Consolidated Financial Statements. Construction and Financing Program Current construction expenditures are primarily transmission and distribution-related, designed to meet continuing customer growth. Construction expenditures, which include energy conservation expenditures and exclude AFUDC and AFUCE, were $206.8 million in 1996. The Company expects combined electric and gas construction expenditures for the period 1997 through 1999 will be approximately $247 million, $252 million and $226 million, respectively. The ratio of cash from operations (net of dividends, AFUDC and AFUCE) to construction expenditures (excluding AFUDC and AFUCE) was 115.4% in 1996. The Company expects cash from operations (net of dividends and AFUDC) during the period 1997 through 1999 will, on average, be approximately 73% of average estimated construction expenditures (excluding AFUDC) during the same period. 29 In October 1992, Puget Power 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 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 10, 1997, the Company has issued $364 million in Series B Notes having an average coupon rate of 6.90%. In August 1995, WNG filed a shelf registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $150 million principal amount of First Mortgage Bonds, designated as Secured Medium-Term Notes, Series C. In December 1995, WNG called $30 million of outstanding First Mortgage bonds and paid a premium of $342,000 and issued $35 million of Medium-Term Notes with lower interest rates. Short-term borrowings from banks and the sale of commercial paper are used to provide working capital for the construction program. At December 31, 1996, the Company had in place $426.5 million in lines of credit with several banks, which provided liquidity support for outstanding commercial paper of $266.4 million, effectively reducing the available borrowing capacity under these lines of credit to $160.1 million. (See Note 8 to the Consolidated Financial Statements.) Rate Matters - Electric In the Washington Commission's September 21, 1993, general rate case order, the Company was allowed 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. On September 22, 1995, the Washington Commission issued a rate order relating to the Company's fifth annual rate adjustment under the PRAM. In addition to approval of the rate adjustment, the Commission also agreed, pursuant to a negotiated settlement, to discontinue the PRAM on September 30, 1996. PRAM accrued revenues of $40.5 million, recorded at December 31, 1996, were recovered in the first quarter of 1997. Over-collection of PRAM revenues were refunded to customers in the second quarter of 1997. With the discontinuance of the PRAM, the annual regulatory adjustments for variations in weather and hydro conditions provided for in the PRAM were also discontinued. On September 30, 1996, the Washington Commission issued an order granting a joint motion by the Company and the Washington Commission Staff to transfer annual revenues of $165.5 million which were being collected in PRAM rates to the Company's permanent rate schedules. As a result of the order, the Company also wrote off $4.5 million in previously accrued revenues related to special industrial customer service contracts. 30 Rate Matters - Gas WNG filed and received rate orders for three general rate cases in the period from July 1992 to May 1995. The following table shows the filing dates of each case, the annual margin effect based on normal weather and the effective date of each rate order: Date of Annual Margin Effective Date Filing Increase (Decrease) of Rate Order ------ ------------------- -------------- July 1992 ($15.4 million) October 9, 1993 November 1993 $19.0 million June 2, 1994 March 1995 $17.7 million (1) May 15, 1995 (1) Excluding municipal utility taxes In the July 1992 filing, WNG had initially sought a $41.4 million rate increase, which was subsequently reduced to $14.8 million. In September 1993, the Washington Commission issued an order decreasing rates by $15.4 million effective in October 1993. The principal differences in the annual revenue requirement between WNG's revised rate request and the Washington Commission's ordered rate reduction were: (1) approximately $11 million of expenses related to advertising, marketing and merchandising disallowed by the Washington Commission; (2) approximately $10 million due to an allowed overall rate of return of 9.15% on a rate base of $483.9 million, compared to WNG's proposed overall rate of return of 9.98% on $504.0 million of rate base; (3) $5.2 million related to disallowance of WNG's proposed attrition allowance; and (4) $4.8 million associated with the weather normalization calculation. In November 1993, WNG filed a limited-scope general rate case seeking a $24.6 million increase in annual revenues. The primary focus was to seek recovery of additional operating costs and the inclusion in rate base of utility plant additions since calendar year 1991, which was the base measurement year used in the prior rate case. In May 1994, the Washington Commission issued an order approving a settlement of the rate case. The settlement provided for a $19.0 million increase in annual revenue and an agreement that WNG would not request an increase in total revenues, other than PGA filings or in other limited circumstances, prior to March 1, 1995. In the March 1995 general rate case filing, WNG requested a $35.4 million increase in annual revenues, with $17.8 million of the total to be granted as interim rate relief in May 1995. The rate case was requested to cover increased costs related to plant additions and upgrades and higher costs for financing and general operations. In May 1995, the Washington Commission issued an order approving a settlement of the case. The settlement provided an additional $17.7 million in annual revenues, excluding municipal utility taxes, and reflected an authorized rate of return on common equity in the range of 11.0% - 11.25%, up from the previous level of 10.5%. The settlement accepted by the Washington Commission also stipulated that WNG will be allowed to earn in excess of that range to the extent that it can do so by managing its cost of service. As part of the rate case settlement, WNG agreed not to make a general rate case filing prior to May 15, 1997. WNG, however, is not precluded from PGA filings or filing for interim or emergency rate relief if conditions warrant. 31 The May 1995 order also implemented a rate redesign approved by the Washington Commission in April 1995. Generally, the rate redesign lowers rates for transportation customers and large commercial and industrial gas sales customers, while increasing the rates for residential customers. In a separate decision in May 1995, the Washington Commission issued an order to implement a PGA to pass through a $46.5 million annual reduction in the cost of purchased gas to customers in the form of lower rates. The Merger On February 7, 1997, the Boards of the Company and WECo approved the merger of their respective companies effective February 10, 1997. The merged company is called Puget Sound Energy, Inc. This announcement followed the approval by the Washington Commission, on February 5, 1997, of a merger agreement between the Company, WECo, WNG, the Staff of the Washington Commission and the Public Counsel Section of the State Attorney General's Office. Shareholders of the Company and WECo, voting as separate groups had, on March 20, 1996, already given their approval to an Agreement and Plan of Merger ("Merger Agreement") between the two companies. The Merger Agreement called for each share of WECo common stock to be exchanged for 0.86 share of the Company's common stock (approximately 20,921,000 shares of Company stock are expected to be issued). On February 10, 1997, the Company increased the number of authorized shares to 150,000,000. Based on the capitalization of the Company and WECo on February 10, 1997, holders of the Company's and WECo's common stock held approximately 75% and 25% respectively, of the aggregate number of outstanding shares of the merged company's common stock. In addition, the Agreement called for the preferred stock of Washington Natural Gas Company, a wholly-owned subsidiary of WECo, to be converted into preferred shares of the merged company. The merger has been structured as a tax-free exchange of shares, and is accounted for as a pooling of interests for financial statement purposes. The Merger Agreement approvorder approving the merger, issued by the Washington Commission, contains a rate plan that is designed to provide a five-year period of rate certainty for customers and provide the Company with an opportunity to achieve a reasonable return on investment. As required under the stipulated settlementmerger order, the Company filed tariffs, effective February 8, 1997, that resulted in an average electric rate decrease of 5.6% related to the PRAM, and an increase in general rates of between 1.0% and 2.5%, depending on rate class. The net impact was an average rate decrease of 3.7%, including a decrease in residential rates of 3.24%. General electric rates for residential and industrial customers will increase by 1.5% on January 1 of each of the four following years, while those for small commercial customers will increase by 1.0% in each of the following three years. General rates for all classes of natural gas customers will remain unchanged until January 1, 1999, when they will decrease sufficiently to reduce utility margin by 1 percent. In connection with the merger, through December 31, 1996, the Company has incurred direct merger related costs and indirect costs related to integration of the operations of the Company and WECo, (including costs related to a voluntary early separation plan accepted by 277 employees of the Company - under terms of the plan, certain employees were terminated in 1996 and termination of others was subject to completion of the merger). Indirect costs of $4.8 million were expensed in the fourth quarter of 1996. Additional costs of $14.0 million have been deferred and will be expensed in the first quarter of 1997, as of the merger consummation date. 32 The Company estimates that additional direct and indirect merger costs of $56 million, including the $14 million deferred, would be charged to expense in 1997. These estimates are subject to revision as the integration process proceeds. Other The U.S. electric utility industry is facing an increasingly competitive environment, particularly in wholesale generation and industrial customer markets. The National Energy Policy Act of 1992 ("EPACT") intensified competition in the wholesale electric market by easing restrictions on wholesale power producers and by allowing the Federal Energy Regulatory Commission ("FERC") to order access for wholesale sellers to deliver power to wholesale buyers over transmission systems owned by others. In 1996 FERC issued its landmark Orders 888 and 889, which require jurisdictional utilities, including the Company, to file wholesale transmission tariffs providing pricing and terms for transmission access for wholesale purposes. The EPACT does not permit the FERC to order transmission access for retail purposes, but Congress now has pending bills that would require existing utilities to allow competitors to use utility property, including transmission and distribution facilities, to provide electric service to retail customers of the existing utilities. Several states, including California, New Hampshire and Rhode Island have enacted legislation to allow such use by competitors of utility property. Most other states, including Washington, are considering, or have adopted, legislative or regulatory proposals which would also allow such use of utility property by competitors to sell to retail customers of the existing utilities. In its February 5, 1997 Order approving the Company's merger with Washington Energy Company described above, the Washington Commission required the Company to conduct a retail access pilot program. Any substantial change in utility regulation in Washington state, such as allowing use of utility property by competitors for retail purposes, would require legislative action. The major credit rating agencies have expressed the general view that increased competition is likely to increase business risks in the electric utility industry, with resulting pressures on utility credit quality and investor returns. Since 1986, the Company has been offering gas transportation as a separate service to industrial and commerical customers who choose to purchase their gas supply directly from producers and gas marketers. The continued evolution of the natural gas industry, resulting primarily from FERC Orders 436, 500 and 636, has served to increase the ability of large gas end-users to bypass the Company in obtaining gas supply and transportation services. Though the Company has not lost any substantial industrial or commercial load as a result of such bypass, in certain years up to 160 customers annually have taken advantage of the potential savings provided by unbundled transportation service; in 1996, approximately 106 commercial and industrial customers, on average, chose to use such service. In the future, the Company's large industrial and commercial customers may also choose to bypass the Company's distribution system by constructing pipelines to interconnect directly with the interstate pipeline that transports natural gas to the Pacific Northwest. 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 33 project, which is expected to be completed in late 1997, will involve a combination of existing facility upgrades and new construction. On May 24, 1996, the Company filed a proposal with the Washington Commission to create an Optional Large Power Sales Rate for its largest customers. Under the Company's proposal, customers who elect the Optional Large Power Sales Rate would no longer be considered "core" customers. Instead, they would form a new class of "non-core" customers, and the Company would no longer have an obligation to plan for future resources to serve their needs. The non-core customers will receive access to electric energy that is priced at current market cost and will pay a charge for energy delivery (including a charge for conservation programs) and a transition charge (representing the difference between the Company's present cost and the current market cost of electric energy and capacity). The transition charge will be phased out before the end of the year 2000. Non-core customers also would take on the risk that market costs could become volatile and that electricity could be unavailable on the open market. On October 9, 1996, the Washington Commission approved the Company's proposal and ordered the new optional large power sales tariff into effect November 1, 1996. On January 29, 1997, the Company and BPA signed a Residential Exchange Termination Agreement. The Agreement ends the Company's participation in the Residential Purchase and Sale Agreement with BPA. The Residential Purchase and Sale Agreement enabled the Company's residential and small farm customers to receive the benefits of lower-cost federal power. As part of the Termination Agreement, the Company will receive payments by the BPA of approximately $237 million over five years. Under the rate plan approved by the Washington Commission in its merger order, the Company will continue to reflect, in customers' bills, the current level of Residential Exchange benefits. Over the five year period, it is projected that the Company will credit customers approximately $250 million more than it will receive from BPA. The Company expects the difference will be made up through the general rate increases approved in the merger order and additional reductions in operating expenses. On July 12, 1996, the Company and several other Northwest electric companies signed a memorandum of understanding to study the creation of an independent transmission grid operator called "IndeGO." Participation in IndeGO would be open to all transmission owners in the Northwest and would include both investor-owned utilities and certain government-owned power agencies. The Company's energy conservation expenditures have historically been accumulated, included in rate base and amortized to expense over a ten year period at the direction of the Washington Commission. In June 1995 the Company sold approximately $202.5 million of its investment in customer- owned energy conservation measures to a grantor trust, which, in turn, issued securities backed by a Washington state statute enacted in 1994. The statute provides that if certain conditions are met, securities could be issued, backed by a statutory requirement that a portion of rate revenues be forwarded to the trust to repay those securities. The proceeds of the sale were used to pay down short-term debt. The Company recognized no gain or loss on the sale. The Company is in the process of selectively replacing the High Molecular Weight ("HMW") underground distribution cable installed during the 1960s and 1970s. The Company installed about 4,800 miles of 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 effect of cable failures on customer service. To minimize the impact on customers of increasing cable failures, the Company replaces a certain amount of HMW 34 cable each year and is beginning to use silicone injection to lengthen the life of potentially problem cables. The Company so far has replaced 780 miles and injected 20 miles of HMW cable. The Company expects to spend $49 million on additional cable replacement during the period 1997-2000. In 1997 the Company is planning either to replace or use silicone injection on 150 miles of HMW cable. For a discussion of environmental obligations, see Note 16 to the Consolidated Financial Statements. 