ITEM 1. BUSINESS
GENERAL
Puget Sound Energy, Inc. (the "Company"), is an investor-owned public utility incorporated in the State of Washington furnishing electric and gas service in a territory covering approximately 6,000 square miles, principally in the Puget Sound region of Washington state.
At December 31, 1999, the Company had approximately 907,000 electric customers; consisting of 803,700 residential, 97,600 commercial, 4,200 industrial and 1,500 other customers and approximately 569,900 gas customers; consisting of 521,800 residential, 45,000 commercial, 3,000 industrial and 100 other customers. In 1999, approximately 290,000 customers purchased both forms of energy from the Company. For the year 1999, the Company added approximately 16,300 electric customers and approximately 26,000 gas customers, representing annualized growth rates of 1.8% and 4.8%, respectively. During 1999, the Company's billed retail revenues from electric utility operations were derived 46% from residential customers, 37% from commercial customers, 14% from industrial customers and 3% from other customers. The Company's retail revenues from gas utility operations were derived 61% from residential customers, 28% from commercial customers, 6% from industrial customers, 3% from transportation customers and 2% from other customers. During this period, the largest customer accounted for 1.8% of the Company's 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 wholesale customers also vary by quarters and years depending principally upon streamflow conditions for the generation of surplus hydro-electric power, customer usage and the market demand by wholesale customers. Earnings from electric operations therefore, can be significantly influenced by surplus sales and variations in weather, hydro conditions and regional electric energy prices. Earnings from gas operations can be significantly influenced by variations in weather. The Company has a Purchased Gas Adjustment mechanism ("PGA") in retail rates to recover variations in gas supply and transportation costs. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.")
During the period from January 1, 1995 through December 31, 1999, the Company made gross electric utility plant additions of $845 million and retirements of $146 million. In the five-year period ended December 31, 1999, the Company made gross gas utility plant additions of $479 million and retirements of $58 million. In the same five-year period, the Company made gross common utility plant additions of $131 million and retirements of $10 million. Gross electric utility plant at December 31, 1999, was approximately $4.0 billion which consisted of 46% distribution, 28% generation, 15% transmission and 11% general plant and other. Gross gas utility plant at December 31, 1999, was approximately $1.4 billion which consisted of 83% distribution, 5% transmission and 12% general plant and other.
At year-end the Company had 2,869 aggregate full-time equivalent utility employees.
On June 23, 1999, Company shareholders approved the formation of a holding company structure for the Company and its subsidiaries. The proposed holding company structure has been approved by the Federal Energy Regulatory Commission and the Federal Trade Commission, but is still subject to regulatory approval by the Washington Commission. The primary purpose for the holding company formation is to allow the Company to separate its regulated utility business from its other businesses, which will enhance the holding company's ability to respond to the changing industry environment and will permit greater financing flexibility. The Company's utility business is expected to constitute the principal part of the holding company's earnings for the foreseeable future after the restructuring.
INDUSTRY OVERVIEW
The electric and gas industries in the United States are undergoing significant changes. The focus of these changes is to promote competition among suppliers of electricity and gas and associated services. In 1996 and 1997, the Federal Energy Regulatory Commission ("FERC") issued orders that require utilities, including the Company, to file open access transmission tariffs that will make the utilities' electric transmission systems available to wholesale sellers and buyers on a non-discriminatory basis. A number of states, including California, have restructured their electric industries to separate or "unbundle" power generation, transmission and distribution in order to permit new competitors to enter the market place. In part because electric rates in the Pacific Northwest have been among the lowest in the nation, certain of the legislatures in this region, including Washington, have not yet enacted laws to provide for competition at the retail level. The Company is actively monitoring developments in this area and has indicated its support for the enactment of legislation that would provide increased choice for electric service customers in the state of Washington.
On December 20, 1999 FERC issued Order 2000 to advance the formation of Regional Transmission Organizations (RTOs). This regulation requires each public utility that owns, operates or controls facilities for the transmission of electric energy in interstate commerce to file with FERC by October 15, 2000 their plans for forming and participating in an RTO. FERC's goal is to promote efficiency in wholesale electricity markets and to ensure that electricity consumers pay the lowest price possible for reliable service.
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. Although 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 1999, 103 commercial and industrial customers, on average, chose to use such service. The shifting of customers from sales to transportation does not materially impact utility margin, as the Company earns similar margins on transportation service as it does on large volume, interruptible gas sales.
REGULATION AND RATES
The Company is subject to the regulatory authority of (1) the Washington Commission as to retail 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, accounting and certain other matters. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Rate Matters.")
ELECTRIC UTILITY OPERATIONS
At December 31, 1999, the Company's peak electric power resources were approximately 5,101,647 KW. The Company's historical peak load of approximately 4,847,000 KW occurred on December 21, 1998.
During 1999, the Company's total electric energy production was supplied 23% by its own resources, 23% through long-term contracts with several of the Washington Public Utility Districts ("PUDs") that own hydro-electric projects on the Columbia River, 22% from other firm purchases and 32% from non-firm purchases.
The following table shows the Company's electric energy supply resources at December 31, 1999, and energy production during the year:
COMPANY-OWNED ELECTRIC GENERATION 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, Montana. 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"), under the terms of long-term coal supply agreements. In the third quarter of 1998, Western Energy, the Company and other joint owners of Units 3 and 4 revised the coal supply contract which reduced the delivered price of coal for Units 3 and 4 and allows for the joint owners to review and approve mining plans and budgets.
In November 1998, the Company announced that it had signed an agreement to sell its interest in the Colstrip plant, as well as associated transmission facilities to PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L Resources, Inc. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other" for a discussion of the sale.)
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 May 1999, the Company and the other owners announced that they had signed an agreement to sell all their ownership shares in the plant to TransAlta Corporation of Calgary, Canada. (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other" for a discussion of the sale.)
The Company owns a 160 megawatt natural-gas fired cogeneration facility located near Bellingham, Washington which was purchased from Encogen Northwest L.P. ("Encogen") on November 1, 1999. (See Electric Energy Supply Contracts and Agreements with Non-Utilities.)
The Company also has the following plants with an aggregate net generating capability of 963,750 KW: Upper Baker River hydro project (103,000 KW) constructed in 1959; Lower Baker River hydro project (71,400 KW) reconstructed in 1960; White River hydro plant (63,400 KW) constructed in 1911; Snoqualmie Falls hydro plant (45,500 KW), half the capability of which was installed during the period 1898 to 1910 and half in 1957; and one smaller hydro plant, Electron (27,400 KW), constructed during the period 1904 to 1929; a standby internal combustion unit (2,750 KW) installed in 1969; an oil-fired combustion turbine unit (67,500 KW) installed in 1974; four dual-fuel combustion turbine units (89,100 KW each) installed during 1981; and two dual-fuel combustion turbine units (113,200 KW each) installed during 1984. All of these generating facilities are located in the Company's service territory.
_________________________________ (1) Power received from other utilities is classified between hydro and other producers based on the character of the utility system used to supply the power or, if the power is supplied from a particular resource, the character of that resource.
The 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 are stored on-site. These plants are operated from time to time for peaking purposes and to produce energy for sales to wholesale customers, either directly or through tolling arrangements.
On December 19, 1997, the Company was issued a 50 year license by FERC for its existing and operating White River project which includes authorization to install an additional 14,000 KW generating unit. The Company has filed for a rehearing with FERC on conditions of the license related to measures designed to enhance salmon runs on the White River, because those conditions may make the plant uneconomic to operate. On June 30, 1999, FERC issued a two year stay in the license proceeding. This additional time allows the Company, state agencies, local governments and public interest groups to resolve common issues relating to the plant's continued operation and economics. 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.
COLUMBIA RIVER ELECTRIC ENERGY SUPPLY CONTRACTS
During 1999, approximately 23.2% of the Company's energy output was obtained at an average cost of approximately 9.4 mills per KWH through long-term contracts with several of the Washington PUDs owning hydro-electric 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 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 50% as of 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, 1999, the Company's aggregate annual capacity from all units of the Rock Island Project was 478,000 KW. The Company has contracted to purchase from Chelan 38.9% (505,000 KW as of December 31, 1999) 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 31.3% (261,000 KW as of December 31, 1999) upon the additional exercise of withdrawal rights by Douglas County PUD. The Company has contracted to purchase from Grant County PUD 8.0% (72,000 KW as of December 31, 1999) of the annual output of the Priest Rapids project and 10.8% (98,000 KW as of December 31, 1999) of the annual output of the Wanapum project, which percentages remain unchanged for the remainder of the contracts. (See Note 17 to the Company's Consolidated Financial Statements.)
ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH OTHER UTILITIES
Under a 1985 settlement agreement relating to Washington Public Power Supply System ("WPPSS") Nuclear Project No. 3, in which the Company had a 5% interest, the Company is receiving from BPA for approximately 30.5 years, beginning January 1, 1987, 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 Avista Corporation (formerly Washington Water Power Company). This agreement calls for the delivery of 100 MW of capacity and 657,000 MWH of energy from the Avista system annually (75 annual average MW). Minimum and maximum delivery rates are prescribed. Under this agreement, the energy is to be priced at Avista's average generation and transmission cost, subject to certain price ceilings. This contract expires on December 31, 2002.
On October 27, 1988, the Company executed a 15-year contract for the purchase of firm power and energy from PacifiCorp. Under the terms of the agreement, the Company receives 120 average MW of energy and 200 MW of peak capacity. This contract expires on October 31, 2003.
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. In 1997, the Company elected to terminate the agreement on June 30, 2001, the date that the purchase was to convert to a summer-winter exchange.
On October 1, 1989, the Company signed a contract with Montana Power under which Montana Power provides the Company, from its share of Colstrip Unit 4, 71 average MW of energy (94 MW of peak capacity) over a 21-year period.
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. Each party may terminate the contract for various reasons.
In October 1997 a 10-year power exchange agreement between the Company and Powerex (a subsidiary of a British Columbia utility) became effective. Under this agreement Powerex pays the Company for the right to deliver power to the Company at the Canadian border in exchange for the Company delivering power to Powerex at various locations in the United States.
ELECTRIC ENERGY SUPPLY CONTRACTS AND AGREEMENTS WITH NON-UTILITIES
As required by the federal Public Utility Regulatory Policies Act ("PURPA"), the Company entered into long-term firm purchased power contracts with non-utility generators. The most significant of these are the contracts described below which the Company entered into in 1989, 1990 and 1991 with operators of natural gas-fired cogeneration projects. The Company purchases the net electrical output of these four projects at fixed and annually escalating prices which were intended to approximate the Company's avoided cost of new generation projected at the time these agreements were made. Principally as a result of dramatic changes in natural gas price levels, the power purchase prices under these agreements are significantly above the current market price of power and, based upon projections of future market prices, are expected to remain well above market for the duration of the contracts. The Company's estimated payments under these four contracts are $181 million for 2000, $204 million for 2001, $206 million for 2002, $207 million for 2003, $213 million for 2004 and in the aggregate, $1.5 billion thereafter through 2012. These payments reflect the Tenaska and Encogen contract restructurings described below. The Company continues to seek restructuring of the other contracts. If retail electric energy prices move to market levels as a result of electric industry restructuring, the Company plans to seek to continue to recover in rates the above market portion of these contract costs.
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 the Equilon 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 Equilon refinery in Anacortes, Washington. A dispute, currently being litigated, exists between the Company and March Point over the PURPA status of and the Company's obligations to buy the output of Phase II.
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 owned and operated a natural-gas fired cogeneration facility located at the Georgia Pacific mill near Bellingham, Washington. The contract had obligated the Company to pay Encogen fixed and escalating fees well above current and projected future market prices through mid-2008 for the output of the plant. On November 1, 1999, the Company purchased the 160 megawatt plant from Encogen. The Company paid $55 million in cash and assumed $109 million in debt to acquire the partnership, which owned no significant assets other than the plant. Pursuant to an October 27, 1999 order from the Washington Commission approving the purchase, the Company will depreciate the original owner's net book value of the plant over the remaining 23 year useful life of the project. The difference between the purchase price and the net book value of the plant (approximately $72.5 million) will be amortized over 9 years (the remaining term of the power purchase contract). The purchase is expected to reduce the net cost of power from the co-generation project by approximately 17% annually.
In December 1999, the Company bought out the remaining 8.5 years of one of the natural gas supply contracts serving Encogen from Cabot Oil & Gas Corporation which provided approximately 60% of the plant's natural gas requirements. The Company will become the replacement gas supplier to the project for 60% of the supply under the terms of the Cabot Agreement and expects the agreement will reduce this portion of gas costs by 5% to 15% annually. The Washington Commission has issued an order creating a regulatory asset relating to the $12 million payment that requires the Company to accrue carrying costs on the unamortized balance over the first 3 years.
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. In December 1997 and January 1998, the Company and Tenaska Washington Partners entered into revised agreements which will lower purchased power costs from the Tenaska project by restructuring its natural gas supply. The Company paid $215 million to buy out the project's existing long-term gas supply contracts, which contained fixed and escalating gas prices that were well above current and projected future market prices for natural gas. The Company became the principal natural gas supplier to the project and power purchase prices under the Tenaska contract were revised to reflect market-based prices for the natural gas supply. The Company obtained an order from the Washington Commission creating a regulatory asset related to the $215 million restructuring payment. Under terms of the order, the Company is allowed to accrue as an additional regulatory asset one-half the carrying costs of the deferred balance over the first five years. These revised arrangements are expected to reduce the Company's power supply costs from the Tenaska project an average of between 15 and 20 percent over the 14 year period from 1998 through 2011, net of the costs of the restructuring payment.
ELECTRIC RATES AND REGULATION
The order approving the merger of the Company, Washington Energy Company and Washington Natural Gas Company ("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. General electric tariff rates were stipulated to increase annually between 1.0% to 1.5% depending on rate class on January 1 of 1998 through 2000. Electric tariff rates for certain customers will increase by 1.5% in 2001.
