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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

For the fiscal year ended September 30, 2004

Commission file number: 1-7196

CASCADE NATURAL GAS CORPORATION
(Exact name of Registrant as specified in its charter)

        Securities registered pursuant to section 12(g) of the Act: None

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes ý    No o

        The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the close of business on October 29, 2004, was $227,843,963

        Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the Registrant's definitive proxy statement for its 2005 Annual Meeting of Shareholders are incorporated by reference into Part III, Items 10, 11, 12, 13 and 14.

CASCADE NATURAL GAS CORPORATION
Annual Report to the Securities and Exchange Commission on Form 10-K
For the Fiscal Year Ended September 30, 2004

Table of Contents

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PART I

Item 1. Business

Available Information

        The Company makes available free of charge, on or through its website, http://www.cngc.com, its annual, quarterly and current reports, and any amendments to those reports, as soon as reasonably practicable after electronically filing such reports with the Securities and Exchange Commission. In addition, copies of these documents may be requested, at no cost, from the Company's corporate headquarters. Requests should be directed to Shareholder Relations, Cascade Natural Gas Corporation, 222 Fairview Avenue North, Seattle WA 98109, or by phone at 206-624-3900.

        To contact any independent board member you may write to Larry L. Pinnt, Board of Directors Chair, P.O. Box 87 Redmond, WA 98073-0087, fax to 425-895-1349, or e-mail to [email protected].

General

        Cascade Natural Gas Corporation (Cascade or the Company) was incorporated under the laws of the state of Washington on January 2, 1953. Its principal business is the distribution of natural gas to customers in the states of Washington and Oregon. Approximately 81% of its gas distribution revenues are from customers in the state of Washington.

        As of September 30, 2004, the Company had approximately 184,300 residential customers, 29,000 commercial customers, and 726 industrial and other customers. Residential, commercial, and most small industrial customers are generally core customers, who take traditional "bundled" natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation. Sales to core customers in fiscal 2004 accounted for approximately 23% of gas deliveries and 69% of operating margin. The Company's sales to its core residential and commercial customers are influenced by fluctuations in temperature, particularly during the winter season. A warm winter season will tend to reduce gas consumption. Over the longer term, these fluctuations tend to offset each other, as rates charged to customers are developed based on the assumption of normal weather.

        Non-core customers are generally large industrial and institutional customers who have chosen "unbundled" service, meaning that they select from among several upstream supply, pipeline transportation, and gas management service options independent of the Company's distribution service. The Company's margin from non-core customers is derived primarily from distribution service and to a lesser extent from gas management service revenue. Gas management service revenue primarily includes operating margin from delivery of gas supplies and fees charged to non-core customers in consideration of securing gas supplies and pipeline capacity for the customers.

State Regulation

        The Company's rates and practices are regulated by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).

        Cascade's gas supply contracts contain pricing provisions for fixed periods of time. To the extent that prices are changed with respect to supplies purchased for core customers, Cascade is able to pass the effect of such changes, subject to regulatory review, to its customers by means of a periodic purchased gas cost adjustment (PGA) in each state. Gas price changes occurring between times when PGA rate changes become effective are deferred for pass through in the next PGA.

        With respect to such gas supplies delivered to Oregon customers, 67% of the incremental change in the actual cost of gas supplies, as compared to the forecasted cost reflected in the PGA, is deferred. The remaining 33% (increase or decrease) is absorbed by the Company. This mechanism is intended to encourage the Company to seek opportunities to lower its cost of supplies and to be innovative in its

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management of the supply portfolio to avoid price spikes. Cascade's gas supply portfolio for Oregon core customers is comprised mostly of gas supplies that have a fixed commodity price, therefore management believes the risk or opportunity for the Company is not significant under the 67% / 33% sharing arrangement during the coming year.

        Cascade has an earnings sharing mechanism with respect to its Oregon jurisdictional operations as required by the Oregon Public Utilities Commission. The mechanism was designed as an incentive to pursue operational efficiencies and new revenue opportunities, and to share the success of such pursuits with ratepayers if the Company's earnings exceed a calculated ceiling. Under that arrangement, the Company is authorized to retain all of its earnings attributable to its Oregon operations up to a threshold level equal to 300 basis points above a 10.25% return on equity (ROE). Subsequent years' base ROE will be adjusted by 50% of the movement in the average of the annual yields, reported monthly, for five-, seven-, and ten-year US Treasury debt securities for the test period. If the adjusted Oregon earnings are below the threshold, there is no rate adjustment. If the adjusted earnings are above the threshold, one-third of the earnings exceeding the threshold will be refunded to customers through future rate reductions.

        The Company is also subject to state regulation with respect to integrated resource planning, and its most recent update of its Integrated Resource Plan (IRP) was filed in 2004 with both the WUTC and the OPUC. The IRP shows the Company's optimum set of supply and demand side resources that minimizes costs and risk over the twenty-year planning horizon. The IRP also sets forth possible core customer growth scenarios for a twenty-year period. In addition, the IRP sets forth the Company's demand side management goals of achieving certain conservation levels in customer usage.

        The IRP also sets forth the Company's supply side management plans regarding transportation capacity and gas supply acquisition over a twenty-year period. The Company develops updates of the IRP every two years. These updated documents take into account input solicited from the public and the WUTC and OPUC staffs. While the filing of the IRP with both commissions gives the Company no advance assurance that its acquisitions of pipeline transportation capacity and gas supplies will be recognized in rates, management believes that the integrated resource planning process benefits the Company by giving it the opportunity to obtain input from regulators and the public concurrently with making these important strategic decisions. Until the Company receives final regulatory approval of these decisions in the context of the ratemaking process, the Company cannot predict with certainty the extent to which the integrated resource planning process will affect its rates.

