Edgar Filing: CASCADE NATURAL GAS CORP

1. Financial Statements:

Consolidated Statements of Income and Comprehensive Income

Consolidated Balance Sheets

Consolidated Statements of Common Shareholders' Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

Washington (State or other jurisdiction of incorporation or organization)		91-0599090 (I.R.S. Employer Identification No.)
222 Fairview Avenue North Seattle, WA 98109 (Address of principal executive offices)		(206) 624-3900 (Registrant's telephone number including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class Common Stock, Par Value $1 per Share		Name of Each Exchange on which Registered New York Stock Exchange

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.

Title
Common Stock, Par Value $1 per Share

Outstanding
11,270,863 as of October 29, 2004

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

		Number Page
Part I
	Item 1—Business	3
	Item 2—Properties	8
	Item 3—Legal Proceedings	8
	Item 4—Submission of Matters to a Vote of Security Holders	8
	Executive Officers of the Registrant	9
Part II
	Item 5—Market for Registrant's Common Equity and Related Stockholder Matters	10
	Item 6—Selected Financial Data	11
	Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations	13
	Item 7A—Quantitative and Qualitative Disclosures about Market Risk	23
	Item 8—Financial Statements and Supplementary Data	24
	Item 9—Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	48
	Item 9A—Controls and Procedures	48
Part III
	Item 10—Directors and Executive Officers of the Registrant	49
	Item 11—Executive Compensation	49
	Item 12—Security Ownership of Certain Beneficial Owners and Management	49
	Item 13—Certain Relationships and Related Transactions	49
	Item 14—Principal Accountant Fees and Services	50
Part IV
	Item 15—Exhibits, Financial Statement Schedules and Reports on Form 8-K	50
Signatures		52

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 lpinnt@cngc.com.

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

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

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.

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.

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.

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.

Executive Officers of the Registrant

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

Name	Office	Age	Year Became Officer
W. Brian Matsuyama	Vice Chairman, President and Chief Executive Officer	58	1987
J. D. Wessling	Chief Financial Officer	61	1995
William H. Odell	Chief Operating Officer	42	2000
Jon T. Stoltz	Senior Vice President—Gas Supply and Regulatory Affairs	57	1981
Larry C. Rosok	Vice President—Human Resources and Corporate Secretary	48	1995
James E. Haug	Controller	55	1981

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.

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.

	Fiscal 2004				Fiscal 2003
Quarter	Fiscal 2004				Fiscal 2003
Quarter	High		Low		High		Low
December 31	$	21.99	$	19.41	$	20.44	$	17.70
March 31		23.05		20.76		20.24		18.05
June 30		22.52		19.10		20.15		18.20
September 30		22.20		19.35		20.24		18.00

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.

Quarter	Fiscal 2004		Fiscal 2003
December 31	$	0.24	$	0.24
March 31	$	0.24	$	0.24
June 30	$	0.24	$	0.24
September 30	$	0.24	$	0.24

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

Item 6. Selected Financial Data

Consolidated Statements of Income and Comprehensive Income:

		Year Ended September 30
		2004			2003			2002			2001			2000
		(dollars in thousands except per share data)
Operating Revenues		$	318,078		$	302,755		$	320,978		$	335,814		$	241,936
Less: Gas Purchases			202,759			191,887			209,225			219,795			136,681
	Revenue taxes		21,511			20,193			21,251			20,987			15,261

Operating Margin			93,808			90,675			90,502			95,032			89,994

Cost of Operations:
	Operating expenses		40,540			45,514			43,052			41,027			38,808
	Depreciation and amortization		16,325			15,338			14,926			13,839			13,293
	Property and payroll taxes		3,696			3,532			3,361			3,182			2,896

			60,561			64,384			61,339			58,048			54,997

Income From Operations			33,247			26,291			29,163			36,984			34,997

Nonoperating Expense (Income):
	Interest		12,375			12,363			12,384			10,509			10,936
	Interest charged to construction		(445	)		(378	)		(219	)		(333	)		(322	)

			11,930			11,985			12,165			10,176			10,614
	Amortization of debt issuance expense		618			696			652			607			607
	Other		(162	)		(227	)		(197	)		(313	)		(649	)

			12,386			12,454			12,620			10,470			10,572

Income Before Income Taxes			20,861			13,837			16,543			26,514			24,425
Income Taxes			7,559			4,733			5,781			9,278			9,051

Net Income Before Preferred Dividends			13,302			9,104			10,762			17,236			15,374
Preferred Dividends			—			—			—			—			4

Net Income		$	13,302		$	9,104		$	10,762		$	17,236		$	15,370

Other Comprehensive Income (Loss)
	Minimum pension liability adjustment	$	1,270		$	(2,619	)	$	(11,792	)	$	(6,502	)	$	—
	Income tax benefit		(448	)		937			4,205			2,341			—

Other Comprehensive Income (Loss)		$	822		$	(1,682	)	$	(7,587	)	$	(4,161	)	$	—

Comprehensive Income		$	14,124		$	7,422		$	3,175		$	13,075		$	15,370

Earnings Per Common Share, Basic and Diluted		$	1.19		$	0.82		$	0.97		$	1.56		$	1.39

Item 6. Selected Financial Data (continued)

			At September 30
			2004			2003			2002			2001			2000
			(dollars in thousands except per share data)
Retained Earnings:
	Beginning of the year		$	15,981		$	17,524		$	17,369		$	10,736		$	5,970
	Net income			13,302			9,104			10,762			17,236			15,370
	Exercise of stock options						—			(4	)		—			—
	Common dividends			(10,783	)		(10,647	)		(10,603	)		(10,603	)		(10,604	)

	End of the year		$	18,500		$	15,981		$	17,524		$	17,369		$	10,736

Capital Structure:
	Common shareholders' equity		$	118,514		$	112,560		$	114,181		$	121,633		$	119,161
	Redeemable preferred stocks			—			—			—			—			62

	Debt:
		Long-term debt		128,900			142,930			164,930			125,000			125,000
		Notes payable and commercial paper		33,500			3,800			—			40,000			1,500
		Current maturities of long-term debt		14,000			22,000			—			—			—

				176,400			168,730			164,930			165,000			126,500

	Total capital		$	294,914		$	281,290		$	279,111		$	286,633		$	245,723

Financial Ratios:
	Return on common shareholders' equity			10.92	%		7.62	%		8.49	%		13.45	%		12.51	%
	Common stock dividend payout ratio			81	%		117	%		99	%		62	%		69	%
	Cash dividends per common share		$	0.96		$	0.96		$	0.96		$	0.96		$	0.96
	Fixed charge coverage (before income tax deduction):
		Times interest earned		2.61			2.06			2.27			3.39			3.12
		Times interest and preferred dividends earned		2.61			2.06			2.27			3.39			3.12
	Book value per year-end share of common stock		$	10.52		$	10.11		$	10.34		$	11.01		$	10.79
	Capitalization Ratios at End of Year Common shareholders' equity			40.2	%		40.0	%		40.9	%		42.4	%		48.5	%
		Preferred stock		0.0	%		0.0	%		0.0	%		0.0	%		0.0	%
		Long-term debt (incl. current)		48.5	%		58.6	%		59.1	%		43.6	%		50.9	%
		Short-term debt		11.4	%		1.4	%		0.0	%		14.0	%		0.6	%

				100.0	%		100.0	%		100.0	%		100.0	%		100.0	%

Utility Plant:
	Utility plant—end of year		$	570,036		$	529,807		$	505,126		$	488,231		$	468,789
	Accumulated depreciation			242,691			227,582			213,476			201,530			189,058

	Net plant		$	327,345		$	302,225		$	291,650		$	286,701		$	279,731

	Capital expenditures, net of contributions in aid		$	39,019		$	27,693		$	20,734		$	21,649		$	15,937

	Total assets		$	422,622		$	371,456		$	367,663		$	364,253		$	328,336

Number of Employees at End of Year				428			437			444			442			440

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:

•: Remain focused on the natural gas distribution business.
•: 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.