35 Selected Financial Data (Dollars in thousands except per share data) Year ended on December 31 1996 1995 1994 1993 1992 - -------------------------------------------------------------------------------------------- Operating revenue $ 1,649,279 $ 1,631,118 $ 1,632,485 $ 1,586,935 $ 1,402,198 Operating income $ 284,474 $ 270,344 $ 224,772 $ 268,390 $ 261,744 Income from continuing operations $ 167,351 $ 128,381 $ 79,312 $ 162,974 $ 152,323 Income for common stock from continuing operations $ 145,170 $ 105,727 $ 58,929 $ 143,819 $ 135,712 Common shares outstanding - weighted average 84,417,601 84,188,841 83,830,017 80,707,419 73,190,689 Earnings per common share from continuing operations $ 1.72 $ 1.26 $ 0.70 $ 1.78 $ 1.85 (Note 1 to the financial statements) Dividends per common share $ 1.67 $ 1.67 $ 1.67 $ 1.78 $ 1.75 Book value per common share $ 16.31 $ 16.27 $ 17.01 $ 18.04 $ 17.39 - -------------------------------------------------------------------------------------------- Total assets at year-end $ 4,227,470 $ 4,244,568 $ 4,496,770 $ 4,386,678 $ 3,907,265 Long-term obligations $ 1,165,584 $ 1,230,499 $ 1,253,498 $ 1,389,479 $ 1,321,672 Redeemable preferred stock $ 87,839 $ 89,039 $ 91,242 $ 115,724 $ 126,570 36 ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS Report of Independent Accountants To the Shareholders of Puget Sound Energy, Inc. We have audited the consolidated financial statements and the financial statement schedule of Puget Sound Energy, Inc. (formerly Puget Sound Power & Light Company) listed on page 39 of this Report on Form 8-K. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We did not audit the consolidated financial statements and financial statement schedule of Washington Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas ("WNG"), which statements reflect total assets of $1,034 million and $979 million as of December 31, 1996 and 1995, respectively and total revenues of $426 million, $444 million and $432 million for 1996, 1995 and 1994, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for WECo and WNG, is based solely on the report of the other auditors. 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 and the report of the other auditors provides a reasonable basis for our opinion. In our opinion, based on our audit and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Puget Sound Energy, Inc. as of December 31, 1996 and 1995, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. As discussed in Note 1, Puget Sound Energy, Inc. merged with WECo and WNG on February 10, 1997 in a transaction accounted for as a pooling of interests. Coopers & Lybrand L.L.P. Seattle, Washington February 12, 1997 37 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Washington Energy Company: We have audited the consolidated balance sheets and statements of capitalization of Washington Energy Company (a Washington corporation) and subsidiaries as of September 30, 1996 and 1995, and the related consolidated statements of income, shareholders' earnings (deficit) reinvested in the business, premium on common stock and cash flows for each of the three years in the period ended September 30, 1996, and the consolidated balance sheets and statements of capitalization of Washington Natural Gas Company (a Washington corporation) and subsidiaries as of September 30, 1996 and 1995, and the related consolidated statements of income, shareholder's earnings reinvested in the business, premium on common stock and cash flows for each of the three years in the period ended September 30, 1996. These financial statements, which are not included in this Form 8-K, are the responsibility of the companies' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. On February 10, 1997, Washington Energy Company and Washington Natural Gas, in a transaction accounted for as a pooling-of-interests, merged with Puget Sound Power and Light to form Puget Sound Energy. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Washington Energy Company and subsidiaries and of Washington Natural Gas Company and subsidiaries as of September 30, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Seattle, Washington, October 31, 1996 (except with respect to the matter discussed in the third paragraph above, for which the date is February 10, 1997) 38 Consolidated Financial Statements, Financial Statement Schedule and Exhibits Covered by the Foregoing Report of Independent Accountants: Consolidated Statements of Income for the years ended December 31, 1996, 1995 and 1994........................................40 Consolidated Balance Sheets, December 31, 1996 and 1995...................42 Consolidated Statements of Capitalization, December 31, 1996 and 1995..............................................44 Consolidated Statements of Earnings Reinvested in the Business for the years ended December 31, 1996, 1995 and 1994....................45 Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994..................................46 Notes to Consolidated Financial Statements................................47 Schedule: II. Valuation and Qualifying Accounts and Reserves for the years ended December 31, 1996, 1995 and 1994.........................79 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. Exhibits: Exhibit Index.............................................................81 39 Consolidated Statements of Income Puget Sound Energy, Inc. - -------------------------------------------------------------------------- Year Ended December 31 (Dollars in thousands except per share amounts) 1996 1995 1994 - -------------------------------------------------------------------------- Operating Revenues: Electric $1,198,769 $1,179,330 $1,194,058 Gas 400,108 420,048 396,407 Other 50,402 31,740 42,020 - -------------------------------------------------------------------------- Total operating revenue 1,649,279 1,631,118 1,632,485 - -------------------------------------------------------------------------- Operating Expenses: Energy Costs: Purchased electricity 428,172 409,541 394,758 Purchased gas 177,719 219,022 223,502 Fuel 40,645 35,658 47,166 Utility operations and maintenance 303,410 311,022 372,819 Other operations and maintenance 6,421 2,497 1,774 Depreciation, depletion and amortization 144,722 141,008 146,971 Taxes other than federal income taxes 155,969 150,507 145,907 Federal income taxes 107,747 91,519 74,816 - -------------------------------------------------------------------------- Total operating expenses 1,364,805 1,360,774 1,407,713 - -------------------------------------------------------------------------- Operating Income 284,474 270,344 224,772 - -------------------------------------------------------------------------- Other Income: Pre-tax loss on merger of subsidiary -- -- (6,304) Federal income tax on merger of subsidiary -- -- (23,711) Pre-tax charges related to unconsolidated affiliate -- (24,803) -- Deferred tax benefit of write downs -- 8,681 -- Other, net 1,593 1,213 7,443 - -------------------------------------------------------------------------- Total other income 1,593 (14,909) (22,572) - -------------------------------------------------------------------------- Income Before Interest Charges 286,067 255,435 202,200 - -------------------------------------------------------------------------- (Continued) 40 Consolidated Statements of Income, continued Puget Sound Energy, Inc. - -------------------------------------------------------------------------- Year Ended December 31 (Dollars in thousands except per share amounts) 1996 1995 1994 - -------------------------------------------------------------------------- Interest Charges: AFUDC (3,919) (4,292) (3,667) Other interest 122,635 131,346 126,555 - -------------------------------------------------------------------------- Total interest charges 118,716 127,054 122,888 - -------------------------------------------------------------------------- Income from continuing operations 167,351 128,381 79,312 Discontinued operations: Loss from operations, net of tax (1,386) (26,597) (130) Loss on disposal, net of tax (446) -- (799) - -------------------------------------------------------------------------- Net Income 165,519 101,784 78,383 Less Preferred Stock Dividends accrual 22,181 22,654 20,383 - -------------------------------------------------------------------------- Income for Common Stock $143,338 $79,130 $58,000 ========================================================================== Common shares outstanding weighted average 84,418 84,189 83,830 ========================================================================== Earnings (Loss) per common share: From continuing operations $1.72 $1.26 $0.70 From discontinued operations (.02) (.32) (.01) - -------------------------------------------------------------------------- Earnings per common share $1.70 $0.94 $0.69 ========================================================================== The accompanying notes are an integral part of the consolidated financial statements. 41 Consolidated Balance Sheets Puget Sound Energy, Inc. - ---------------------------------------------------------------------------- Assets December 31 (Dollars in Thousands) 1996 1995 - ---------------------------------------------------------------------------- Utility Plant: Electric plant, at original cost $3,479,652 $3,400,723 Gas plant 1,129,849 1,044,617 Less: Accumulated depreciation and amortization 1,493,024 1,392,413 - ---------------------------------------------------------------------------- Net utility plant 3,116,477 3,052,927 - ---------------------------------------------------------------------------- Other Property and Investments: Investment in Bonneville Exchange Power Contract 86,772 94,241 Investment in Cabot 69,014 69,975 Subsidiary properties and investment 80,770 104,608 Other 43,444 30,705 - ---------------------------------------------------------------------------- Total other property and investments 280,000 299,529 - ---------------------------------------------------------------------------- Current Assets: Cash 4,335 21,814 - ---------------------------------------------------------------------------- Accounts receivable 160,836 138,759 Less: Allowance for doubtful accounts 1,700 1,865 - ---------------------------------------------------------------------------- Total accounts receivable 159,136 136,894 - ---------------------------------------------------------------------------- Unbilled revenue 102,409 91,305 PRAM accrued revenues 40,470 59,123 Materials and supplies, at average cost 61,638 78,375 Prepayments and Other 10,458 11,949 - ---------------------------------------------------------------------------- Total current assets 378,446 399,460 - ---------------------------------------------------------------------------- Long-Term Assets: Regulatory asset for deferred income taxes 242,454 256,320 PRAM accrued revenues (net of current portion) -- 55,673 Unamortized energy conservation charges 44,673 41,068 Other 165,420 139,591 - ---------------------------------------------------------------------------- Total long-term assets 452,547 492,652 - ---------------------------------------------------------------------------- Total Assets $4,227,470 $4,244,568 ============================================================================ The accompanying notes are an integral part of the consolidated financial statements. 42 Capitalization and Liabilities December 31 (Dollars in Thousands) 1996 1995 - ---------------------------------------------------------------------------- Capitalization (See "Consolidated Statements of Capitalization"): Common equity $1,378,377 $1,372,590 Preferred stock not subject to mandatory redemption 215,000 215,000 Preferred stock subject to mandatory redemption 87,839 89,039 Long-term debt 1,165,584 1,230,499 - ---------------------------------------------------------------------------- Total capitalization 2,846,800 2,907,128 - ---------------------------------------------------------------------------- Current Liabilities: Accounts payable 95,736 79,739 Short-term debt 298,122 329,043 Current maturities of long-term debt 100,062 73,140 Purchased gas liability 41,368 15,554 Accrued expenses: Taxes 57,419 47,882 Salaries and wages 28,215 27,802 Interest 27,173 27,291 Other 51,906 60,622 - ---------------------------------------------------------------------------- Total current liabilities 700,001 661,073 - ---------------------------------------------------------------------------- Deferred Income Taxes 586,661 593,685 - ---------------------------------------------------------------------------- Other Deferred Credits 94,008 82,682 - ---------------------------------------------------------------------------- Commitments and Contingencies -- -- - ---------------------------------------------------------------------------- Total Capitalization and Liabilities $4,227,470 $4,244,568 ============================================================================ The accompanying notes are an integral part of the consolidated financial statements. 