Natural Gas Supply

        The majority of Cascade's supply of natural gas is transported via Williams Gas Pipelines—West (Williams). Williams owns and operates a transmission system extending from points of interconnection with El Paso Natural Gas Company and Transwestern Pipeline Company near Blanco, New Mexico through the states of New Mexico, Colorado, Utah, Wyoming, Idaho, Oregon and Washington to the Canadian border near Sumas, Washington. Natural gas is transported north from the Colorado and New Mexico area, and south from British Columbia, Canada. The Company is also a shipper on the transmission system of Gas Transmission Northwest Corporation (GTN), and TransCanada Pipeline (TCPL). GTN owns and operates a gas transmission line that connects with the facilities of the TCPL at the international border near Kingsgate, British Columbia and extends through Washington and central Oregon into California. In addition, Cascade receives natural gas directly from Duke Energy Gas Transmission (DEGT) at the Canadian border near Sumas, Washington and also intra British Columbia at a receipt point known as Station 2 on DEGT.

        Presently, baseload requirements for Cascade's core market are provided by eight major gas supply contracts with various expiration dates ranging from 2004 through 2009 and averaging 460,000 therms per day of Canadian supply and 106,500 therms per day of domestic supply. These contracts are

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supplemented by various service agreements to cover periods of peak demand including three storage agreements. One such agreement, with Williams, extends to October 31, 2014 and provides for 167,890 therms per day and a maximum, renewable inventory of 6,043,510 therms. The second storage agreement is with Avista Energy, and has a primary term ending April 30, 2006 and entitles Cascade to receive up to 150,000 therms per day and a maximum, renewable inventory of 4,800,000 therms. A third contract, also with Williams, for liquefied natural gas (LNG) storage is effective through October 31, 2014. Under this LNG agreement, Cascade is entitled to receive up to 600,000 therms per day to a maximum inventory of 5,622,000 therms. In addition to withdrawal and inventory capacity, Cascade maintains a corresponding amount of firm transportation from the storage facility to the city gate for each of these agreements.

        The Company enters into various seasonal and annual gas supply contracts designed to match the load requirements of its customers. Interstate pipelines provide natural gas to the Company from production areas in the Rocky Mountain states and from western Canada. Management believes gas supply resources in those areas are adequate to serve the Company's current needs and to support future growth. The wholesale price of gas in the region has increased in recent years, paralleling national trends. Additionally, a favorable differential that has historically existed between Pacific Northwest gas prices and national prices has narrowed as new pipelines have increased access to Rocky Mountain and Canadian supplies by California and mid-west markets.

        To mitigate price volatility the Company has in the past relied primarily on three year fixed-price physical gas supply contracts with its suppliers. Due to the continued volatility of the price of natural gas and the increased business risk associated with the potential for supplier failure, the Company has implemented a gas procurement strategy for core customers for supplies to be delivered in fiscal year 2005 and beyond. The Company has entered into physical gas supply contracts with suppliers at published first-of-the-month index prices for up to five-year terms. To mitigate the price volatility, these index related supplies will be converted to fixed-price physical contracts with suppliers or hedged through the use of derivatives, primarily swaps, with financial institutions. Approximately 90% of the core market's requirement for fiscal 2005, 60% of fiscal 2006, and 30% of fiscal 2007 are secured with fixed prices as of the end of fiscal 2004. To minimize earnings volatility, the Company received accounting orders from the WUTC and the OPUC which allowed the application of Statement of Financial Accounting Standards (FAS) No. 71 to periodic changes in fair market value of derivatives associated with supplies for core customers. The Company records an offset to such changes in regulatory asset and regulatory liability accounts. The accounting orders permit the recognition of settlement of these contracts and financial instruments in the Company's normal purchased gas adjustment process. Refer to Note 2 to the Notes to Consolidated Financial Statements for more information on application of FAS No. 71.

        During 2004, Cascade purchased approximately 84% of its gas supplies from firm gas supply contracts and 16% from 30-day spot market contracts. In addition, 790,870,000 therms of customer purchased supplies were transported through Cascade facilities.

Federal Energy Regulatory Commission (FERC) Matters

        Cascade is not subject to regulation by the FERC, however FERC actions can affect the amounts Cascade pays to interstate pipeline companies for interstate deliveries of natural gas supplies. Several issues are pending before FERC, or are on appeal before the U.S. Court of Appeals. The final outcome may affect prices Cascade pays, however none would have a significant impact. Since the policies of the WUTC and OPUC provide for 100% pass through of costs subject to FERC regulation, the Company expects that the final resolution of pending issues will not significantly affect net income.

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Curtailment Procedures

        In some previous heating seasons, cold weather has required Cascade to curtail deliveries to its interruptible customers. Cascade has not curtailed any firm customers, except under force majeure conditions. Cascade's tariffs effective in Washington and Oregon allow for curtailment of interruptible services, which are provided at rates lower than for firm services. In the event of curtailment by Cascade of firm service due to force majeure, Cascade's tariffs provide that it will not be liable for damages to any customer for failure to deliver gas curtailed in accordance with the provisions of the tariffs. The tariffs provide for appropriate adjustment of the monthly charges to firm customers curtailed by reason of an insufficient supply of gas.

Territory Served and Franchises

        The population of communities served by Cascade totals approximately 1,022,000. At the end of September 2004, Cascade held the franchises necessary for the distribution of natural gas in all of the communities it serves in Washington and Oregon. Under the laws of those states, incorporated municipalities and counties may grant non-exclusive franchises for a fixed term of years conferring upon the grantee certain rights with respect to public streets and highways in the location, construction, operation, maintenance and removal of gas distribution facilities.

