FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2004

Commission file number: 1-7196

CASCADE NATURAL GAS CORPORATION

(Exact name of Registrant as specified in its charter)

Washington		91-0599090
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

222 Fairview Avenue North, Seattle, WA		98109
(Address of principal executive offices)		(Zip code)

(Registrant’s telephone number including area code)	(206) 624-3900

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 whether the registrant is an accelerated filer (as defined in Rule 23b-2 of the Exchange Act). Yes ý No o

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

Title		Outstanding

Common Stock, Par Value $1 per Share		11,245,757 as of July 30, 2004

CASCADE NATURAL GAS CORPORATION

Index

Part I.	Financial Information

			Item 1. Financial Statements

				Consolidated Condensed Statements of Income

				Consolidated Condensed Balance Sheets

				Consolidated Condensed Statements of Cash Flows

				Notes to Consolidated Condensed Financial Statements

			Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

			Item 3. Quantitative and Qualitative Disclosures about Market Risk

			Item 4. Controls and Procedures

Part II.		Other Information

			Item 2. Changes in Securities

			Item 5. Other Information

			Item 6. Exhibits and Reports on Form 8-K

Signature

PART I. Financial Information

Item 1. Financial Statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(unaudited)

	THREE MONTHS ENDED						NINE MONTHS ENDED
	Jun 30, 2004			Jun 30, 2003			Jun 30, 2004		Jun 30, 2003
							(Restated See Note 1)
	(thousands except per share data)

Operating revenues	$	52,077		$	53,793		$	276,416	$	263,575

Less: Gas purchases	31,896			32,652			178,019		169,481
Revenue taxes	3,544			3,813			18,924		17,610
Operating margin	16,637			17,328			79,473		76,484

Cost of operations:
Operating expenses	9,729			12,465			30,656		34,601
Depreciation and amortization	4,026			3,846			11,882		11,466
Property and miscellaneous taxes	941			938			2,748		2,720
	14,696			17,249			45,286		48,787

Income from operations	1,941			79			34,187		27,697
Less interest and other deductions - net	3,099			3,197			9,337		9,508
Income (loss) before income taxes	(1,158		)	(3,118		)	24,850		18,189

Income taxes	(492		)	(1,138		)	8,943		6,639
Net Income (Loss)	$	(666	)	$	(1,980	)	$	15,907	$	11,550

Weighted average common shares outstanding	11,227			11,086			11,193		11,063

Net earnings (loss) per common share
Basic	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04
Diluted	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04

Cash dividends per share	$	0.24		$	0.24		$	0.72	$	0.72

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	Jun 30, 2004		Sep 30, 2003
	(Unaudited)
ASSETS
Utility Plant, net of accumulated depreciation of $239,530 and $227,582	$	316,619	$	302,225
Construction work in progress	12,938		10,078
	329,557		312,303
Other Assets:
Investments in non-utility property	202		202
Notes receivable, less current maturities	49		52
	251		254
Current Assets:
Cash and cash equivalents	562		7,452
Accounts receivable and current maturities of notes receivable, less allowance of $946 and $877 for doubtful accounts	19,213		12,296
Materials, supplies and inventories	11,866		14,737
Prepaid expenses and other assets	7,946		6,144
Deferred income taxes	911		755
	40,498		41,384
Deferred Charges
Gas cost changes	9,288		11,584
Other	7,668		5,931
	16,956		17,515

	$	387,262	$	371,456

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)

(Dollars in Thousands)

	Jun 30, 2004			Sep 30, 2003
	(Unaudited)
COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES
Common Shareholders’ Equity:
Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,240,716 and 11,131,860 shares	$	11,241		$	11,132
Additional paid-in capital	100,837			98,877
Accumulated other comprehensive income (loss)	(13,430		)	(13,430		)
Retained earnings	23,811			15,981
	122,459			112,560

Long-term Debt	133,930			142,930

Current Liabilities:
Notes payable and commercial paper	1,000			3,800
Current maturities of long-term debt	31,000			22,000
Accounts payable	14,644			10,501
Property, payroll and excise taxes	4,996			5,387
Dividends and interest payable	5,504			7,884
Other current liabilities	8,654			6,431
	65,798			56,003