43 Consolidated Statements of Capitalization Puget Sound Energy, Inc. - ------------------------------------------------------------------------------------ December 31 (Dollars in Thousands) 1996 1995 - ------------------------------------------------------------------------------------ Common Equity: Common stock - ($10 stated value) - 150,000,000 shares authorized, 84,511,245 and 84,340,755 shares outstanding $ 845,112 $ 843,408 Additional paid-in capital 446,910 444,928 Earnings reinvested in the business 86,355 84,254 - ------------------------------------------------------------------------------------ Total common equity 1,378,377 1,372,590 - ------------------------------------------------------------------------------------ Preferred Stock Not Subject to Mandatory Redemption - cumulative - $25 par value:* 7.875% series - 3,000,000 shares authorized and outstanding 75,000 75,000 Adjustable Rate, Series B - 2,000,000 shares authorized and outstanding 50,000 50,000 7.45% series II - 2,400,000 shares authorized and outstanding 60,000 60,000 8.50% series III - 1,200,000 shares authorized and outstanding 30,000 30,000 - ------------------------------------------------------------------------------------ Total preferred stock not subject to mandatory redemption 215,000 215,000 - ------------------------------------------------------------------------------------ Preferred Stock Subject To Mandatory Redemption - cumulative $100 par value:* 4.84% series - 150,000 shares authorized, 47,956 shares outstanding 4,796 4,796 4.70% series - 150,000 shares authorized, 56,215 shares outstanding 5,621 5,621 8% series - 150,000 shares authorized, 24,224 and 36,224 shares outstanding 2,422 3,622 7.75% series - 750,000 shares authorized and outstanding 75,000 75,000 - ------------------------------------------------------------------------------------ Total preferred stock subject to mandatory redemption 87,839 89,039 - ------------------------------------------------------------------------------------ Long-Term Debt: First mortgage bonds 1,104,060 1,134,200 Guaranteed collateralized bonds -- 8,000 Pollution control revenue bonds: Revenue refunding 1991 series, due 2021 50,900 50,900 Revenue refunding 1992 series, due 2022 87,500 87,500 Revenue refunding 1993 series, due 2020 23,460 23,460 Other notes 19 21 Unamortized discount - net of premium (293) (442) Long-term debt due within one year (100,062) (73,140) - ------------------------------------------------------------------------------------ Total long-term debt excluding current maturities 1,165,584 1,230,499 - ----------------------------------------------------------------------------------- Total Capitalization $2,846,800 $2,907,128 ==================================================================================== * 13,000,000 shares authorized for $25 par value preferred stock and 3,000,000 shares authorized for $100 par value preferred stock. The accompanying notes are an integral part of the consolidated financial statements. 44 Consolidated Statements of Earnings Reinvested in the Business Puget Sound Energy, Inc. - ---------------------------------------------------------------------------- Year Ended December 31 (Dollars in thousands except per share amounts) 1996 1995 1994 - ---------------------------------------------------------------------------- Balance at Beginning of Year $ 84,254 $146,228 $228,716 Net Income 165,519 101,784 78,383 - ---------------------------------------------------------------------------- Total 249,773 248,012 307,099 - ---------------------------------------------------------------------------- Deductions: Excess premium, preferred redemption -- -- 673 Dividends Declared: Preferred stock: $4.84 per share on 4.84% series 232 232 242 $4.70 per share on 4.70% series 265 276 319 $8.00 per share on 8% series 218 314 410 $0.77 per share on 8.875% series C -- -- 23 $0.73 per share on 8.750% series F -- -- 22 $0.18 per share on 8.750 series I -- -- 88 $7.75 per share on 7.75% series 5,813 5,813 5,813 $1.97 per share on 7.875% series 5,906 5,906 5,906 $1.86 per share on 7.45% series II 4,470 4,470 3,824 $2.13 per share on 8.50% series III 2,550 2,656 -- Adjustable Rate, series A -- -- 700 Adjustable Rate, series B 2,716 3,115 2,277 $0.43 per share on 5.00% series A -- -- 9 $0.52 per share on 6.00% series A -- -- 13 Common stock 141,248 140,976 140,552 - ---------------------------------------------------------------------------- Total deductions 163,418 163,758 160,871 - ---------------------------------------------------------------------------- Balance at End of Year $ 86,355 $ 84,254 $146,228 - ---------------------------------------------------------------------------- Dividends declared per common share $ 1.67 $ 1.67 $ 1.67 ============================================================================ The accompanying notes are an integral part of the consolidated financial statements. 45 Consolidated Statements of Cash Flows Puget Sound Energy, Inc. - ---------------------------------------------------------------------------------------- Year Ended December 31 (Dollars in Thousands) 1996 1995 1994 - ---------------------------------------------------------------------------------------- Operating Activities: Income from continuing operations $167,351 $128,381 $ 79,312 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation and amortization 144,722 141,008 146,971 Deferred income taxes and tax credits - net 6,842 11,421 (5,690) PRAM accrued revenues - net 74,326 (3,955) (25,835) Pre-tax loss on merger of unconsolidated subsidiary -- -- 6,304 Pretax writedown and equity in undistributed (income) losses of unconsolidated affiliate 961 27,826 (699) Deferred tax on merger of unconsolidated subsidiary -- -- 24,784 Other (22,434) 4,143 13,103 Change in certain current assets and liabilities 27,809 34,959 38,164 - ---------------------------------------------------------------------------------------- Net Cash Provided by Operating Activities 399,577 343,783 276,414 - ---------------------------------------------------------------------------------------- Investing Activities: Construction expenditures - excluding equity AFUDC (205,050) (205,981) (297,140) Energy conservation expenditures (6,683) (15,156) (36,648) Cash received from sale of conservation assets - net -- 199,452 -- Proceeds from property sales 34,000 -- -- Proceeds from merger of unconsolidated subsidiary -- -- 63,661 Investment in unconsolidated subsidiary prior to merger -- -- (20,760) Other (7,384) 882 22,972 - ---------------------------------------------------------------------------------------- Net Cash Used by Investing Activities (185,117) (20,803) (267,915) - ---------------------------------------------------------------------------------------- Financing Activities: Increase (decrease) in short-term debt (30,921) (30,593) 64,832 Dividends paid (163,418) (163,758) (160,871) Issuance of common and preferred stock 3,686 4,824 144,229 Redemption of preferred stock (1,200) (1,993) (65,086) Issuance of bonds 34,470 74,280 85,000 Redemption of bonds and notes (72,612) (193,144) (76,354) Other (558) (43) (1,299) - ---------------------------------------------------------------------------------------- Net Cash Used by Financing Activities (230,553) (310,427) (9,549) - ---------------------------------------------------------------------------------------- Increase (decrease) in cash from continuing operations (16,093) 12,553 (1,050) Decrease in cash from discontinued operations: Operating activities (1,386) (139) (3,609) Investing activities -- (1,271) (1,164) - --------------------------------------------------------------------------------------- Net increase (decrease) in cash (17,479) 11,143 (5,823) Cash at Beginning of Year 21,814 10,671 16,494 - --------------------------------------------------------------------------------------- Cash at End of Year $ 4,335 $ 21,814 $ 10,671 ======================================================================================= The accompanying notes are an integral part of the consolidated financial statements. 46 Puget Sound Energy, Inc. Notes To Consolidated Financial Statements - ---------------------------------------------------------------------------- 1. Summary of Significant Accounting Policies Significant accounting policies are described below. Basis of Presentation: Puget Sound Energy, Inc., formerly Puget Sound Power & Light Company, ("the Company") is an investor-owned public utility incorporated in the State of Washington furnishing electric, and since February 10, 1997, gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of Washington State. On February 10, 1997, the Company completed a merger ("the Merger") with the Washington Energy Company ("WECo") and its principal subsidiary, Washington Natural Gas Company ("WNG"). The change of the Company's name was effective with the merger. Herein, the Company refers to the combined entity; Puget Power and WECo refer to the individual entities. The Merger Agreement called for each share of WECo common stock to be exchanged for 0.86 share of the Company's common stock (approximately 20,921,000 shares of Company stock are expected to be issued). On February 10, 1997, the Company increased the number of authorized shares to 150,000,000. Based on the capitalization of the Company and WECo on February 10, 1997, holders of the Company's and WECo's common stock held approximately 75% and 25% respectively, of the aggregate number of outstanding shares of the merged company's common stock. In addition, the agreement called for the preferred stock of Washington Natural Gas Company, a wholly-owned subsidiary of WECo, to be converted into preferred shares of the merged company. The order approving the merger, issued by the Washington Commission, contains a rate plan that is designed to provide a five-year period of rate certainty for customers and provide the Company with an opportunity to achieve a reasonable return on investment. As required under the merger order, the Company filed tariffs, effective February 8, 1997, that resulted in an average electric rate decrease of 5.6% related to the PRAM, and an increase in general rates of between 1.0% and 2.5%, depending on rate class. The net impact was an average rate decrease of 3.7%, including a decrease in residential rates of 3.2%. General rates for electric residential and industrial service will increase by 1.5% on January 1 of each of the four following years, while those for small commercial customers will increase by 1.0% in each of the following three years. General rates for all classes of natural gas customers will remain unchanged until January 1, 1999, when they will decrease sufficiently to reduce utility margin by 1 percent. The merger has been structured as a tax-free exchange of shares, and is accounted for as a pooling of interests for financial statement purposes. Accordingly, the consolidated financial statements have been retroactively restated to include the results of operations, financial position and cash flows of WECo and WNG for all periods prior to consummation of the merger. Certain amounts have been reclassified to conform to the combined presentation. The consolidated financial statements include the accounts of the Company and all its significant wholly-owned subsidiaries, after elimination of all significant intercompany items and transactions. One immaterial subsidiary is stated on the equity basis. 47 Financial information for WECo herein is as of its fiscal year-end, September 30, 1996 and 1995, and for the three years in the period ended September 30, 1996. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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. Accounting for Regulatory Assets: The Company prepares its financial statements in accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" ("Statement No. 71"). Statement No. 71 requires the Company to defer certain costs that would otherwise be charged to expense, if it is probable that future rates will permit recovery of such costs. Accounting under Statement No. 71 is appropriate as long as: rates are established by or subject to approval by independent, third-party regulators; rates are designed to recover the specific enterprise's cost-of- service; and in view of demand for service, it is reasonable to assume that rates set at levels that will recover costs can be charged to and collected from customers. In applying Statement No. 71, the Company must give consideration to changes in the level of demand or competition during the cost recovery period. In accordance with Statement No. 71, the Company capitalizes certain costs in accordance with regulatory authority whereby those costs will be expensed and recovered in future periods. Net regulatory assets at December 31, 1996 and 1995 included the following: - ---------------------------------------------------------------- (Dollars in Millions) 1996 1995 - ----------------------------------------- ------ ------ Deferred income taxes $242.5 $256.3 Investment in BEP Exchange Contract 86.8 94.2 Unamortized energy conservation charges 44.7 41.1 PRAM accrued revenues 40.5 114.8 Storm damage costs 39.3 27.3 Various other costs 67.9 70.9 - ----------------------------------------- ------ ----- Total $521.7 $604.6 ================================================================ If the Company, at some point in the future, determines that all or a portion of the utility operations no longer meets the criteria for continued application of Statement No. 71, the Company would be required to adopt the provisions of Statement of Financial Accounting Standards No. 101, "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71." Adoption of Statement No. 101 would require the 48 Company to write off the regulatory assets and liabilities related to those operations not meeting Statement No. 71 requirements. The Company, in prior years, incurred costs associated with its 5% interest in a now terminated nuclear generating project (identified herein as "Investment in Bonneville Exchange Power ("BEP")"). Under terms of a settlement agreement with the Bonneville Power Administration ("BPA"), which settled claims of the Company relating to construction delays associated with that project, the Company is receiving, over 30.5 years, power from the federal power system resources marketed by BPA. Approximately two-thirds of the Company's Investment in BEP is included in rate base and amortized on a straight-line basis over the 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). Operating Revenues: Operating revenues are recorded on the basis of service rendered, which include estimated unbilled revenue and revenue accrued under the Periodic Rate Adjustment Mechanism ("PRAM"). Energy Conservation: The Company accumulates energy conservation expenditures which are included in rate base and amortized to expense as prescribed by the Washington Utilities and Transportation Commission ("Washington Commission"). In June 1995, the Company sold approximately $202.5 million of its investment in customer-owned energy conservation measures to a grantor trust which, in turn, issued securities backed by a Washington state statute enacted in 1994. The proceeds of the sale were used to pay down short-term debt. The Company recognized no gain or loss on the sale. Self-Insurance: Prior to October 1, 1993, provision was made by Puget Power 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. 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 storms. At December 31, 1996, Puget Power had no insurance coverage for storm damage and is self-insured for a portion of the risk associated with comprehensive liability, industrial accidents and catastrophic property losses. The amount of uninsured storm damage costs deferred under the regulatory treatment approved by the Washington Commission at December 31, 1996 was $39.3 million, which includes $14.7 million of costs deferred as a result of a severe snowstorm in late December 1996. 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. The annual depreciation provision stated as a percent of 49 average original cost of depreciable electric utility plant was 3.0% in 1996, 1995 and 1994 and for depreciable gas utility plant was 3.6% in 1996 and 3.5% for 1995 and 1994. The Company's investments in terminated generating projects were amortized on a straight-line basis over the ten year period ending in 1994 (included in operating expenses under "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 ("Statement No. 90"). These adjustments result in reduced net amortization expense over the recovery periods, the effect of which is included in other income in the amount, net of federal income tax expense, of $1.1 million, $1.3 million and $1.8 million for 1996, 1995 and 1994, respectively. Federal Income Taxes: The Company normalizes, with the approval of the Washington Commission, certain items. Deferred taxes have been determined under Statement of Financial Accounting Standards No. 109. (See Note 12.) 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 for gas utility plant additions was 9.03%, 8.68% and 8.72% for 1996, 1995 and 1994, respectively. The allowed AFUDC rate on electric utility plant was 8.94% during the same period. To the extent amounts calculated using this rate exceed the AFUDC 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: $2,112,000 for 1996; $1,614,000 for 1995; and $3,016,000 for 1994. The deferred asset is being amortized over the average useful life of the Company's non-project utility plant. Allowance For Funds Used to Conserve Energy: The Washington Commission has 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 $780,000 in 1996, $1,530,000 in 1995, and $3,370,000 in 1994. Cash inflow related to AFUCE occurs when these charges are reflected in rates, or when the underlying asset is sold to a third party. AFUCE related to electric energy conservation was discontinued with the PRAM on September 30, 1996. 