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:

•: Improved margins from residential and commercial customers related to increased per-customer consumption and growth in the number of customers—$0.18 per share.
•: 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.
•: Increase in depreciation and amortization—($0.06) per share.
•: Decreased margin from electric generation customers—($0.06) per share.
•: 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

		(12 months ended September 30)
		2004		2003		2002
		($ in thousands)
Degree Days			5,212		5,042		5,455
Average Number of Customers
	Residential		184,845		177,300		169,454
	Commercial		29,320		28,851		28,216
Average Therm Usage Per Customer
	Residential		710		692		763
	Commercial		3,628		3,473		3,802
Operating Margin
	Residential	$	39,691	$	37,483	$	38,396
	Commercial	$	22,014	$	21,014	$	22,209

Industrial and Other Operating Margin

		(12 months ended September 30)
		2004		2003		2002
		($ and therms in thousands)
Average Number of Customers
	Electric Generation		14		14		12
	Industrial		737		741		755
Therms Delivered
	Electric Generation		480,859		543,621		591,653
	Industrial		415,740		395,480		373,252
Operating Margin
	Electric Generation	$	8,013	$	9,032	$	9,263
	Industrial	$	19,394	$	19,394	$	19,194
	Gas Management Services	$	4,142	$	3,509	$	370
	Other	$	553	$	243	$	1,070

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

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

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.

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:

		Amounts Due by Fiscal Year
Contract Category		2005		2006	2007	2008	2009	Beyond 2009	Total
		(dollars in thousands)
Short-term Debt		$	33,500	—	—	—	—	—	$	33,500
Long-term Debt			14,000	8,000	—	—	—	120,900		142,900
Interest on Debt			10,603	10,014	9,338	9,253	9,253	125,582		174,043
Operating Leases			672	513	288	33	17	446		1,969
Gas Supply			139,378	113,500	127,794	143,096	91,029	4,358		619,155
Interstate Pipeline
	Transportation		28,571	28,571	27,864	27,864	27,864	266,283		407,017
Gas Storage and Peaking
	Services		4,796	4,796	4,796	4,796	4,796	4,796		28,776
Other			611	285	161	55	55	—		1,167

Total		$	232,131	165,679	170,241	185,097	133,014	522,365	$	1,408,527

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

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.

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.

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.

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.

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.

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

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Dollars in thousands except per share data)

			Year Ended September 30,
			2004			2003			2002
Operating Revenues			$	318,078		$	302,755		$	320,978
	Less
		Gas purchases		202,759			191,887			209,225
		Revenue taxes		21,511			20,193			21,251

Operating Margin				93,808			90,675			90,502

Cost of Operations
	Operating expenses			40,540			45,514			43,052
	Depreciation and amortization			16,325			15,338			14,926
	Property and miscellaneous taxes			3,696			3,532			3,361

				60,561			64,384			61,339

	Income from operations			33,247			26,291			29,163

Nonoperating Expense (Income)
	Interest			12,375			12,363			12,384
	Interest charged to construction			(445	)		(378	)		(219	)

				11,930			11,985			12,165
	Amortization of debt issuance expense			618			696			652
	Other			(162	)		(227	)		(197	)

				12,386			12,454			12,620

Income Before Income Taxes				20,861			13,837			16,543
Income Taxes				7,559			4,733			5,781

Net Income			$	13,302		$	9,104		$	10,762
Other Comprehensive Income (Loss):
	Minimum pension liability adjustment		$	1,270		$	(2,619	)	$	(11,792	)
	Income tax benefit			(448	)		937			4,205

Other Comprehensive Income (Loss)			$	822		$	(1,682	)	$	(7,587	)

Comprehensive Income			$	14,124		$	7,422		$	3,175

Earnings Per Common Share, Basic and Diluted			$	1.19		$	0.82		$	0.97

Dividends Paid Per Common Share			$	0.96		$	0.96		$	0.96

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

		September 30,
		2004		2003
		(Dollars in thousands)
ASSETS
Utility Plant		$	570,036	$	529,807
	Less accumulated depreciation		242,691		227,582

			327,345		302,225
	Construction work in progress		7,229		10,078

			334,574		312,303

Other Assets
	Investments in non utility property		202		202
	Notes receivable, less current maturities		43		52

			245		254

Current Assets
	Cash and cash equivalents		499		7,452
	Accounts receivable and current maturities of notes receivable, less allowance of $1,028 and $877 for doubtful accounts		15,001		12,296
	Materials, supplies, and inventories		13,268		14,737
	Derivative instrument asset—energy commodity		17,983		—
	Prepaid expenses and other assets		18,674		6,144
	Deferred income taxes		955		755

			66,380		41,384

Deferred Charges and Other
	Gas cost changes		12,288		11,584
	Derivative instrument asset—energy commodity		3,952		79
	Other		5,183		5,852

			21,423		17,515

		$	422,622	$	371,456

COMMON SHAREHOLDERS' EQUITY AND LIABILITIES
Common Shareholders' Equity
	Common stock, par value $1 per share; Authorized, 15,000,000 shares Issued and outstanding, 11,268,069 and 11,131,860 shares	$	11,268		$	11,132
	Additional paid-in capital		101,354			98,877
	Accumulated other comprehensive income (loss)		(12,608	)		(13,430	)
	Retained earnings		18,500			15,981

			118,514			112,560

Long-Term Debt			128,900			142,930

Current Liabilities
	Notes payable and commercial paper		33,500			3,800
	Current maturities of long-term debt		14,000			22,000
	Accounts payable		12,923			10,501
	Property, payroll, and excise taxes		5,287			5,387
	Dividends and interest payable		7,125			7,884
	Regulatory liabilities		17,209			—
	Other current liabilities		8,972			6,431

			99,016			56,003

Deferred Credits and Other Non-current Liabilities
	Income taxes		37,089			23,292
	Investment tax credits		1,303			1,479
	Retirement plan obligations		20,780			23,677
	Regulatory liabilities		10,515			4,422
	Other		6,505			7,093

			76,192			59,963

Commitments and Contingencies (Note 11)			—			—

		$	422,622		$	371,456

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

			Common Stock						Accumulated Other Comprehensive Income (Loss)
			Common Stock			Paid-In Capital						Retained Earnings
			Shares	Par Value		Paid-In Capital						Retained Earnings
			(Dollars in thousands except per share data)
Balance, September 30, 2001			11,045,095	$	11,045	$	97,380		$	(4,161	)	$	17,369
	Cash dividends:
		Common stock, $.96 per share											(10,603	)
	Other comprehensive income (loss)									(7,587	)
	Exercise of stock options						(20	)					(4	)
	Net Income												10,762

Balance, September 30, 2002			11,045,095	$	11,045	$	97,360		$	(11,748	)	$	17,524

	Cash dividends:
		Common stock, $.96 per share											(10,647	)
	Other comprehensive income (loss)									(1,682	)
	Issuance of common stock		86,765		87		1,517
	Net Income												9,104

Balance, September 30, 2003			11,131,860	$	11,132	$	98,877		$	(13,430	)	$	15,981

	Cash dividends:
		Common stock, $.96 per share											(10,783	)
	Other comprehensive income (loss)									822
	Issuance of common stock		136,209		136		2,477
	Net Income												13,302

Balance, September 30, 2004			11,268,069	$	11,268	$	101,354		$	(12,608	)	$	18,500

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

			Year Ended September 30,
			2004			2003			2002
			(Dollars in thousands)
Operating Activities
	Net Income		$	13,302		$	9,104		$	10,762
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization		16,325			15,338			14,926
		Deferrals of gas cost changes		(7,001	)		1,336			1,804
		Amortization of gas cost changes		6,296			5,868			8,270
		Other deferrals and amortizations		1,099			6,032			(2,559	)
		Deferred income taxes and tax credits—net		12,972			2,804			3,541
		Change in current assets and liabilities		(10,427	)		(3,782	)		(740	)

	Net cash provided by operating activities			32,566			36,700			36,004

Investing Activities
	Capital expenditures			(39,465	)		(28,551	)		(21,117	)
	Customer contributions in aid of construction			446			858			383
	Other			—			—			183

	Net cash used by investing activities			(39,019	)		(27,693	)		(20,551	)

Financing Activities
	Proceeds from long-term debt, net			—			—			38,510
	Repayment of long-term debt			(22,030	)		—			(70	)
	Changes in notes payable and commercial paper, net			29,700			3,800			(40,000	)
	Proceeds from issuance of common stock			2,613			1,604			—
	Dividends paid			(10,783	)		(10,647	)		(10,603	)
	Other			—			—			(24	)

	Net cash used by financing activities			(500	)		(5,243	)		(12,187	)

Net Increase (Decrease) in Cash and Cash Equivalents				(6,953	)		3,764			3,266
Cash and Cash Equivalents
	Beginning of year			7,452			3,688			422

	End of year		$	499		$	7,452		$	3,688

The accompanying notes are an integral part of these financial statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Nature of Business

Cascade Natural Gas Corporation (the Company) is a local distribution company (LDC) engaged in the distribution of natural gas. The Company's service territory consists of towns in Washington and Oregon, ranging from the Canadian border in northwestern Washington to the Idaho border in eastern Oregon.