        In the opinion of Cascade's management, none of its franchises contain any restrictions or requirements that are of a materially burdensome nature, and such franchises are adequate for the conduct of Cascade's present business. Franchises expire on various dates from fiscal 2005 to 2065. Management has not incurred significant difficulties in renewing franchises when they expire and does not expect any significant problems in the future.

Customers

        Residential and commercial customers principally use natural gas for space heating and water heating. This market is very weather-sensitive. See "Seasonality" below.

        Agreements with Cascade's principal industrial customers are for fixed terms of not less than one year and provide for automatic extension from year to year unless terminated by either party on at least 120-days' notice.

        The principal industrial activities in Cascade's service area include the production of pulp, paper and converted paper products, plywood, industrial chemicals; refining of crude oil; the processing, flash freezing and canning of many types of vegetable, fruit and fish products; processing of milk products; meat processing; drying and curing of wood and agricultural products; and electric power generation. Electric generation customers represent a significant portion of industrial revenues. The demand for gas-fired generation tends to decrease as the availability of hydroelectric generation increases.

Seasonality

        Weather is an important factor affecting gas revenues because of the large number of customers using gas for space heating. For the fiscal year ended September 30, 2004, 71% of operating revenues and 98% of income from operations were derived from the first two quarters (October 2003 through March 2004). Because of the seasonality of space heating revenues, financial results for interim periods are not indicative of results to be expected for an entire year. To mitigate the seasonality of space heating revenues, the Company pursues a marketing strategy of encouraging the installation of gas water heaters by customers, since they are not as influenced by weather conditions.

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Competitive Conditions

        Cascade operates in a competitive market for natural gas service. Cascade competes with residual fuel oil and other alternative energy sources for industrial boiler uses, and oil, propane, and electricity for residential and commercial space heating, and electricity for water heating.

        Competition is primarily based on price. Though wholesale natural gas prices have increased significantly beginning in the 2000 - 2001 heating season, Cascade's residential and commercial rate schedules continue to maintain a price advantage over oil in its entire service territory and have an advantage over electricity in the vast majority of its territory. In the remaining areas of its service territory served by public electric utilities with their own hydro power supply, Cascade is almost equal in cost with respect to electricity furnished by those utilities for space heating and water heating uses. In addition, natural gas enjoys the advantage of being the preferred energy choice by builders for new home construction.

        The large volume industrial market has always been very sensitive to price fluctuations between the comparable cost of natural gas and alternate fuels, principally residual fuel oil used in boiler applications. However, the advent of open access transportation in the late 1980's and early 1990's and the subsequent restructuring of gas supply and contractual provisions with these customers have improved the Company's competitive position. With the escalation of wholesale natural gas prices that began in the 2000 - 2001 heating season, the Company has experienced some movement of its gas load to alternative fuels and some plant curtailments by industrial customers.

        In addition to multiple alternative fuels, the Company is subject to bypass. Bypass refers to actual or prospective customers who install their own facilities and connect directly to an upstream pipeline and thereby "bypass" the Company's distribution service. The Company has in the past experienced bypass, but has also experienced success in offering competitive rates to reduce economic incentives to bypass.

        The Company competes with others in acquiring gas supplies for resale to governmental and industrial customers. Further opportunities in this area will be dependent upon market conditions that can change over time, credit worthiness of customers and the increase or decrease in the number of competing providers that are available.

        The Bonneville Power Administration (BPA) is a major supplier of hydroelectric power in the Pacific Northwest including Cascade's service area. BPA significantly influences the electric rates of all classes of customers including those applications in direct competition with natural gas marketed by Cascade.

Environmental

        The Company is subject to federal and state environmental regulation of its operations and properties through the United States Environmental Protection Agency, the Washington Department of Ecology and the Oregon Department of Environmental Quality. Such regulation may, at times, result in the imposition of liability or responsibility for the clean up or treatment of existing environmental problems or for the prevention of future environmental problems. For detailed descriptions of specific environmental issues, see "Environmental Matters" under Item 7.

Capital Expenditures

        Capital expenditures are primarily used to expand the Company's distribution system to serve its expanding customer base, as well as to increase deliverability on its existing system to accommodate increased customer utilization. Capital expenditures for the five fiscal years ended September 30, 2004 totaled approximately $125 million, and the budget for fiscal 2005 is $28 million.

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        The Company is currently forecasting that capital expenditures will total approximately $155 million over the next five years. The overall objective is to invest limited capital to generate the highest possible returns within the shortest possible time, while assuming prudent risk, anticipating customer needs and complying with the requirements of regulators.

Non-Utility Subsidiaries

        Cascade has four non-utility subsidiaries, only two of which are actively engaged in business at present. The first active subsidiary, Cascade Land Leasing, is engaged in the servicing of loans that were made to Cascade's gas customers to finance their purchases of energy-efficient appliances. The subsidiary ceased making new loans in September 1997. The second active subsidiary, CGC Resources, is engaged in pipeline capacity management, with the objective of mitigating gas costs for Cascade. The subsidiaries, which in the aggregate account for less than 1% of the consolidated assets of the Company, do not currently have a significant impact on Cascade's financial statements.

Personnel

        At September 30, 2004, Cascade had 428 employees. Of the total employees, 182 are represented by the International Chemical Workers Union. The present contract with the union extends to April 1, 2006, and remains in force thereafter from year to year unless terminated by either party by written notice sixty days prior to the expiration date.

Item 2. Properties

        At September 30, 2004, Cascade's utility plant investments included approximately 5,088 miles of distribution mains ranging in diameter from two inches to sixteen inches, 215 miles of transmission mains ranging in diameter from two inches to twenty inches, and 3,524 miles of service lines.

        The distribution and transmission mains are located under public property such as streets and highways or on private property with the permission or consent of the individual owner.