50 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 electric general rate cases. Under the PRAM, Puget Power was 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 was decoupled from levels of electricity sales. Rates established for the PRAM period were 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 varied from amounts allowed under the methodology established in the PRAM order, the difference was accumulated, without interest, for rate recovery which was then established in the next PRAM hearing. In its September 22, 1995 order, the Washington Commission approved Puget Power's last PRAM filing and the recovery of $71.2 million over the period October 1, 1995 through September 30, 1996. In addition to approval of the rate adjustment, the Commission also agreed, pursuant to a negotiated settlement, to discontinue the PRAM on September 30, 1996, the end of the last PRAM period. PRAM accrued revenues of $40.5 million, recorded at December 31, 1996, were recovered in the first quarter of 1997. Over-collection of PRAM revenues were refunded to customers in the second quarter of 1997. PGA Mechanism Differences between the actual cost of the Company's gas supplies and that currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment ("PGA") mechanism. Off-System Sales and Capacity Release: WECo has been selling excess gas supplies and entering into gas supply exchanges with third parties outside of its distribution area since 1992. WECo began releasing to third parties excess interstate gas pipeline capacity and gas storage rights on a short-term basis in 1993 and 1994, respectively. The Company contracts for firm gas supplies and holds firm transportation and storage capacity sufficient to meet the expected peak winter demand for gas for space heating by its firm customers. Due to the variability in weather and other factors, however, the Company holds contractual rights to gas supplies and transportation and storage capacity in excess of its immediate requirements to serve firm customers on its distribution system for much of the year which, therefore, are available for third-party gas sales, exchanges and capacity releases. The net proceeds from such activities are accounted for as reductions in the cost of purchased gas and passed on to customers through the PGA mechanism, with no impact on net income. As a result, the Company does not reflect sales revenue or associated cost of sales for these transactions in its income statement. The net proceeds from these activities were $10,711,500, $7,374,000 and $3,997,000 for 1996, 1995 and 1994, respectively. 51 Other: Debt premium, discount and expenses are amortized over the life of the related debt. In March 1995, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("Statement No. 121"). Statement No. 121 requires that long-lived assets and certain intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. If impairment has occurred, an impairment loss must be recognized. Statement No. 121 was implemented in 1995 by WECo and is discussed in Notes 15 and 17. Adoption of this standard did not have a material impact on Puget Power. In October 1995, the FASB issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("Statement No. 123"). Statement No. 123 establishes a fair value based method of accounting for stock-based compensation plans and encourages entities to adopt that method in place of the provisions of Accounting Principles Board Opinion No. 25 ("APB 25"). The Company intends to continue to apply the provisions of APB 25 in recognizing compensation expense related to its stock-based compensation plans. The difference in expense between Statement No. 123 and APB 25 is not material. In June 1996, the FASB issued Statement of Financial Accounting Standards No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities" ("Statement No. 125"). Statement No. 125 provides consistent standards for distinguishing sales of financial assets from transactions that are secured borrowings. A company is required to recognize such transactions as sales when control has been surrendered and the transferred assets are presumptively isolated beyond the reach of the transferor and its creditors. Statement No. 125 will be effective for transactions occuring after December 31, 1996. When effective Statement No. 125 will impact the Company's accounting for sales of merchandise and gas accounts receivable. Under Statement No. 125, all such receivable sales under the Company's current sales agreement occuring after December 31, 1996 would be accounted for as secured borrowings. Earnings Per Common Share: Earnings per common share have been computed based on the weighted average number of common shares outstanding. 52 2. Property Plant and Equipment - --------------------------------------------------------------------------- December 31 (Dollars in Thousands) 1996 1995 - --------------------------------------------------------------------------- Electric and gas utility plant classified by prescribed accounts at original cost: Distribution plant $2,545,155 $2,418,366 Production plant 930,806 909,085 Transmission plant 580,475 549,149 General plant 338,330 330,988 Construction work in progress 83,633 112,404 Completed work not classified 52,248 55,878 Intangible plant 50,880 38,952 Underground storage 12,713 10,414 Plant held for future use 10,802 15,644 Gas stored underground - non current 2,893 2,894 Acquisition adjustments 1,566 1,566 - --------------------------------------------------------------------------- Total electric and gas utility plant $4,609,501 $4,445,340 =========================================================================== 53 3. Capital Stock Preferred Stock ------------------------------------- Not Subject to Subject to Mandatory Mandatory Common Redemption Redemption Stock - ------------------- ------------------ ---------------- ---------- Without $25 $100 $25 $100 Par Value Par Par Par Par ($10 Stated Value Value Value Value Value) - ------------------- --------- ------- ------- ------- ---------- Shares outstanding January 1, 1994 3,000,000 475,480 480,000 961,763 83,677,199 Sold to Public: 1994 5,600,000 -- -- -- -- Issued to share- holders under the stock purchase and dividend reinvestment plan: 1994 -- -- -- -- 324,381 1995 -- -- -- -- 279,362 1996 -- -- -- -- 148,417 Issued pursuant to employee compensation plans: 1994 -- -- -- -- 32,890 1995 -- -- -- -- 26,585 1996 -- -- -- -- 21,886 Issued pursuant to Directors' Stock Bonus Plan: 1994 -- -- -- -- 163 1995 -- -- -- -- 175 1996 -- -- -- -- 187 Acquired for sinking fund: 1994 -- -- -- (19,339) -- 1995 -- -- -- (22,029) -- 1996 -- -- -- (12,000) -- Called for redemption and canceled: 1994 -- (475,480) (480,000) (30,000) -- - ------------------------------------------------------------------------ Shares outstanding December 31, 1996 8,600,000 -- -- 878,395 84,511,245 ======================================================================== See "Consolidated Statements of Capitalization" for details on specific series. 54 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 Bank of New York, as Rights Agent. The Rights expire on January 25, 2001, unless earlier redeemed by the Company. On October 18, 1995, the Company's Board of Directors approved an amendment to the Rights Agreement which precludes the merger with WECo from triggering any rights under the Rights Agreement. 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 B was 5.49% for 1996, 6.05% for 1995 and 5.93% for 1994. The weighted average dividend rate for the ARPS Series A was 7.00% in the first two months of 1994. 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. 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. On September 15, 1994, the Company sold 1,200,000 shares of 8.50% cumulative preferred stock, $25 par value. The preferred stock is redeemable on or after September 1, 1999, at par value. In 1994, the Company sold 2,400,000 shares of 7.45% cumulative preferred stock, $25 par value. The preferred stock is redeemable on or after November 1, 2003, at par value. In 1994, the Company redeemed early five series of preferred stock. A total of 585,480 shares, including 510,000 shares subject to mandatory redemption, with an aggregate par value of $22,548,000 was redeemed at an average premium of 2.4%. At September 30, 1996, WECo had outstanding incentive stock options for approximately 415,000 shares at grant prices ranging from $13.38 to $21.38. All options granted include a stock appreciation right issued in tandem with the option grant. 55 4. 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 of preferred stock 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, 1996, there were 9,044 shares of the 4.84% Series, 6,785 shares of the 4.70% Series and 776 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 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 $105.17 per share plus accrued dividends through February 15, 1997 and at per share amounts which decline annually to a price of $100 after February 15, 2007. 5. Additional Paid-in Capital (Dollars in Thousands) 1996 1995 1994 - ---------------------------------------------------------------------------- Balance at beginning of year $444,928 $442,954 $443,918 Excess of proceeds over stated values of common stock issued 2,022 1,934 3,006 Par value over (under) cost of reacquired preferred stock -- 210 (424) Issue costs of common and preferred stock (40) (170) (3,546) - --------------------------------------------------------------------------- Balance at end of year $446,910 $444,928 $442,954 =========================================================================== 6. Earnings Reinvested in the Business Earnings reinvested in the business unrestricted as to payment of cash dividends on common stock approximated $254 million at December 31, 1996, 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 mortgage indenture and WNG's mortgage indenture. The adjustments made to the carrying value of costs associated with the terminated generating projects and Bonneville Exchange Power as a result of Statement No. 90, adjustments made as a result of Statement No. 121 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.) 56 7. Long-Term Debt First Mortgage Bonds at December 31: Series Due 1996 1995 - ---------------------------------------------- (Dollars in Thousands) 5.25% 1996 $ -- $ 20,000 4.85% 1996 -- 15,000 7.875% 1997 100,000 100,000 8.125% 1997 3,060 3,200 10.25% 1997 -- 30,000 6.17% 1998 10,000 10,000 5.70% 1998 5,000 5,000 8.25% 1998 11,000 11,000 8.83% 1998 25,000 25,000 6.50% 1999 16,500 16,500 6.65% 1999 10,000 10,000 6.41% 1999 20,500 20,500 7.08% 1999 10,000 10,000 7.25% 1999 50,000 50,000 6.61% 2000 10,000 10,000 9.60% 2000 25,000 25,000 8.51 - 8.55% 2001 19,000 19,000 9.14% 2001 30,000 30,000 7.53 - 7.91% 2002 30,000 30,000 7.85% 2002 30,000 30,000 7.07% 2002 27,000 27,000 7.15% 2002 5,000 5,000 7.625% 2002 25,000 25,000 6.23 - 6.31% 2003 28,000 28,000 7.02% 2003 30,000 30,000 6.20% 2003 3,000 3,000 6.40% 2003 11,000 11,000 6.07 & 6.10% 2004 18,500 18,500 7.70% 2004 50,000 50,000 7.80% 2004 30,000 30,000 6.92 & 6.93% 2005 31,000 31,000 6.58% 2006 10,000 -- 8.06% 2006 46,000 46,000 8.14% 2006 25,000 25,000 7.02 & 7.04% 2007 25,000 25,000 7.75% 2007 100,000 100,000 8.40% 2007 10,000 10,000 6.51 & 6.53% 2008 4,500 4,500 6.61 & 6.62% 2009 8,000 -- 57 7. Long-Term Debt, continued First Mortgage Bonds at December 31: Series Due 1996 1995 - ---------------------------------------------- (Dollars in Thousands) 7.12% 2010 7,000 7,000 8.59% 2012 5,000 5,000 8.20% 2012 30,000 30,000 6.83 & 6.90% 2013 13,000 13,000 7.35 & 7.36% 2015 12,000 12,000 9.57% 2020 25,000 25,000 8.25 - 8.40% 2022 35,000 35,000 7.19% 2023 13,000 13,000 7.35% 2024 55,000 55,000 7.15 & 7.20% 2025 17,000 -- - ---------------------------------------------- Total First Mortgage Bonds $1,104,060 $1,134,200 ============================================== Guaranteed Collateralized Bonds at December 31: Series Due 1996 1995 - ---------------------------------------------- (Dollars in Thousands) - ---------------------------------------------- 8.45% 1996 $ -- $ 8,000 - ---------------------------------------------- Total Guaranteed Collateralized Bonds $ -- $ 8,000 ============================================== The Company unconditionally guaranteed all payments of principal, premium and interest on each series of the Guaranteed Collateralized Bonds issued in 1986 by its wholly-owned subsidiary. Substantially all utility properties owned by the Company are subject to the lien of the Company's mortgage indenture and the WNG mortgage indenture. Pollution Control Bonds: The Company has outstanding three series of Pollution Control Bonds. Amounts outstanding were borrowed from the City of Forsyth, Montana ("the City"). The City obtained the funds from the sale of Customized Pollution Control Refunding Bonds issued to finance pollution control facilities at Colstrip Units 3 and 4. Each series of bonds are 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. Interest rates for the 1992 and 1993 series are 6.80% and 5.875%, respectively. The 1991 series consists of $27.5 million principal amount bearing interest at 7.05% and $23.4 million principal amount bearing interest at 7.25%. 58 Long-Term Debt Maturities: The principal amounts of long-term debt maturities for the next five years are as follows: (Dollars in Thousands) 1997 1998 1999 2000 2001 - ----------------------------------------------------------------------- Maturities of long-term debt $103,060 $ 51,000 $107,000 $ 35,000 $ 49,000 ======================================================================== The $30,000,000 of 10.25% bonds due in 1997 were called early and redeemed with a premium of 1.14% in December 1995. 8. Short-Term Debt and Other Financing Arrangements At December 31, 1996, the Company had short-term borrowing arrangements which included a $250 million line of credit with nine banks, $100 million line of credit with four banks, a $75 million line of credit with five banks and a $1.5 million line with another two banks. In February 1997, the Company replaced these credit lines with a new $400 million line of credit with 15 banks. The agreement provides the Company with the ability to borrow at different interest rate options. For the new $400 million line 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 Eurodollar rate plus .30 percent. The new agreement requires an availability fee of .09 percent per annum on the unused loan commitment. 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, 1996 the Company had an agreement with Cooperative Receivables Corporation ("CRC") whereby it could sell to CRC up to $90 million principal amount of undivided interests in merchandise and gas accounts receivable at face value. At December 31, 1996, $13 million of outstanding merchandise and gas receivables had been sold under the agreement, and $9.7 million of eligible receivables had not been sold under the arrangement. This agreement was terminated effective with the merger. At December 31: (Dollars in Thousands) 1996 1995 1994 - --------------------------------------------------------------------------- Short-term borrowings outstanding: Bank notes $ 31,700 $ 44,000 $130,801 Commercial paper notes $266,422 $285,043 $228,835 Weighted average interest rate 6.05% 6.54% 6.26% Unused lines of credit (a) $426,500 $426,500 $326,500 - --------------------------------------------------------------------------- (a) Provides liquidity support for outstanding commercial paper in the amount of $266.4 million, $285.0 million and $228.7 million for 1996, 1995 and 1994, respectively, effectively reducing the available borrowing capacity under these credit lines to $160.1 million, $141.5 million, and $97.8 million, respectively. The Company has, on occasion, entered into interest rate swap agreements to reduce the impact of changes in interest rates on portions of its floating- rate, short-term debt. The one agreement outstanding at December 31, 1996 effectively changes the Company's interest rate on outstanding commercial 59 paper to 9.64% on a notional principal amount of $16.5 million expiring March 31, 2000. 