As of September 30, 2004, the Company had approximately 214,000 billed core customers and 189 non-core customers. Core customers are principally residential and small commercial and industrial customers who take traditional "bundled" natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation. Sales to core customers account 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, electric generation, and institutional customers who have chosen "unbundled" service, meaning that they select from among several supply and upstream pipeline transportation options, independent of the Company's distribution service. The Company's margin from non-core customers is derived primarily from this distribution service, as well as gas management services. The principal industrial activities of its customers include the generation of electricity, processing of food, processing of forest products, production of chemicals, and refining of crude oil.

The Company is subject to regulation of most aspects of its operations by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC). It is subject to regulatory risk primarily with respect to recovery of costs incurred. Various deferred charges and deferred credits reflect assumptions regarding recovery of certain costs through temporary customer rate adjustments during future periods.

Note 2—Summary of Significant Accounting Policies

The Company's accounting records and practices conform to the requirements of the uniform system of accounts prescribed by the WUTC and the OPUC.

Principles of consolidation: The consolidated financial statements include the accounts of Cascade Natural Gas Corporation and its wholly owned subsidiaries: Cascade Land Leasing Co.; CGC Properties, Inc.; CGC Energy, Inc.; and CGC Resources, Inc.All intercompany transactions are eliminated in consolidation.

Reclassifications: Certain reclassifications have been made in the 2002 financial statements to conform to the classifications used in 2004 and 2003.

Utility plant: Utility plant is stated at the historical cost of construction or purchase. These costs include payroll-related costs such as taxes and other employee benefits, general and administrative costs, and the estimated cost of funds used during construction. Maintenance and repairs of property, and replacements and renewals of items deemed to be less than units of property, are charged to operations. Units of utility plant retired or replaced are credited to property accounts at cost. Such amounts plus removal cost, less salvage, are charged to accumulated depreciation. In the case of a sale of non-depreciable property or major operating units, the resulting gain or loss on the sale is included in other income or expense.

Depreciation of utility plant is computed using the straight-line method. The Company periodically conducts depreciation studies to establish and update asset depreciation lives. Asset lives used for computing depreciation range from six to seventy years, and the weighted average annual depreciation rate is approximately 3.0%. The Company periodically reviews the carrying amount of its utility plant and other long-lived assets for impairment. An asset is considered impaired when estimated future cash flows are less than the carrying amount of the asset. In the event the carrying amount of such asset is deemed not recoverable, the asset is adjusted to its fair value. Fair value is generally determined based on discounted future cash flow.

The Company periodically reviews items, such as its franchises and easements, which may give rise to asset retirement obligations (ARO). Based on these reviews the Company has concluded it has no ARO's.

Investments in non-utility property: Real estate, carried at the lower of cost or estimated net realizable value is the primary investment.

Cash and cash equivalents: For purposes of reporting cash flows, the Company accounts for all liquid investments, with a purchased maturity of three months or less, as cash equivalents. The following provides additional information to the Consolidated Statements of Cash Flows:

		2004			2003			2002
		(Dollars in thousands)
Changes in current assets and current liabilities:
	Accounts and notes receivable	$	(2,696	)	$	2,327		$	4,318
	Income taxes		(12,026	)		1,156			(4,031	)
	Inventories		1,468			(180	)		(5,686	)
	Prepaid expenses and other assets		(504	)		108			12
	Accounts payable and accrued expenses		3,967			(7,192	)		4,647
	Other		(636	)		(1	)		—

	Net change in current assets and current liabilities	$	(10,427	)	$	(3,782	)	$	(740	)

Cash payments:
	Interest (net of amounts capitalized)	$	12,839		$	12,288		$	11,074
	Income taxes	$	4,610		$	—		$	6,938

Materials, supplies and inventories: Materials and supplies for construction, operations, and maintenance, and inventories of natural gas are recorded at cost.

Regulatory accounts: The Company follows Statement of Financial Accounting Standards (FAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement provides for the deferral of certain costs and benefits that would otherwise be recognized in revenue or expense, if it is probable that future rates will result in recovery from customers or refund to customers of such amounts.

Regulatory assets (liabilities) at September 30, 2004 and 2003 include the following:

		2004			2003
		(dollars in thousands)
Non-current Assets
	Gas cost changes	$	12,288		$	11,584
	Unamortized loss on reacquired debt		1,887			2,379
	Other		541			354
Current Liabilities
	Gas supply hedging		(17,209	)		—
Non-current Liabilities
	Deferred income taxes		(5,971	)		(3,967	)
	Gas supply hedging		(3,941	)		—
	Other, net		(603	)		(455	)

	Net	$	(13,008	)	$	9,895

Under Non-current Assets, Unamortized loss on reacquired debt and Other are included on the Consolidated Balance Sheets in "Other Deferred Charges".

Revenue recognition: The Company recognizes operating revenues based on deliveries of gas 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.

Allowance for doubtful accounts: With respect to its residential and commercial customer accounts, the Company establishes an allowance for doubtful accounts based on historical trends and ratios of write-offs to revenues. With respect to industrial customer accounts which are generally significantly larger than residential and commercial, a specific allowance is established for accounts determined to be at risk of collection.

Leases: The Company leases a portion of its vehicle fleet. These leases are classified as operating leases. The Company's primary obligation under these leases is for a twelve-month period, with options to extend the lease thereafter. Commitments beyond one year are not material. Rent expense under operating leases totaled $776,000, $835,000, and $813,000 for fiscal years ended September 30, 2004, 2003, and 2002, respectively.

Federal income taxes: Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using current tax rates. The Company normalizes temporary differences between book income and taxable income, with the exception of depreciation differences on assets placed in service prior to 1981, consistent with the policies of the WUTC and OPUC. With respect to utility plant placed in service after 1980, the Company calculates its deferred income tax provision to conform to the Federal normalization requirements, as approved by the WUTC and OPUC.

Investment tax credits: Investment tax credits were deferred and are amortized over the remaining life of the properties that gave rise to the credits.

Use of estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 these estimates. 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, values of derivative instruments, unbilled revenue, and in the determination of depreciable lives of utility plant.

Stock-based compensation: Compensation cost for stock options is measured as the excess of the market price of the Company's stock at the date of the grant over the price the employee must pay to acquire the stock. The Company accounts for its stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" rather than using the fair-value-based method prescribed under FAS No. 123, "Accounting for Stock-Based Compensation." The Company has adopted the disclosure requirements of FAS No. 123. See Note 6 for more information about the Company's stock-based compensation plan. Had compensation expense been determined in accordance with FAS No. 123, the Company's net income and earnings per share would have been as follows:

		2004		2003		2002
		(in thousands except per-share data)
Net Income
	As reported	$	13,302	$	9,104	$	10,762
	Less total stock-based employee compensation expense determined under the fair value method, net of tax		53		110		129

	Pro forma net income	$	13,249	$	8,994	$	10,633

Earnings per share, basic and diluted
	As reported	$	1.19	$	0.82	$	0.97
	Pro forma	$	1.18	$	0.81	$	0.96

Comprehensive income (loss): Comprehensive income for the fiscal years ended September 30, 2004, 2003 and 2002, included Other Comprehensive Income (Loss) of $822,000, ($1,682,000) and ($7,587,000), net of income tax. The charges are related to minimum pension liability adjustments. See Note 10 for more information.

Segment reporting: Management views the Company as operating as a single segment, that of a local distribution company in the Pacific Northwest. Therefore, the financial statements do not include disclosure of segment information.

Derivatives: The Company records derivative transactions according to the provisions of FAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by FAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", and by FAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities". 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. Changes during a period in the fair value of a derivative instrument are required to be included in earnings or other comprehensive income for the period.