ELECTRIC UTILITY OPERATING STATISTICS
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(2) Operating revenues in 1999, 1998 and 1997 were reduced by $43.8 million, $46.7 million and $40.5 million, respectively, as a result of the Company's sale of $237.7 million of its investment in customer-owned conservation measures. (See "Operating revenues" in Management's Discussion and Analysis and Note 1 to the Consolidated Financial Statements.)
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Gas Utility Operations
Gas Supply
The Company currently purchases a blended portfolio of long-term firm, short-term firm, and non-firm gas supplies from a diverse group of major and independent producers and gas marketers in the United States and Canada. All of the Company's gas supply is ultimately transported through Northwest Pipeline Corporation ("NPC"), the sole interstate pipeline delivering directly into the western Washington area.
All peak firm gas supplies and storage are connected to PSE's market with firm transportation capacity.
For baseload and peak-shaving purposes, the Company supplements its firm gas supply portfolio 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 Western Washington and at Clay Basin in Utah are used for this purpose. Peaking needs are also met by using Company-owned gas held in NPC's liquefied natural gas ("LNG") facility at Plymouth, Washington, and by producing propane-air gas at a plant owned by the Company and located on its distribution system.
In 1998, the Company took assignment from Cascade Natural Gas of a Peaking Gas Supply Service ("PGSS") contract whereby the Company can divert up to 48,000 Dth per day of gas supply away from the Tenaska Cogeneration Facility and toward the core gas load by causing Tenaska to operate its facility on distillate fuel and paying any additional costs of such operation.
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.
Gas Supply Portfolio
For the 1999-2000 winter heating season, the Company has contracted for approximately 19% 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. 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 19% 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 resources, which represent approximately 39%, 9% and 4%, respectively, of expected peak-day requirements.
During 1999, approximately 48% of gas supplies purchased by the Company originated from British Columbia while 26% originated in Alberta and 26% originated in the U.S.
The current firm, long-term gas supply portfolio consists of arrangements with 18 producers and gas marketers, with no single supplier representing more than 12% of expected peak-day requirements. Contracts have remaining terms ranging from less than one year to 12 years, with an average term of 2 years. All gas supply contracts contain market-sensitive pricing provisions based on several published indices.
The Company's firm gas supply portfolio is structured to capitalize on regional price differentials when they arise. Gas and services are marketed outside the Company's service territory ("off-system sales") whenever on-system customer demand requirements permit. The geographic mix of suppliers and daily, monthly and annual take requirements permit a high degree of flexibility in selecting gas supplies during off-peak periods to minimize costs.
GAS TRANSPORTATION CAPACITY
The Company currently holds firm transportation capacity on pipelines owned by NPC and PG&E Gas Transmission-Northwest ("PGT"). Accordingly, the Company pays fixed monthly demand charges for the right, but not the obligation, to transport specified quantities of gas from receipt points to delivery points 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 Dekatherms per day (one Dekatherm, or Dth, is equal to one million British thermal units or "MMBtu" per day), acquired under several agreements at various times. The Company has exchanged certain segments of its firm capacity with third parties to effectively lower transportation costs. The Company's firm transportation capacity contracts with NPC have remaining terms ranging from 5 to 16 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 current FERC orders. The Company's firm transportation capacity on PGT's pipeline, totaling 90,392 Dth per day, has a remaining term of 24 years.
GAS STORAGE CAPACITY
The Company holds storage capacity in the Jackson Prairie and Clay Basin underground gas storage facilities adjacent to NPC's pipeline. The Jackson Prairie facility, operated and one-third owned by the Company, is used primarily for intermediate peaking purposes, able to deliver a large volume of gas over a relatively short time period. Combined with capacity contracted from NPC's one-third stake in Jackson Prairie, the Company has peak, firm delivery capacity of over 340,000 Dth per day and total firm storage capacity exceeding 7,500,000 Dth at the facility. The location of the Jackson Prairie facility in the Company's market area provides significant cost savings by reducing the amount of annual pipeline capacity required to meet peak-day gas requirements. On November 1, 1999, a facility expansion was placed in service. The Company's share of the expanded service provides additional firm delivery capacity of over 100,000 Dth per day and additional firm storage capacity in excess of 1,000,000 Dth. The Company secured rights to additional firm seasonal pipeline capacity to be utilized in conjunction with the expanded service.
The Clay Basin storage facility is supply area storage and is withdrawn over the entire winter, capturing savings due to injecting lower cost gas supplies during the summer. The Company has maximum firm withdrawal capacity of over 100,000 Dth per day from the facility with total storage capacity exceeding 13,000,000 Dth. The capacity is held under two contracts with remaining terms of 14 and 20 years.
LNG AND PROPANE-AIR RESOURCES
LNG and propane-air resources provide gas supply on short notice for short periods of time. Due to their high cost, these resources are utilized as the supply of last resort in extreme peak-demand periods, typically lasting a few hours or days. The Company has long-term contracts for storage of nearly 250,000 Dth of Company-owned 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 Dth. The Company owns storage capacity for approximately 1.4 million gallons of propane. The propane-air injection facilities are capable of delivering the equivalent of 30,000 Dth of gas per day for up to four days directly into the Company's distribution system.
CAPACITY RELEASE
FERC provided a capacity release mechanism as the means for holders of firm pipeline and storage entitlements to temporarily relinquish unutilized 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 pre-arrangement. The Company continues to successfully mitigate a portion of the demand charges related to both storage and NPC and PGT pipeline capacity not utilized during off-peak periods. WNG CAP I, a wholly owned subsidiary of the Company, was formed to provide additional flexibility and benefits from capacity release. Capacity release benefits are passed on to customers through the PGA.
GAS RATES AND REGULATION
The order approving the Merger, issued by the Washington Commission on February 5, 1997, contains a rate plan which provided unchanged rates for all classes of natural gas customers until January 1, 1999, when rates decreased by approximately $2 million annually.
On October 27, 1999, the Washington Commission approved the Company's PGA and deferral amortization (true-up) filings effective November 1, 1999. The PGA filing allows the Company to recover an expected increase in annual gas costs and the deferral amortization filing allows the Company to recover prior period gas cost undercollections. The filings replaced the PGA and deferral amortization refund that had been effective since April 1, 1998. As a result, gas rates to all sales customers increased by an average of 16.3%, while rates for gas transportation service as well as gas margins remained unchanged.
On June 25, 1998, the Company received approval from the Washington Commission to begin a new performance-based mechanism for strengthening its gas-supply purchasing and gas-storage practices. The PGA Incentive Mechanism, which encourages competitive gas purchasing and management of pipeline and storage-capacity became effective July 1, 1998. Incentive gains and losses from the three-year program are shared between customers and shareholders. After the first $0.5 million, which is allocated to customers, gains and losses are shared 40%/60% between the Company and customers up to $26.5 million, and 33%/67% thereafter. Gains or losses are determined relative to a weighted average index which is reflective of the Company's gas supply and transportation contract costs. The Company's share of incentive gains under the PGA Incentive Mechanism in 1999 and 1998 were approximately $7.2 million and $1.1 million, respectively while customers received approximately $11.3 million and $2.0 million, respectively.
GAS UTILITY OPERATING STATISTICS
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ENERGY CONSERVATION
The Company offers programs designed to help new and existing customers use 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 operating practices.
Since May 1997, the Company has recovered electric energy conservation expenditures through a tariff rider mechanism. The rider mechanism allows the Company to defer the conservation expenditures and amortize them to expense as the Company concurrently collects the conservation expenditures in rates over a one year period. As a result of the rider, there is no effect on earnings per share.
Since 1995, the Company has been authorized by the Washington Commission to defer gas energy conservation expenditures and recover them through a tariff tracker mechanism. The tracker mechanism allows the Company to defer conservation expenditures and recover them in rates over the subsequent year. The tracker mechanism also allows the Company to recover an Allowance for Funds Used to Conserve Energy (AFUCE) on any outstanding balance that is not being recovered in rates.
ENVIRONMENT
The Company's operations are subject to environmental regulation by federal, state and local authorities. 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. (See Note 17 to the Consolidated Financial Statements for further discussion of environmental 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 met the sulfur dioxide limits of the CAAA in Phase I (1995). All four units at the Colstrip Project, operated by Montana Power, meet Phase II emission limits. In accordance with the purchase agreement with TransAlta, the Centralia Owners are installing flue gas scrubbers and low NOx burners on both units of the Centralia generating station to meet state and federal emissions standards. The current cost estimate for the Company's share of these additions is $14 million, of which approximately $4.2 million will have been committed by the anticipated closing date of the sale of Centralia to TransAlta. In accordance with the agreements with TransAlta, these expenditures will be reimbursed by TransAlta.
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, or 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 ("ESA"). 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.
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 hydro-electric 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.
Since the 1991 listings, one more species of salmon has been listed and two more have been proposed which may further influence operations. Upper Columbia River Steelhead were listed by NMFS in August 1997. Anticipating the Steelhead listing, the Mid-Columbia PUDs initiated consultation with the federal and state agencies, Native American tribes and non-governmental organizations to secure operational protection through a long-term settlement and habitat conservation plan which includes fish protection and enhancement measurement for the next 50 years. The negotiations have concluded among the Chelan and Douglas County PUDs and various fishery agencies, and final agreement is subject to a National Environmental Policy Act review and power purchaser approval. Generally, the agreement obligates the PUDs to achieve certain levels of passage efficiency for downstream migrants at their hydro-electric facilities and to fund certain habitat conservation measures. Grant County PUD has yet to reach agreement on these issues.
The proposed listings of Puget Sound Chinook salmon and spring Chinook for the upper Columbia were approved in March 1999. The listing of spring Chinook for the upper Columbia should not result in markedly differing conditions for operations from previous listings in the area. However, Puget Sound has not experienced ESA listing to date and listing of Puget Sound Chinook could cause a number of changes to operations of government agencies and private entities in the region including the Company. These may adversely affect hydro plant operations, permit issuance for facilities construction and increased costs for process and facilities. Because the Company relies substantially less on hydro-electric energy from the Puget Sound area than from the Mid-Columbia and because the impact on Company operations in the Puget Sound area is not likely to impair significant generating resources, the impact of listing for Puget Sound Chinook salmon should be proportionately less than the Columbia River listings.
EXECUTIVE OFFICERS AT MARCH 1, 2000
NAME AGE OFFICES - -------------------------------------------------------------------------------- W. S. Weaver 56 President & Chief Executive Officer since January 1998; President, May 1997 - January 1998; Vice Chairman and Chairman of Unregulated Subsidiaries, February 1997 - May 1997; Executive Vice President and Chief Financial Officer 1991-1997; Director since 1991. J. W. Eldredge 49 Chief Accounting Officer since 1994; Corporate Secretary and Controller since 1993; Controller since 1988. D. E. Gaines 43 Treasurer since 1994; Director Strategic Planning 1992- 1994; Manager Financial Planning 1986 - 1992. W. A. Gaines 44 Vice President Energy Supply since February 1997; Manager Power Management 1996-1997; Manager Operations Planning 1986-1996. D. A. Graham 59 Vice President Human Resources since April 1998; Director Human Resources 1989-1998. R. L. Hawley 50 Vice President and Chief Financial Officer since March 1998. For more than five years prior to that time, he was a partner with the accounting firm of PricewaterhouseCoopers LLP. T. J. Hogan 48 Vice President Systems Operations since February 1997; Washington Energy Company positions held: Executive Vice President and Chief Operating Officer 1995-1997; Vice President Supply, Administration and Corporate Secretary 1994-1995; Vice President Legal and Corporate Secretary 1991-1994. S. A. McKeon 54 Vice President and General Counsel since June 1997. For more than five years prior to that time he was a partner with the law firm of Perkins Coie LLP. S. McLain 43 Vice President Operations - Delivery since June 1999; Vice President Corporate Performance 1997-1999; Director Planning and Work Practices 1997; various positions in Human Resources, Operations, Customer Service and Strategic Planning 1988-1997. G. B. Swofford 58 Vice President and Chief Operating Officer - Delivery since June 1999; Vice President Customer Operations 1997-1999; Senior Vice President Customer Operations 1994-1997; Vice President Divisions and Customer Services 1991-1994; Vice President Rates and Customer Programs 1986-1991.
Officers are elected for one-year terms.
ITEM 2.
ITEM 2. PROPERTIES
The principal electric generating plants and underground gas storage facilities owned by the Company are described under Item 1 - "Business - Electric Utility Operations and Gas Utility Operations." The Company owns its transmission and distribution facilities and various other properties. Substantially all properties of the Company are subject to the liens of the Company's Mortgage Indentures.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
See Note 17 to the Consolidated Financial Statements.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's common stock (symbol PSD) is traded on the New York Stock Exchange. The number of shareholders of record of the Company's common stock at December 31, 1999, was 53,434.
The Company has paid dividends on its common stock each year since 1943 when such stock first became publicly held. Future dividends will be dependent upon earnings, the financial condition of the Company and other factors.
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in the Company's Articles of Incorporation and electric and gas mortgage indentures. Under the most restrictive covenants, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $202 million at December 31, 1999. (See Note 7 to the Consolidated Financial Statements.)
Dividends paid and high and low stock prices for each quarter over the last two years were:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA (1)
(Dollars in thousands except per share data)
(1) Amounts for 1996 and 1995 have been retroactively restated to include the results of operations, financial position and cash flows of WECo and WNG.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the Company's business includes some forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," and similar expressions identify forward-looking statements involving risks and uncertainties. Those risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric and gas industries and the outcome of regulatory proceedings related to that restructuring. The ultimate impacts of both increased competition and the changing regulatory environment on future results are uncertain, but are expected to fundamentally change how the Company conducts its business. The outcome of these changes and other matters discussed below may cause future results to differ materially from historic results, or from results or outcomes currently expected or sought by the Company.
Financial Condition and Results of Operations
Net income in 1999 was $185.6 million on operating revenues of $2.067 billion, compared to $169.6 million on operating revenues of $1.924 billion in 1998 and $123.1 million on operating revenues of $1.682 billion in 1997. Income for common stock was $174.5 million in 1999, compared to $156.6 million in 1998 and $105.7 million in 1997.