9. Estimated Fair Value of Financial Instruments The following table presents the carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1996 and 1995: 1996 1996 1995 1995 Carrying Fair Carrying Fair (Dollars in Millions) Amount Value Amount Value - -------------------------------------------------------------------------- Financial Assets: Cash $ 4.3 $ 4.3 $ 21.8 $ 21.8 Financial Liabilities: Short-term debt $ 298.1 $ 298.1 $ 329.0 $ 329.0 Preferred stock subject to mandatory redemption $ 87.8 $ 88.5 $ 89.0 $ 91.2 Long-term debt $1,265.6 $1,303.4 $1,303.6 $1,366.4 Unrecognized financial instruments: Interest rate swaps $ -.- $ (1.7) $ -.- $ (2.6) - -------------------------------------------------------------------------- The fair value of outstanding bonds including current maturities is estimated based on quoted market prices. The preferred stock subject to mandatory redemption is estimated based on dealer quotes. The carrying value of short-term debt is considered to be a reasonable estimate of fair value. The carrying amount of cash, which includes temporary investments with maturities of 3 months or less, is also considered to be a reasonable estimate of fair value. The fair value of interest rate swaps (used for hedging purposes) is the estimated amount that the Company would receive or pay to terminate each swap agreement at the reporting date, taking into account current interest rates and the current credit-worthiness of all the parties to each swap. 60 10. Supplementary Income Statement Information (Dollars in Thousands) 1996 1995 1994 - ------------------------------------------------------------------------- Taxes: Real estate and personal property $ 43,762 $ 41,627 $ 40,585 State business 60,787 60,695 58,837 Municipal, occupational and other 43,681 41,663 39,073 Payroll 8,650 8,638 10,607 Other 4,079 3,530 4,208 - ------------------------------------------------------------------------- Total taxes $160,959 $156,153 $153,310 - ------------------------------------------------------------------------- Charged to: Operating expense $155,969 $150,507 $145,907 Other accounts, including construction work in progress 4,990 5,646 7,403 - ------------------------------------------------------------------------- Total taxes $160,959 $156,153 $153,310 ========================================================================= 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. 11. Leases The Company treats all leases as operating leases for ratemaking purposes as required by the Washington Commission. Certain leases contain purchase options, renewal and escalation provisions. Capitalized leases are not material. Rental and operating lease expense for the years ended December 31, 1996, 1995 and 1994 were approximately $19,394,000, $19,217,000 and $17,924,000, respectively. Payments due for the years ended December 31, 1996, 1995 and 1994 for the sublease of properties were approximately $1,674,000, $604,000 and $529,000, respectively. Future minimum lease payments for noncancelable leases are approximately $12,801,000 for 1997, $12,085,000 for 1998, $10,631,000 for 1999, $9,669,000 for 2000, $9,290,000 for 2001, and in the aggregate, $36,387,000 thereafter. Future minimum sublease receipts for noncancelable subleases are $918,000 for 1997, $845,000 for 1998, $820,000 for 1999, $766,000 for 2000, $500,000 for 2001, and in the aggregate, $791,000 thereafter. 61 12. Federal Income Taxes The details of federal income taxes ("FIT") are as follows: (Dollars in Thousands) 1996 1995 1994 - -------------------------------------------------------------------------- Charged to Operating Expense: Current $111,989 $ 73,562 $ 57,898 Deferred - net (3,058) 19,152 18,114 Deferred investment tax credits (1,184) (1,195) (1,196) - -------------------------------------------------------------------------- Total FIT charged to operations $107,747 $ 91,519 $ 74,816 ========================================================================== Charged to Miscellaneous Income: Current $ (784) $ (1,851) $ (2,505) Deferred - net -- (10,116) 25,192 - -------------------------------------------------------------------------- Total FIT charged to miscellaneous income $ (784) $(11,967) $ 22,687 ========================================================================== Credited to discontinued operations $ (986) $(14,320) $ (500) ========================================================================== Total FIT $105,977 $ 65,232 $ 97,003 ========================================================================== 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: (Dollars in Thousands) 1996 1995 1994 - --------------------------------------------------------------------------- FIT at the statutory rate $95,024 $58,455 $61,385 - --------------------------------------------------------------------------- Increase (Decrease): Depreciation expense deducted in the financial statements in excess of tax depreciation, net of depreciation of depreciation treated as a temporary difference 6,603 5,856 5,707 AFUDC included in income in the financial statements but excluded from taxable income (2,191) (2,319) (2,525) Accelerated benefit on early retirement of depreciable assets (1,105) (840) (847) Tax credit on gas produced from tight sands formation -- -- 1,413 Investment tax credit amortization (1,184) (1,195) (1,196) Energy conservation expenditures - net 3,380 806 5,607 Cabot merger and related reserves -- -- 25,254 Other - net 5,450 4,469 2,205 - --------------------------------------------------------------------------- Total FIT $105,977 $65,232 $97,003 =========================================================================== Effective tax rate 39.0% 39.1% 55.3% =========================================================================== 62 The following are the principal components of FIT as reported: (Dollars in Thousands) 1996 1995 1994 - --------------------------------------------------------------------------- Current FIT $111,205 $71,711 $55,393 =========================================================================== Deferred FIT - other: Conservation tax settlement (759) (7) 341 Periodic rate adjustment mechanism (PRAM) (26,014) 1,384 9,287 Cabot merger -- -- 24,484 Cabot valuation -- (8,681) -- Deferred taxes related to insurance reserves (938) (938) (938) Terminated generating projects -- -- (3,345) Reversal of Statement No. 90 present value adjustments 552 688 926 Residential Purchase and Sale Agreement - net (2,178) (4,010) (624) Normalized tax benefits of the accelerated cost recovery system 23,407 25,029 22,214 Energy conservation program (1,208) 1,412 (1,768) Environmental remediation 1,148 -- (2,445) Other 2,932 (5,841) (4,826) - ---------------------------------------------------------------------------- Total deferred FIT - other $ (3,058) $ 9,036 $43,306 ============================================================================ Deferred investment tax credits - net of amortization (1,184) (1,195) (1,196) Credited to discontinued operations (986) (14,320) (500) - ---------------------------------------------------------------------------- Total FIT $105,977 $65,232 $97,003 ============================================================================ 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 for certain temporary differences between tax and financial statement purposes because they are not allowed for ratemaking purposes. The Company calculates its deferred tax assets and liabilities under 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. Because of prior, and expected future ratemaking treatment for temporary differences for which flow-through tax accounting has been utilized, a regulatory asset for income taxes recoverable through future rates related to those differences has also been established. At December 31, 1996, the balance of this asset is $242 million. The deferred tax liability at December 31, 1996 and 1995 is comprised of amounts related to the following types of temporary differences: 63 (Dollars in Thousands) 1996 1995 - -------------------------------------------------------------- Utility plant $542,399 $523,029 Investment in Cabot stock 13,650 14,826 PRAM 14,167 40,181 Energy conservation charges 27,242 34,051 Contributions in aid of construction (29,222) (28,698) Bonneville Exchange Power 11,622 14,217 Net operating loss carry-forwards (3,212) (18,625) Alternative minimum tax credits (15,187) (5,813) Other 25,202 20,517 - -------------------------------------------------------------- Total $586,661 $593,685 ============================================================== The totals of $587 million and $594 million for 1996 and 1995 consist of deferred tax liabilities of $663 million and $674 million net of deferred tax assets of $76 million and $80 million, respectively. 13. Retirement Benefits At December 31, 1996, the Company had separate defined benefit pension plans covering substantially all electric and gas employees Electric operations employees - ----------------------------- Pension benefits are 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. Net pension costs for 1996, 1995 and 1994, including $1,564,000 for 1996, $1,966,000 for 1995 and $2,752,000 for 1994 which were charged to construction and other asset accounts, were comprised of the following components: (Dollars in Thousands) 1996 1995 1994 - --------------------------------------------------------------------------- Service cost (benefits earned during the period) $ 6,792 $ 6,129 $ 7,244 Interest cost on projected benefit obligation 16,365 15,656 14,895 Actual return on plan assets (38,474) (53,810) 4,392 Net amortization and deferral 18,064 35,335 (21,539) - --------------------------------------------------------------------------- Net pension costs under FASB Statement No. 87 2,747 3,310 4,992 - --------------------------------------------------------------------------- Regulatory adjustment 1,263 1,263 1,263 - --------------------------------------------------------------------------- Net pension costs $ 4,010 $ 4,573 $ 6,255 =========================================================================== 64 Funded Status of Plan At December 31 (Dollars in Thousands) 1996 1995 - --------------------------------------------------------------------------- Actuarial present value of benefit obligations: Vested $(182,805) $(181,367) Non-vested (3,274) (1,387) - ---------------------------------------------------------------------------- Accumulated benefit obligation (186,079) (182,754) Effect of future compensation levels (46,411) (41,566) - ---------------------------------------------------------------------------- Total projected benefit obligation (232,490) (224,320) Plan assets at market value 282,886 254,844 - ---------------------------------------------------------------------------- Plan assets in excess of projected benefit obligation 50,396 30,524 Unrecognized net gain due to variance between assumptions and experience (52,250) (34,584) Prior service cost 7,819 9,606 Transition asset as of January 1, 1986, being amortized on a straight-line basis over 18 years (2,934) (3,354) Regulatory adjustment, cumulative 3,664 4,927 - --------------------------------------------------------------------------- Prepaid pension cost recognized in long-term assets on balance sheet $ 6,695 $ 7,119 =========================================================================== 1996 1995 1994 ---------- --------- --------- Assumptions used in the calculations: Settlement discount rate 7 1/2% 7 1/2% 8 1/4% Long-term rate-of-return on assets 9% 9% 8 1/2% Compensation increase 5% 5% 5 1/2% In December 1995, in connection with the proposed merger with WECo, Puget Power offered to its employees a Voluntary Separation Plan. A total of 204 employees elected to participate in the Voluntary Separation Plan resulting in a curtailment gain for 1996 of $1.6 million under Statement of Financial Accounting Standards No. 88. Plan assets consist primarily of U.S. Government securities, corporate debt and equity securities. In addition to providing pension benefits, Puget Power provides certain health care and life insurance benefits for retired employees. These benefits are provided principally through an insurance company whose premiums are based on the benefits paid during the year. Effective January 1, 1993, Puget Power 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 Post-retirement benefits to be accrued over the period of employment. Puget Power is recognizing the impact of Statement No. 106 by amortizing its transition obligation of $24.9 million to expense over 20 years. The resulting 1996, 1995 and 1994 annual costs under Statement No. 106 were approximately $2.8 million, $3.6 million, and $3.8 million, 65 respectively. In addition, a curtailment loss under Statement No. 106 for 1996 of $1.4 million resulted from the 1995 Voluntary Separation Plan discussed above. In the rate order issued by the Washington Commission on September 21, 1993, the Washington Commission approved adoption of accrual accounting for Post- retirement 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 differs from the Company's cost by an insignificant amount. In 1996, 1995 and 1994, the expenses recognized for Post-retirement benefits were $3.8 million, $2.5 million and $2.4 million, respectively. Gas operations employees - ------------------------ Pension benefits are based on annual compensation and length of service. WECo's policy is to fund the plan annually at the level necessary to provide benefits attributable to service to date and for benefits expected to be earned in the future. As required by SFAS No. 87, WECo follows the projected unit credit method for determining pension expense for financial reporting purposes. Application of this accounting method on October 1, 1987, resulted in a transition gain (excess of plan assets over projected benefit obligations) of $14,584,000, which is being amortized over 18 years. The entry-age normal actuarial cost method continues to be used for funding purposes. The following tables set forth the plan's funded status and the pension liability recognized in the consolidated financial statements: (Dollars in Thousands) 1996 1995 - ---------------------------------------------------------------- Actuarial present value of accumulated benefit obligations: Vested $45,405 $39,319 Non-vested 524 599 - ---------------------------------------------------------------- Total $45,929 $39,918 ================================================================ Projected benefit obligations for service rendered to date $55,540 $49,819 Plan assets at fair value, primarily marketable stocks, bonds and short- term investments 71,748 64,248 - ---------------------------------------------------------------- Plan assets in excess of projected benefit obligations 16,208 14,429 Unrecognized amounts: Prior service cost 1,418 1,568 Net gains (12,488) (10,770) Net transition gain (7,293) (8,103) - ----------------------------------------------------------------- Net pension liability included in the balance sheet $(2,155) $(2,876) ================================================================= 66 (Dollars in Thousands) 1996 1995 1994 - --------------------------------------------------------------------------- Net pension cost includes: Service cost of benefits earned during the period $ 2,116 $ 2,163 $ 2,577 Interest cost on projected benefit obligations 3,791 $ 3,568 $ 3,238 Actual return on Plan assets (9,483) (8,704) (1,870) Amortization of net transition gain (810) (810) (810) Unrecognized prior service cost 149 149 165 Amortization of deferred gains (598) (275) (456) Current asset gain (loss) deferred 4,113 4,440 (2,376) - --------------------------------------------------------------------------- Net pension cost (income) $ (722) $ 531 $ 468 =========================================================================== Assumptions used in the calculations: Weighted-average discount rate 7 1/2% 7 1/2% 7 1/2% Long-term rate-of-return on assets 8 1/2% 7 1/2% 7 1/2% Compensation increase 5 1/2% 6% 6% The Company has supplemental retirement plans for officer and director level employees. Expenses for these plans for 1996, 1995 and 1994 were $1,848,000, $1,780,000, and $2,037,000, respectively. 