Deferred Credits and Other Liabilities	65,075			59,963

Commitments and Contingencies	—			—
	$	387,262		$	371,456

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	NINE MONTHS ENDED
	(dollars in thousands)
	Jun 30, 2004			Jun 30, 2003
	(Restated See Note 1)
Operating Activities
Net income	$	15,907		$	11,550
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	11,882			11,466
Deferrals of gas cost changes	(3,378		)	3,391
Amortization of gas cost changes	5,674			5,268
Other deferrals and amortizations	(453		)	2,692
Deferred income taxes and tax credits - net	3,982			1,992
Change in current assets and liabilities	(2,252		)	2,595
Net cash provided by operating activities	31,362			38,954

Investing Activities
Capital expenditures	(29,762		)	(17,553		)
Customer contributions in aid of construction	318			713
Other	—			10
Net cash used by investing activities	(29,444		)	(16,830		)

Financing Activities
Proceeds from issuance of common stock	2,070			1,041
Changes in notes payable and commercial paper, net	(2,800		)	—
Dividends paid	(8,078		)	(7,974		)
Net cash used by financing activities	(8,808		)	(6,933		)

Net Increase (Decrease) in Cash and Cash Equivalents	(6,890		)	15,191

Cash and Cash Equivalents
Beginning of year	7,452			3,688
End of period	$	562		$	18,879

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

THREE- AND NINE-MONTH PERIODS ENDED JUNE 30, 2004

The preceding statements were taken from the books and records of the Company and reflect all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the interim periods. All adjustments were of a normal and recurring nature. Because of the highly seasonal nature of the natural gas distribution business, earnings or loss for any portion of the year are disproportionate in relation to the full year.

Reference is directed to the Notes to Consolidated Financial Statements contained in the 2003 Annual Report on Form 10-K for the fiscal year ended September 30, 2003, and comments included therein under “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Note 1. Restatement and Reclassifications

The Company has restated its earnings for the quarter ended March 31, 2004 as a result of the remeasurement of retiree medical expense, with a remeasurement date of December 31, 2003. This remeasurement, reducing operating expenses by $158,000, is described in Note 2 under the caption “FSP FAS Nos. 106-1 and 106-2”. The following table sets forth the reported and restated amounts for the quarter ended March 31, 2004.

	Quarter Ended March 31, 2004				Six Months Ended March 31, 2004
	(thousands except per-share data )
	As Reported		As Restated		As Reported		As Restated
Operating Expenses	$	10,807	$	10,649	$	21,085	$	20,927
Net Income	$	8,511	$	8,669	$	16,415	$	16,573
Earnings Per Share,
Basic and Diluted	$	0.76	$	0.77	$	1.47	$	1.48

The restatement reduces Other Liabilities by $158,000 as of March 31, 2004.

Certain reclassifications have been made in the financial statements for the quarter and year-to-date periods ended June 30, 2003 to conform to the classifications used in fiscal 2004.

Note 2. 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 financial statements. The expanded disclosures required by this statement are included in Note 4.

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 is 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 applicable to the second, third, and fourth fiscal quarters of $475,000, with $158,000 of the reduction applicable to each quarter. Because of the remeasurement, and as prescribed in the FSP, the Company has restated its earnings for the quarter ended March 31, 2004. Additional information on the restatement is included in Note 1. Further information regarding postretirement medical benefits is included in Note 4.

FIN 46

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities,” which was revised in December 2003 (collectively referred to as FIN 46). Variable interest entities are commonly referred to as special purpose entities or off-balance sheet structures. FIN 46 requires a variable interest entity to be consolidated by the primary beneficiary of that entity. The primary beneficiary is subject to a majority of the risk of loss from the variable interest entity’s activities or it is entitled to receive a majority of the entity’s residual returns. The Company does not have any variable interest entities and adoption of FIN 46 did not have any effect on the Company’s financial statements.

Note 3. Earnings Per Share

The following table sets forth the calculation of earnings per share.

	Three Months Ended June 30						Nine Months Ended June 30
	2004			2003			2004		2003
							(Restated See Note 1)
	(in thousands except per-share data)

Net income (loss)	$	(666	)	$	(1,980	)	$	15,907	$	11,550

Weighted average shares outstanding	11,227			11,086			11,193		11,063
Basic earnings (loss) per share	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04

Weighted average shares outstanding	11,227			11,086			11,193		11,063
Plus: Issued on assumed exercise of stock options	13			16			14		17
Weighted average shares outstanding assuming dilution	11,240			11,102			11,207		11,080

Diluted earnings (loss) per share	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04

Note 4. Retirement Plan Information

The following table sets forth the components of net periodic benefit costs recognized in the three-and nine-month periods ended June 30, 2004 and 2003.