Basic and diluted earnings per share in 1999 were $2.06 on 84.6 million weighted average common shares outstanding compared to $1.85 on 84.6 million weighted average common shares outstanding in 1998 and $1.25 on 84.6 million weighted average common shares outstanding in 1997 including a $0.03 loss per share from discontinued operations.
Net income in 1999 was positively impacted by net gains of approximately $7.8 million or $0.09 per share from non-utility operations. The $0.09 per share included gains from the sale of Homeguard Security Services, Inc., a wholly owned subsidiary, and the Company's common stock investment in Cabot Oil & Gas Corporation. These gains were offset in part by losses related to sales of non-core assets and gas transportation contracts, establishing reserves for two proposed small hydroelectric projects and costs of a subsidiary exiting certain product lines. Net income for 1997 included an after-tax charge of $36.3 million ($0.43 per share) for costs related to the merger including transaction expenses, employee separation and system and facilities integration. Net income in 1997 also included an after-tax charge of $2.6 million ($0.03 per share), to write off the Company's remaining investment in undeveloped coal reserves and related activities in southeastern Montana (See Note 18 to the Consolidated Financial Statements). These charges in 1997 were partially offset by $13.6 million ($0.16 per share) related to an income tax refund received in 1997. Excluding the impact of these charges and credits to income, continuing operations for 1997 produced earnings of $1.55 per share.
Total kilowatt-hour sales to ultimate consumers in 1999 were 21.4 billion, compared with 20.9 billion in 1998 and 20.5 billion in 1997. Kilowatt-hour sales to wholesale customers were 11.7 billion in 1999, 9.9 billion in 1998 and 7.4 billion in 1997.
Total gas volumes, including gas sales service and transportation, were 1,109 million therms in 1999, 1,008 million therms in 1998 and 1,011 million therms in 1997.
INCREASE (DECREASE) OVER PRECEDING YEAR
years ended December 31 (dollars in millions)
1999 1998 - --------------------------------------------------------------------- Operating revenues: General rate increases $17.3 $18.5 PRAM electric revenue surcharges/refunds -- 44.8 BPA Residential Purchase and
Sale Agreement (4.8) (1.2) Electric sales to wholesale customers 41.8 141.2 Electric revenue sold to conservation trust 2.9 (6.3) Electric load and other changes 25.7 46.7 Gas revenue change 68.9 7.1 Other revenues (9.0) (8.6) - --------------------------------------------------------------------- Total operating revenue changes 142.8 242.2 - --------------------------------------------------------------------- Operating expenses: Energy costs: Purchased electricity 28.0 137.2 Residential exchange 16.6 16.4 Purchased gas 44.2 (3.5) Electric generation fuel 2.9 15.1 Utility operations and maintenance 9.0 (12.5) Other operations and maintenance (7.7) (3.8) Depreciation and amortization 10.1 3.7 Conservation amortization 1.6 (1.1) Merger and related costs -- (55.8) Taxes other than federal income taxes 19.7 1.2 Federal income taxes 3.3 60.9 - --------------------------------------------------------------------- Total operating expense changes 127.7 157.8 - --------------------------------------------------------------------- Other income 12.6 (20.2) Interest charges 11.7 20.3 Discontinued operations -- 2.6 - --------------------------------------------------------------------- Net income changes $ 16.0 $ 46.5 - ---------------------------------------------------------------------
The following information pertains to the changes outlined in the table above:
Operating Revenues - Electric
Electric operating revenues increased $17.3 million and $18.5 million in 1999 and 1998, respectively, when compared to the prior years due to overall average 1.2% general rate increases effective January 1, 1998 and January 1, 1999.
Electric operating revenues in 1998 increased $44.8 million compared to 1997 as a result of a $48.6 million Periodic Rate Adjustment Mechanism ("PRAM") revenue reduction in 1997 associated with an IRS 1991-1994 Conservation tax refund and related interest income. Based on the Company's agreement with the Washington Commission, the benefit of the tax refund was passed on to retail customers as a reduction of the PRAM accrued revenue balance. A decrease in federal, state and local taxes as well as a decrease in interest expense and recognition of interest income offset the $48.6 million reduction in revenues in 1997.
Electric revenues in 1999, 1998 and 1997 were reduced because 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. On January 29, 1997, the Company and the BPA signed a Residential Exchange Termination Agreement. The Termination Agreement ends the Company's participation in the Residential Purchase and Sale Agreement with BPA. As part of the Termination Agreement, the Company will receive payments by the BPA of approximately $235 million over an approximately 5-year period ending June 2001. These payments are recorded as a reduction of purchased electricity expenses. Under the rate plan approved by the Washington Commission in its merger order, the Company will continue to reflect, in customers' bills, the level of Residential Exchange benefits in place at the time of the merger. Over the remainder of the Residential Exchange Termination Agreement from January 2000 through June 2001, it is projected that the Company will credit customers approximately $106.8 million more than it will receive from BPA during the following periods:
Credit to Received from BPA Excess Credits Customers Period (in Millions) -------------------------------------------------------------------------- January - December 2000 $111.2 $41.0 $70.2 January - June 2001 63.6 27.0 36.6 -------------------------------------------------- $174.8 $68.0 $106.8
The allocation of future benefits of low-cost federal power, for the five-year BPA rate plan period 2002 to 2006 will be decided as part of a current BPA rate case process. As part of its rate case, the BPA has a "subscription plan" that outlines how the agency proposes to allocate the low-cost federal power, or in some cases, the power's equivalent monetary benefits. Following a public rate-hearing process, the BPA is expected to publish a record of decision on final power rates and allocations in the latter part of 2000.
Electric revenues in 1999 and 1998 were reduced by $43.8 million and $46.7 million, respectively, when compared to prior years as a result of the Company's sale of revenues associated with $237.7 million of its investment in conservation assets to grantor trusts. The revenue decrease represents the portion of rate revenues that were sold and forwarded to the trusts. The impact of this revenue decrease, however, was offset by related reductions in other utility operations and maintenance and interest expenses.
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 hydro-electric generation and weather effects on customer demand, from time to time the Company may have surplus power available for sale to wholesale customers. In addition, the Company has increased its wholesale surplus power business in order to manage its core energy portfolio through short and intermediate-term purchases, sales, arbitrage and other risk management techniques. The Company has a Risk Management Committee which oversees energy price risk matters. Sales to wholesale customers increased $41.8 million and $141.2 million in 1999 and 1998, respectively, compared to the prior years due primarily to favorable hydroelectric conditions and increased wholesale power transactions. Wholesale sales generally have small margins. However, there may be certain times when the market price of power may cause margins to fluctuate.
OPERATING REVENUES - GAS
Regulated gas utility revenue in 1999 increased by $68.9 million from the prior year on a 15.8% increase in gas volumes sold. Total gas volumes, including transported gas, increased 10.0% in 1999 from 1998. The increase in sales revenue was primarily the result of a 4.5% increase in gas customers during 1999, the impact of temperatures that averaged near normal as compared to warmer than normal in the prior year and a Purchased Gas Adjustment that became effective November 1, 1999. The Purchased Gas Adjustment ("PGA") and deferral amortization (true-up) filings effective November 1, 1999 accounted for $17.3 million of this increase. (See "Rate Matters - Gas"). A larger percentage of firm gas sales with higher prices and less transportation volumes in 1999 when compared to last year also contributed to increased revenues. Utility gas margin (the difference between gas revenues and gas purchases) increased by $19.4 million, or 9.8 %, in 1999 over 1998.
Regulated gas utility sales revenue in 1998 increased by $7.1 million, or 1.7%, from the prior year on a 2.6% increase in gas volumes sold. Total gas volumes, including transported gas, decreased 0.35% in 1998 from 1997.
OTHER REVENUES
Other revenues decreased $9.0 million in 1999 compared to 1998 due primarily to decreased revenues at the Company's ConneXt subsidiary. Other revenues decreased $8.6 million in 1998 compared to 1997 due primarily to the sale of an unregulated subsidiary (Washington Energy Services Company) in October 1997.
OPERATING EXPENSES
Purchased electricity expenses increased $28.0 million in 1999 when compared to 1998 and $137.2 million in 1998 when compared to 1997. The increase in 1999 was due primarily to an increase in secondary power purchases from other utilities and marketers to support wholesale sales as a part of the Company's energy price risk management policies and the increased load due to temperatures that averaged near normal as compared to warmer than normal in 1998 and the increase in electric customers in 1999 compared to 1998. The increase in 1998 was due primarily to a $112.3 million increase in secondary power purchases from other utilities to support wholesale sales and increased payments of $18.8 million for firm power purchases from non-utility generators.
Residential exchange credits associated with the Residential Purchase and Sale Agreement with BPA decreased $16.6 million in 1999 when compared to 1998, primarily as a result of the 1997 Residential Exchange Termination Agreement discussed in "Operating Revenues - Electric." Residential exchange credits also decreased $16.4 million in 1998 compared to 1997 as a result of the aforementioned Termination Agreement. Residential exchange credits received in 1999 were $39.0 million and are estimated to be $41.0 million and $27.0 million in the years 2000 and 2001, respectively. (See discussion of the Residential Purchase and Sale Agreement under Operating Revenues.)
Purchased gas expenses increased $44.2 million in 1999 compared to 1998 due to both the increased volumes of purchases as a result of higher heating load and the increase in gas service customers. Purchased gas expenses also increased by $17.3 million in 1999 compared to 1998 due to approval of the Company's PGA filing effective November 1, 1999. Changes in gas costs are passed through to customers with the PGA mechanism. Purchased gas expenses decreased $3.5 million in 1998 compared to 1997 despite the 2.6% increase in gas volumes sold in 1998. This was primarily the result of a $5.4 million credit to purchased gas costs in the fourth quarter of 1998 due to a true up of gas costs through the PGA mechanism.
Electric generation fuel expense increased $2.9 million in 1999 compared to 1998 as a result of a $6.7 million Encogen fuel expense in the fourth quarter of 1999 which was partially offset by the Company generating less electricity at other Company-owned combustion turbines. The Company's acquisition of the 160 megawatt Encogen natural gas-fired cogeneration facility was completed on November 1, 1999. (See "Other"). Electric generation fuel expense increased $15.1 million in 1998 compared to 1997 primarily due to the Company generating more electricity at Company-owned gas-fired combustion turbine plants. This increase was partially offset by reductions to Colstrip fuel expense. In September 1998, the Company recorded a reduction of $4.9 million in fuel expense and $3.5 million of interest income related to the resolution of outstanding issues with the Colstrip fuel supplier.
Utility operations and maintenance expenses increased $9.0 million in 1999 compared to 1998. The primary reasons for the increase were increased storm-repair costs of $8.3 million and increased expenditures for Year 2000 remediation efforts of $4.3 million (total expended in 1999 approximated $7.1 million for Year 2000 remediation). Utility operations and maintenance expenses decreased $12.5 million in 1998 compared to 1997. The decrease was primarily the result of the reduction in operating expenses resulting from consolidation of the joint operations of two formerly separate electric and gas utilities with overlapping service territories, the elimination of duplicate administrative functions and the consolidation of Company facilities.
Other operations and maintenance expenses decreased $7.7 million in 1999 compared to 1998 primarily as a result of a wholly owned subsidiary's exiting certain product lines. Other operations and maintenance expenses decreased $3.8 million in 1998 compared to 1997. The decrease resulted primarily from the sale of the Company's unregulated subsidiary, Washington Energy Services Company, in October 1997. The decreases were partially offset by increased operating expenses at another subsidiary.
Depreciation and amortization expense increased $10.1 million in 1999 compared to 1998 due primarily to the effects of new plant placed into service during the past year. Depreciation and amortization expense increased $3.7 million in 1998 compared to 1997. Depreciation and amortization expense due to capital spending related to adding customers, distribution and transmission system improvements and computer software amortization increased $12.3 million in 1998. Partially offsetting this increase in 1998 was a decrease in depreciation and amortization expense resulting from an August 1997 Washington Commission Order which authorized the Company to record in 1997 interest income of $8.3 million related to a conservation tax refund, but required the Company to expense in 1997 deferred storm damage costs in the amount of $7.4 million and to establish a $1.0 million reserve to cover the costs of a Company retail pilot program.
Taxes other than federal income taxes increased $19.7 million in 1999 compared to 1998 and $1.2 million in 1998 compared to 1997 due primarily to increases in municipal taxes, state excise taxes and state property taxes. Federal income taxes increased by $3.3 million in 1999 over 1998 primarily due to higher pre-tax operating income for the period. Federal income taxes in 1997 were $60.9 million less than in 1998 as a result of the following factors: an IRS tax refund related to the method of accounting for taxes on conservation expenditures during the first quarter of 1997 decreased federal income taxes for 1997 by $26.5 million, a decrease in PRAM revenues of $48.6 million in 1997 reduced federal income taxes by $17.0 million and merger costs expensed in the first quarter of 1997 further reduced federal income taxes by $19.3 million.
OTHER INCOME
Other income, net of federal income tax, increased $12.6 million in 1999 compared to 1998 due primarily to net gains of approximately $7.8 million from non-utility operations in 1999 and an increase of $2.8 million in AFUDC income. The $7.8 million of net gains included gains from the sale of Homeguard Security Services, Inc., a wholly owned subsidiary, and the Company's common stock investment in Cabot Oil & Gas Corporation. These gains were offset in part by losses related to sales of non-core assets and gas transportation contracts, establishing reserves for two proposed small hydroelectric projects and expenses of a subsidiary exiting certain product lines.
Other income, net of federal income tax, decreased $20.2 million in 1998 from 1997. The decrease was due primarily to the receipt of interest income in 1997 of $13.6 million from the IRS on tax refunds for prior years in connection with a plant abandonment loss, conservation tax refunds and certain additional research and experimental credits claimed for tax purposes.
INTEREST CHARGES
Interest charges, which consist of interest and amortization on long-term debt and other interest, increased $11.7 million in 1999 compared to 1998 as a result of the issuance of $200 million 6.74% Senior Medium-Term Notes, Series A, in June 1998 and $250 million Senior Medium-Term Notes, Series B, in March 1999. These increases were partially offset by the maturity or redemption of $188 million in Secured Medium-Term Notes since February 1998. Other interest expense decreased $1.7 million compared to 1998 as a result of lower weighted average interest rates.