14. Employee Investment Plan & Employee Stock Purchase Plan The Company has qualified employee Investment Plans for both electric and gas employees under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. The Company made a monthly contribution equal to 50% for gas employees and 55% for electric employees 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 $4,102,000, $4,158,000 and $4,485,000 for the years 1996, 1995 and 1994, respectively. The shareholders have authorized the issuance of up to 2,000,000 shares of common stock under the plan, of which 959,142 were issued through December 31, 1996. The employee Investment Plan eligibility requirements are set forth in the plan documents. WECo also had an employee stock purchase plan, under which options were granted to eligible employees who elect to participate in the plan on January 1st and July 1st of each year. Participants were allowed to exercise those options six months later to the extent of payroll deductions or cash payments accumulated during that six-month period. The option price under the plan was 90% of the fair market value of the common stock at the grant date or 100% of the fair market value at the exercise date, whichever is less; but in no event less than the par value of the common stock. 15. Unconsolidated Oil and Gas Affiliate On May 2, 1994, WECo merged its oil and gas exploration and production subsidiary, Washington Energy Resources Company ("Resources"), with a wholly- owned subsidiary of Cabot in a tax-free exchange. WECo received 2,133,000 shares of Cabot Class A common stock and 1,134,000 shares of 6% convertible voting preferred stock of Cabot, stated value $50, in exchange for all the 67 outstanding capital stock of Resources, in addition to the repayment of $63,661,000 of intercompany debt. The 1,134,000 shares of Cabot preferred stock are convertible into 1,972,174 shares of Cabot Class A common stock and are entitled to that number of votes on shareholder matters, making the Company the holder of 16.6% of Cabot's total voting securities. As part of the transaction, Cabot increased its board of directors from nine to eleven and appointed two directors nominated by WECo to fill the new positions. WECo recorded a net loss on the merger of $25,110,000, after providing for deferred taxes of approximately $29,600,000. In 1995, WECo resolved certain merger-related issues with Cabot, which resulted in an additional charge to earnings of $503,000 ($327,000 after tax). The following table details WECo's investment in Cabot as of September 30, 1996, 1995 and 1994, and earnings and dividends received from the investment during each year (dollars in thousands): 1996 1995 1994 - ------------------------------------------------------------------------ Investment in Cabot $69,014 $69,975 $97,801 Percentage of total Cabot common stock 9.4% 9.4% 9.4% Percentage of voting interest in Cabot 16.6% 16.6% 16.6% Pre-tax income Preferred dividends accrued $ 3,402 $ 3,402 $ 1,418 Equity in (loss) (619) (9,185) (573) Investment impairment write down -- (18,300) -- Dividends received Preferred 3,402 3,402 567 Common 341 341 171 - ------------------------------------------------------------------------ At September 30, 1996, the carrying value of WECo's investment in Cabot exceeded WECo's proportionate interest in the underlying equity of Cabot by $6,800,000. The Company is amortizing this remaining balance on a straight- line basis over 16 years. Based on the closing price on the NYSE on September 30, 1996, the aggregate fair value of WECo's investment in Cabot common stock was $31,462,000. No fair value is readily available for the Cabot preferred stock as it is not publicly traded; however, the fair value of WECo's shares of Cabot preferred was estimated to be approximately $48,000,000 at September 30, 1996. WECo's interest in Cabot's common stock is being accounted for using the equity method because WECo, through its representation on Cabot's board of directors, has the ability to exercise significant influence over operating and financial policies of Cabot. The decrease in value of WECo's investment in Cabot from 1994 to 1995 was primarily a result of WECo charges totaling $24,803,000 ($16,122,000 after tax) in 1995 related to the adoption of SFAS No. 121 by Cabot and to recognize a permanent impairment in the carrying value of WECo's investment in Cabot. Cabot elected early adoption of SFAS No. 121 and recognized $113,900,000 of pre-tax impairment losses related to oil and gas producing properties in its fiscal quarter ended September 30, 1995. Under the equity method of accounting, WECo recognized its 9.4% share of the impairment write down, which totaled $6,503,000 after Cabot's income tax provision ($4,227,000 after WECo's income tax provision). In addition, WECo wrote down its investment in Cabot by an additional $18,300,000 ($11,895,000 after- tax) to a value which approximated the fair market value of the Cabot securities held by WECo. Both charges resulted primarily from the decline in natural gas prices during 1995 and lower projections of future natural gas prices. 68 See Note 16 regarding certain gas transportation, storage and other contractual arrangements of Resources that were excluded from the Cabot merger and retained by a subsidiary of WECo. 16. Commitments and Contingencies Commitments: Electric For the twelve months ended December 31, 1996, approximately 32% of the Company's energy output was obtained at an average cost of approximately 8.7 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 share of the annual cost of each project in direct proportion to the amount of power annually purchased by the Company from such project. 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 PUDs and others over the lives of the contracts. As of December 31, 1996, 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) Contract License Outstanding --------------------------- Exp. Exp. 12/31/96(a) % of Kilowatt Costs(b) Project Date Date (Millions) Output Capacity (Millions) - --------------------------------------------------------------------------- Rock Island Original units 2012 2029 $ 84.5 57.1 ) ) 423,000 $ 45.4 Additional units 2012 2029 320.9 100.0 ) Rocky Reach 2011 2006(c) 200.0 38.9 482,750 19.3 Wells 2018 2012(c) 183.9 32.3 271,320 9.9 Priest Rapids 2005 2005(c) 186.8 8.0 72,320 2.2 Wanapum 2009 2005(c) 209.1 10.8 106,380 2.8 - --------------------------------------------------------------------------- Total 1,355,770 $79.6 =========================================================================== (a) The contracts for purchases initially were generally coextensive with the term of the PUD bonds associated with the project. Under the terms of some financings and refinancings, 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: 70.7% at Rock Island; 31.8% at Rocky Reach; 71.3% at Priest Rapids; and 46.3% at Wanapum. 69 (b) The components of 1997 costs associated with the interest portion of debt service are: Rock Island, $24.2 million for all units; Rocky Reach, $5.3 million; Wells, $2.9 million; Priest Rapids, $0.9 million; and Wanapum, $1.2 million. (c) The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. In the past twelve months, the FERC has issued orders for Rocky Reach, Wells and Priest Rapids/Wanapum projects under Section 22 of the Federal Power Act, which affirm the Company's contractual rights to receive power under existing terms and conditions even if a new licensee is granted a license prior to expiration of the contract term. - ----------------------------- The Company's estimated payments for power purchases from the Columbia River projects are $80 million for 1997, $79 million for 1998, $81 million for 1999, $83 million for 2000, $84 million for 2001 and in the aggregate $1.05 billion thereafter through 2018. The Company also has numerous long-term firm purchased power contracts with other utilities and non-utility generators in the region. The Company is generally 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, excluding the Columbia River projects, are $422 million for 1997, $441 million for 1998, $464 million for 1999, $481 million for 2000, $509 million for 2001 and in the aggregate $5 billion thereafter through 2024. These contracts have varying terms and may include escalation and termination provisions. Total purchased power contracts provided the Company with approximately 17.1 million, 16.4 million and 16.0 million MWH of firm energy at a cost of approximately $485.6 million, $478.7 million and $450.7 million for the years 1996, 1995 and 1994, 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, 1996: Company's Share ------------------------------ Energy Company's Plant in Accumulated Source Ownership Service at cost Depreciation Project (Fuel) Share (%) (Millions) (Millions) - -------------- ------ --------- -------------- ------------ Centralia Coal 7 $ 27.4 $ 17.3 Colstrip 1 & 2 Coal 50 184.7 96.4 Colstrip 3 & 4 Coal 25 450.3 154.6 - ------------------------------------------------------------------------ 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. 70 Gas Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned subsidiary, holds firm rights to transport natural gas on the Nova Corporation of Alberta ("Nova"), Alberta Natural Gas Company ("ANG") and Pacific Gas Transmission Company ("PGT") pipelines from Alberta, Canada, to the northern border of California, as well as certain gas storage rights at the Alberta Energy Company ("AECO") field in Alberta and the Jackson Prairie field in western Washington. These rights were formerly held by a wholly-owned subsidiary of Resources but were excluded from the merger of Resources and Cabot completed in May 1994. Following the merger, WEGM entered into a five- year contract with IGI Resources ("IGI"), Boise, Idaho, to manage these rights. The transportation rights on the PGT pipeline initially consisted of approximately 25,000 MMBtu per day of annual capacity and 20,000 MMBtu per day of winter-only capacity to Stanfield, Oregon, and approximately 20,000 MMBtu per day of annual capacity to the California border. WEGM held similar rights on Nova and ANG. Effective November 1, 1995, WEGM permanently assigned to IGI all of its Stanfield capacity and associated rights on Nova and ANG. In addition, WEGM segmented its capacity to California at Stanfield and permanently assigned 10,000 MMBtu per day of the Alberta to Stanfield rights to a third party effective November 1, 1995. WEGM's remaining PGT rights expire in October 2023, and the ANG and Nova rights expire in October 2008, with annual renewal options. As of September 30, 1996, WEGM has a reserve for future losses associated with these contractual obligations of $9,505,000. WEGM, as an expansion capacity holder, has been unable to fully recoup its demand charges, which have been approximately 70% higher than those paid by holders of vintage capacity. On September 11, 1996, the FERC approved a request from PGT for the cost of the expansion capacity to be "rolled in" with the cost of the vintage capacity to establish a uniform rate for holders of both types of capacity. Rates will be rolled in, in two stages over six years with the first stage effective November 1, 1996. WEGM's annual obligations for future demand charges through the primary term of WEGM's gas transportation and storage contracts are as follows: 1997, $2,833,000; 1998, $2,782,000; 1999, $2,782,000; 2000, $2,782,000; 2001, $2,782,000; and thereafter, $40,690,000. The IGI management contract provides for incentive payments to IGI based on actual mitigation of demand charges relative to targets established on an annual basis. WEGM initially established the reserve for estimated future losses associated with the transportation and storage obligations with a $16,000,000 ($10,400,000 after tax) charge to earnings upon completion of the merger of Resources and Cabot in May 1994. In the fourth quarter of 1995, WEGM recorded a $5,000,000 ($3,250,000 after tax) charge to increase the reserve based on an assessment of the likelihood and timing of approval of rolled-in rates and actual mitigation results in 1995. During 1996, 1995 and 1994, pre-tax losses totaling $2,652,000, $5,841,000 and $3,001,000, respectively, were charged against the reserve. The Company has also entered into various firm supply, transportation and storage service contracts in order to assure adequate availability of gas supply for its firm customers. Many of these contracts, which have remaining terms of from one to 27 years, provide that the Company must pay a fixed demand charge each month, regardless of actual usage. Certain of the Company's firm gas supply agreements also obligate the Company to purchase a minimum annual quantity at market-based contract prices. Generally, if the minimum volumes are not purchased and taken during the year, the Company is obligated to pay either: 1) a monthly or annual gas inventory charge calculated as a percentage of the then-current contract commodity price times the minimum quantity not taken; or 2) pay for gas not taken. 71 Alternatively, under some of the contracts, the supplier may exercise a right to reduce its subsequent obligation to provide firm gas to the Company. The Company incurred demand charges in 1996 for firm gas supply, firm transportation service, and for firm storage and peaking service of $31,900,000, $53,221,000 and $9,738,000 respectively. The following tables summarize the Company's obligations for future demand charges through the primary terms of its existing contracts and the minimum annual take requirements under the gas supply agreements. The quantified obligations are based on current contract prices and FERC authorized rates, which are subject to change. Amounts are for the twelve months ended September 30. Demand Charge Obligations (in thousands): 2002 & There- 1997 1998 1999 2000 2001 after Total ---------------------------------------------------------- Firm gas supply $30,952 $30,821 $29,833 $26,875 $26,875 $ 65,375 $210,731 Firm transpor- tation service 55,933 55,933 55,933 55,933 55,933 240,796 520,461 Firm storage and peaking service 11,943 11,943 11,943 11,943 11,943 172,027 231,742 ---------------------------------------------------------- Total $98,828 $98,697 $97,709 $94,751 $94,751 $478,198 $962,934 ========================================================== Minimum Annual Take Obligations (in thousands of therms): 2002 & There- 1997 1998 1999 2000 2001 after Total --------------------------------------------------------------- Firm gas supply 373,192 354,942 249,092 230,844 230,844 604,020 2,042,934 ================================================================ The Company believes that all demand charges will be recoverable in rates charged to its customers. Further, pursuant to implementation of FERC Order No. 636, the Company has the right to resell or release to others any of its unutilized gas supply or transportation and storage capacity. The Company does not anticipate any difficulty in achieving the minimum annual take obligations shown, as such volumes represent less than 53% of expected annual sales for 1997 and less than 48% of expected sales in subsequent years. 