        Cascade owns 21 buildings used for operations, office space and warehousing in Washington and six such buildings in Oregon. It leases five commercial offices and warehouse buildings. Cascade considers its properties well maintained and in good operating condition, and adequate for Cascade's present and anticipated needs. All facilities are substantially utilized. In addition, the Company owns two buildings currently for sale due to operational consolidation.

Item 3. Legal Proceedings

        Litigation:    In the fourth quarter of fiscal 2002 a fatal accident occurred involving facilities owned by the Company, located on the property of one of the Company's commercial customers. In fiscal 2003 a settlement of all plaintiffs' claims was agreed to in consideration of a $750,000 payment. The Company and its co-defendant submitted the allocation of the payment to arbitration. In the first quarter of fiscal 2005, the arbitrator assigned 65% of the financial responsibility to the Company. The Company's additional $112,000 expense was recorded in fiscal year 2004. This brings this matter to a conclusion.

        Other:    Incorporated herein by reference is the information under "Environmental Matters" in Item 7.

Item 4. Submission of Matters to a Vote of Security Holders

        No matters were submitted during the fourth quarter of fiscal year 2004.

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Executive Officers of the Registrant

        The executive officers of the Company, as of December 1, 2004, are as follows:

        None of the above officers is related by blood, marriage or adoption to any other of the above named officers. Each of the above named officers has been employed by the Company in a management capacity for at least the past five years. None of the above officers holds directorships in other public corporations. All officers serve at the pleasure of the Board of Directors.

        On September 29, 2004, the registrant's Board of Directors elected W. Brian Matsuyama as Vice Chairman. He will continue to serve as President and CEO while a search is conducted for the new President and CEO. The registrant's Board of Directors has established an ad hoc committee to initiate a search to find a successor Chief Executive Officer.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

        The Common Stock is traded on the New York Stock Exchange under the symbol CGC. The following table states the per share high and low sales prices of the Common Stock.

        At September 30, 2004, there were 5,673 registered holders of the Common Stock. The following table shows for the periods indicated the dividends paid per share on the Common Stock.

        At September 30, 2004, the Company was in compliance with all indebtedness covenants and was not restricted on dividend payments.

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Item 6. Selected Financial Data

Consolidated Statements of Income and Comprehensive Income:

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Item 6. Selected Financial Data (continued)

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

        The following is management's assessment of the Company's financial condition and a discussion of the principal factors that affect consolidated results of operations and cash flows for the fiscal years ended September 30, 2004, 2003, and 2002. References herein to 2004, 2003, and 2002 refer to these fiscal years.

OVERVIEW

        The Company is a local distribution company (LDC) serving approximately 215,000 customers in the States of Washington and Oregon. Its service area consists primarily of relatively small cities and rural communities rather than larger urban areas. The Company's primary source of revenue and operating margin is the distribution of natural gas to end-use residential, commercial, industrial, and institutional customers. Revenues are also derived from providing gas management and other services to some of its large industrial and commercial customers. The Company's rates and practices are regulated by the WUTC and the OPUC.

        Key elements of the Company's strategy include:

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Remain focused on the natural gas distribution business.



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Achieve earnings growth through expansion of its customer base and operating efficiencies, minimizing the need to seek rate increases to recover increased costs.

Opportunities and Challenges

        The Company operates in a diverse service territory over a wide geographic area relative to the Company's overall size and number of customers. The economies of various parts of the service area are supported by a variety of industries, and are affected by the conditions that impact those industries.

        Management believes there are growth opportunities in the Company's service area.Factors contributing to these opportunities include low market penetration in many of the towns served, and general population growth in the service area, including some areas of rapid growth.

        Rates charged by the Company for its utility services are regulated by the WUTC and the OPUC. The Company's basic business strategy is to minimize reliance on rate increases for earnings growth. However, realization of risks affecting earnings could require the Company to seek approval of higher rates. The results of such rate requests are subject to uncertainties associated with the regulatory process.

        The Company earns more than one third of its operating margin from industrial and electric generation customers. Loss of major industrial customers, or unfavorable conditions affecting an industry segment, could have a detrimental impact on the Company's earnings. Many external factors over which the Company has no control can significantly impact the amount of gas consumed by industrial and electric generation customers, and consequently the margins earned by the Company.

        Revenues and margins from the Company's residential and small commercial customers are highly weather sensitive. In a cold year, the Company's earnings are boosted by the effects of the weather, and conversely in a warm year, the Company's earnings suffer. The Company continues to explore alternatives such as weather normalization mechanisms that utility regulators in many jurisdictions have approved, to reduce weather related volatility in earnings and in customers' bills.

        Overall revenues and margins are also negatively impacted by customers taking measures to reduce energy usage. The increasing cost of energy in recent years, including the wholesale cost of natural gas, continues to encourage such measures.

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        Prospects for continuing strong residential and commercial customer growth are excellent. The pace of new home and commercial construction remains steady in our communities. Good potential also exists for converting homes and businesses located on or near our current lines to gas from other fuels, as well as for expanding our system into adjacent areas.

RESULTS OF OPERATIONS

2004 versus 2003

        The Company reported net income for 2004 of $13,302,000, or $1.19 per basic and diluted share, compared to $9,104,000, or $0.82 per basic and diluted share for 2003. Primary factors and the resulting increase (decrease) in earnings per share affecting this comparison include:

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Improved margins from residential and commercial customers related to increased per-customer consumption and growth in the number of customers—$0.18 per share.



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Reduction in employee benefit expenses resulting from the successful 2003 implementation of plan changes designed to reduce costs—$0.17 per share.



•

Recognition in 2003 of retirement plan curtailment losses in connection with above-mentioned plan changes—$0.08 per share.



•

Favorable mark-to-market valuations in 2004 and negative valuations in 2003—$0.07 per share.



•

Contract termination charge in 2003—$0.05 per share.