Net Periodic Benefits Cost

	Three Months Ended						Nine Months Ended
	Jun 30, 2004			Jun 30, 2003			Jun 30, 2004			Jun 30, 2003
	(Thousands of Dollars)
DEFINED BENEFIT PENSION PLANS
Service cost	$	192		$	346		$	576		$	1,223
Interest cost	932			932			2,796			2,819
Expected return on plan assets	(978		)	(942		)	(2,935		)	(2,785		)
Amortization of unrecognized
transition obligation	—			8			—			58
Recognized gains or losses	349			295			1,048			856
Prior service cost	57			78			172			305
Curtailment loss	—			1,451			—			1,451
Net Periodic Benefit Cost Recognized	$	552		$	2,168		$	1,657		$	3,927

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost	$	39		$	125		$	121		$	421
Interest cost	308			517			963			1,702
Expected return on plan assets	(217		)	(184		)	(636		)	(546		)
Amortization of unrecognized
transition obligation	164			164			493			493
Recognized gains or losses	234			311			799			881
Prior service cost	(366		)	(139		)	(1,097		)	(175		)
Net Periodic Benefit Cost Recognized	$	162		$	794		$	643		$	2,776

DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized	$	242		$	—		$	729

Retirement Plan Changes

The comparability of the amounts in the above table is affected by changes in the Company’s retirement plans for non-bargaining unit employees announced in the third quarter of fiscal 2003 as part of a comprehensive review of its employee benefit plans.

Effective October 1, 2003, no additional benefits accrue under the defined benefit pension plans for the affected employees. Subsequent benefits are in the form of contributions to the existing 401(k) Plan. In addition to the existing match for employee contributions the Company contributes 4% of eligible salaries, and a 1% to 4% transition contribution, to employee retirement accounts. Additionally there will be annually determined “profit-sharing” contributions dependent on the Company achieving established targets.

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 which began January 1, 2004.

Retirement Plan Funding

For the nine months ended June 30, 2004, $3,168,000 of contributions have been made to the Company’s defined benefit pension plans. The Company presently anticipates contributing an additional $675,000 to fund its pension plans for a total of $3,843,000 in fiscal 2004.

Note 5. Stock-Based Compensation

The Company follows the disclosure-only provisions of FAS No. 123, “Accounting for Stock-Based Compensation.” Accordingly, employee stock options are accounted for under Accounting Principle Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.” Stock options are granted at exercise prices not less than the fair value of common stock on the date of grant. Under APB No. 25, no compensation expense is recognized related to the Company’s stock option plans. If compensation expense for the Company’s stock option plans were determined consistent with SFAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three- and nine-month periods ended June 30:

	Three Months Ended						Nine Months Ended
	Jun 30, 2004			Jun 30, 2003			Jun 30, 2004		Jun 30, 2003
	(in thousands except per-share data)
Net income (loss)
As reported	$	(666	)	$	(1,980	)	$	15,907	$	11,550
Less total stock-based employee compensation expense determined under the fair value method, net of tax	$	13		27			40		82
Pro forma net income (loss)	$	(679	)	$	(2,007	)	$	15,867	$	11,468

Earnings (loss) per share
As reported, basic and diluted	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04
Pro forma, basic	$	(0.06	)	$	(0.18	)	$	1.42	$	1.04
Pro forma, diluted	$	(0.06	)	$	(0.18	)	$	1.42	$	1.03

Note 6. Commitments and Contingencies

Environmental Matters

There are two claims against the Company for as yet unknown costs for cleanup 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 cleanup 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 Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utilities Commission (OPUC) have previously allowed regulated utilities to increase customer rates to recover similar costs.

Litigation and Other Contingencies

Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Company’s business.

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 the property owner have each paid $375,000 and have agreed to resolve the allocation of the total settlement payment between them in future negotiations or proceedings.

No other 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.

Item 2. 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 affected consolidated results of operations and cash flows for the three- and nine-month periods ended June 30, 2004 and June 30, 2003.

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 rather than 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 a major industrial customer, or unfavorable conditions affecting an industry segment, could have a significant 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.