72 The Company's current firm gas supply contracts obligate the suppliers to provide, in the aggregate, annual volumes up to those shown below: Maximum Supply Available Under Current Firm Supply Contracts (in thousands of therms): 2002 & There- 1997 1998 1999 2000 2001 after Total ------- ------- ------- ------- ------- --------- --------- Total 713,575 695,325 567,575 503,700 503,700 1,255,600 4,239,475 ======= ======= ======= ======= ======= ========= ========= 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 ("EPA") at several contaminated disposal sites and manufactured gas plant sites. The Company has also instituted an ongoing program to test, replace and remediate certain underground storage tanks as required by federal and state laws. Remediation and testing of Company vehicle service facilities and storage yards is also continuing. During 1992, the Washington Commission issued orders regarding the treatment of costs incurred by the Company for certain sites under its environmental remediation program. The orders authorize 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. The information presented here as it relates to estimates of future liability is as of December 31, 1996 for electric sites and September 30, 1996 for gas sites. Electric Sites The Company has expended approximately $14.3 million related to the remediation activities covered by the Washington Commission's order, of which approximately $5.7 million has been recovered from insurance carriers. At December 31, 1996, approximately $2.1 million has been accrued as a liability for future remediation costs for these and other remediation activities. At December 31, 1996, an asset of approximately $10.0 million has been recorded related to expected future recoveries. Gas Sites Five former WNG or predecessor companies manufactured gas plant ("MGP") sites are currently undergoing investigation, remedial actions or monitoring actions relating to environmental contamination: 1) Everett, Washington; 2) "Gas Works Park" in Seattle, Washington; 3) "Tacoma 22nd and A St." Site in Tacoma, Washington; 4) Chehalis, Washington; and 5) the "Tideflats" area of Tacoma, Washington. 73 (a) Everett The Company is conducting an independent remedial action at the Everett site. Current analysis indicates that the reserve for investigation and remediation costs of $3,250,000, previously established, is currently sufficient to cover the expected costs at the site. Investigation and feasibility costs of $463,000 have been incurred through September 30, 1996. The Everett site was previously owned and operated by other companies who are potentially liable parties ("PLPs") for the remediation of the site. The cost estimate reflects the total cost expected to remediate the site before contributions by other PLPS. (b) Gas Works Park The Company sold the site of a former manufactured gas plant at Lake Union, now known as "Gas Works Park," to the City of Seattle in 1962. The City of Seattle, in a letter dated February 24, 1995, requested that the Company participate in a cleanup of this site. The Company believes that the contract, by which it conveyed the land to the City of Seattle, presents substantial defenses that mitigate its exposure for environmental remediation costs which may be incurred at this site. On July 15, 1996, the City of Seattle completed a preliminary study that estimated that the remediation costs were in the range of $4.9 million to $8.6 million. The Company anticipates that in order to resolve this matter with the City of Seattle, the potential cost may approximate $3,000,000 which has been accrued. (c) Tacoma 22nd and A St. Site and Thea Foss Waterway The Company was the former owner of land, located upland from the Thea Foss Waterway in Tacoma, Washington where a MGP was operated by several other companies. This site ("22nd and A St.") was acquired after the plant was closed. The site was later sold in parcels to several buyers. Five parties, including the Company, have been designated as PLPs at this site. In May 1996, a consultant to the PLPs estimated the cost of remediating the Tacoma 22nd and A St. site to be approximately $4,000,000, exclusive of any remediation costs which may arise in connection with the adjacent Thea Foss Waterway. Because there are multiple PLPs, the Company believes, based on currently available information, that its maximum exposure is approximately $700,000, which has been recorded as a liability. The City of Tacoma has undertaken an investigation study of contamination in the Thea Foss Waterway. The extent of the contamination related to possible MGP operation is not currently known, but the Company has been designated a Potentially Responsible Party ("PRP") by the U.S. Environmental Protection Agency ("EPA"). (d) Chehalis The Company has completed significant source control and installed groundwater monitoring wells as part of an independent cleanup action. In 1997, the Company expects to complete groundwater monitoring at the site, at which time a determination will be made as to what, if any, additional remedial measures are required. As of September 30, 1996, the financial statements include a reserve of $283,000, which is sufficient to cover remaining costs at the site, assuming that further remedial measures are not required. 74 (e) Tideflats The remediation activities at the Tideflats site were completed as of July 1995, and confirmed by the EPA in a letter dated September 28, 1995. Ongoing monitoring and maintenance costs are being expensed as incurred and are not material. In June 1991, a lawsuit was filed in Washington State Superior Court, King County, Washington ("Superior Court"), against certain insurance companies that provided insurance applicable to the Tideflats site at various times dating back to the 1940's. On June 10, 1994, the Superior Court entered a final judgment in favor of the Company. Under the terms of the final judgment, the Company was entitled to collect its present and future uncompensated reasonable and necessary costs in remediating the site from the policies of certain insurer defendants in the action. During 1995, the Company settled its lawsuit with the insurance carriers in consideration of their dismissal of the appeal of the Superior Court judgment regarding coverage of the Tideflats remediation costs. In September 1995, the Company received approximately $29,000,000 in final settlement of all remaining claims against insurance carriers regarding this site. As a result of this settlement and amounts previously received, WECo has recovered substantially all the remediation costs which had been deferred. (f) Expected Recoveries The Company's financial statements as of year-end 1996, include environmental receivables related to these MGP sites totaling $10,164,000 primarily for expected recoveries from insurance carriers, based upon the successful litigation against its insurers regarding the Tideflats site, and other PLPs. Although the factual situations at the other sites differ in some respects from the factual situation at the Tideflats site, the Company believes, based on the precedents established in the Tideflats case and discussion with legal counsel, that it is probable that it has insurance coverage sufficient to recover costs not recovered from other PLPs. In the event that recoveries from insurance and other PLPs are not sufficient, the Company, under an agreement with the Washington Commission, will seek recovery of such unreimbursed costs in future customer rates. Based on all known facts and analyses, the Company believes it is not likely that the identified environmental liabilities will result in a material adverse impact on the Company's financial position, operating results or cash flow trends. Litigation (a) Alleged Securities Violations A class-action lawsuit was filed against WECo and two of its officers, (collectively, "the Defendants"), in U.S. District Court, Western District of Washington ("District Court"), in February 1994, alleging violations of state and federal securities act provisions and associated violations of Washington state law. The essence of the complaint concerned alleged disclosure violations regarding the nature or the extent of the financial risk associated with the 1992 utility rate request filing of WNG. In May 1994, the Defendants filed a motion to dismiss the lawsuit. On July 25, 1994, the District Court issued an Order Granting Defendants' Motion To Dismiss and entered a judgment dismissing the action. The plaintiffs appealed to the Ninth Circuit Court of Appeals ("Court of Appeals"). On May 15, 1996, the Court of Appeals upheld WNG's motion to dismiss. The plaintiffs did not pursue a timely appeal to the U.S. Supreme Court, thus concluding this matter. 75 (b) Alleged Anti-Trust Violations On September 6, 1994, Cost Management Services, Inc. ("Cost Management"), a Mercer Island, Washington, company involved in the purchase and resale of natural gas, filed an action against WNG in District Court. Cost Management alleged that WNG monopolized or attempted to monopolize the market for the sale of natural gas in central western Washington. Cost Management also alleged WNG failed to charge its customers in accordance with the prices, terms and conditions set forth in tariffs filed by WNG with the WUTC and that it wrongfully interfered with Cost Management's relationships with its customers. Cost Management sought injunctive relief and damages in an unspecified amount. WNG filed a motion to dismiss the lawsuit, which was granted on May 5, 1995. In dismissing Cost Management's action the court ruled that the state action doctrine provides antitrust immunity for conduct pursuant to a clearly articulated and actively supervised state policy, where unfettered competition is replaced with regulation. In dismissing the federal antitrust claims, the court declined to retain jurisdiction over Cost Management's state law claims, which were dismissed without prejudice. Cost Management then filed its state claims in Superior Court. That case was stayed by agreement of the parties, pending resolution of the federal court action. Cost Management filed an appeal of the federal court dismissal in the Court of Appeals. The parties on November 22, 1995 filed briefs with the Court of Appeals and arguments were presented on August 8, 1996. The Court of Appeals issued a decision which reversed the District Court's dismissal of the case and remanded the case to the District Court for rehearing. The Court of Appeals ruled if Cost Management's claims were assumed to be true for purposes of the Appellate Review, the lower court's dismissal was improper. No ruling was made on the merits of any of Cost Management's claims. Neither the outcome or the financial exposure from this lawsuit can be predicted at this time. Other contingencies, arising out of the normal course of the Company's business, exist at December 31, 1996. The ultimate resolution of these issues is not expected to have a material adverse impact on the financial condition, results of operations or liquidity of the Company. 17. Discontinued Operations In September 1996, WECo decided to seek a buyer for its undeveloped coal properties and to cease development efforts on the associated railroad. Accordingly, the consolidated financial statements of the Company reflect these activities as discontinued operations. The 1996 loss from discontinued operations does not include any asset write downs, but does include estimated losses of $446,000, net of $240,000 of income taxes, until disposal is completed. In 1995, WECo wrote down the carrying value of its coal properties by $34,700,000 ($22,555,000 after tax) with the adoption of SFAS No. 121. 76 Summarized operating results for the coal and railroad activities are as follows: Years Ended December 31, 1996 1995 1994 - ------------------------------------------------------------------------ (Dollars in thousands) Net Sales $ -- $ -- $ -- - --------------------- Loss from operations before income taxes 2,133 40,919 200 Income tax benefit (747) (14,322) (70) Loss from operations, net of income tax $ 1,386 $26,597 $ 130 ======================================================================== In August 1993, WECo decided to sell Unisyn, its biowaste technology business, and reported Unisyn as a discontinued operation in that year. In August 1994, WECo sold the stock of its wholly-owned subsidiaries, Thermal Efficiency, Inc., and Holdings Northwest, Inc., which jointly owned Unisyn. The 1994 results include a loss in excess of the estimated loss recorded in 1993 of $799,000, net of $430,000 of income taxes, realized upon disposition of the two subsidiaries. 18. 1995 and 1994 Restructuring and Other Charges In 1995, WECo recorded a $3,150,000 ($2,000,000 after-tax) charge for severance costs related to a 4% reduction in its work force. The work-force reduction, which affected only salaried employees, was part of ongoing organizational change efforts initiated in 1994. In addition, WECo recorded a charge of $1,250,000 for federal tax contingencies. In 1994, Puget Power and WECo recognized $39,200,000 ($25,500,000 after tax) of restructuring and other one-time charges. Charges totaling $28,000,000 ($18,200,000 after tax) related to restructuring and downsizing utility operations and included employee severance and facility consolidation costs. The 1994 charges also included provisions by WECo for estimated environmental investigation, legal and remediation costs associated with certain former manufactured gas plant sites and the write-off of certain deferred environmental-related costs. These charges totaled $2,231,000 ($1,450,000 after tax). WECo recorded an additional $3,351,000 ($2,178,000 after tax) charge related to supplemental executive retirement contracts. 19. Supplemental Quarterly Financial Data (Unaudited) The following unaudited amounts, in the opinion of the Company, include all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the results of operations for the interim periods. Quarterly amounts vary during the year due to the seasonal nature of the utility business. Amounts for the individual companies have been combined based on the respective quarters of their fiscal years. 77 (Unaudited) 1996 Quarter First Second Third Fourth - -------------------------------------------------------------------------- (Dollars in thousands except per share amounts) Operating revenues $459,372 $414,609 $350,018 $425,280 Operating income $ 87,614 $ 70,460 $ 51,135 $ 75,265 Other income $ 1,065 $ 795 $ 413 $ (680) Net income $ 58,309 $ 41,410 $ 21,960 $ 43,840 Earnings per common share $ 0.63 $ 0.43 $ 0.19 $ 0.45 - -------------------------------------------------------------------------- 1995 Quarter First Second Third Fourth - -------------------------------------------------------------------------- (Dollars in thousands except per share amounts) Operating revenues $496,519 $421,247 $328,953 $384,399 Operating income $ 95,404 $ 67,319 $ 44,486 $ 63,135 Other income $ 1,320 $ 1,038 $ 1,269 $(18,536) Net income $ 63,863 $ 35,846 $ 15,150 $(13,075) Earnings per common share $ 0.69 $ 0.36 $ 0.11 $ (0.22) - -------------------------------------------------------------------------- 20. 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: 1996 1995 1994 (Dollars in Thousands) - -------------------------------------------------------------------------- Changes in certain current assets and current liabilities: Accounts receivable $(22,242) $ 3,769 $ 3,151 Unbilled revenue (11,104) 6,382 2,521 Materials and supplies 16,737 (763) 14,664 Prepayments and other 1,491 (1,607) 486 Purchased gas liability 25,814 36,815 2,608 Accounts payable 15,997 (3,128) 27,793 Accrued expenses and other 1,116 (6,509) (13,059) - -------------------------------------------------------------------------- Net change in certain current assets and current liabilities $ 27,809 $ 34,959 $ 38,164 ========================================================================== Cash payments: Interest (net of capitalized interest) $113,634 $131,807 $119,427 Income taxes $ 98,609 $ 77,608 $ 68,657 - -------------------------------------------------------------------------- 78 21. Merger of Puget Power and WECo Included in consolidated results of operations for the years ended December 31, 1996, 1995 and 1994, are the following results of the previously separate companies for those periods: YEAR ENDED DECEMBER 31, 1996 (Dollars in Thousands) ------------------------------------------------- Puget WECo Consolidated ------------- ------------- ------------ Revenues $1,223,568 $425,711 $1,649,279 Net Income $ 135,371 $ 30,148 $ 165,519 Common Dividends Declared $ 117,099 $ 24,149 $ 141,248 YEAR ENDED DECEMBER 31, 1995 (Dollars in Thousands) ------------------------------------------------- Puget WECo Consolidated ------------- ------------- ------------ Revenues $1,187,507 $443,611 $1,631,118 Net Income $ 135,720 $(33,936) $ 101,784 Common Dividends Declared $ 117,099 $ 23,877 $ 140,976 YEAR ENDED DECEMBER 31, 1994 (Dollars in Thousands) -------------------------------------------------- Puget WECo Consolidated -------------- -------------- ------------ Revenues $1,200,460 $432,025 $1,632,485 Net Income $ 120,059 $(41,676) $ 78,383 Common Dividends Declared $ 117,084 $ 23,468 $ 140,552 In connection with the merger, through December 31, 1996, the Company has incurred direct merger related costs and indirect costs related to integration of the operations of the Company and WECo, (including costs related to a voluntary early separation plan accepted by 277 employees of the Company - under terms of the plan, certain employees were terminated in 1996 and termination of others was subject to completion of the merger). Indirect costs of $4.8 million were expensed in the fourth quarter of 1996. Additional costs of $14.0 million have been deferred and will be expensed in the first quarter of 1997, as of the merger consummation date. The Company estimates that additional direct and indirect merger costs of $56 million, including the $14 million deferred, would be charged to expense in 1997. These estimates are subject to revision as the integration process proceeds. 