Interest charges increased $20.3 million in 1998 compared to 1997 primarily as a result of the issuance of $300 million 7.02% Senior Medium-Term Notes, Series A, in December 1997, the issuance of $100 million 8.231% Capital Trust Debentures in June 1997 and the issuance of $200 million 6.74% Senior Medium-Term Notes, Series A, in June 1998. These increases were partially offset by the maturity of $151 million Secured Medium-Term Notes during the 15 months ended December 31, 1998 and the redemption of $30 million 9.14% Secured Medium-Term Notes, Series A, in June 1998.
CONSTRUCTION, CAPITAL RESOURCES AND LIQUIDITY
Current construction expenditures, primarily transmission and distribution-related, are designed to meet continuing customer growth and to improve efficiencies of the Company's energy delivery systems. Construction expenditures in 1999 and 2000 also include costs of developing a new customer information system. Construction expenditures, which include energy conservation expenditures and exclude AFUDC, were $330.8 million in 1999. The Company expects construction expenditures for the period 2000 through 2002 will be approximately $269 million, $250 million and $250 million, respectively. Construction expenditure estimates are subject to periodic review and adjustment.
The Company expects cash from operations (net of dividends and AFUDC) during the period 2000 through 2002 will, on average, be approximately 95% of average estimated construction expenditures (excluding AFUDC) during the same period.
On November 1, 1999, the Company assumed approximately $109 million of project debt under the agreement to purchase the 160-megawatt natural gas-fired cogeneration plant from Encogen Northwest L.P. Interest rates on the project debt ranged from 8.64% to 13.03%. In February 2000, the Company used a portion of the proceeds from the issuance of $225 million principal amount of Senior Medium-Term notes to pay off the project debt.
In September 1998, the Company filed a shelf-registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million principal amount of Senior Notes secured by a pledge of First Mortgage Bonds. On March 9, 1999, the Company issued $250 million principal amount of Senior Medium-Term Notes, Series B, which consisted of $150 million principal amount due March 9, 2009 at an interest rate of 6.46% and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%. On February 22, 2000, the Company issued $225 million principal amount of 7.96% Senior Medium-Term Notes, Series B. The Notes are due February 22, 2010 and proceeds were used to redeem the Encogen project debt and pay down a portion of the Company's short-term debt.
In February 1999, the Company redeemed the remaining 203,006 outstanding shares of Series B, Adjustable Rate Preferred Stock. In September 1999, the Company redeemed $30 million 8.50% Series III Preferred Stock.
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 financing, the Company may be limited by restrictions contained in its electric and gas mortgage indentures, articles of incorporation and certain loan agreements.
Under the most restrictive tests, at December 31, 1999, the Company could issue either (i) approximately $867 million of additional first mortgage bonds, (ii) approximately $712 million of additional preferred stock at an assumed dividend rate of 7.3%, or (iii) a combination thereof.
Short-term borrowings from banks and the sale of commercial paper are used to provide working capital for the construction program. At December 31, 1999, the Company had available $375 million in lines of credit with various banks, which provide credit support for outstanding commercial paper of $105.7 million, effectively reducing the available borrowing capacity under these lines of credit to $269.3 million. (See Note 9 to the Consolidated Financial Statements.)
Under the most restrictive covenants in the Company's Articles of Incorporation and electric and gas mortgage indentures, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $202 million at December 31, 1999.
RATE MATTERS - ELECTRIC
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. General electric tariff rates were stipulated to increase annually between 1.0% to 1.5% depending on rate class on January 1 of 1998 through 2000. Electric tariff rates for certain customers will increase by 1.5% in 2001.
In September 1996, pursuant to a negotiated settlement with the Washington Commission, the Company's PRAM was discontinued. PRAM accrued revenues of $40.5 million, recorded at December 31, 1996, were recovered in the first quarter of 1997. Overcollections of PRAM revenues were refunded to customers in the second quarter of 1997. With the discontinuance of the PRAM, the Company no longer has a rate adjustment mechanism to adjust for changes in energy or fuel costs or variances in hydro and weather conditions. These variances may now significantly influence earnings.
On July 8, 1998, the Washington Commission approved the Company's requested accounting treatment for its program to reduce costly tree-caused power outages. The Tree Watch program, which focuses on controlling vegetation outside the Company's rights-of-way, should improve service reliability for its customers and result in future savings in outage recovery costs. The five-year, $43 million program will be treated as an investment that will be amortized over ten years. The Company expects the Tree Watch investment to be offset by savings from lower outage restoration and storm damage costs over the same period.
On October 13, 1999, the Company received from the Washington Commission an order regarding the accounting and ratemaking treatment of a proposed Silicone Injection Program, which extends the life of treated underground cable providing benefits to future periods. The order authorizes the Company to capitalize the cost of the program and to depreciate the cost over the life of the underground conductor. Therefore, this ratemaking treatment will more closely match the cost of the program with the extended life of the treated cables. The Company expects to spend between $20 and $30 million over the next five years on the program.
RATE MATTERS - GAS
The order approving the Merger, issued by the Washington Commission on February 5, 1997, contains a rate plan which provided unchanged rates for all classes of natural gas customers until January 1, 1999, when rates decreased by approximately $2 million annually.
On October 27, 1999, the Washington Commission approved the Company's PGA and deferral amortization (true-up) filings effective November 1, 1999. The PGA filing allows the Company to recover an expected increase in annual gas costs and the deferral amortization filing allows the Company to recover prior period gas cost undercollections. The filings replaced the PGA and deferral amortization refund that had been effective since April 1, 1998. As a result gas rates to all sales customers increased by an average of 16.3% while rates for gas transportation service as well as gas margins remained unchanged. (See Note 1 to the Consolidated Financial Statements for a description of the Company's PGA mechanism.)
YEAR 2000 CONVERSION
Over the previous three years, the Company conducted an extensive program to ensure the Company was ready for the Year 2000. The Company established a central project team to coordinate all Year 2000 activities and identified exposure in three categories: information technology; embedded chip technology; and external noncompliance by customers and suppliers. The project team took a phased approach in conducting the Year 2000 project for its internal systems. In addition, a specialized embedded systems team was formed by the Company to inventory, assess and remediate microprocessor technology in its generation, transmission and distribution systems for both gas and electric operations.
Through December 31, 1999, the Company's total Year 2000 project costs were approximately $13 million, exclusive of internal labor costs. Approximately $3 million of these costs were capital costs. The Company does not anticipate incurring any further costs related to the Year 2000 project. During the rollover to the Year 2000 and to date, the Company has not experienced any significant problems or interruptions to normal operations related to the Year 2000 issue.
Other
A power supply operating alliance between the Company and Duke Energy Trading and Marketing ("DETM"), whereby the Company participated in the Western market activities of DETM, was terminated effective May 31, 1999. Going forward the Company will perform the functions of minimizing the cost of, and optimizing the value inherent in, its core power supply portfolio. The Company augmented its traditional supply management activities with an energy risk management and hedging program.
In the second quarter of 1999, the Company sold its investment in the common stock of Cabot Oil and Gas Corporation. The after-tax gain of $12.3 million was offset in part by the cost of ConneXt, a wholly-owned subsidiary, exiting certain product lines.
In the third quarter of 1999, the Company sold the assets, liabilities and trade name of its wholly-owned subsidiary, Homeguard Security Services, Inc. The Company also sold in the third quarter of 1999 the majority of the gas pipeline capacity rights and gas storage rights of Washington Energy Gas Marketing ("WEGM", a wholly-owned subsidiary), in the United States and the Province of Alberta, Canada.
In March 1998, the Company entered into an agreement with CellNet Data Services Inc. ("CellNet") under which the Company would lend CellNet up to $35 million in the form of multiple draws so that CellNet can finance an Automated Meter Reading (AMR) network system to be deployed in the Company's service territory. The Company's promissory note with CellNet calls for the network system to serve as collateral for the loan. The term of the loan is five years after the first loan under the agreement is made to CellNet. The loan agreement provides for interest only payments during the five year term, with the principal due at the end of the five year term. In September 1999, the Company announced it was expanding its AMR network system from 800,000 meters to 1,325,000 meters and as a result increased the authorized loan amount to $72 million. On June 30, 1999, the Company made the first loan under the loan agreement and as of December 31, 1999, there were loans outstanding of $31.1 million. In February 2000, CellNet announced it would be acquired by a unit of energy services firm Schlumberger Ltd. The acquisition will be handled through a bankruptcy court filing and requires bankruptcy court approval. The Company does not anticipate a change in its AMR project due to the reorganization of CellNet.
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. In December 1997 and January 1998, the Company and Tenaska Washington Partners entered into revised agreements which will lower purchased power costs from the Tenaska project by
restructuring its natural gas supply. The Company paid $215 million to buy out the project's existing long-term gas supply contracts, which contained fixed and escalating gas prices that were well above current and projected future market prices for natural gas. The Company became the principal natural gas supplier to the project and power purchase prices under the Tenaska contract were revised to reflect market-based prices for the natural gas supply. The Company obtained an order from the Washington Commission creating a regulatory asset related to the $215 million restructuring payment. Under terms of the order, the Company is allowed to accrue as an additional regulatory asset one-half the carrying costs of the deferred balance over the first five years. These revised arrangements are expected to reduce the Company's power supply costs from the Tenaska project an average of between 15% and 20% over the 14 year period from 1998 through 2011, net of the costs of the restructuring payment.
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 owned and operated a natural-gas fired cogeneration facility located at the Georgia Pacific mill near Bellingham, Washington. The contract had obligated the Company to pay fixed and escalating fees well above current and projected future market prices through mid-2008 for the output of the plant. On November 1, 1999, the Company purchased the 160 megawatt plant from Encogen. The Company paid $55 million in cash and assumed $109 million in debt to acquire the partnership, which owned no significant assets other than the plant. Pursuant to an October 27, 1999 order from the Washington Commission approving the purchase, the Company will depreciate the original owner's net book value of the plant over the remaining 23 year useful life of the project. The difference between the purchase price and the net book value of the plant (approximately $72.5 million) will be amortized over 9 years (the remaining term of the power purchase contract). The purchase is expected to reduce the net cost of power from the co-generation project by approximately 17% annually.
In December 1999, the Company bought out the remaining 8.5 years of one of the natural gas supply contracts serving Encogen from Cabot Oil & Gas Corporation which provided approximately 60% of the plant's natural gas requirements. The Company will become the replacement gas supplier to the project for 60% of the supply under terms of the Cabot agreement and expects the agreement will reduce this portion of gas costs by 5% to 15% annually. The Washington Commission has issued an order creating a regulatory asset relating to the $12 million payment that requires the Company to accrue carrying costs on the unamortized balance over the first 3 years.
On November 2, 1998, the Company announced that it signed an agreement to sell the Company's 735-megawatt interest in the four-unit, coal-fired Colstrip generation plant in eastern Montana, as well as associated transmission facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L Resources, Inc. Included in the sale are the Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4; and associated Colstrip transmission capacity across Montana. Completion of the sale is contingent on acceptable regulatory treatment from the Washington Commission. On September 30, 1999, the Washington Commission conditionally approved the Colstrip sale, which at that time was fixed at $556 million. The net book value of these assets and related regulatory assets is approximately $464 million. After taxes and other costs, the Company expected to realize a gain of approximately $37.6 million. However, the terms and conditions of the Washington Commission order made the sale economically unattractive to the Company. The Company appealed the Washington Commission's decision in December 1999. Pending the outcome of the appeal, the Company is working with various parties to obtain other terms and conditions so the sale can proceed.
In May 1999, the eight partners, including the Company, in the Centralia coal fired generating plant project announced the sale of the plant to TransAlta Corporation of Calgary, Canada. The purchase price of the plant and the adjacent mine (owned and operated by PacifiCorp) is $554 million. The Company owns a 7% interest in the plant. The transaction is currently under review by the Washington Commission.
SAFE HARBOR
The Company is including the following cautionary statement in this Form 10-K to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company.
Any statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "anticipates", "believes", "estimates", "expects", "intends", "plans", "predicts", "projects", "will likely result", "will continue", or similar expressions) are not statements of historical facts and may be forward-looking.
Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that the Company's expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere herein, some important factors that could cause actual results or outcomes for the Company to differ materially from those discussed in forward-looking statements include:
- prevailing legislative developments, governmental policies and regulatory actions with respect to allowed rates of return, financings, or industry and rate structures - weather and hydroelectric conditions - effect of competition - changes in and compliance with environmental and endangered species laws and policies - population growth rates and demographic patterns - capital market conditions - legal and regulatory proceedings
Any forward-looking statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all such factors, nor can it assess the impact of any such factor on the business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
ITEM 7a.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risks, including changes in commodity prices and interest rates.
Commodity Price Risk
The Company manages its energy supply portfolio to achieve three primary objectives:
(i) Ensure that physical energy supplies are available to serve retail customer requirements; (ii) Manage portfolio risks to limit undesired impacts on Company financial results; and (iii) Optimize the value of the Company's energy supply assets.
The portfolio is subject to major sources of variability (e.g., hydro generation, temperature-sensitive retail sales, and market prices for gas and power supplies). At certain times, these sources of variability can mitigate portfolio imbalances; at other times they can exacerbate portfolio imbalances.
Hedging strategies for the Company's energy supply portfolio interact with portfolio optimization activities. Some hedges can be implemented in ways that retain the Company's ability to use its energy supply portfolio to produce additional value, other hedges can only be achieved by forgoing optimization opportunities.
The prices of energy commodities and transportation services are subject to fluctuations due to unpredictable factors including weather, transportation congestion and other factors which impact supply and demand. This commodity price risk is a consequence of purchasing energy at fixed and variable prices and providing deliveries at different tariff and variable prices. Costs associated with ownership and operation of production facilities are another component of this risk. The Company may use forward delivery agreements, swaps and option contracts for the purpose of hedging commodity price risk. Unrealized changes in the market value of these derivatives are deferred and recognized upon settlement along with the underlying hedged transaction. In addition, the Company believes its current rate design, including its Optional Large Power Sales Rate, various special contracts and the PGA mechanism mitigate a portion of this risk.