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 is currently implementing a new 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. The company plans to have 90% of the core market’s requirement for fiscal 2005, 60% of fiscal 2006, and 30% of fiscal 2007 secured with fixed prices by the end of fiscal 2004. To minimize earnings volatility, the company received accounting orders from the WUTC and the OPUC to apply FAS No. 71 to periodic

changes in fair market value of derivatives associated with supplies for core customers and records 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.

RESULTS OF OPERATIONS

The Company reported a $666,000 net loss, or $0.06 per share, basic and diluted for the fiscal 2004 third quarter (quarter ended June 30, 2004), compared to a $1,980,000 net loss, or $0.18 per share, basic and diluted, for the quarter ended June 30, 2003. Primary factors influencing the quarterly comparisons were:

• Recognition in 2003 of retirement plans curtailment losses.

• 2004 reductions in employee benefit expenses from plan changes and the favorable impact of the Medicare prescription drug subsidy.

• Addition of new customers.

Partially offsetting these factors were lower margins from customers related to lower per-customer gas use.

On a year-to-date basis, as restated, basic and diluted earnings per share improved 37%, to $1.42 from $1.04, on net income of $15,907,000, compared to $11,550,000. The year-to-date comparisons were influenced by similar factors to the third quarter comparisons as well as improved margins in 2004 from residential, commercial, and industrial customers, and charges in fiscal 2003 of $375,000 for a claim settlement, and $865,000 for a gas supply contract termination.

Operating Margin

Operating margins by customer category for the third quarter and year-to-date periods of fiscal years 2004 and 2003 are set forth in the following tables:

Residential and Commercial Margin

	Three Months Ended June 30				Percent		Nine Months Ended June 30				Percent
	2004		2003		Change		2004		2003		Change
	(dollars in thousands)						(dollars in thousands)
Degree Days
Actual	661		826		-20.0	%	5,015		4,902		2.3	%
5-Year Average	874		871				5,193		5,185
Average Number of Customers Billed
Residential	185,584		177,978		4.3	%	185,114		177,246		4.4	%
Commercial	29,471		28,984		1.7	%	29,422		28,903		1.8	%
Average Therm Usage per Customer
Residential	97		114		-14.9	%	654		638		2.5	%
Commercial	536		591		-9.3	%	3,223		3,078		4.7	%
Operating Margin
Residential	$	6,299	$	6,945	-9.3	%	$	35,533	$	33,485	6.1	%
Commercial	$	3,414	$	3,786	-9.8	%	$	19,602	$	18,661	5.0	%

Residential and commercial operating margin for the third quarter decreased $1,018,000. Lower gas use by customers, related to 20% warmer weather, depressed margins by approximately $1,439,000. This reduction was partially offset by $406,000 higher margin resulting from the addition of 8,093 more residential and commercial customers. The primary use of gas by residential customers is for space heating and water heating, therefore average consumption per customer is very sensitive to weather, particularly during the Company’s first and second fiscal quarters, but also during the third quarter. Consumption by commercial customers is also sensitive to weather. The sensitivity is more difficult to isolate and measure

than for residential customers because of a variety of uses in addition to space and water heating. The combined growth rate for residential and commercial customers was 3.9%, more than two times the national average for natural gas distribution companies.

Of the $2,989,000 increase in year-to-date residential and commercial margins, approximately $2,073,000 resulted from the addition of new customers and the remainder is primarily from higher per-customer consumption earlier in the fiscal year.

Industrial and Other Margin

	Three Months Ended June 30				Percent		Nine Months Ended June 30				Percent
	2004		2003		Change		2004		2003		Change
	(dollars in thousands)						(dollars in thousands)
Average Number of Customers
Electric Generation	14		14		0.0	%	14		14		0.0	%
Industrial	736		737		-0.1	%	740		739		0.1	%

Therms Delivered (thousands)
Electric Generation	88,586		86,769		2.1	%	342,404		383,877		-10.8	%
Industrial	93,801		89,898		4.3	%	324,764		305,184		6.4	%

Operating Margin
Electric Generation	$	1,667	$	1,457	14.4	%	$	5,803	$	6,470	-10.3	%
Industrial	$	4,245	$	4,200	1.1	%	$	15,364	$	14,993	2.5	%
Gas Management Services	$	612	$	947	-35.4	%	$	3,028	$	2,827	7.1	%
Other	$	396	$	149	165.8	%	$	668	$	399	67.4	%

Distribution service margins from electric generation customers were up $210,000, or 14% for the quarter, but below our original expectations for this group. High wholesale natural gas prices throughout the spring, combined with availability of cheaper hydroelectric power, reduced demand from gas-fired generators. Consumption levels by generators will continue to be governed by whether alternative generating resources cheaper than gas are available to meet regional demands for electricity. The Company expects some increase in gas usage from third quarter levels for the remainder of the year, but probably not as much as was experienced during the fourth quarter last year.