The Company's contracts for purchase and sale of natural gas generally qualify for the normal purchase and normal sales exceptions under FAS No. 133. 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 arrangements.

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.

New Accounting Standards:

FAS No. 132 (revised 2003): In December 2003, the Financial Accounting Standards Board (FASB) issued FAS No. 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits." This statement requires expanded disclosures with respect to pension plan assets, benefit obligations, cash flows, benefit costs and other relevant information. However, this statement does not change the measurement and recognition provisions of previous FASB statements related to pensions and other postretirement benefits. The Company was required to adopt this statement during the quarter ended March 31, 2004. The adoption of this statement did not have any effect on the Company's results of operations, cash flows, or balance sheet. The expanded disclosures required by this statement are included in Note 10.

FSP FAS Nos. 106-1 and 106-2: In January 2004, the FASB issued FASB Staff Position (FSP) No. FAS 106-1, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. FSP No. FAS 106-1 provided guidance permitting a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). At that time the Company made such an election. The Act, signed into law by President Bush on December 8, 2003, 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.

In May 2004, the FASB issued FSP FAS No. 106-2, superseding FSP No. FAS 106-1. This standard applies to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded that prescription drug benefits available under the plan to some or all participants for some or all future years are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act, and (b) the expected subsidy will offset or reduce the employer's share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based.

This FSP was effective for the first interim or annual period beginning after June 15, 2004, with earlier adoption permitted. The Company has concluded that prescription drug benefits available under the plan to some or all participants for some or all future years are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy under the Act, and elected to remeasure its postretirement medical expense for fiscal year 2004, with a remeasurement date of December 31, 2003. The result of the remeasurement is a reduction of retiree medical expense of $315,000. Further information regarding postretirement medical benefits is included in Note 10.

Note 3—Earnings per Share

The following table sets forth the calculation of earnings per share as prescribed in FAS No. 128.

	2004		2003		2002
	(in thousands except per share data)
Net Income	$	13,302	$	9,104	$	10,762
Weighted average shares outstanding		11,209		11,075		11,045
Plus: Issued on assumed exercise of stock options		13		16		19

Weighted average shares outstanding assuming dilution		11,222		11,091		11,064

Earnings per common share, basic	$	1.19	$	0.82	$	0.97

Earnings per common share, diluted	$	1.19	$	0.82	$	0.97

The only dilutive securities are the stock options described in Note 6.

Note 4—Utility Plant

Utility plant at September 30, 2004 and 2003 consists of the following components:

	2004		2003
	(dollars in thousands)
Distribution plant	$	505,232	$	470,550
Transmission plant		14,693		14,693
General plant		45,840		40,345
Intangible plant		212		212
Nondepreciable plant		4,059		4,007

	$	570,036	$	529,807

Note 5—Common Stock

At September 30, 2004, shares of common stock are reserved for issuance as follows:

		Number of shares
Employee Savings Plan and Retirement Trust (401(k) plan)		198,344
Dividend Reinvestment Plan		235,405
Director Stock Award Plan		32,612
Stock Incentive Plan (Note 6)		396,930

		863,291

The price of shares issued to the above plans is determined by the market price of shares on the day of, or immediately preceding the issuance date.

Note 6—Stock-Based Compensation Plan

Under the Company's stock incentive plan, officers and other key management employees may be granted options to purchase stock. The grants vest ¹/3 per year over three years. Options granted in 1999, 2000, and 2001 expire five years after the grant date. Options granted in 2002 expire ten years from the grant date. No options were granted in 2003 or 2004. The weighted average remaining life of options outstanding at September 30, 2004 is 3.8 years.

The following table summarizes the grants under option at September 30:

	2004				2003				2002
	Wtd. Avg. Exercise Price		No. Shares Under Option		Wtd. Avg. Exercise Price		No. Shares Under Option		Wtd. Avg. Exercise Price		No. Shares Under Option
Balance at October 1	$	18.15	182,030		$	18.04	192,430		$	16.81	142,966
Options granted		N/A	—			N/A	—		$	20.84	63,000
Options cancelled			(7,999	)			(3,600	)			(7,166	)
Options exercised			(49,633	)			(6,800	)	$	16.62	(6,370	)

Balance at September 30	$	18.69	124,398		$	18.15	182,030		$	18.04	192,430

Exercisable at September 30	$	18.34	107,405		$	17.24	124,753		$	16.39	79,989

Weighted average fair value of options granted during the fiscal year		N/A				N/A			$	2.51

The fair value was estimated at the date of the grants using a Black-Scholes option pricing model using the following assumptions for options granted in 2002:

Dividend yield	4.61	%
Expected volatility	17	%
Expected life	7.5 years
Risk-Free interest rate	4.09	%

Note 7—Notes Payable and Commercial Paper

The Company's short-term borrowing needs are met with a three-year $60,000,000 revolving credit agreement with one of its banks. This agreement has a variable commitment fee and a term that expires in October 2007.

	September 30
	2004			2003			2002
	(dollars in thousands)
Amount outstanding at September 30	$	33,500		$	3,800		$	—
Average daily balance outstanding	$	4,511		$	449		$	7,973
Average interest rate, excluding commitment fee		2.29	%		2.54	%		3.01	%
Maximum month end amount outstanding	$	33,500		$	6,250		$	46,000

Various debt and credit agreements restrict the Company and its subsidiaries as to indebtedness, payment of cash dividends on common stock, and other matters. As of September 30, 2004, the Company is in compliance with all restrictive covenants of its debt agreements.

Note 8—Long-Term Debt

Long-term debt and current maturities of long-term debt at September 30, 2004 and 2003 consists of the following:

		2004		2003
		(dollars in thousands)
Medium-term notes:
	7.18% due Oct. 2004	$	—	$	4,000
	8.38% due Jan. 2005		—		5,000
	8.35% due Jul. 2005		—		5,000
	8.50% due Oct. 2006		8,000		8,000
	8.06% due Sep. 2012		14,000		14,000
	8.10% due Oct. 2012		5,000		5,000
	8.11% due Oct. 2012		3,000		3,000
	7.95% due Feb. 2013		4,000		4,000
	8.01% due Feb. 2013		10,000		10,000
	7.95% due Feb. 2013		10,000		10,000
	7.48% due Sep. 2027		20,000		20,000
	7.098% due Mar. 2029		15,000		15,000
7.50% Thirty-year notes due November 2031			39,900		39,930

	Total long-term debt	$	128,900	$	142,930

Current Maturities of Long-Term Debt
Medium-term notes:
	7.18% due Oct. 2004	$	4,000	$	—
	8.38% due Jan. 2005		5,000		—
	8.35% due Jul. 2005		5,000		—
	7.32% due August 2004		—		22,000

	Total current maturities	$	14,000	$	22,000

None of the long-term debt includes sinking fund requirements. Annual obligations for redemption of long-term debt and current maturities are as follows: $14,000,000 in fiscal year 2005, none in fiscal year 2006, $8,000,000 in fiscal year 2007, none in fiscal years 2008 and 2009, and $120,900,000 thereafter.

There are $103 million Medium-Term Notes (MTN's), including current maturities, outstanding as of September 30, 2004. The $39,900,000 Thirty-Year Notes were issued under a 2001 shelf registration providing ability to issue up to $150 million long-term debt and equity securities. As of September 30, 2004, that registration statement has $110,000,000 available for issuance.

Note 9—Income Taxes

The provision for income tax expense consists of the following:

	2004			2003			2002
	(dollars in thousands)
Current tax expense	$	(7,416	)	$	270		$	2,850
Deferred tax expense		15,151			4,652			3,137
Amortization of deferred investment tax credits		(176	)		(189	)		(206	)

Total income tax expense	$	7,559		$	4,733		$	5,781

A deferred income tax charge (benefit) associated with accruals of minimum pension liability is included in Other Comprehensive Income (OCI) for each year ended September 30, as follows: $448,000 in 2004, ($937,000) in 2003, and ($4,205,000) in 2002. See Note 10 for more information on OCI.