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Increase in depreciation and amortization—($0.06) per share.



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Decreased margin from electric generation customers—($0.06) per share.



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Decreased margin from gas management services—($0.08) per share.

2003 versus 2002.

        Net income for 2003 was $9,104,000 compared to $10,762,000 for 2002. Basic and diluted earnings per share for 2003 were $0.82, a 15% decrease from the $0.97 per share earnings for 2002.

OPERATING MARGIN

        Operating margins (revenue minus gas cost and revenue taxes) by customer category for the fiscal years ended September 30, 2004, 2003 and 2002 are set forth in the tables below:

Residential and Commercial Operating Margin

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Industrial and Other Operating Margin

2004 Versus 2003

        The increase of $3,133,000 in total operating margin was primarily driven by improvements in residential and commercial margins, partially offset by reductions in margins from electric generation customers.

        Residential and Commercial.    Margins from residential and commercial customers increased $3,208,000. Of this increase, approximately $2,200,000 resulted from the increase of 8,013 in the average number of customers billed. The remaining increase stems primarily from increased gas usage per customer, related to somewhat cooler weather.

        Industrial.    For the year, gas distribution margins from industrial customers were the same as 2003. In the first half of the year, industrial distribution margin showed promising signs of recovery from the stagnation that followed the 2000 energy crisis and a prolonged recession. However, the upward trend stalled in the third quarter, when industrial distribution margins were essentially flat to last year, and in the fourth quarter margins declined. We believe that the primary reason for the reversal of the positive trend in industrial consumption was the surprisingly high wholesale cost of gas that prevailed through most of the period from May through July. Contrary to traditional expectations for softer prices during the warm spring and summer months, the daily spot prices at Sumas were significantly higher than prices during the preceding heating months of February and March.

        While many of our service communities continue to suffer effects from the long economic downturn, we are seeing signs of increased industrial activity. New plants ranging from food processors to a manufacturer of small planes have been announced, and expansion projects for a number of existing plants are underway. Other facilities that ceased operations during the recession are reopening. Nevertheless, gas utilization by industrial customers remains somewhat uncertain for the near term due to volatile wholesale gas prices. In order to help our industrial customers cope with price volatility, in September we obtained and offered gas supplies with prices fixed at the more reasonable levels that prevailed at the time. Many took advantage of the offering, but others remain exposed to fluctuating market prices. Usage by such customers may be affected if prices remain high for an extended period.

        Electric Generation.    Margins from electric generation customers were down $1,019,000 compared to 2003. Much of the decline was due to an abundance of cheap hydroelectricity and moderate regional demands for power during the first part of the year. Drought conditions during the spring significantly reduced hydro resources, improving prospects for gas-fired generation requirements going into the summer. However, the high wholesale gas costs that were depressing general industrial usage also

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affected demand by generators, and fourth quarter margins from the sector fell short of the quarter last year. Looking ahead, gas usage by generation customers will continue to depend on the same variables: regional demand for power, availability of hydro resources, and the relationship between the market price of electricity and the cost of gas.

        Gas Management.    Though margins from providing gas management services increased $633,000 over 2003, this comparison is impacted by three factors. Margins in 2003 were negatively impacted by an $865,000 contract termination charge, and negative mark-to-market energy derivative valuations of $315,000. Margins in 2004 were boosted $836,000 by positive mark-to-market energy derivative valuations. Absent these factors, gas management margin decreased by $1,383,000.

        The re-emergence of energy marketers, an industry segment that all but disappeared in the wake of the Enron failure, has resulted in stiff competition for gas supply sales to larger gas customers. Cascade has lost some customers to such marketers, and margins that are available for any sales are smaller than in the past. We will continue to provide gas supply services to customers to facilitate their use of gas, but expect revenues from the activity to be limited.

2003 Versus 2002

        Total operating margin of $90,675,000 was only slightly greater than prior year margin of $90,502,000. Declines in margins from residential and commercial customers were substantially offset by improvements in margins from industrial and other customers.

        Residential and Commercial.    Margins from residential and commercial customers declined $2,108,000. Weather, 7.6% warmer in 2003 compared to 2002, contributed to declines in per-customer gas consumption. The resulting impact on margin was a reduction of approximately $4,600,000. Partially offsetting this decline was a positive impact from the addition of new customers, which contributed approximately $2,600,000 margin.

        Industrial and Other.    Margins from delivery of gas to electric generation customers declined $231,000. Lower margins from electric generation customers in 2003 reflect continued sluggish economic conditions and adequate supplies of lower cost hydropower displacing electricity from gas generation facilities.

        Margins from delivering gas to industrial customers increased slightly, substantially offsetting the decline from electric generation customers.

        Margins from gas management services to customers were negatively affected in both years by termination charges in settlement of two cancelled gas supply contracts. The contracts were entered into to provide supplies to a group of industrial customers who had contracted for gas management services. In 2002 an initial charge of $2,800,000 was recorded reflecting management's estimate at that time of the estimated liability under the claims. An additional charge of $865,000 was recorded in 2003 reflecting full settlement of all claims related to these contracts.

COST OF OPERATIONS

2004 versus 2003

        Compared to 2003, overall Cost of Operations was $3,823,000 lower for the year. Within Cost of Operations, notable changes in Operating Expenses included the reduction in employee benefits expenses of $4,448,000. The comparison is affected by retirement plan curtailment charges of $1,451,000 in 2003. The remaining decrease is primarily attributed to changes in benefit plans initiated in 2003, designed to reduce costs. Benefits expense in 2004 was also favorably impacted by recognition of $315,000 for the Medicare prescription drug subsidy, reflected as a reduction in retiree medical expense. Additional information on the Medicare prescription drug subsidy and the related accounting

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is included in Note 2 in the Notes to Consolidated Financial Statements under the caption "FSP-FAS Nos. 106-1 and 106-2". In addition, 2003 expenses included a $524,000 severance cost.