Operating margin from distribution services for other industrial customers improved by $45,000 for the quarter. Although current high gas costs also negatively affect industrial usage, the Company expects continued moderate improvement in industrial distribution revenue as Washington and Oregon industry recovers from the effects of the economic slowdown.

The reduction in margin from gas management was due in part to a $117,000 negative mark-to-market valuation for instruments to hedge prices on gas supply contracts to serve this group. On a year-to-date basis the comparison is affected by a favorable mark-to-market valuation of $358,000 and a 2003 contract termination charge that reduced gas management margin by $865,000. Competition continues to increase for the sale of gas supplies to large volume customers, resulting in lower commodity margins than were available in the past. Since such sales account for most of the revenues from these services, in the near term the Company expects less contribution to margins from this sector.

Oregon Earnings Sharing.

The following table sets forth the amounts accrued as a charge to operating margin under the Company’s earnings-sharing arrangement with the Oregon Public Utility Commission (OPUC).

	Three Months Ended Jun 30					Nine Months Ended Jun 30
	2004		2003			2004			2003
	(dollars in thousands)					(dollars in thousands)

Oregon Earnings Sharing	$	3	$	(156	)	$	(525	)	$	(351	)

Under this arrangement, the Company is authorized to retain all of its earnings up to a threshold rate of return, based on Oregon jurisdictional earnings. 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. In the third quarter of fiscal 2004, the OPUC issued an order that raises the earnings-sharing threshold to a return on equity of 13.25% for the current year, replacing a calculation that would have required sharing at approximately 10.5%.

Cost of Operations

Compared to the prior year, overall Cost of Operations was $2,553,000 lower for the quarter and $3,501,000 lower for the year-to-date period. Within Cost of Operations, notable changes in Operating Expenses included a reduction in employee benefits expenses of $2,044,000 for the quarter and $3,607,000 year-to-date. The quarterly comparison is affected by retirement plan curtailment charges of $1,451,000 in the third quarter last year, and by the $158,000 favorable impact of the Medicare prescription drug subsidy in third quarter 2004. Additional information on the Medicare prescription drug subsidy is included in Item 1 of this report under Note 2 in the Notes to Consolidated Condensed Financial Statements under the caption “FSP-FAS Nos. 106-1 and 106-2”.

The same factors affect the year-to-date comparisons, as well as an additional $158,000 impact of the Medicare prescription drug subsidy applicable to second quarter 2004. The Medicare prescription drug subsidy was passed into law in December 2003. The Company elected to restate its second quarter earnings in order to adopt the recognition of the effect of the subsidy retroactive to the beginning of the second quarter.

Other than the aforementioned items, the benefit expense reductions result primarily from plan changes implemented beginning in July 2003, designed to reduce overall benefits expenses.

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 $50,000,000 bank revolving credit commitment. This agreement has an annual 0.16% commitment fee, and a term that expires in November 2004. Several banks have made proposals to the Company for renewing and increasing its credit line. Management considers its relationship with its bankers to be excellent, and does not anticipate problems in renewing or increasing the credit line. The Company also has a $10,000,000 uncommitted bank credit line. As of June 30, 2004, there was $1,000,000 outstanding debt under these credit lines. In August 2004 a $22 million long-term Medium-Term Note matures 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

In spite of $4.4 million higher net income compared to 2003, cash provided by operating activities is $7.6 million less in the nine months ended June 30, 2004 compared to 2003. 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. Also affecting the year-to-year comparison of cash provided by operating activities is the net change in inventories of materials and supplies and natural gas storage for the two periods. A primary contributing factor is the annual refilling of gas storage earlier in 2004 compared to 2003, with approximately 48% more gas in storage at June 30, 2004 compared to June 30, 2003. This difference is reflected in Change in current assets and liabilities.

Cash provided by operating activities in fiscal 2004 continues to benefit from Amortization of gas cost changes, contributing $5,674,000 year-to-date through June 30, 2004. 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 is set to expire in November 2004. As a result of higher gas costs experienced in fiscal 2004, the Company expects a new temporary rate component, effective December 2004, at approximately the same level as the one expiring. There is no impact on operating margin or net income from Amortization of gas cost changes.