A reconciliation between income taxes calculated at the statutory federal tax rate and income taxes reflected in the financial statements is as follows:

		2004			2003			2002
		(dollars in thousands)
Statutory federal income tax rate			35	%		35	%		35	%
Income tax calculated at statutory federal rate		$	7,301		$	4,843		$	5,790
Increase (decrease) resulting from:
	State income tax, net of federal tax benefit		60			109			130
	Non-normalized depreciation differences		364			305			355
	Amortization of investment tax credits		(176	)		(189	)		(206	)
	Other		10			(335	)		(288	)

		$	7,559		$	4,733		$	5,781

Effective tax rate			36.2	%		34.2	%		34.9	%

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. There is no deferred tax provision for temporary differences related to depreciation of pre-1981 assets because with respect to those assets, there is no regulatory recognition of deferred tax accounting.

Deferred tax assets and liabilities are calculated under FAS No. 109, "Accounting for Income Taxes". FAS 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 of temporary differences for which flow-through accounting has been utilized, a regulatory liability for income taxes payable through future rates related to those temporary differences has been established. At September 30, 2004, the balance of this regulatory liability is $5,936,000.

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 tax effects of significant items comprising the Company's deferred income tax accounts at September 30, 2004 and 2003 are as follows:

			2004		2003
			(dollars in thousands)
Current Amount:
	Deferred assets:
		Allowance for doubtful accounts	$	421	$	365
		Accrued liabilities		520		360
		Other		14		30

			$	955	$	755

Non-current Amounts:
	Deferred tax liabilities:
		Basis differences on net fixed assets	$	39,395	$	31,854
		Deferred gas costs		5,190		—
		Debt refinancing costs		676		851
		Retirement benefit obligations		1,388		941
		Other		235		—

				46,884		33,646

	Deferred tax assets:
		Retirement benefit obligations		2,582		2,658
		Other comprehensive income		7,036		7,484
		Other		177		212

				9,795		10,354

	Net non-current deferred tax liability		$	37,089	$	23,292

Note 10—Retirement Plans

The Company has a noncontributory defined benefit pension plan that covers substantially all employees over 21 years of age with one year of service. Under a plan amendment effective October 1, 2003 non-bargaining-unit employees no longer accrue benefits under the plan. Benefits accrued as of that point were frozen for those employees. Employees covered by a bargaining agreement accrue benefits based on a formula that includes credited years of service and the employee's annual compensation.

The Company has also provided executive officers with supplemental retirement, death, and disability benefits. This plan was also frozen September 30, 2003. Under the plan, vesting occurred on a stepped basis, with full vesting at age 55 and completing either five years of participation under the plan or seventeen years of employment with the Company, upon death, or upon a change in control. The plan supplemented the benefit received through Social Security and the defined benefit pension plan so that the total retirement benefits would be equal to 70% of the executive's highest salary during any of the five years preceding retirement. The plan also provides a death benefit equivalent to ten years of vested benefits.

The Company has an Employee Savings Plan and Retirement Trust (401(k) plan). All employees 21 years of age or older with one full year of service are eligible to enroll in the plan. Under the terms of the plan, the Company matches contributions based on a percentage of each employee's contribution up to 6% of the employee's compensation, as defined. Effective July 1, 2003, the Company's matching contribution percentage was reduced from 75% to 50% with respect to non-bargaining-unit employees.

The rate remains at 75% for bargaining-unit employees. The Company recognized costs for matching contributions of $728,000, $782,000, and $755,000, for 2004, 2003 and 2002, respectively.

In addition to the existing match of non-bargaining-unit employee contributions, the Company contributes 4% of eligible salaries, and a 1% to 4% transition contribution, to employee retirement accounts. The Company recognized $973,000 in additional fiscal 2004 401(k) costs for the two new contributions to this plan. Additionally there will be annually determined "profit- sharing" contributions based on the Company achieving established targets. There was no profit sharing contribution for 2004. The retirement plans remain unchanged for bargaining-unit employees until the existing agreement expires in 2006.

The Company's health care plan provides Postretirement Benefits Other than Pensions (PBOP), consisting of medical and prescription drug benefits, to its retired employees hired prior to June 1, 1992, and their eligible dependents. Changes to this plan, announced in 2003, provide for the addition of participant contributions that began January 1, 2004.

The following tables set forth the pension and health care plan disclosures. The amounts shown in the tables under Pension Benefits represent the aggregate amounts of the employee pension plan and the executive supplemental retirement plan. Amounts shown under Other Benefits represent the retiree medical plan. The measurement date of plan assets and obligations is as of September 30 for each year presented.

Components of net periodic benefit cost

	Pension Benefits									Other Benefits
	2004			2003			2002			2004			2003			2002
Service cost	$	768		$	1,522		$	1,569		$	160		$	534		$	522
Interest cost		3,728			3,745			3,630			1,270			2,182			2,153
Expected return on plan assets		(3,913	)		(3,738	)		(3,927	)		(853	)		(731	)		(721	)
Amortization of transition obligation		—			58			100			—			657			657
Amortization of prior service cost		229			365			499			(1,319	)		(375	)		(72	)
Recognized net actuarial loss / (gain)		1,397			1,160			24			961			1,205			298

Net periodic benefit cost	$	2,209		$	3,112		$	1,895		$	219		$	3,472		$	2,837
Curtailment loss recognized		—			1,451			—			—			—			—

Total benefit cost	$	2,209		$	4,563		$	1,895		$	219		$	3,472		$	2,837

		Pension Benefits						Other Benefits
		2004			2003			2004			2003
		(dollars in thousands)
Change in benefit obligations
Projected benefit obligation at beginning of year		$	63,371		$	56,885		$	25,011		$	35,820
Service Cost			768			1,522			160			534
Interest Cost			3,728			3,745			1,270			2,182
Plan participants' contributions			—			—			56			—
Amendments			—			—			(1,216	)		(14,742	)
Curtailments			—			(2,566	)		—			—
Benefits paid			(2,645	)		(2,397	)		(1,106	)		(1,130	)
Changes in assumptions			—			5,955			—			—
Actuarial (gain)/loss			301			227			(5,215	)		2,347

Projected benefit obligation at end of year		$	65,523		$	63,371		$	18,960		$	25,011

Change in Plan Assets
Fair value of plan assets at beginning of year		$	45,723		$	37,898		$	10,383		$	9,245
Actual return on plan assets			4,411			5,953			1,234			1,428
Employer contributions			3,843			4,269			368			840
Plan participants' contributions			—			—			56			—
Benefits Paid			(2,645	)		(2,397	)		(1,106	)		(1,130	)

Fair value of plan assets at end of year		$	51,332		$	45,723		$	10,935		$	10,383

Funded Status		$	(14,191	)	$	(17,648	)	$	(8,025	)	$	(14,628	)
Unrecognized prior service cost			827			1,056			(8,940	)		(15,121	)
Unrecognized net (gain)/loss			23,345			24,940			10,187			16,745
Unrecognized transition obligation/(asset)			—			—			—			6,077

Net amount recognized		$	9,981		$	8,348		$	(6,778	)	$	(6,927	)

Amounts recognized in the balance sheet consist of:
	Prepaid pension cost	$	3,507		$	3,120		$	—		$	—
	Accrued pension (liability)		(13,997	)		(16,743	)		(6,778	)		(6,927	)
	Intangible asset		827			1,056			—			—
	Accumulated other comprehensive (income) loss		19,644			20,914			—			—

	Net amount recognized	$	9,981		$	8,347		$	(6,778	)	$	(6,927	)

Accumulated Benefit Obligation		$	63,512		$	61,220

For the fiscal year ending September 30, 2005, the Company expects to contribute $3,500,000 to the employee pension plan, none to the supplemental executive retirement plan and $375,000 to the retiree medical plan.

Expected pension benefit payments for the next five fiscal years, 2005 through 2009, are $2,945,000, $3,167,000, $3,389,000, $3,602,000, and $3,828,000. For the ensuing five years, pension benefit payments are expected to total $22,167,000. Other postretirement benefit payments for those years are expected to be $1,215,000, $1,141,000, $1,158,000, $1,210,000, and $1,286,000. Other postretirement benefit payments for the ensuing five years are expected to total $7,191,000.