        The $987,000 increase in depreciation and amortization is primarily related to increases in depreciable gas distribution system assets.

2003 versus 2002

        Operating Expenses increased $2,462,000, 5.7% over 2002, including an increase in employee benefits expenses of $1,946,000. Included in benefits expense was recognition of a $1,451,000 curtailment loss in connection with changes in the Company's retirement plans for salaried employees and executives. The revisions to the defined benefit plans constitute plan curtailments under FAS No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefit, resulting in the above-mentioned curtailment loss associated with unrecognized prior service cost and transition obligation. Further information on benefits plan changes is included below under "Employee Benefits Plan Changes".

        Also contributing to the increase in operating expenses is a $524,000 charge for accrual of severance costs, and a $701,000 increase in purchased services, stemming primarily from consulting charges related to two projects, the Company's review of its benefit plans, and a project to prepare the Company for the compliance requirements of the Sarbanes-Oxley Act.

        Depreciation and Amortization increased $412,000, 2.8%, over 2002 primarily as a result of increases in depreciable gas distribution system assets.

INCOME TAXES

        The changes in the provision for income taxes from 2003 to 2004, and from 2002 to 2003 are attributable to the changes in pre-tax earnings.

OTHER COMPREHENSIVE INCOME (LOSS)

        In 2004, the value of pension plan assets continued a modest recovery from the declines experienced in 2001 and 2002. As a result of this recovery, the Company has reduced its accrual related to its unfunded accumulated benefit obligation by $1,270,000 for the year before taxes.

LIQUIDITY AND CAPITAL RESOURCES

        The seasonal nature of the Company's business creates short-term cash requirements to finance customer accounts receivable and construction expenditures. To provide working capital for these requirements, the Company has a $60,000,000 bank revolving credit commitment. This agreement has a variable commitment fee, and a term that expires in October 2007. As of September 30, 2004, there was $33,500,000 outstanding debt under these credit lines. In fiscal 2005, $14 million in long-term Medium-Term Notes will mature and will be repaid using funds available from the short-term credit line.

        To provide longer-term financing the Company filed an omnibus registration statement in 2001, under the Securities Act of 1933, which provided the ability to issue up to $150,000,000 of new debt and equity securities. Of that amount, the Company has $110,000,000 remaining available for issuance subject to market conditions and other factors.

        Because of the availability of short-term credit and the ability to issue long-term debt and additional equity, management believes it has adequate financial flexibility to meet its anticipated cash needs, including cash requirements for investing and financing activities described in the following paragraphs.

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OPERATING ACTIVITIES

        Though net income improved in 2004 compared to 2003, net cash provided by operating activities declined by $4,134,000. A significant factor is reflected in Deferrals of gas cost changes, resulting from higher wholesale gas costs paid this year relative to the amount built in to customer rates.

        Cash provided by operating activities in fiscal 2004 continues to benefit from Amortization of gas cost changes, contributing $6,296,000 for the year. This results from a temporary component of customer rates designed to collect un-recovered gas costs incurred primarily during the winter of 2000 - 2001 when wholesale gas prices reached unprecedented high levels, and the Company did not immediately increase customer rates to recover the full amount of higher costs. This temporary rate component expired in October 2004. As a result of higher gas costs experienced in fiscal 2004, the Company implemented a new temporary rate component, effective November 2004, at approximately the same level as the one expired. There is no impact on operating margin or net income from Amortization of gas cost changes.

        Significant factors affecting non-cash components of net income are prepaid income taxes and deferred income taxes. In the fourth quarter of 2004, the Company received Internal Revenue Service approval of an application to change the method of accounting for deferred gas costs for purposes of calculating current federal income taxes. As a result the Company will be able to deduct on its federal tax returns amounts included in deferred gas cost charges. This change is effective retroactive to the tax return for fiscal year 2001, and the Company is preparing amended tax returns for its fiscal years 2001 and 2002. Accordingly the Company has accrued an estimated refund of federal and state income taxes for those years of $7.5 million. These refunds represent temporary differences between book and taxable income, and deferred income taxes have been accrued, so that there is no impact on net income resulting from this change. As deferred gas cost charges are amortized in future years, the Company's income tax liability and cash payments for income taxes will increase accordingly.

        The table below shows the Company's future commitments under contractual obligations as of September 30, 2004:

INVESTING ACTIVITIES

        Net capital expenditures for 2004 were approximately 41% greater than last year. The increase is primarily attributable to $12,515,000 expended on a project to install electronic devices on all the Company's customer meters to allow for automated meter reading (AMR.). The AMR project was

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begun in 2003, and is essentially complete as of the end of fiscal 2004, with total expenditures on the project of approximately $16,198,000.

FINANCING ACTIVITIES

        Other than the payment of dividends, the Company's primary financing activity during fiscal 2004 was the repayment of $22,030,000 in long-term debt and increasing its borrowing under its bank credit line by $29,700,000. The Company also received $2,613,000 in proceeds from issuance of common stock. In the second quarter of fiscal 2003, the Company began issuing new stock through its dividend reinvestment plan, 401(k) plan, and on exercise of stock options. The prior practice was to purchase shares of stock on the open market.

        In the fourth quarter of 2004, the Company renewed its credit line with its bank, increasing the committed credit line from $50,000,000 to $60,000,000. The renewed credit line expires in October 2007.

        In fiscal 2005, the Company will repay $14,000,000 in current maturities of long-term debt, beginning with $4,000,000 in October 2004. The Company expects to fund these repayments primarily through use of its bank credit lines, cash from operating activities, and long-term capital sources.