Market risk is managed subject to parameters established by the Board of Directors. A Risk Management Committee separate from the units that manage these risks monitors compliance with the Company's policies and procedures. In addition, the Audit Committee of the Company's Board of Directors has oversight of the Risk Management Committee.
Interest rate risk
The Company believes interest rate risk of the Company primarily relates to the use of short-term debt instruments and new long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt of various maturities. The Company does utilize bank borrowings, commercial paper and line of credit facilities to meet short-term cash requirements. These short-term obligations are commonly refinanced with fixed rate bonds or notes when needed and when interest rates are considered favorable. The Company may enter into swap instruments to manage the interest rate risk associated with these debts, and three interest rate swaps were outstanding as of December 31, 1999. The carrying amounts and fair values of the Company's fixed rate debt instruments are described in Note 10 to the Consolidated Financial Statements.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See index on page 38.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
Part III is incorporated by reference from the Company's definitive proxy statement issued in connection with the 2000 Annual Meeting of Shareholders.
Certain information regarding executive officers is set forth in Part I.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1) Financial statement schedule - see index on page 38.
2) Exhibits - see index on page 74.
(b) Reports on Form 8-K:
The Company did not file any reports on Form 8-K during the quarter ended December 31, 1999.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUGET SOUND ENERGY, INC.
William S. Weaver ------------------------ William S. Weaver President and Chief Executive Officer Date: March 3, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE - ------------------------------------------------------------------------------
William S. Weaver President, Chief Executive March 3, 2000 - ------------------------- (William S. Weaver) Officer and Director
Richard L. Hawley Vice President - ------------------------- (Richard L. Hawley) and Chief Financial Officer
James W. Eldredge Corporate Secretary - ------------------------- (James W. Eldredge) and Controller and Chief Accounting Officer
Douglas P. Beighle Director - ------------------------- (Douglas P. Beighle)
Charles W. Bingham Director - ------------------------- (Charles W. Bingham)
Phyllis J. Campbell Director - ------------------------- (Phyllis J. Campbell)
Craig W. Cole
- ------------------------- (Craig W. Cole) Director
SIGNATURE TITLE DATE - ------------------------------------------------------------------------------
Donald J. Covey Director March 3, 2000 - ------------------------- (Donald J. Covey)
Robert L. Dryden Director - ------------------------- (Robert L. Dryden)
Director
- ------------------------- (John D. Durbin)
John W. Ellis Director - ------------------------- (John W. Ellis)
Daniel J. Evans Director - ------------------------- (Daniel J. Evans)
Tomio Moriguchi Director
- ------------------------- (Tomio Moriguchi)
Sally G. Narodick Director - ------------------------- (Sally G. Narodick)
REPORT OF MANAGEMENT PUGET SOUND ENERGY, INC.
The accompanying consolidated financial statements of Puget Sound Energy, Inc. have been prepared under the direction of management, which is responsible for their integrity and objectivity. The statements have been prepared in accordance with generally accepted accounting principles and include amounts based on judgments and estimates by management where necessary. Management also prepared the other information in the Annual Report on Form 10-K and is responsible for its accuracy and consistency with the financial statements.
The Company maintains a system of internal control which, in management's opinion, provides reasonable assurance that assets are properly safeguarded and transactions are executed in accordance with management's authorization and properly recorded to produce reliable financial records and reports. The system of internal control provides for appropriate division of responsibility and is documented by written policy and updated as necessary. The Company's internal audit staff assesses the effectiveness and adequacy of the internal controls on a regular basis and recommends improvements when appropriate. Management considers the internal auditor's and independent auditor's recommendations concerning the Company's internal controls and takes steps to implement those that they believe are appropriate in the circumstances.
In addition, PricewaterhouseCoopers LLP, the independent accountants, have performed audit procedures deemed appropriate to obtain reasonable assurance about whether the financial statements are free of material misstatement.
The Board of Directors pursues its oversight role for the financial statements through the audit committee, which is composed solely of outside Directors. The audit committee meets regularly with management, the internal auditors and the independent auditors, jointly and separately, to review management's process of implementation and maintenance of internal accounting controls and auditing and financial reporting matters. The internal and independent auditors have unrestricted access to the audit committee.
William S. Weaver Richard L. Hawley James W. Eldredge - --------------------- ------------------------ ----------------------------- William S. Weaver Richard L. Hawley James W. Eldredge President and Chief Vice President and Chief Corporate Secretary and Executive Officer Financial Officer Controller (Chief Accounting Officer)
REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Puget Sound Energy, Inc.:
In our opinion, the consolidated financial statements listed on page 38 of this Annual Report on Form 10-K present fairly, in all material respects, the financial position of Puget Sound Energy, Inc. and its subsidiaries (the "Company") at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. In addition, in our opinion, the financial statement schedule listed on page 38 of this document presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP Seattle, Washington February 10, 2000
Consolidated Financial Statements, Financial Statement Schedule and Exhibits Covered by the Foregoing Report of Independent Accountants
CONSOLIDATED FINANCIAL STATEMENTS: PAGE
Consolidated Statements of Income for the years ended December 31, 1999, 1998 and 1997 39
Consolidated Balance Sheets, December 31, 1999 and 1998 40-41
Consolidated Statements of Capitalization, December 31, 1999 and 1998 42
Consolidated Statements of Earnings Reinvested in the Business
for the years ended December 31, 1999, 1998 and 1997 43
Consolidated Statements of Comprehensive Income for the years ended December 31, 1999, 1998 and 1997 43
Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997 44
Notes to Consolidated Financial Statements 45
Schedule:
II. Valuation and Qualifying Accounts and Reserves for the years ended December 31, 1999, 1998 and 1997 73
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 74
Consolidated Statements of
INCOME
The accompanying notes are an integral part of the consolidated financial statements.
Consolidated Balance Sheets
ASSETS
(at December 31; dollars in thousands) 1999 1998 - -------------------------------------------------------------------------------- Utility Plant: Electric plant $3,966,220 $3,640,647 Gas plant 1,371,589 1,278,275 Common plant 314,770 233,086 Less: Accumulated depreciation and amortization 1,901,658 1,721,096 - -------------------------------------------------------------------------------- Net utility plant 3,750,921 3,430,912 - -------------------------------------------------------------------------------- Other Property and Investments: Investment in Bonneville Exchange Power Contract 61,716 70,537 Other 202,488 189,550 - -------------------------------------------------------------------------------- Total other property and investments 264,204 260,087 - -------------------------------------------------------------------------------- Current Assets: Cash 65,707 28,216 - -------------------------------------------------------------------------------- Accounts receivable 214,523 190,658 Less: Allowance for doubtful accounts (1,503) (1,020) - -------------------------------------------------------------------------------- Total accounts receivable 213,020 189,638 - -------------------------------------------------------------------------------- Unbilled revenues 121,303 126,740 Purchased gas receivable 33,700 5,492 Materials and supplies, at average cost 69,241 58,534 Prepayments and other 9,822 7,990 - -------------------------------------------------------------------------------- Total current assets 512,793 416,610 - -------------------------------------------------------------------------------- Long-Term Assets: Regulatory asset for deferred income taxes 228,454 241,406 PURPA buyout costs 238,734 221,802 Other 150,500 138,870 - -------------------------------------------------------------------------------- Total long-term assets 617,688 602,078 - -------------------------------------------------------------------------------- Total Assets $5,145,606 $4,709,687 ================================================================================
The accompanying notes are an integral part of the consolidated financial statements.
Consolidated Balance Sheets
CAPITALIZATION AND LIABILITIES
(AT DECEMBER 31; DOLLARS IN THOUSANDS) 1999 1998 - -------------------------------------------------------------------------------- Capitalization: (See "Consolidated Statements of Capitalization"): Common equity $1,379,073 $1,352,680 Preferred stock not subject to mandatory redemption 60,000 95,075 Preferred stock subject to mandatory redemption 65,662 73,162 Corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation 100,000 100,000 Long-term debt 1,783,139 1,475,106 - -------------------------------------------------------------------------------- Total capitalization 3,387,874 3,096,023 - -------------------------------------------------------------------------------- Current Liabilities: Accounts payable 178,218 163,141 Short-term debt 604,712 450,905 Current maturities of long-term debt 47,620 107,000 Accrued expenses: Taxes 72,688 59,764 Salaries and wages 18,023 18,650 Interest 43,955 39,062 Other 24,129 23,150 - -------------------------------------------------------------------------------- Total current liabilities 989,345 861,672 - -------------------------------------------------------------------------------- Deferred Income Taxes 636,735 628,554 - -------------------------------------------------------------------------------- Other Deferred Credits 131,652 123,438 - -------------------------------------------------------------------------------- Commitments and Contingencies -- -- - -------------------------------------------------------------------------------- Total Capitalization and Liabilities $5,145,606 $4,709,687 ================================================================================
The accompanying notes are an integral part of the consolidated financial statements.
* 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.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
Notes
To Consolidated Financial Statements Note 1.
Summary of Significant Accounting Policies
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 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 was structured as a tax-free exchange of shares, and is accounted for as a pooling of interests for financial statement purposes
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. Certain reclassifications have been made to the prior year financial statements to conform to the current year's presentation with no material effect on consolidated net income, total assets or common equity.
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 employee 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.
REGULATORY ASSETS & AGREEMENTS
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 and liabilities at December 31, 1999 and 1998, included the following:
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" ("Statement No. 101"). Adoption of Statement No. 101 would require the Company to write off the regulatory assets and liabilities related to those operations not meeting Statement No. 71 requirements. Discontinuation of Statement No. 71 could have a material impact on the Company's financial statements.
The Emerging Issues Task Force ("EITF") of the Financial Accounting Standards Board ("FASB") has issued its Consensus 97-4 which addresses when an entity should discontinue the application of Statement No. 71, and how Statement No. 101 should be applied to a portion of an entity subject to a transition-to-competition plan. The EITF states that Statement No. 71 shall be discontinued at a date no later than when the details of the transition-to-competition plan for all or a portion of the entity subject to such plan are known. Additionally, the EITF reached a consensus that stranded costs which are to be recovered through cash flows derived from another portion of the entity which continues to apply Statement No. 71 should not be written off; rather, they should be considered regulatory assets of the segment which will continue to apply Statement No. 71.
Although discussions with regulatory authorities regarding retail competition have occurred and are expected to continue, no transition to competition plans for the Company's regulated operations have been proposed. The Company's financial statements continue to apply Statement No. 71 for regulated operations.
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 was recovered in rates over the ten years ended December 31, 1999, without a return during the recovery period (the related amortization is included in "Depreciation and Amortization", pursuant to a FERC accounting order).
The Company has regulatory assets of approximately $239 million related to the buyout of purchased power and gas sales contracts of two non-utility generation projects. Washington Commission accounting orders have approved the payments for deferral and collection in rates over the remaining life of the energy supply contracts. Under terms of the orders, the Company is allowed to accrue as an additional regulatory asset certain carrying costs of the deferred balances.
The Company also has agreements under which ConneXt, a wholly owned subsidiary of the Company, performs certain billing and customer information technology functions. Under an accounting order approved by the Washington Commission, the Company records payments to ConneXt as if such costs were paid to third-party providers and these costs will be reviewed in a future rate filing.
OPERATING REVENUES
Operating revenues are recorded on the basis of service rendered, which includes estimated unbilled revenue.
ENERGY CONSERVATION
The Company accumulates energy conservation expenditures which are included in rate base and amortized to expense as prescribed by 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 Company sold an additional investment of $35.2 million in customer-owned energy conservation measures in August 1997. The proceeds of the sales were used to pay down short-term debt. The Company recognized no gain or loss on the sales.
SELF-INSURANCE
The Company currently has 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. With approval of the Washington Commission, the Company is able to defer for collection in future rates certain uninsured storm damage costs associated with major storms.
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 average original cost of depreciable electric utility plant was 3.0% in 1999, 1998 and 1997 and for depreciable gas utility plant was 3.4% in 1999,1998 and 1997.
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. Investment tax credits are deferred and amortized based on the average useful life of the related property in accordance with regulatory and income tax requirements. (See Note 13)
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 9.15% in 1999, 1998 and 1997. 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: $4,262,000 for 1999, $3,409,000 for 1998 and $2,704,000 for 1997. The deferred asset is being amortized over the average useful life of the Company's non-project utility plant.
PERIODIC RATE ADJUSTMENT MECHANISM
In April 1991, the Washington Commission issued an order establishing a Periodic Rate Adjustment Mechanism ("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.
In September 1996, pursuant to a negotiated settlement with the Washington Commission, the PRAM was discontinued. 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 was refunded to customers in the second quarter of 1997.
With the discontinuance of the PRAM, the Company no longer has an electric rate adjustment mechanism to adjust for changes in energy or fuel costs or variances in hydro and weather conditions. These variances may now significantly influence earnings.
PGA MECHANISM
Differences between the actual cost of the Company's gas supplies and gas transportation contracts and that currently allowed by the Washington Commission are deferred and recovered or repaid through the purchased gas adjustment ("PGA") mechanism.
On June 25, 1998, the Company received approval from the Washington Commission to begin a new performance-based mechanism for strengthening its gas-supply purchasing and gas-storage practices. The PGA Incentive Mechanism, which encourages competitive gas purchasing and management of pipeline and storage-capacity, became effective July 1, 1998. Incentive gains and losses from the three-year program are shared between customers and shareholders. After the first $0.5 million, which is allocated to customers, gains and losses are shared 40%/60% between the Company and customers up to $26.5 million and 33%/67% thereafter. Gains or losses are determined relative to a weighted average index which is reflective of the Company's gas supply and transportation contract costs. The Company's share of incentive gains under the PGA Incentive Mechanism in 1999 and 1998 were approximately $7.2 million and $1.1 million, respectively, while customers received approximately $11.3 and $2.0 million, respectively.