		Discount Rate				Average Compensation Increase				Expected Return on Plan Assets
		2004		2003		2004		2003		2004		2003
Weighted Average Assumptions
	Pension plan	6.00	%	6.00	%	3.50	%	3.50	%	8.25	%	8.25	%
	Supplemental executive retirement plan	6.00	%	6.00	%	N/A		3.50	%	8.25	%	8.25	%
	Postretirement medical benefit plan	6.00	%	6.00	%	N/A		N/A		8.25	%	8.25	%

Assumed Health Care Cost Trend Rates

		2004		2003
Medical and Medicare
	Initial rate	7	%	8	%
	Trends down to 5.5% ultimate rate by 2008
Prescription Drugs
	Initial rate	12	%	13	%
	Trends down to 5.5% ultimate rate by 2014

A one percent change in the assumed health care cost trend rate would have the following effects as of September 30, 2004:

	One Percentage Point
	Increase		Decrease
	(thousands)
Effect on service and interest cost for year ended September 30, 2004	$	184	$	(155	)
Effect on accumulated postretirement benefit obligation as of September 30, 2004	$	2,109	$	(1,806	)

The following information regarding asset allocation, development of expected rate of return on plan assets, and investment strategy is presented separately for each of the three plans.

Employee Pension Plan

Investment Policy Summary

The fundamental investment objective of the Employee Pension Plan (the Plan) is to provide a rate of return sufficient to fund the retirement benefits under the plan at a reasonable cost to the plan sponsor, Cascade Natural Gas Corporation. At a minimum, the rate of return should equal or exceed the discount rate assumed by the plan's actuaries in projecting the funding cost of the plan under applicable ERISA standards. To do so, the Company's Pension Committee (the Committee) may appoint one or more investment managers to invest all or portions of the assets of the Plan (collectively referred to as the "Fund") in accordance with specific investment guidelines, objectives, standards, and benchmarks.

Because the Committee expects the Fund's investment income, when combined with anticipated contributions by the Company, to exceed the sum of benefit payments and expenses over the next several years, the Committee intends that the Fund be managed to achieve long-term returns, with only a small percentage of the Fund invested in cash.

The Fund shall be divided into the following segments with the following weightings:

	Target		Minimum		Maximum
Equity Securities	65	%	25	%	75	%
Fixed Income Securities	25	%	10	%	40	%
Other	10	%	0	%	45	%

Asset Allocation

The asset allocation at September 30, 2004, and 2003, by major asset category is as follows:

		Plan Assets at September 30
Asset Category		Plan Assets at September 30
Asset Category		2004		2003
Equity Securities		72	%	75	%
Fixed Income Securities		24	%	22	%
Other		4	%	3	%
	Total	100	%	100	%

Expected Long-term Rate of Return on Plan Assets

The expected long-term rate of return on assets assumption is based on historical experience and consultation with our actuarial consultants. The current 8.25% assumption compares favorably to the 10-year historical weighted average compound return of 8.67% actually achieved by the Plan assets.

Additional year-end information for plans with accumulated benefit obligation in excess of plan assets:

The amounts listed in the following table apply only to the employee retirement plan. This plan has an accumulated benefit obligation in excess of plan assets, resulting in the amounts shown in the table.

	Employee Pension Plan
	2004			2003
Projected benefit obligation	$	59,308		$	57,160
Accumulated benefit obligation		57,298			55,009
Fair value of assets		43,300			38,267
Other comprehensive (income) loss		19,644			20,914
(Increase) / decrease in intangible asset		229			1,542
Increase (decrease) in accrued pension cost		(1,499	)		1,077

Supplemental Executive Retirement Plan (SERP)

Investment Policy Summary

SERP assets are in insurance policies and managed investments. The value of insurance policies at September 30, 2004 was $5,169,000 and at September 30, 2003 was $4,715,000. The managed assets are divided into the following segments with the following weightings:

	Target		Minimum		Maximum
Equity Securities	65	%	25	%	75	%
Fixed Income Securities	25	%	10	%	40	%
Other	10	%	0	%	45	%

Asset Allocation

The allocation of managed assets at September 30, 2004, and 2003, by major asset category is as follows:

		Plan Assets at September 30
Asset Category		Plan Assets at September 30
Asset Category		2004		2003
Equity Securities		64	%	56	%
Fixed Income Securities		23	%	38	%
Other		13	%	6	%
	Total	100	%	100	%

Expected Long-term Rate of Return on Plan Assets

The expected long-term rate of return on assets assumption is based on historic experience with the investment manager and consultation with our actuarial consultants. The investment manager has managed SERP assets for less than 10 years and over that period the weighted average compound return was 7.08%. For medical plan assets, managed by the same investment manager, the 10 year

weighted average compound return was 8.32%. The 8.25% assumption compares favorably to the 10-year historical weighted average compound return of 8.32% actually achieved by the investment manager.

Retiree Medical Plans

Investment Policy Summary

The fundamental investment objective of the Trusts (voluntary employee benefit associations within the meaning of Section 501(c)(9) of the Internal Revenue Code) is to provide assets sufficient to fund medical benefits under the Company's medical plan at a reasonable cost to the plan sponsor, Cascade Natural Gas Corporation. The Company will appoint a qualified actuary to determine the benefit obligation under the medical plan (including post-retirement benefits) and the necessary funding to meet those obligations. In performing this analysis, the actuary will use appropriate actuarial methods for medical benefits and comply with existing financial accounting standards.

	Target		Minimum		Maximum
Equity Securities	65	%	25	%	75	%
Fixed Income Securities	25	%	10	%	40	%
Other	10	%	0	%	45	%

Asset Allocation

The asset allocation at September 30, 2004, and 2003, by major asset category is as follows:

		Plan Assets at September 30
Asset Category		Plan Assets at September 30
Asset Category		2004		2003
Equity Securities		65	%	56	%
Fixed Income Securities		24	%	39	%
Other		11	%	5	%
	Total	100	%	100	%

Expected Long-term Rate of Return on Plan Assets

The expected long-term rate of return on assets assumption is based on historic experience and consultation with our actuarial consultants. The 8.25% assumption compares favorably to the 10-year historical weighted average compound return of 8.32% actually achieved by the Plan assets.

Note 11—Commitments and Contingencies

Gas Service Contracts

The Company has entered into various long-term contracts for natural gas supply, transportation, storage, and peaking services. These contracts are intended to provide adequate supplies of gas for service to core customers and to meet obligations under long-term non-core customer agreements, and to provide that adequate capacity is available on interstate pipelines for the delivery of these supplies. These contracts have maturities ranging up to 25 years, and generally provide for monthly and annual fixed demand charges and minimum purchase obligations.

The Company's minimum obligations under these contracts are set forth in the following table. The amounts are based on hedged prices, as applicable, current contract price terms and estimated commodity prices on un-hedged supplies, which are subject to market fluctuations:

Fiscal Year Ending September 30	Firm Gas Supply		Interstate Pipeline Transportation		Storage and Peaking Service		Total
	(dollars in thousands)
2005	$	139,378	$	28,571	$	4,796	$	172,745
2006		113,500		28,571		4,796		146,867
2007		127,794		27,864		4,796		160,454
2008		143,096		27,864		4,796		175,756
2009		91,029		27,864		4,796		123,689
Thereafter		4,358		266,283		4,796		275,437

	$	619,155	$	407,017	$	28,776	$	1,054,948

Purchases under these contracts for fiscal 2004, 2003, and 2002 were as follows:

	Firm Gas Supply		Interstate Pipeline Transportation		Storage and Peaking Service		Total
	(dollars in thousands)
2004	$	195,445	$	32,114	$	2,609	$	230,168
2003	$	159,028	$	26,450	$	2,140	$	187,618
2002	$	141,093	$	25,210	$	2,140	$	168,443

Financial Derivatives

To mitigate market risk and provide assurance of stable prices for its customers, the Company has entered into a number of hedging arrangements related to its gas supply contracts. The hedging arrangements are primarily in the form of financial swaps to fix the price of supplies. Under the terms of the swap arrangements the Company will either pay or receive settlement payments based on the difference between a fixed strike price and the monthly index price applicable to each contract. The total quantities subject to hedging arrangements are 20,769,000 MMBTU's in 2005, 11,175,000 MMBTU's in 2006, 5,221,000 MMBTU's in 2007, and 194,000 MMBTU's in 2008. The mark-to-market value of these hedges as of September 30, 2004 and 2003 are included in the balance sheet as follows:

	2004			2003
Derivative instrument asset—energy commodity (current)	$	17,983		$	—
Derivative instrument asset—energy commodity (non-current)		3,952			79
Other current liabilities		(138	)		—
Other non-current liabilities		(40	)		(268	)

Net	$	21,757		$	(189	)

Environmental Matters

There are two claims against the Company for as yet unknown costs for clean up of alleged environmental contamination related to manufactured gas plant sites that were previously operated by companies, which were subsequently merged into Cascade.