79 Puget Sound Energy Schedule II. 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, 1996 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $1,865 $5,920 $6,085 $1,700 ============================================================================= Year Ended December 31, 1995 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $1,905 $6,327 $6,367 $1,865 ============================================================================= Year Ended December 31, 1994 - ---------------------------- Accounts deducted from assets on balance sheet: Allowance for doubtful accounts receivable $ 800 $6,469 $5,364 $1,905 ============================================================================= 80 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. 2.1 Agreement and Plan of merger dated as of October 18, 1995, among the Registrant, Washington Energy Company and Washington Natural Gas Company. (Exhibit 2.1 to Registration No. 333-617) 3-a Restated Articles of Incorporation of the Company. (Included as Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996, Registration No. 333-617) 3-b Restated Bylaws of the Company. (Exhibit 3 to Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1997, Commission File No. 1-4393) 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 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) 4.3 Amendment No. 1 dated as of August 30, 1991, to the Rights Agreement dated as of January 15, 1991, between the Registrant and the Bank of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights Agent. (Exhibit 2.1 to Registration Statement on Form 8 filed on August 30, 1991) 4.4 Amendment No. 2 dated as of October 18, 1995, to the Rights Agreement dated as of January 15, 1991, between the Registrant and The bank of New York (as successor to The Chase Manhatten Bank, N.A.), as Rights Agent. (Exhibit 1 to Registration Statement on Form 8-A/A filed on October 27, 1995) 4.5 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) 4.6 Loan Agreement dated August 1, 1991, betweeen the City of Forsyth, Rosebud County, Montana and the Company. (Exhibit (4)-k to Registration No. 33-45916) 4.7 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) 4.8 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) 4.9 Statement of Relative Rights and Preferences fo 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) 4.10 Pledge Agreement, dated as of March 1, 1992, by and between the Company and Chemical Bank relating to a series of first mortgage bonds. (Exhibit 4.15 to Annual report on Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-4393) 4.11 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. (Exhibit 4.16 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-4393) 4.12 Form of Statement of Relative Rights and Preferences for the Series II Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996). 4.13 Form of Statement of Relative Rights and Preferences for the Series III Cumulative Preferred Stock, $25 Par Value (included as Annex F to the Joint Proxy Statement/Prospectus filed February 1, 1996). 4.14 Indenture of First Mortgage dated as of April 1, 1957 (incorporated herein by reference to Washington Natural Gas Company Exhibit 4-B, Registration No. 2-14307). 4.15 Sixth Supplemental Indenture dated as of August 1, 1996 (incorporated herein by reference to Washington Natural Gas Company Exhibit to Form 8-K for the month of August 1966, File No. 0-951). 4.16 Twelfth Supplemental Indenture dated as of November 1, 1972 (incorporated herein by reference to Washington Natural Gas Company Exhibit to Form 8-K for November 1972, File No. 0-951). 4.17 Seventeenth Supplemental Indenture dated as of August 9, 1978 (incorporated herein by reference to Washignton Energy Company Exhibit 5- K.18, Registration No. 2-64428). 4.18 Twenty-sixth Supplemental Indenture dated as of September 1, 1990 (incorporated herein by reference to Washington Natural Gas Company Exhibit 4-B.19, Form 10-K for the year ended September 30, 1990, File No. 0-951). 4.19 Twenty-seventh Supplemental Indenture dated as of September 1, 1990 (incorporated herein by reference to Washington Natural Gas Company Exhibit 4-B.20, Form 10-K for the year ended September 30, 1988, File No. 0-951). 4.20 Twenty-eighth Supplemental Indenture dated as of July 31, 1991 (incorporated herein by reference to Washington Natural Gas Company exhibit 4-A, Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). 4.21 Twenty-ninth Supplemental Indenture dated as of June 1, 1993 (incoporated herein by reference to Exhibit 4-A of Washington Natural Gas Company's S-3 Registration Statement, Registration No. 33-49599). 4.22 Thirtieth Supplemental Indenture dated as of August 15, 1995 (incorporated herein by reference to Exhbiit 4-A of Washington Natural Gas Company's S-3 Registration Statement, Registration No. 33-61859). 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 the 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 Deveopment. (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 Devleopment. (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 Febrary 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 5-1-35 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 5-1-36 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. (Exhbiit 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 Administraiton 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 betweeen 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 Bonnevillle 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 Costrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended Decmber 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 Comany (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 Septmeber 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 Adminsitration dated Augut 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, 19888, 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 Administraiton 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 for the 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, betweeen 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 betweeen 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 Bonnevillle Power Adminstrator 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 for 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, betweeen 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 continuing operations 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 Power 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, betweeen 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, betweeen 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 Decmeber 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, betweeen 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, betweeen 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, betweeen the Company and the Bonnevillle 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. (Exhibit 10.114 to Annual Report on Form 10-K for the fiscal year ended December 31, 1993, Commission File No. 1-4393) 10.115 General Transmission Agreement dated as of December 1, 1994, between the Bonneville Power Administration and the Company (BPA Contract No. DE-MS79-94BP93947) (Exhibit 10.115 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393) 10.116 PNW AC Intertie Capacity Ownership Agreement dated as of October 11, 1994 between the Bonneville Power Administration and the Company (BPA Contract No. DE-MS79-94BP94521) (Exhibit 10.116 to Annual Report on Form 10-K for the fiscal year ended December 31, 1994, Commission File No. 1-4393) 10.117 Power Exchange Agreement dated as of September 27, 1995, between British Columbia Power Exchange Corporation and the Company. (Exhibit 10.117 to Commission File No. 1-4393) 10.118 Contract with W.S. Weaver, Executive Vice President and Chief Financial Officer, dated October 18, 1996. (Exhibit 10.118 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393) 10.119 Contract with S.M. Vortman, Senior Vice President Corporate and Regulatory Relations, dated October 18, 1996. (Exhibit 10.119 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393) 10.120 Contract with G.B. Swofford, Senior Vice President Customer Operations, dated October 18, 1996. (Exhibit 10.120 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393) 10.121 Service Agreement dated September 1, 1987 between Northwest Pipeline Corporation and Washington Natural Gas Company for SGS-1 firm storage service at Jackson Prairie (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-A Form 10-K for the year ended September 30, 1994, File No. 11271). 10.122 Service Agreement dated April 14, 1993 between Questar Pipeline Corporation and Washington Natural Gas Company for FSS-1 firm storage service at Clay Basin(incorporated herein by reference to Washington Natural Gas Company Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271). 10.123 Service Agreement dated November 1, 1989, with Northwest Pipeline Corporation covering liquefaction storage gas service filed under cover of Form SE dated December 27, 1989. 10.124 Firm Transportation Service Agreement dated October 1, 1990 between Northwest Pipeline Corporation and Washington Natural Gas Company (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-D Form 10-K for the year ended September 30, 1994, File No. 11271). 10.125 Gas Transportation Service Contract dated June 29, 1990 betweeen Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Washington Natural Gas Company exhibit 4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). 10.126 Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and Northwest Pipeline Corporation (incorporated herein by reference to Washington Natural Gas Company exhibit 4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951). 10.127 Amendment to Gas Transportation Service Contract dated July 31, 1991 between Washington Natural Gas Company and NOrthwest Pipeline Corporation. 10.128 Gas Transportation Service Contract dated July 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation. 10.129 Amendment to Gas Transportation Service Contract dated August 15, 1994 between Washington Natural Gas Company and Northwest Pipeline Corporation. 10.130 Washington Natural Gas Company Deferred Compensation Plan effective September 1, 1995. 10.131 Form of Washington Natural Gas Company - Executive Retirement Compensation Agreement reflecting all amendments through August 16, 1995. 10.132 Second Washington Energy Company Performance Share Plan (amended and restated effective October 1, 1991) (incorporated herein by reference to Washington Energy Company Exhibit 10-L.1, Form 10-K for the year ended September 30, 1991, File No. 0-8745). 10.133 Washington Energy Company Interim Performance Share Plan effective December 7, 1994. 10.134 Washington Energy Company Stock Option Plan (incorporated herein by reference to Exhibit 10-C Washington Energy Company Form 10-Q for the Quarter ended March 31, 1984, File No. 0-8745). 10.135 Amendment to Washington Energy Company Stock Option Plan (incorporated herein by reference to Washington Energy Company Exhibit 10-S, Form 10-K for the year ended September 30, 1986, File No. 0-8745). 10.136 Amendment to Washington Energy Company Stock Option Plan dated as of February 26, 1988 (incorporated herein by reference to Washington Energy Company for S-8, Registration No. 33-24221). 10.137 Washington Energy Company Stock Option Plan effective December 15, 1993 (incorporated herein by reference to Washington Energy Company Exhibit 99, Registration No. 33-55381). 10.138 Washington Energy Company Directors Stock Bonus Plan (incorporated herein by reference to Washington Energy Company Exhibit 10-0 Form 10-K for the year ended September 30, 1990, File No. 0-8745). 10.139 Employment Agreement between Washington Energy Company, Washington Natural Gas Company and William P. Vititoe dated January 15, 1994 (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-M.1, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.140 Form of Conditional Executive Employment Contract, filed under cover of Form SE dated December 27, 1988, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-M.2, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.141 Amended and restated Washington Energy Company and subsidiaries Annual Incentive Plan for Vice Presidents and above, dated October 1994. 10.142 Interest Rate Swap Agreement dated September 27, 1989 between Thermal Resources, Inc., and the First National Bank of Chicago, filed under cover of Form SE dated December 27, 1989, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-N, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.143 Firm Transportation Service Agreement dated March 1, 1992 betweeen Northwest Pipeline Corporation and Washington Natural Gas Company, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-O, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.144 Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transporation service from Jackson Prairie, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-P, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.145 Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-Q, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.146 Firm Transportation Service Agreement dated January 12, 1994 betweeen Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Plymouth, LNG, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-R, Form 10-K for the year ended September 30, 1994, File No.1-11271). 10.147 Service Agreement dated July 9, 1991 with Northwest Pipeline Corporation for SGS-2F Storage Sevice filed under cover of Form SE dated December 23, 1991 (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-S, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.148 Firm Transportation Agreement dated October 27, 1993 between Pacific Gas Transmission Company and Washington Natural Gas Company for firm transportation service from Kingsgate, (incorporated herein by reference to Washington Natural Gas Company Exhibit 10-T, Form 10-K for the year ended September 30, 1994, File No. 1-11271). 10.149 Firm Storage Service Agreement and Amendment dated April 30, 1991 between Questar Pipeline Company and Washington Natural Gas Company for firm storage service at Clay Basin filed under cover of Form SE dated December 23, 1991. *12-a Statement setting forth computation of ratios of earnings to fixed charges (1992 through 1996). *12-b Statement setting forth computation of ratios of earnings to combined fixed charges and preferred stock dividends (1992 through 1996). *21 Subsidiaries of the Registrant. *23 Consent of accountants. *27 Financial Data Schedule ________________________________________ *Filed herewith. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. PUGET SOUND ENERGY, INC Date: October 23, 1997 James W. Eldredge ------------------------------- James W. Eldredge Corporate Secretary and Controller