OFF-SYSTEM SALES AND CAPACITY RELEASE
The Company has been selling excess gas supplies and entering into gas supply exchanges with third parties outside of its distribution area since 1992. The Company 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 proceeds, net of transactional costs, 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 direct 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.
ENERGY RISK MANAGEMENT
The Company's energy related businesses are exposed to risks related to changes in commodity prices. As part of its business, the Company markets power to wholesale customers by entering into contracts to purchase or supply electric energy or natural gas at specified delivery points and at specified future delivery dates. The Company's energy risk management function manages the Company's core electric and gas supply portfolios.
The Company manages its energy supply portfolio to achieve three primary objectives:
(i) Ensure that physical energy supplies are available to serve retail customer requirements; (ii) Manage portfolio risks to limit undesired impacts on Company financial results; and (iii) Optimize the value of the Company's energy supply assets.
The Company enters into futures and options for the purpose of hedging commodity price risk. Gains or losses on these derivatives are deferred and recognized upon settlement along with the underlying sales or purchase contract. The Company has established policies and procedures to manage these risks. A Risk Management Committee separate from the units that create these risks monitors compliance with the Company's policies and procedures. In addition, the Audit Committee of the Company's Board of Directors has oversight of the Risk Management Committee.
During the first quarter of 1999, the Company adopted Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk management Activities" ("EITF 98-10") issued by the Emerging Issues Task Force of the Financial Accounting Standards Board ("FASB"). EITF 98-10 addresses accounting for the purchase and sale of energy trading contracts and is effective for fiscal years beginning after December 15, 1998. The conclusion reached by the EITF was that such contracts should be recorded at fair value when entered into for trading activities with the mark-to-market gains or losses recorded in current earnings. The Company does not consider its current operations to meet the definition of trading activities as described by EITF 98-10. Accordingly, the adoption of EITF 98-10 did not have an impact on the Company's financial position or results of operations.
In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("Statement No. 133"). In July 1999, the FASB issued Statement of Financial Accounting Standards No. 137 which delayed the effective date of Statement No. 133 for one year, to fiscal years beginning after June 15, 2000. Statement No. 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. The Company has not yet determined the impact that the adoption of Statement No. 133 will have on its financial statements.
OTHER
Debt premium, discount and expenses are amortized over the life of the related debt. The premiums and costs associated with reacquired debt are being amortized over the life of the related new issuances, in accordance with ratemaking treatment.
In April 1998, the Accounting Standards Executive Committee issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities" ("SOP 98-5"). SOP 98-5 was adopted by the Company in the first quarter of 1999. SOP 98-5 provides guidance on the financial reporting of start-up costs and organization costs. It requires costs of start-up activities and organization costs to be expensed as incurred. Adoption of SOP 98-5 did not have a material impact on the Company's financial position or results of operations.
EARNINGS PER COMMON SHARE
Basic earnings per common share have been computed based on weighted average common shares outstanding of 84,613,000, 84,561,000 and 84,560,000 for 1999, 1998 and 1997, respectively. Diluted earnings per common share have been computed based on weighted average common shares outstanding of 84,847,000, 84,768,000 and 84,628,000 for 1999, 1998 and 1997, respectively, which include the dilutive effect of securities related to employee compensation plans.
NOTE 2. UTILITY PLANT
Utility plant at December 31, 1999 and 1998 included the following:
On November 1, 1999, the Company purchased a 160 megawatt natural gas-fired cogeneration plant from Encogen Northwest L.P. for $164 million. Pursuant to an October 27, 1999 order from the Washington Commission approving the purchase, the Company will depreciate the original owner's net book value of the plant over the remaining 23 year useful life of the project. The difference between the purchase price and the net book value of the plant (approximately $72.5 million) will be amortized over 9 years.
In December 1999, the Company bought out the remaining 8.5 years of one of the natural gas supply contracts serving Encogen from Cabot Oil & Gas Corporation which provided approximately 60% of the plant's natural gas requirements. The Company will become the replacement gas supplier to the project for 60% of the supply under terms of the Cabot Agreement. The Washington Commission has issued an order creating a regulatory asset relating to the $12 million payment that requires the Company to accrue carrying costs on the unamortized balance over the first 3 years.
NOTE 3. CAPITAL STOCK
See "Consolidated Statements of Capitalization" for details on specific series.
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.
The weighted average dividend rate for the Adjustable Rate Cumulative Preferred Stock ("ARPS"), Series B ($25 par value) was 4.23% for 1999, 4.83% for 1998 and 5.61% for 1997. The Company reacquired 16,500 shares of ARPS Series B through open-market purchases during 1998 and redeemed the remaining ARPS on February 2, 1999 at $25 par plus accrued dividends through February 2, 1999. The 8.50% Series Preferred was redeemed at par plus accrued dividends on September 1, 1999. The 7.45% Series Preferred may be redeemed at par on or after November 1, 2003.
NOTE 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 and 7.75% Series, 37,500 shares. All previous sinking fund requirements have been satisfied. At December 31, 1999, there were 33,192 shares of the 4.84% Series and 49,689 shares of the 4.70% 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 and 4.70% Series, $101. The 7.75% Series may be redeemed by the Company, subject to certain restrictions, at $104.13 per share plus accrued dividends through February 15, 2000, and at per share amounts which decline annually to a price of $100 after February 15, 2007.
NOTE 5. COMPANY-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED SECURITIES
In 1997, the Company formed Puget Sound Energy Capital Trust I (the "Trust") for the sole purpose of issuing and selling common and preferred securities ("Trust Securities"). The proceeds from the sale of Trust Securities were used to purchase Junior Subordinated Debentures ("Debentures") from the Company. The Debentures are the sole assets of the Trust and the Company owns all common securities of the Trust.
The Debentures have an interest rate of 8.231% and a stated maturity date of June 1, 2027. The Trust Securities are subject to mandatory redemption at par on the stated maturity date of the Debentures. The Trust Securities may be redeemed earlier, under certain conditions, at the option of the Company. Dividends relating to preferred securities are included in interest expense.
NOTE 6. ADDITIONAL PAID-IN CAPITAL
The changes in Additional Paid-in Capital are as follows:
NOTE 7. EARNINGS REINVESTED IN THE BUSINESS
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock and long-term debt contained in the Company's Articles of Incorporation and Mortgage Indentures. Under the most restrictive covenants, earnings reinvested in the business unrestricted as to payment of cash dividends were approximately $202 million at December 31, 1999.
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 Company's Articles and Mortgage Indentures. (See Note 1.)
NOTE 8. LONG-TERM DEBT
In September 1998, the Company filed a shelf-registration statement with the Securities and Exchange Commission for the offering, on a delayed or continuous basis, of up to $500 million principal amount of Senior Notes secured by a pledge of First Mortgage Bonds. On March 9, 1999, the Company issued $250 million principal amount of Senior Medium-Term Notes, Series B, which consisted of $150 million principal amount due March 9, 2009 at an interest rate of 6.46% and $100 million principal amount due March 9, 2029 at an interest rate of 7.0%. On February 22, 2000, the Company issued $225 million principal amount of 7.96% Senior Medium-Term Notes, Series B. The Notes are due February 22, 2010 and proceeds were used to redeem the Encogen project debt and pay down a portion of the Company's short-term debt.
Substantially all utility properties owned by the Company are subject to the lien of the Company's electric and gas mortgage indentures.
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%.
PROJECT DEBT
On November 1, 1999, the Company assumed approximately $109 million of project debt under the agreement to purchase the 160-megawatt natural gas-fired cogeneration plant from Encogen Northwest L.P. Interest rates on the project debt ranged from 8.64% to 13.03%. In February 2000, the Company used a portion of the proceeds from the issuance of $225 million principal amount of Senior Medium-Term notes to pay off the project debt. At December 31, 1999, the project debt was included in Other notes.
LONG-TERM DEBT MATURITIES
The principal amounts of long-term debt maturities for the next five years are as follows:
NOTE 9. SHORT-TERM DEBT AND OTHER FINANCING ARRANGEMENTS
At December 31, 1999, the Company had short-term borrowing arrangements which included a $375 million line of credit with thirteen banks. The agreement provides the Company with the ability to borrow at different interest rate options and includes variable fee levels. 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 .25 percent. The current availability fee is .08 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.
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 debt. One agreement outstanding at December 31, 1999, effectively changes the Company's interest rate on outstanding commercial paper to 9.64% on a notional principal amount of $16.5 million expiring March 31, 2000. Two other agreements outstanding at December 31, 1999, effectively change the Company's interest rate on outstanding commercial paper to 7.39% on a notional principal amount of $53.0 million expiring June 29, 2007.
___________________________ (1) Provides liquidity support for outstanding commercial paper and borrowing from credit line banks in the amount of $105.7 million, $167.1 million and $339.5 million for 1999, 1998 and 1997 respectively, effectively reducing the available borrowing capacity under these credit lines to $269.3 million, $207.9 million and $35.5 million, respectively.
NOTE 10. 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, 1999 and 1998:
The fair value of outstanding bonds including current maturities is estimated based on quoted market prices.
The preferred stock subject to mandatory redemption and corporation obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely junior subordinated debentures of the corporation 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 original 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.
Derivative instruments have been used by the Company on a limited basis. The Company has a policy that financial derivatives are to be used only to mitigate business risk and not for speculative purposes.
_______________________________ (1) 1999 carrying amount includes an adjustment of $13.5 million to report the available-for-sale securities at market value. This amount has been included as a component of other comprehensive income net of deferred taxes of $4.7 million.
NOTE 11. SUPPLEMENTARY INCOME STATEMENT INFORMATION
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.
NOTE 12. 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, 1999, 1998 and 1997, were approximately $19,179,000, $ 17,798,000 and $19,428,000, respectively. Payments due for the years ended December 31, 1999, 1998 and 1997, for the sublease of properties were approximately $2,321,000, $1,242,000, and $962,000, respectively.
Future minimum lease payments for noncancelable leases are approximately $16,459,000 for 2000, $14,621,000 for 2001, $14,210,000 for 2002, $12,019,000 for 2003, $7,854,000 for 2004 and in the aggregate, $9,252,000 thereafter. Future minimum sublease receipts for noncancelable subleases are $2,025,000 for 2000, $2,025,000 for 2001, $2,025,000 for 2002, $2,025,000 for 2003, $3,000 for 2004 and in the aggregate, $3,000 thereafter.
NOTE 13. FEDERAL INCOME TAXES
The details of federal income taxes ("FIT") are as follows:
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:
The following are the principal components of FIT as reported:
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 rate making 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, 1999, the balance of this asset is $228.5 million.
The deferred tax liability at December 31, 1999 and 1998, is comprised of amounts related to the following types of temporary differences
The totals of $636.7 million and $628.6 million for 1999 and 1998 consist of deferred tax liabilities of $719.7 million and $712.2 million net of deferred tax assets of $83.0 million and $83.6 million, respectively.
NOTE 14. RETIREMENT BENEFITS
The Company has a defined benefit pension plan covering substantially all of its employees. Benefits are a function of both age and salary. Additionally, the Company maintains a non-qualified supplemental retirement plan for officers and certain director-level employees.
In addition to providing pension benefits, the Company 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.
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In accounting for pension and other benefits costs under the plans, the following weighted average actuarial assumptions were used:
The projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $29 million, $23.7 million, and $0, respectively, as of December 31, 1999.
The assumed medical inflation rate is 7% in 1999 decreasing to 6% in 2003. A 1% change in the assumed medical inflation rate would have the following effects:
In December 1995, in connection with the proposed merger with WECo, the Company 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 loss under Statement No. 106 for 1997 of $4.7 million. Also in connection with the merger was a curtailment loss of $5.1 million in 1997 related to the supplemental retirement plans.
NOTE 15. EMPLOYEE INVESTMENT PLAN & EMPLOYEE STOCK PURCHASE PLAN
The Company has qualified Employee Investment Plans under which employee salary deferrals and after-tax contributions are used to purchase several different investment fund options. The Company makes a monthly contribution equal to 100% on up to 4% of participant contributions and 50% on the next 4% of participant contributions which equates to a maximum contribution of 6% of eligible earnings. In addition, the Company contributes an amount equal to 1% of each participant's base pay at the end of the plan year.
The Company contributions to the Employee Investment Plan were $7,123,400, $6,532,400 and $5,000,200 for the years 1999, 1998 and 1997, 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, 1999. The Employee Investment Plan eligibility requirements are set forth in the plan documents.
The Company also has an Employee Stock Purchase Plan which was approved by shareholders on May 19, 1997, and commenced July 1, 1997, under which options are granted to eligible employees who elect to participate in the plan on January 1st and July 1st of each year. Participants are 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 during 1999 was 90% of either the fair market value of the common stock at the grant date or the fair market value at the exercise date, whichever is less. Effective with the beginning of the next offering period on January 1, 2000, the option price will be 85% of either the fair market value of the common stock at the grant date or the fair market value at the exercise date, whichever is less. The Company contributions to the Plan were $88,900, $98,200 and $97,600 for 1999, 1998 and 1997, respectively.
On February 1, 1998, the Company granted 50 performance shares to 2,800 eligible employees in recognition of their efforts to implement the Company's strategies. On February 1, 2000, those performance shares and dividend equivalents were converted to common stock. Total cost of the performance share grant program was $4,053,400.