The first claim was received in 1995, and relates to a site in Oregon. An investigation has shown that contamination does exist, but there is currently not enough information available to estimate the potential liability associated with this claim. It is expected that other parties will participate in the clean

up costs. Through the end of the fiscal year the amounts spent, primarily on investigation and containment, have been immaterial.

The second claim was received in 1997, and relates to a site in Washington. An investigation has determined there is evidence of contamination at the site, but there is also evidence of an oil line crossing the property, operated by an unrelated party, which may have also contributed to the contamination. There is currently not enough information available to estimate the potential liability associated with this claim. The party who originally made this claim has not been actively pursuing it.

Management intends to pursue reimbursement from its insurance carriers, and recovery from its customers through increased rates, for any remediation costs for which the Company is determined to be liable. There is precedent for such recovery through increased rates, as both the WUTC and OPUC have previously allowed regulated utilities to increase customer rates to recover similar costs. No claims now pending, in the opinion of management, are expected to have a material effect on the Company's financial position, results of operations, or liquidity.

Litigation and Other Contingencies

Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Company's business. Except for the claims described under Environmental Matters above, there are no other claims now pending that, in the opinion of management, are expected to have a material effect on the Company's financial position, results of operations, or liquidity.

Note 12—Fair Value of Financial Instruments

The following estimated fair value amounts have been determined by the Company, using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, these estimates are not necessarily indicative of the amounts that the Company could realize in a current market exchange. Thus, the use of different market assumptions or estimation methodologies may have a material effect on the estimated fair value amounts. The estimated fair values have been determined by using interest rates that are currently available to the Company for issuance of instruments with similar terms and remaining maturities. The estimated fair value amounts, at September 30, 2004 and 2003, of financial instruments whose values are sensitive to market conditions are set forth in the following table:

	2004				2003
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	(dollars in thousands)
Long-term debt	$	128,900	$	151,795	$	142,930	$	166,137
Current maturities of long-term debt	$	14,000	$	14,168	$	22,000	$	22,955

Note 13—Interim Results of Operations (unaudited)

		Quarter Ended
		Sep 30 2004			Jun 30 2004			Mar 31 2004		Dec 31 2003
		(thousands except per share data)
Operating revenues		$	41,663		$	52,077		$	119,454	$	104,884
Gas costs and revenue taxes			27,327			35,440			87,312		74,191

Operating margin			14,336			16,637			32,142		30,693
Cost of operations			15,276			14,696			15,460		15,129

Income (loss) from operations			(940	)		1,941			16,682		15,564
Interest and other, net			3,050			3,099			3,121		3,116

Income (loss) before income taxes			(3,990	)		(1,158	)		13,561		12,448
Income taxes			(1,384	)		(492	)		4,892		4,543

Net income (loss)		$	(2,606	)	$	(666	)	$	8,669	$	7,905
Other comprehensive income (loss)			822			—			—		—

Comprehensive Income (loss)		$	(1,784	)	$	(666	)	$	8,669	$	7,905

Earnings (loss) per common share
	Basic	$	(0.23	)	$	(0.06	)	$	0.77	$	0.71

	Diluted	$	(0.23	)	$	(0.06	)	$	0.77	$	0.71

		Quarter Ended
		Sep 30 2003			Jun 30 2003			Mar 31 2003		Dec 31 2002
Operating revenues		$	39,180		$	53,793		$	109,286	$	100,496
Gas costs and revenue taxes			24,989			36,465			79,639		70,987

Operating margin			14,191			17,328			29,647		29,509
Cost of operations			15,597			17,249			15,749		15,789

Income (loss) from operations			(1,406	)		79			13,898		13,720
Interest and other, net			2,946			3,197			3,112		3,199

Income (loss) before income taxes			(4,352	)		(3,118	)		10,786		10,521
Income taxes			(1,906	)		(1,138	)		3,937		3,840

Net income (loss)		$	(2,446	)	$	(1,980	)	$	6,849	$	6,681
Other comprehensive income (loss)			(1,682	)		—			—		—

Comprehensive Income (loss)		$	(4,128	)	$	(1,980	)	$	6,849	$	6,681

Earnings (loss) per common share
	Basic	$	(0.22	)	$	(0.18	)	$	0.62	$	0.61

	Diluted	$	(0.22	)	$	(0.18	)	$	0.62	$	0.60

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

The Company maintains controls and procedures designed to provide reasonable assurance that required disclosure information in the reports the Company files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time period specified in the rules and forms of the Securities and Exchange Commission. Based upon their evaluation of those controls and procedures as of the end of the year covered by this report, the Chief Executive Officer and Chief Financial Officer of the Company concluded that the Company's disclosure controls and procedures were effective.

In response to the changes in the filing requirements for Current Reports on Form 8-K effective August 23, 2004, the Company implemented additional controls and procedures designed to provide reasonable assurance that required disclosures under such new requirements will be made in a timely manner. We did not make any other changes in our internal control over financial reporting during the quarter ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Subsequent to the end of the period covered by this report, we identified two material contracts for which we determined reports on Form 8-K had not been filed within the required four business days. The Company has since filed the required reports, and has adopted additional procedures to correct these deficiencies.

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant

Reference is made to the information regarding directors under the caption "Election of Directors" and the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement sent to shareholders for the 2005 Annual Meeting (the 2005 Proxy Statement), which information is incorporated herein by reference. Certain information concerning the executive officers of the Company is set forth in Part I, under the caption "Executive Officers of the Registrant."

The Registrant has adopted codes of ethics for directors, officers (including the principal executive officer, principal financial officer and principal accounting officer), and employees. These codes of ethics are available on the Registrant's website at www.cngc.com. Any changes to or waivers from the codes of ethics will be posted to the Registrant's website as well.

Item 11. Executive Compensation

Reference is made to the information regarding executive compensation set forth in the 2005 Proxy Statement under "Executive Compensation", "Retirement Plan", "Executive Supplemental Retirement Income Plan", "Employment Agreements", "Supplemental Benefit Trust", "Director Compensation", and under "Compensation Committee Interlocks and Insider Participation", which information is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Reference is made to the information regarding security ownership of certain beneficial owners and management under the caption "Security Ownership of Certain Beneficial Owners and Management" in the 2005 Proxy Statement (excluding the information under the subheading "Section 16(a) Beneficial Ownership Reporting Compliance"), which information is incorporated herein by reference.

The following table sets forth information as of September 30, 2004 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:

Equity Compensation Plan Information

Plan Category		Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders		124,398	$	18.69	305,144
Equity compensation plans not approved by security holders		None		None	None
	Total	124,398	$	18.69	305,144

Item 13. Certain Relationships and Related Transactions

Reference is made to the information regarding certain relationships and transactions under the caption "Compensation Committee Interlocks and Insider Participation" in the 2005 Proxy Statement, which information is incorporated herein by reference.

Item 14: Principal Accountant Fees and Services

Reference is made to the information regarding fees paid to, and services provided by the registrant's principal accountant under the caption Independent Public Auditors in the 2005 Proxy Statement, which information is incorporated herein by reference.

PART IV

Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

2. Financial Statement Schedule

SCHEDULE II

CASCADE NATURAL GAS CORPORATION

VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)

Column A			Column B		Column C			Column D	Column E
					Additions
Description			Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts	Deductions (Note)	Balance at End of Period
Allowance for Doubtful Accounts:
	Year ended:
		September 30, 2002	$	904	1,250			1,028	$	1,126
		September 30, 2003	$	1,126	701			950	$	877
		September 30, 2004	$	877	970			819	$	1,028
Reserve—Notes Receivable
		September 30, 2002	$	643	(155	)		388	$	100
		September 30, 2003	$	100	100			57	$	143
		September 30, 2004	$	143	5			—	$	148

Note: Accounts written off, net of recoveries

		3. Exhibits. Reference is made to the index to exhibits following the signature page of this report. Each management contract or compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the list.
(b)		Reports on Form 8-K:

On July 28, 2004, the Company furnished a Report on Form 8-K dated July 27, 2004, to provide the information contained in its July 27 release of third quarter fiscal 2004 earnings.