ENVIRONMENTAL MATTERS

        In 1995, the Company received a claim from a property owner in Eugene, Oregon requesting that the Company assume responsibility for investigation and possible clean up of alleged contamination on property previously owned by a predecessor of Cascade. The predecessor company conducted a manufactured gas business on the property from approximately 1929 to 1948. Manufactured gas operations apparently were conducted on the site by several operators beginning about 1907. The site was used for other purposes beginning in 1949.

        The present owner has retained an environmental consultant, who is investigating possible contamination on the property. To date the consultant has reported that it believes contamination is present. The contamination is consistent with that which might originate from a manufactured gas operation. There have been no estimates as to possible clean up costs. The consultant's initial report has been furnished to the Oregon Department of Environmental Quality (DEQ). The owner has reached an intergovernmental agreement with the DEQ with respect to further investigation and possible remediation of contamination on the property under the voluntary cleanup program.

        Another northwest utility, which purchased the property from Cascade in 1958, has declined to participate in the site investigation, although it may, as a one-time owner of the property, bear some share of the responsibility as well.

        The Company has notified its insurance carriers of the claim and is keeping them advised as to the investigation. On one occasion in the past when hazardous materials on property formerly owned by a predecessor of the Company required clean up, the OPUC allowed the clean up costs to be passed on to customers. In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking for reimbursement through rates for such costs.

        In 1997, a property owner in Washington notified the Company that there is contamination on his property, and that he believes it comes from a former manufactured gas site, owned at one time by a predecessor company, which was merged with Cascade in 1953. The State of Washington Department of Ecology has categorized this site as a "listed site" ranked in its most hazardous category. As a former owner of the site, the Company may be strictly liable to the State of Washington for investigation and remediation of the contamination of the site, but may share that cost or allocate all the cost to others who actually caused or contributed to the contamination.

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        The Company retained an environmental consultant who conducted a preliminary investigation of possible contamination at the site. There is evidence of contamination at the site, and there is also evidence of an oil line across the site property owned and operated by others, which may be a contributor to the contamination. There have been no estimates as to possible clean up costs. The Company has investigated title and other government records to identify other potentially liable parties. The Company has notified the other identified parties of the contamination claims, and has requested cooperation and financial contribution.

        In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking the WUTC for reimbursement for such costs, through rates charged to customers.

EFFICIENCY INITIATIVES

Automated Meter Reading

        The AMR project is discussed above under "Investing Activities". Objectives of the project include the reduction of labor cost associated with reading of customer meters and improved accuracy of meter reading. The AMR project, started in the third quarter of last year, was completed ahead of schedule. The project enabled the Company to reduce the number of meter readers from thirty-two full-time employees to three. Many of these experienced employees were redeployed to expand service and construction capabilities, displacing the use of outside contractors. The AMR project will also allow for more efficient use of service and construction personnel who acted as back-up meter-readers, and will eliminate the need to add new meter readers to keep up with customer growth.

Call Center

        The Company is in the process of implementing a customer-service call center at its present Bellingham, Washington district office location. This will consolidate in one location the customer service function, which is now spread through fifteen local offices. The new call center is expected to reduce expenses through the elimination of sixteen full time equivalent positions, and to allow for more specialization, increased efficiency, and improved service quality. The Company expects the center to be fully operational in the spring of 2005.

CRITICAL ACCOUNTING POLICIES

        The Company's financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). In following GAAP, management exercises judgment in selection and application of accounting principles. Management considers Critical Accounting Policies to be those where different assumptions regarding application could result in material differences in financial statements.

Use of Estimates

        The preparation of financial statements in conformity with GAAP 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. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC. Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, unbilled revenue, valuation of derivative instruments, and in the determination of depreciable lives of utility plant. On an ongoing basis, management evaluates the estimates used, based on historical experience, current conditions and on various other assumptions believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

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Revenue Recognition

        The Company recognizes operating revenues based on deliveries of gas and other services to customers. This includes estimated revenues for gas delivered but not billed to residential and commercial customers from the latest meter reading date to the end of the accounting period.

Regulatory Accounting

        The Company's accounting policies and practices are generally the same as used by unregulated companies for financial reporting under GAAP. However, Statement of Financial Accounting Standards (FAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", requires regulated companies to apply accounting treatment intended to reflect the financial impact of regulation. For example, in establishing the rates to be charged to the Company's retail customers, the WUTC and the OPUC may not allow the Company to charge its customers for recovery of certain expenses in the same period they are incurred. Instead, rates are expected to be established to recover costs that were incurred in a prior period. In this situation, following FAS No. 71 requires the Company to defer these costs and include them as regulatory assets on the balance sheet. In the subsequent period when these costs are recovered from customers, the Company then amortizes these costs as expense in the income statement, in an amount equivalent to the amounts recovered. Similarly, certain revenue items, or cost reductions may be deferred as regulatory liabilities, which are later amortized to the income statement as customer rates are reduced. In order to apply the provisions of FAS No. 71, the following conditions must apply:

•

An independent regulator approves the company's customer rates.



•

The rates are designed to recover the company's costs of providing the regulated services or products.



•

There is sufficient demand for the regulated service to reasonably assure that rates can be set at a level to recover the costs.

        The Company periodically assesses whether conditions merit the continued applicability of FAS No. 71. In the event the Company should determine in the future that all or a portion of its regulatory assets and liabilities no longer meet the above criteria, it would be required to write off the related balances of its regulatory assets and liabilities, and reflect the write off in its income statement.

Pension Plans

        The Company has a defined benefit pension plan covering substantially all employees over 21 years of age with one year of service. The Company also provides executive officers with supplemental retirement, death and disability benefits. These plans were amended in fiscal 2003, so that subsequent to September 30, 2003, benefits under these plans no longer accrue to non-bargaining-unit employees and officers. The pension plan remains substantially unchanged for bargaining-unit employees at this time.