NOTE 16. OTHER INVESTMENTS
In May 1994, the Company merged its oil and gas exploration and production subsidiary, Washington Energy Resources Company ("Resources"), with a wholly-owned subsidiary of Cabot Oil and Gas Corporation ("Cabot") in a tax-free exchange. At December 31, 1998, the Company owned 15.4% of Cabot's outstanding voting securities consisting of 2,133,000 shares of common stock and 1,134,000 shares of 6% convertible voting preferred stock, stated value $50. For 1998, the investment in Cabot common stock was classified as an available-for-sale security and was reported at its fair value of $31,995,000. The unrealized gain of $8,802,000 (net of deferred taxes of $4,739,000) was included as a separate component of common equity. In May 1999, the Company sold the 2,133,000 shares of common stock and recorded an after-tax gain of $12.3 million. At the time of the sale, the fair value of the stock was $37,350,000, resulting in an increase of $3,483,000 in the unrealized gain. This amount has been included as a component of other comprehensive income, net of deferred taxes of $1,875,000. The $12.3 million realized gain on the sale has been reclassified out of accumulated other comprehensive income. No fair value is readily available for the Cabot preferred stock as it is not publicly traded; however, its cost basis of $51,619,000 is believed to be a reasonable approximation of fair value at December 31, 1999. The Company has an agreement that Cabot, subject to certain conditions, will repurchase all shares of the preferred stock by November 1, 2000. Prior to October 1, 1997, the Company's interest in Cabot's common stock was accounted for using the equity method because the Company, through its representation on Cabot's board of directors, had the ability to exercise significant influence over operating and financial policies of Cabot. Effective October 1, 1997, the Company discontinued equity-method accounting for Cabot and records its interest as an investment in stock because the Company no longer has representation on Cabot's board of directors. Equity in earnings from Cabot was $948,000 for 1997. See Note 17 regarding certain gas transportation, storage and other contractual arrangements of Resources that were excluded from the Cabot merger and retained by a subsidiary of the Company.
In March 1998, the Company entered into an agreement with CellNet Data Services Inc. ("CellNet") under which the Company would lend CellNet up to $35 million in the form of multiple draws so that CellNet can finance an Automated Meter Reading (AMR) network system to be deployed in the Company's service territory. In September 1999, the Company announced it was expanding its AMR network system from 800,000 meters to 1,325,000 meters and as a result increased the authorized loan amount to $72 million. On June 30, 1999, the Company made the first loan under the loan agreement and as of December 31, 1999, there were loans outstanding of $31.1 million.
NOTE 17. COMMITMENTS AND CONTINGENCIES
COMMITMENTS - ELECTRIC
For the twelve months ended December 31, 1999, approximately 23.2% of the Company's energy output was obtained at an average cost of approximately 9.4 mills per KWH through long-term contracts with several of the Washington public utility districts ("PUDs") owning hydro-electric 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, 1999, the Company was entitled to purchase portions of the power output of the PUDs' projects as set forth in the following tabulation:
The Company's estimated payments for power purchases from the Columbia River projects are $81 million for 2000, $80 million for 2001, $80 million for 2002, $78 million for 2003, $76 million for 2004 and in the aggregate, $605 million thereafter through 2018.
The Company also has numerous long-term firm purchased power contracts with other utilities 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, excluding the Columbia River projects, are $155 million for 2000, $150 million for 2001, $141 million for 2002, $130 million for 2003, $77 million for 2004 and in the aggregate, $707 million thereafter through 2037. These contracts have varying terms and may include escalation and termination provisions.
As required by the federal Public Utility Regulatory Policies Act ("PURPA"), the Company entered into long-term firm purchased power contracts with non-utility generators. The Company purchases the net electrical output of four significant projects at fixed and annually escalating prices which were intended to approximate the Company's avoided cost of new generation projected at the time these agreements were made. Principally, as a result of dramatic changes in natural gas price levels, the power purchase prices under these agreements are significantly above the current market price of power and, based upon projections of future market prices, are expected to remain well above market for the duration of the contracts. The Company's estimated payment under these four contracts are $181 million for 2000, $204 million for 2001, $206 million for 2002, $207 million for 2003, $213 million for 2004 and in the aggregate, $1.5 billion thereafter through 2012. If retail electric energy prices move to market levels as a result of electric industry restructuring, the Company plans to seek to continue to recover in rates the above-market portion of these contract costs.
____________________________ (1) The Company is unable to predict whether the licenses under the Federal Power Act will be renewed to the current licensees. 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.
(2) 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 date are: 40.8% at Rock Island; 45.7% at Rocky Reach; 81.3% at Priest Rapids; and 49.7% at Wanapum; and 5.1% at Wells.
(3) The components of 1999 costs associated with the interest portion of debt service are: Rock Island, $23.2 million for all units; Rocky Reach, $5.3 million; Wells, $2.7 million; Priest Rapids, $0.8 million; and Wanapum, $1.1 million.
The following table summarizes the Company's obligations for future power purchases.
Total purchased power contracts provided the Company with approximately 16.1 million, 15.8 million and 15.6 million MWH of firm energy at a cost of approximately $487.4 million, $481.6 million and $464.5 million for the years 1999, 1998 and 1997, respectively.
As part of its electric operations and in connection with the 1997 restructuring of the Tenaska Power Purchase Agreement the Company is obligated to deliver to Tenaska up to 48,000 MMBtu per day of natural gas for operation of Tenaska's cogeneration facility. This obligation continues for the remaining term of the agreement, provided that no deliveries are required during the month of May. The price paid by Tenaska for this gas is reflective of the daily price of gas at the U.S./Canada border near Sumas, Washington.
As part of its electric operations and in connection with the 1999 buy-out of the Cabot gas supply contract, the Company is obligated to deliver to Encogen up to 21,800 MMBtu per day of natural gas for operation of the Encogen cogeneration facility. This obligation continues for the remaining term of the original Cabot agreement. The price paid by Encogen for this gas is reflective of the price paid under the Cabot agreement. The difference between the price paid by Encogen and the replacement cost of gas at current market prices will reduce the Company's cost of power. The Company entered into two financial arrangements to hedge future gas supply costs associated with this obligation, hedging 20,000 MMBtu per day for 2000, and 10,000 MMBtu per day for the remaining term of the agreement. Encogen has two remaining gas supply agreements that comprise 40% of the plant's requirements with remaining terms of 8.5 years. Not included in the table above are Encogen's obligations under these contracts of $11,821,000 in 2000, $12,414,000 in 2001, $13,047,000 in 2002, $13,690,000 in 2003, $14,375,000 in 2004 and $65,098,000 in the aggregate thereafter.
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, 1999:
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.
On November 2, 1998, the Company announced that it signed an agreement to sell the Company's 735-megawatt interest in the four-unit, coal-fired Colstrip generation plant in eastern Montana, as well as associated transmission facilities. The Company signed the agreement with PP&L Global, Inc., of Fairfax, Virginia, a subsidiary of PP&L Resources, Inc. Included in the sale are the Company's 50% interest in Colstrip Units 1 and 2; 25% interest in Units 3 and 4; and associated Colstrip transmission capacity across Montana. Completion of the sale is contingent on acceptable regulatory treatment from the Washington Commission. On September 30, 1999, the Washington Commission conditionally approved the Colstrip sale, which at that time was fixed at $556 million. The net book value of these assets and related regulatory assets is approximately $464 million. After taxes and other costs, the Company expected to realize a gain of approximately $37.6 million. However, the terms and conditions of the Washington Commission order made the sale economically unattractive to the Company. The Company appealed the Washington Commission's decision in December 1999. Pending the outcome of the appeal, the Company is working with various parties to obtain other terms and conditions so the sale can proceed.
In May 1999, the eight partners, including the Company, in the Centralia coal fired generating plant project announced the sale of the plant to TransAlta Corporation of Calgary, Canada. The purchase price of the plant and the adjacent mine (owned and operated by PacifiCorp) is $554 million. The Company owns a 7% interest in the plant. The transaction is currently under review by the Washington Commission.
GAS
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 from one to 24 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. 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 1999 for firm gas supply, firm transportation service and firm storage and peaking service of $31,012,000, $52,190,000 and $8,799,000, 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.
DEMAND CHARGE OBLIGATIONS
MINIMUM ANNUAL TAKE OBLIGATIONS
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 65% of expected annual sales for 2000 and less than 49% of expected sales in subsequent years.
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
Washington Energy Gas Marketing Company ("WEGM"), a wholly-owned subsidiary, holds firm rights to transport natural gas on the Nova Corporation of Alberta ("Nova"), and Alberta Natural Gas Company ("ANG"), pipelines from Alberta, Canada, to the northern border of Idaho, 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 Washington Energy 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 management contract terminated on September 30, 1999. WEGM's annual obligations for future demand charges through the primary term of WEGM's gas transportation and storage contracts are as follows: 2000, $778,200; 2001, $778,200; 2002, $778,200; 2003, $634,900; 2004, $553,000 and thereafter, $1,924,000.
Through October of 1999, WEGM also held firm rights to transport natural gas on the PG&E Gas Transmission - Northwest ("PGT") pipeline from the northern Idaho border to the northern California border. Effective November 1, 1999, WEGM sold its remaining interests in the PGT pipeline capacity.
As of December 31, 1999, WEGM has a reserve for future losses associated with the remaining contractual obligations of $1,779,800. In the third quarter of 1999, WEGM recorded a $4,888,400 ($3,177,500 after tax) charge based on the sale of its interest in the PGT pipeline capacity and actual mitigation results in 1999. In the fourth quarter of 1999, WEGM recorded a $709,000 ($461,000 after tax) charge to adjust the remaining reserve for expected future losses. During 1999, 1998 and 1997, pre-tax losses totaling $8,429,000, $1,916,000 and $2,235,000, respectively, were charged against the reserve.
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 sites and manufactured gas plant sites. The Company has implemented an ongoing program to test, replace and remediate certain underground storage tanks as required by federal and state laws and this process is nearing completion. 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, 1999.
ELECTRIC SITES
The Company has expended approximately $15.1 million related to the remediation activities covered by the Washington Commission's order, of which approximately $7.5 million has been recovered from insurance carriers. At December 31, 1999, approximately $2.6 million has been accrued as a liability for future remediation costs for these and other remediation activities.
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. Legal and remedial costs incurred to date total approximately $51.8 million and currently estimated future remediation costs are approximately $6.9 million. Work at both the Chehalis and Tideflats sites is substantially completed and the remediation construction activity at Everett is completed. To date, the Company has recovered approximately $57.5 million from insurance carriers and other third parties.
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
Other contingencies, arising out of the normal course of the Company's business, exist at December 31, 1999. 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.
NOTE 18. DISCONTINUED OPERATIONS
On March 5, 1997, the Company conveyed its interests in undeveloped coal properties through its wholly-owned subsidiary Thermal Energy, Inc. to Wesco Resources, Inc. effective February 1, 1997. The Company's remaining $4.0 million investment in Thermal Energy, Inc. was written off to expense and appears in the consolidated financial statements as discontinued operations.
NOTE 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.
(unaudited; dollars in thousands except per-share amounts)
_____________________________________ (1) Results for 1998 include certain reclassifications to present financial results on a consistent basis with 1999.
NOTE 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. At December 31, 1999 and 1998, book overdrafts of $22,245,000 and $15,710,000 were included in accounts payable. Non-cash transactions in 1999 included the issuance of $6,682,000 of Company common stock for the Company's Dividend Reinvestment Plan and the assumption of $109 million in long-term debt as part of the purchase of the Encogen partnership.
The following provides additional information concerning cash flow activities:
NOTE 21. MERGER OF PUGET POWER AND WECO
Included in consolidated results of operations for the month of January 1997 are the following results of the previously separate companies for that period (Dollars in Thousands):
WECo's operations for the three months ended December 31, 1996, have been reported as an adjustment of $10.8 million to consolidated retained earnings in the first quarter of 1997. WECo's revenues for the three months ended December 31, 1996, were $148.6 million, net income was $16.9 million, common stock issued was $1.0 million and common stock dividends declared were $6.1 million for the same period.
In connection with the merger, the Company recognized direct and indirect merger-related expenses of $55.8 million during the first quarter of 1997. The charge consisted primarily of severance costs of $15.5 million, benefit-related curtailment costs of $9.1 million, transaction costs of $13.7 million and systems and facilities integration costs of $7.2 million. The nonrecurring charge reduced net income by approximately $36.3 million or $0.43 per share.
NOTE 22. SEGMENT INFORMATION
The Company primarily operates in one business segment, Regulated Utility Operations. The Company's regulated utility operation generates, purchases and sells electricity and purchases, transports and sells natural gas. The Company's service territory covers approximately 6,000 square miles in the state of Washington.
Principal non-utility lines of business include computer billing system software, real estate investment and development and small hydro-electric project development. Reconciling items between segments are not material.
In the third quarter of 1999, the Company sold the assets, liabilities and trade name of Homeguard Security Services, Inc., its wholly-owned home security services subsidiary and recorded a net gain of approximately $7.6 million.
Financial data for business segments are as follows:
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
______________________________________ (1) Includes additions of $369 and deductions of $384 related to October through December 1996 for WECo.
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-seventh 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; Exhibit 4.3 to Registration No. 33-63278; Exhibit 4.25 to Registration No. 333-41181; and Exhibit 4.27 to Current Report on Form 8-K dated March 5, 1999.)
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 Manhattan 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 Manhattan 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, between 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 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)
4.8 Statement of Relative Rights and Preferences for the 7 3/4% Series Preferred Stock Cumulative, $100 Par Value. (Exhibit 1.6 to Registration Statement on Form 8-A filed February 14, 1994, Commission File No. 1-4393)
4.9 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)
4.10 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)
4.11 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).
4.12 Indenture of First Mortgage dated as of April 1, 1957 (Exhibit 4-B, Registration No. 2-14307).
4.13 First Supplemental Indenture dated as of October 1, 1959 (Exhibit 4-D to Registration No. 2-17876).
4.14 Sixth Supplemental Indenture dated as of August 1, 1966 (Exhibit to Form 8-K for month of August 1966, File No. 0-951).
4.15 Sixteenth Supplemental Indenture dated as of June 1, 1977 (Exhibit 6-05 to Registration No. 2-60352).
4.16 Seventeenth Supplemental Indenture dated as of August 9, 1978 (Exhibit 5-K.18 to Registration No. 2-64428).
4.17 Twenty-second Supplemental Indenture dated as of July 15, 1986 (Exhibit 4-B.20 to Form 10-K for the year ended September 30, 1986, File No. 0-951).
4.18 Twenty-sixth Supplemental Indenture dated as of September 1, 1990 (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 (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 (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 (Exhibit 4-A to Registration No. 33-49599).