On September 3, 2004, the Company furnished a Report on Form 8-K dated September 2, 2004, to report a temporary suspension of trading under registrant's employee benefit plans.

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.

				CASCADE NATURAL GAS CORPORATION
November 29, 2004 Date				By:	/s/ J. D. WESSLING J. D. Wessling Chief Financial Officer

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.

/s/ W. BRIAN MATSUYAMA W. Brian Matsuyama	Vice Chairman, President, and Chief Executive Officer (Principal Executive Officer)	November 29, 2004 Date
/s/ J. D. WESSLING J. D. Wessling	Chief Financial Officer (Principal Financial Officer)	November 29, 2004 Date
/s/ JAMES E. HAUG James E. Haug	Controller (Principal Accounting Officer)	November 29, 2004 Date
/s/ LARRY L. PINNT Larry L. Pinnt	Chairman of the Board of Directors	November 29, 2004 Date
/s/ SCOTT M. BOGGS Scott M. Boggs	Director	November 29, 2004 Date
/s/ PIRKKO H. BORLAND Pirkko H. Borland	Director	November 29, 2004 Date
/s/ CARL BURNHAM, JR. Carl Burnham, Jr.	Director	November 29, 2004 Date
/s/ THOMAS E. CRONIN Thomas E. Cronin	Director	November 29, 2004 Date
/s/ DAVID A. EDERER David A. Ederer	Director	November 29, 2004 Date
/s/ BROOKS G. RAGEN Brooks G. Ragen	Director	November 29, 2004 Date
/s/ DOUGLAS G. THOMAS Douglas G. Thomas	Director	November 29, 2004 Date

INDEX TO EXHIBITS

Exhibit No		Description
3.1		Restated Articles of Incorporation of the Registrant as amended through March 28, 1996. Incorporated by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed July 19, 1996.
3.2		Restated Bylaws of the Registrant.
4.1		Indenture dated as of August 1, 1992, between the Registrant and The Bank of New York relating to Medium-Term Notes. Incorporated by reference to Exhibit 4 to the Registrant's current report on Form 8-K dated August 12, 1992.
4.2		First Supplemental Indenture dated as of October 25, 1993, between the Registrant and The Bank of New York relating to Medium-Term Notes and the 7.5% Notes due November 15, 2031. Incorporated by reference to Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the quarter ended June 30, 1993.
4.3		Intentionally omitted
4.4		Intentionally omitted
10.1		1998 Stock Incentive Plan of the Registrant.* Incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1998.
10.2		Service Agreement (Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (1993 Form 10-K).
10.3		Service agreement (assigned Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.3 to the Registrant's 1993 Form 10-K.
10.4		Service Agreement (Liquefaction—Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.4 to the Registrant's 1993 Form 10-K.
10.5		Transaction Confirmation, dated May 18, 2004, between Enserco Energy Inc. and the Registrant, to the Base Contract for Sale and Purchase of Natural Gas dated September 12, 2002 between Enserco and the Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
10.6		Consent to Assignments, Dated June 1, 1997, which assigns from Westcoast Gas Services Inc. (WGSI), to Engage Energy Canada, L.P. (Engage) all the rights and obligations as specified in the contracts contained herein as Exhibit No. 10.22. Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1997 (1997 Form 10-K).
10.7		Intentionally omitted

10.8		Natural Gas Transaction Confirmation (GTC) dated November 21, 2001, and executed on April 3, 2002, between Engage Energy Canada, L.P., and the Registrant, covering the period November 1, 2003 to November 1, 2008. Incorporated by reference to Exhibit 10.8 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2002. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
10.8.1		Assignment and Novation Agreement dated June 24, 2004, between Engage Energy Canada L.P., Nexen Marketing and the Registrant. This Assignment and Novation Agreement applies to the contract identified as Exhibit 10.8.
10.9		Service Agreement dated and executed on September 11, 2001, between TransCanada Pipelines Limited and the Registrant, covering the period November 1, 2003 to October 31, 2028.
10.10		Intentionally omitted.
10.11		Gas transportation agreement between Pacific Gas Transmission Company and the Registrant dated as of April 30, 1997. Incorporated by reference to Exhibit 10.11 to the Registrant's 1997 10-K.
10.12		Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(1) to the Registrant's registration statement on Form S-2, No. 33-52672 (1992 Form S-2).
10.12.1		Amendments dated August 20, 1992, November 1, 1992, October 20, 1993, and December 17, 1993, to Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.12.1 to the Registrant's 1993 Form 10-K.
10.13		Firm Transportation Service Agreement dated April 25, 1991, between Pacific Gas Transmission Company and the Registrant (1993 expansion). Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2.
10.14		Firm Transportation Service Agreement dated October 27, 1993, between Pacific Gas Transmission Company and the Registrant. Incorporated by reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K.
10.15		Intentionally omitted.
10.16		Natural gas purchase agreement dated April 26, 2001, between Sempra Energy and the Registrant. Incorporated by reference to Exhibit 10.16 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.
10.17		Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10(v) to the 1992 Form S-2.
10.17.1		Second amendment to the agreement for the release of Jackson Prairie Storage Capacity dated as of July 30, 1997, amending the Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10.17.1 to the Registrant's 1997 Form 10-K.

10.18		Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by Reference to Exhibit 10.18 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (1994 Form 10-K).
10.19		Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant .Incorporated by reference to Exhibit 10.19 to the Registrant's 1994 Form 10-K.
10.20		Service Agreement (Firm Redelivery Transportation Agreement under rate Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.20 to the Registrant's 1994 Form 10-K.
10.21		Intentionally omitted
10.22		Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Westcoast Gas Services, Inc. and the Registrant. Incorporated by reference to Exhibit 10.22 to the Registrant's 1994 Form 10-K.
10.22.1		Intentionally omitted.
10.22.2		Amendment dated February 28, 2003 to Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Engage Energy Canada L.P. and Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT Incorporated by reference to Exhibit 10.22.2 to the Registrant's 2003 Form 10-K.
10.23		Firm Transportation Service Agreement dated November 4, 1994, between Pacific Gas Transmission and the Registrant, effective November 1, 1995. Incorporated by reference to Exhibit 10.23 to the Registrant's 1994 Form 10-K.
10.24		Firm Transportation Agreement dated August 1, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.24 to the Registrant's 1994 Form 10-K.
10.25		Prearranged Permanent Capacity Release of Firm Natural Gas Transportation Agreements dated November 30, 1993 between Tenaska Gas Co., Tenaska Washington Partners, L.P. and the Registrant. Incorporated by reference to Exhibit 10.25 to the Registrant's 1994 Form 10-K.
10.26		Intentionally omitted
10.27		Intentionally omitted.
10.28		Intentionally omitted.
10.29		2000 Director Stock Award Plan of the Registrant.* Incorporated by reference to Exhibit 10.29 to the Registrant's 2003 Form 10-K.
10.30		Executive Supplemental Retirement Income Plan of the Registrant and Supplemental Benefit Trust as amended and restated as of October 1, 2003. Incorporated by reference to Exhibit 10.30 to the Registrant's 2003 Form 10-K.
10.31		Form of employment agreement between the Registrant and certain executive officers of the Registrant. Incorporated by reference to Exhibit 10.31 to the Registrant's 2003 Form 10-K.

10.32		Cascade Natural Gas Corporation Officer Severance Pay Plan, dated October 1, 2004.* Incorporated by reference to Exhibit 10.01 to the Registrant's Current Report on Form 8-K dated October 8, 2004.
10.33		Cascade Natural Gas Corporation Key Performance Incentive Plan for Fiscal 2005 dated September 29, 2004*
10.34		Cascade Natural Gas Team Performance Incentive Plan 2005*
10.35		Amended and Restated Loan Agreement, dated as of September 30, 2004, between U.S. Bank National Association and the Registrant. A portion of this agreement is subject to a request for confidential treatment.
10.36		Cascade Natural Gas Corporation Employee Retirement Savings Plan 2002 Restatement January 1, 2002 (As Amended Through Amendment No. 3)*
12.		Statement regarding computation of ratio of earnings to fixed charges and preferred dividend requirements.
21.		A list of the Registrant's subsidiaries is omitted because the subsidiaries considered in the aggregate as a single subsidiary do not constitute a significant subsidiary.
23.		Consent of Deloitte & Touche LLP to the incorporation of their report in the Registrant's registration statements
31.		Certification Accompanying Periodic Report Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002