        The Company's pension costs for these plans are affected by the amount of cash contributions to the plans, the return on plan assets, and by employee demographics, including age, compensation, and length of service. Actuarial formulas are used in the determination of pension costs and are affected by actual plan experience and assumptions of future experience. Key actuarial assumptions include the expected return on plan assets, the discount rate used in determining the projected benefit obligation and pension costs, and the assumed rate of increase in employee compensation. Changes in these assumptions may significantly affect pension costs. Changes to the provisions of the plans may also impact current and future pension costs. Changes in pension plan obligations resulting from these factors may not be immediately recognized as pension costs, but generally are recognized in future years over the remaining average service period of pension plan participants.

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        The Company's funding policy is to contribute amounts equal to or greater than the minimum amounts required to be funded under the Employee Retirement Income Security Act, and not more than the maximum amounts currently deductible for income tax purposes. The Company contributed $3,843,000 in 2004 and $4,269,000 in 2003 to the pension and supplemental executive retirement plans, and expects to contribute $3,500,000 in 2005.

        The discount rate the Company selects is based on the average of the 20 year and above Aa debt rates published by Moody's. These are rates considered to be consistent with the expected term of pension benefits. In 2003 the Company reduced the discount rate from 6.75% to 6.25% in connection with remeasurement of the pension obligation at May 1, 2003, with a further reduction to 6.00% at September 30, 2003. At the September 30, 2004, the Company used a discount rate of 6.00%. A reduction in the discount rate results in increases in projected benefit obligation, pension liability, and pension costs.

        In selecting an assumed long-term rate of return on plan assets, the Company considers past performance and economic forecasts for the types of investments held by the plan. In 2004 and 2003 the Company's assumed rate of return on plan assets was 8.25%. A reduction in the assumed rate of return would result in increases in pension liability and pension costs.

Derivatives

        The Company accounts for derivative transactions according to the provisions of FAS No. 133, as amended by FAS No. 138 and by FAS No. 149. These standards require that the fair value of all derivative financial instruments be recognized as either assets or liabilities on the Company's balance sheet and the recognition of unrealized gains and losses.

        Most of the Company's contracts for purchase and sale of natural gas qualify for the normal purchase and normal sales exception under FAS No. 133 and are not required to be recorded as derivative assets and liabilities. Accordingly, the Company recognizes revenues and expenses on an accrual basis, based on physical delivery of natural gas. The Company applies mark-to-market accounting to financial derivative contracts. Periodic changes in fair market value of derivatives associated with supplies for non-core customers are recognized in earnings. The differences in accounting for purchases and sales contracts versus financial contracts do not change the underlying economics of the transactions, but could result in increased quarterly earnings volatility. The Company applies FAS No. 71 to periodic changes in fair market value of derivatives associated with supplies for core customers and records an offset in regulatory asset and regulatory liability accounts.

Medicare Prescription Drug, Improvement and Modernization Act of 2003

        On December 8, 2003, President Bush signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company has elected to recognize the impact of this subsidy retroactive to the beginning of the second quarter of fiscal 2004. Please refer to the information contained under the caption "FSP FAS No. 106-1 and 106-2", under New Accounting Standards in the Note 2 to the Consolidated Financial Statements, contained in this report.

New Accounting Standards:

        Information on new accounting standards is included in the Notes to the Consolidated Financial Statements, contained in this report.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

        Cascade has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The Company has fixed-rate debt obligations, but does not have derivative financial instruments subject to interest rate risk. Cascade makes interest and principal payments on these obligations in the normal course of its business, and does not plan to redeem these obligations prior to normal maturities.

        The Company's natural gas purchase commodity prices are subject to fluctuations resulting from weather, congestion on interstate pipelines, and other unpredictable factors. The Company's PGA mechanisms assure the recovery of prudently incurred wholesale cost of gas purchased for the core market. The Company utilizes fixed price contracts and financial derivatives to manage risk associated with wholesale costs of gas purchased for customers.

        With respect to derivative arrangements covering gas supplies for core customers, periodic changes in fair market value are recorded in regulatory asset or regulatory liability accounts, pursuant to authority granted by the WUTC and OPUC recognizing that settlements of these arrangements will be recovered through the Purchased Gas Cost Adjustment (PGA) mechanism.

        For derivative arrangements related to supplies for non-core customers, which are not covered by a PGA mechanism, periodic changes in fair market value are recognized in earnings.

FORWARD-LOOKING STATEMENTS

        Statements contained in this report that are not historical in nature are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are subject to risks and uncertainties that may cause actual future results to differ materially. Such risks and uncertainties with respect to the Company include, among others, its ability to successfully implement internal performance goals, competition from alternative forms of energy and other sellers of energy, consolidation in the energy industry, performance issues with key natural gas suppliers, the capital-intensive nature of the Company's business, regulatory issues, including the need for adequate and timely rate relief to recover capital and operating costs and to sustain dividend levels, the weather, increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, the potential loss of large volume industrial customers due to "bypass" or the shift by such customers to special competitive contracts at lower per unit margins, exposure to environmental cleanup requirements, and economic conditions, particularly in the Company's service area.

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders
Cascade Natural Gas Corporation
Seattle, Washington

        We have audited the accompanying consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the "Company") as of September 30, 2004 and 2003, and the related consolidated statements of income and comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2004. Our audits also included the financial statement schedule contained in Item 15(a)-2. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

        We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements and financial statement schedule present fairly, in all material respects, the financial position of the Company as of September 30, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

DELOITTE & TOUCHE LLP
Seattle, Washington
November 12, 2004

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Dollars in thousands except per share data)

The accompanying notes are an integral part of these financial statements

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

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