4.22 Thirtieth Supplemental Indenture dated as of August 15, 1995 (incorporated herein by reference to Exhibit 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 Public Utility District No. 2 of Grant County, Washington, relating to the Priest Rapids Development. (Exhibit 13-h to Registration No. 2-15618)
10.14 Power Sales Contract dated June 22, 1959, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Wanapum Development. (Exhibit 13-j to Registration No. 2-15618)
10.15 Reserve Share Power Sales Contract dated June 22, 1959, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Priest Rapids Project. (Exhibit 13-k to Registration No. 2-15618)
10.16 Agreement to Amend Power Sales Contracts dated July 30, 1963, between Public Utility District No. 2 of Grant County, Washington and the Company, relating to the Wanapum Development. (Exhibit 13-1 to Registration No. 2-21824)
10.17 Power Sales Contract executed as of September 18, 1963, between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development (Exhibit 13-r to Registration No. 2-21824)
10.18 Reserved Share Power Sales Contract executed as of September 18, 1963, between Public Utility District No. 1 of Douglas County, Washington and the Company, relating to the Wells Development. (Exhibit 13-s to Registration No. 2-21824)
10.19 Exchange Agreement dated April 12, 1963, between the United States of America, Department of the Interior, acting through the Bonneville Power Administration and Washington Public Power Supply System and the Company, relating to the Hanford Project. (Exhibit 13-u to Registration 2-21824)
10.20 Replacement Power Sales Contract dated April 12, 1963, between the United States of America, Department of the Interior, acting through the Bonneville Power Administrator and the Company, relating to the Hanford Project. (Exhibit 13-v to Registration No. 2-21824)
10.21 Contract covering undivided interest in ownership and operation of Centralia Thermal Plant, dated May 15, 1969. (Exhibit 5-b to Registration No. 2-3765)
10.22 Construction and Ownership Agreement dated as of July 30, 1971, between The Montana Power Company and the Company. (Exhibit 5-b to Registration No. 2-45702)
10.23 Operation and Maintenance Agreement dated as of July 30, 1971, between The Montana Power Company and the Company. (Exhibit 5-c to Registration No. 2-45702)
10.24 Coal Supply Agreement, dated as of July 30, 1971, among The Montana Power Company, the Company and Western Energy Company. (Exhibit 5-d to Registration No. 2-45702)
10.25 Power Purchase Agreement with Washington Public Power Supply System and the Bonneville Power Administration dated February 6, 1973. (Exhibit 5-e to Registration No. 2-49029)
10.26 Ownership Agreement among the Company, Washington Public Power Supply System and others dated September 17, 1973. (Exhibit 5-a-29 to Registration No. 2-60200)
10.27 Contract dated June 19, 1974, between the Company and P.U.D No. 1 of Chelan County. (Exhibit D to Form 8-K dated July 5, 1974)
10.28 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)
10.29 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)
10.30 Letter Agreement dated March 31, 1980, between the Company and Manufacturers Hanover Leasing Corporation. (Exhibit b-8 to Registration No. 2-68498)
10.31 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)
10.32 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)
10.33 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)
10.34 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)
10.35 Agreement executed as of April 17, 1984, between the United States of America, Department of the Interior, acting through the Bonneville Power Administration, and wholesale customers 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)
10.36 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)
10.37 Settlement Agreement and Covenant Not to Sue executed by the United States Department of Energy acting by and through the Bonneville Power Administration and the Company dated September 17, 1985. (Exhibit (10)-49 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.38 Agreement to Dismiss Claims and Covenant Not to Sue dated September 17, 1985 between Washington Public Power Supply System and the Company. (Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.39 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)
10.40 Settlement Exchange Agreement ("Bonneville Exchange Power Contract") executed by the United States of America Department of Energy acting by and through the Bonneville Power Administration and the Company, dated September 17, 1985. (Exhibit B of Exhibit (10)-50 to Annual Report on Form 10-K for the fiscal year ended December 31, 1985, Commission File No. 1-4393)
10.41 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)
10.42 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)
10.43 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)
10.44 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)
10.45 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)
10.46 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)
10.47 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)
10.48 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)
10.49 Common Facilities Agreement dated as of May 6, 1981, between the Company and Owners of Colstrip 1 and 2, and 3 and 4. (Exhibit (10)-59 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.50 Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork II, Inc. and the Company (Weeks Falls Hydro-electric Project). (Exhibit (10)-60 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.51 Agreement for the Purchase of Power dated as of October 29, 1984, between South Fork Resources, Inc. and the Company (Twin Falls Hydro-electric Project). (Exhibit (10)-61 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.52 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)
10.53 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 Hydro-electric Project). (Exhibit (10)-63 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.54 Power Sales Agreement dated as of August 1, 1986, between Pacific Power & Light Company ("PacifiCorp")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)
10.55 Agreement for Purchase and Sale of Firm Capacity and Energy dated as of August 1, 1986 between The Washington Water Power Company ("Avista") 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)
10.56 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)
10.57 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)
10.58 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)
10.59 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)
10.60 Interruptible Gas Service Agreement dated May 14, 1981, between Washington Natural Gas Company and the Company (Fredrickson Generating Station). (Exhibit (10)-70 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.61 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)
10.62 Amendment No. 2 dated as of September 1, 1981, and Amendment No. 3 dated September 14, 1987, to Coal Supply Agreement between Western Energy Company and the Company and the other Owners of Colstrip 3 and 4. (Exhibit (10)-72 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.63 Amendatory Agreement No. 1 dated August 27, 1982, and Amendatory Agreement No. 2 dated August 27, 1982, to the Power Sales Contract between the Company and the Bonneville Power Administration dated August 27, 1982. (Exhibit (10)-73 to Annual Report on Form 10-K for the fiscal year ended December 31, 1987, Commission File No. 1-4393)
10.64 Transmission Agreement dated as of December 30, 1987, between the Bonneville Power Administration and the Company (Rock Island Project). (Exhibit (10)-74 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No.1-4393)
10.65 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)
10.66 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)
10.67 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)
10.68 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)
10.69 Agreement for Sale and Exchange of Firm Power dated as of November 23, 1988, between the Bonneville Power Administration and the Company. (Exhibit (10)-79 to Annual Report on Form 10-K for the fiscal year ended December 31, 1988, Commission File No.1-4393)
10.70 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)
10.71 Settlement Agreement, dated as of April 27, 1989, between Public Utility District No. 1 of Douglas County, Washington, Portland General Electric Company ("Enron"), PacifiCorp, The Washington Water Power Company ("Avista") and the Company. (Exhibit (10)-1 to Quarterly Report on Form 10-Q quarter ended September 30, 1989, Commission File No. 1-4393)
10.72 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)
10.73 Agreement for Verification of Transfer, Assignment and Assumption, dated as of September 15, 1989, between San Juan Energy Company, March Point Cogeneration Company and the Company. (Exhibit (10)-3 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.74 Power Sales Agreement between The Montana Power Company and the Company, dated as of October 1, 1989. (Exhibit (10)-4 to Quarterly Report on Form 10-Q for the quarter ended September 30, 1989, Commission File No. 1-4393)
10.75 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)
10.76 Memorandum of Understanding dated as of January 24, 1990, between the Bonneville Power Administration and The Washington Public Power Supply System, Portland General Electric Company ("Enron"), Pacific Power & Light Company ("PacifiCorp"), 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)
10.77 Amendment No. 1 to Agreement for the Assignment of Power from the Centralia Thermal Project dated as of January 1, 1990, between Public Utility District No. 1 of Grays Harbor County, Washington and the Company. (Exhibit (10)-89 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.78 Preliminary Materials and Equipment Acquisition Agreement dated as of February 9, 1990, between Northwest Pipeline Corporation and the Company. (Exhibit (10)-90 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.79 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 ("Avista"), Portland General Electric Company ("Enron"), 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)
10.80 Settlement Agreement dated as of February 27, 1990, among United States of America Department of Energy acting by and through the Bonneville Power Administration, 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)
10.81 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)
10.82 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 ("PacifiCorp"), The Washington Water Power Company ("Avista"), Portland General Electric Company ("Enron"), the Washington Department of Fisheries, the Washington Department of Wildlife, the Oregon Department of Fish and Wildlife, the National Marine Fisheries Service, the U.S. Fish and Wildlife Service, the Confederated Tribes and Bands of the Yakima Indian Nation, the Confederated Tribes of the Umatilla Reservation, and the Confederated Tribes of the Colville Reservation. (Exhibit (10)-95 to Annual Report on Form 10-K for the fiscal year ended December 31, 1990, Commission File No. 1-4393)
10.83 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)
10.84 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)
10.85 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)
10.86 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)
10.87 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)
10.88 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)
10.89 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)
10.90 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)
10.91 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)
10.92 Amendment of Seasonal Exchange Agreement, dated December 4, 1991, between Pacific Gas and Electric Company and the Company. (Exhibit (10)-107 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.93 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)
10.94 Intertie and Network Transmission Agreement, dated as of October 4, 1991, between Bonneville Power Administration and the Company. (Exhibit (10)-109 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.95 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)
10.96 Amendment to Agreement for Firm Power Purchase, dated as of September 30, 1991, between Sumas Energy, Inc. and the Company. (Exhibit (10)-112 to Annual Report on Form 10-K for the fiscal year ended December 31, 1991, Commission File No. 1-4393)
10.97 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)
10.98 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)
10.99 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)
10.100 Letter Agreement dated October 12, 1992, between Tenaska Washington Partners, L.P. and the Company regarding clarification of issues under the Agreement for Firm Power Purchase. (Exhibit (10)-121 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.101 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)
10.102 Settlement Agreement dated December 29, 1992, between the Company and the Bonneville Power Administration (BPA) providing for power purchase by BPA. (Exhibit (10)-123 to Annual Report on Form 10-K for the fiscal year ended December 31, 1992, Commission File No. 1-4393)
10.103 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)
10.104 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)
10.105 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)
10.106 Power Exchange Agreement dated as of September 27, 1995, between British Columbia Power Exchange Corporation and the Company. (Exhibit 10.117 to Annual Report on Form 10-K for the fiscal year ended December 31, 1996, Commission File No. 1-4393)
10.107 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)
10.108 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)
10.109 Service Agreement dated September 1, 1987 between Northwest Pipeline Corporation and Washington Natural Gas Company for SGS-1 firm storage service at Jackson Prairie (Exhibit 10-A Form 10-K for the year ended September 30, 1994, File No. 11271).
10.110 Service Agreement dated April 14, 1993 between Questar Pipeline Corporation and Washington Natural Gas Company for FSS-1 firm storage service at Clay Basin (Exhibit 10-B Form 10-K for the year ended September 30, 1994, File No. 11271).
10.111 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.
10.112 Firm Transportation Service Agreement dated October 1, 1990, between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-D Form 10-K for the year ended September 30, 1994, File No. 11271).
10.113 Gas Transportation Service Contract dated June 29, 1990, between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.114 Gas Transportation Service Contract dated July 31, 1991, between Washington Natural Gas Company and Northwest Pipeline Corporation (Exhibit 4-A Form 10-Q for the quarter ended March 31, 1993, File No. 0-951).
10.115 Amendment to Gas Transportation Service Contract dated July 31, 1991, between Washington Natural Gas Company and Northwest Pipeline Corporation. (Exhibit 10-E.2 Form 10-K for the year ended September 30, 1995, File No. 11271).
10.116 Gas Transportation Service Contract dated July 15, 1994, between Washington Natural Gas Company and Northwest Pipeline Corporation. (Exhibit 10-E.3 Form 10-K for the year ended September 30, 1995, File No. 11271). 10.117 Amendment to Gas Transportation Service Contract dated August 15, 1994, between Washington Natural Gas Company and Northwest Pipeline Corporation. (Exhibit 10-E.4 Form 10-K for the year ended September 30, 1995, File No. 11271). 10.118 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, (Exhibit 10-N, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.119 Firm Transportation Service Agreement dated March 1, 1992 between Northwest Pipeline Corporation and Washington Natural Gas Company (Exhibit 10-O, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.120 Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit 10-P, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.121 Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Jackson Prairie (Exhibit 10-Q, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.122 Firm Transportation Service Agreement dated January 12, 1994 between Northwest Pipeline Corporation and Washington Natural Gas Company for firm transportation service from Plymouth, LNG (Exhibit 10-R, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.123 Service Agreement dated July 9, 1991 with Northwest Pipeline Corporation for SGS-2F Storage Service filed under cover of Form SE dated December 23, 1991 (Exhibit 10-S, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.124 Firm Transportation Agreement dated October 27, 1993 between Pacific Gas Transmission Company and Washington Natural Gas Company for firm transportation service from Kingsgate (Exhibit 10-T, Form 10-K for the year ended September 30, 1994, File No. 1-11271).
10.125 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.
10.126 Employment agreement with R. R. Sonstelie, Chairman of the Board, dated January 13, 1998. (Exhibit 10.150 to Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File No. 1-4393)
10.127 Change in control agreement with T. J. Hogan, dated August 17, 1995. (Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December 31, 1997, Commission File No. 1-4393)
10.128 Asset Purchase Agreement between PP&L Global, Inc. and the Company. (Exhibit 2a to Current Report on Form 8-K dated November 13, 1998)
10.129 Employment agreement with S. A. McKeon, Vice President and General Counsel, dated May 27, 1997. (Exhibit 10.152 to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, Commission File No. 1-4393)
10.130 Employment agreement with R. L. Hawley, Vice President and Chief Financial Officer, dated March 16, 1998. (Exhibit 10.153 to Annual Report on Form 10-K for the fiscal year ended December 31, 1998, Commission File No. 1-4393)
*10.131 Separation agreement with J. Quintana, Vice President External Affairs, dated December 29, 1999.
*12-a Statement setting forth computation of ratios of earnings to fixed charges (1995 through 1999).
*12-b Statement setting forth computation of ratios of earnings to combined fixed charges and preferred stock dividends (1995 through 1999).
*21 Subsidiaries of the Registrant.
*23.1 Consent of PricewaterhouseCoopers LLP.
*27 Financial Data Schedules.
--------------------------------- *Filed herewith.