Investing Activities

Net capital expenditures for the nine months of $29,444,000 are approximately 75% greater than last year. The increase is primarily attributable to $9,192,000 expended on a project to install electronic devices on all the Company’s customer meters to allow for automated reading of the meters (AMR Project.) The project was begun in 2003, and total expenditures to date are $12,875,000 out of a total estimated project cost of $16,000,000. Because the Company expects the AMR project to progress ahead of schedule for the remainder of the year, expenditures planned for fiscal 2005 will likely be incurred in 2004. In addition, the January cold snap produced record peak demands in some areas of the Company’s distribution system, identifying the need for additional distribution capacity in a few localized parts of the system. These factors will likely push full fiscal 2004 expenditures closer to $38 million, from the previously budgeted amount of $35 million.

Financing Activities

Other than the payment of dividends, the primary financing activity during fiscal 2004 was paying down the debt under the Company’s bank credit line by $2,800,000. The Company also received $2,070,000 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.

Over the next seven months, concluding in January 2005, the Company will repay $31,000,000 in current maturities of long-term debt, beginning with $22,000,000 in August 2004. The Company expects to fund these repayments primarily through use of its bank credit lines and with cash from operating activities.

EFFICIENCY INITIATIVES

Automated Meter Reading

The Automated Meter Reading (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, is proceeding ahead of schedule. The Company is already using the new system to read over three fourths of its customers’ meters. When completed, the project is expected to enable the Company to reduce the number of meter readers from thirty-two full time employees to three. Many of these experienced employees are being 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 act 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 under one roof 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 established in the future to recover costs that were incurred in a prior period. In this situation, 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 $4,412,000 in 2002 and $4,269,000 in 2003 to the pension and supplemental executive retirement plans, and expects to contribute $3,843,000 in 2004.

In selecting a discount rate, the Company uses the average of the 20 year and above Aaa, Aa, A, and Baa 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. 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 2002 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 them 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 Notes to the Consolidated Condensed Financial Statements, contained in Item 1 of this report.

New Accounting Standards:

Information on new accounting standards is included in the Notes to the Consolidated Condensed Financial Statements, contained in Item 1 of this report.

Item 3. 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.

The Company’s purchased natural gas has commodity prices subject to fluctuations resulting from weather, congestion on interstate pipelines, and other unpredictable factors. The Company’s Purchased Gas Adjustment mechanisms provide for 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 core and non-core customers.

Item 4: Controls and Procedures

The Company maintains controls and procedures designed to ensure that required disclosure information in 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 these controls and procedures, as of the end of the quarter 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.

The Company made no material changes in its internal control over financial reporting during the quarter covered by this report.

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, natural disasters, acts of terrorism, accidents resulting in personal injury, labor issues, the Company’s ability to successfully implement internal performance goals, competition from alternative forms of energy, consolidation in the energy industry, natural gas prices, performance issues with key natural gas suppliers and upstream pipelines, 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.

PART II. Other Information

Item 2. Changes in Securities and Use of Proceeds

Under the terms of its bank credit agreement, the Company is required to maintain a minimum tangible net worth of $108,441,000 as of June 30, 2004. Under this agreement, approximately $22,295,000 was available for payment of dividends at June 30, 2004.

Item 5. Other Information

Ratio of Earnings to Fixed Charges:

Twelve Months Ended
6/30/2004	9/30/2003	9/30/2002	9/30/2001	9/30/2000	9/30/1999

2.56	2.06	2.27	3.39	3.12	3.00

For purposes of this calculation, earnings include income before income taxes, plus fixed charges. Fixed charges include interest expense and the amortization of debt issuance expenses. Refer to Exhibit 12 for the calculation of these ratios, as well as the ratio of earnings to fixed charges including preferred dividends.

b) There have been no changes in the Company’s procedures by which security holders may recommend nominees to the Company’s Board of Directors.

Item 6. Exhibits and Reports on Form 8-K

a. Exhibits:

No.		Description

3.2		Amended and Restated Bylaws of the Registrant

12		Computation of Ratio of Earnings to Fixed Charges

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

b. Reports on Form 8-K:

On April 21, 2004, the Company filed a Report on Form 8-K to furnish its April 19, 2004 release of second quarter fiscal 2004 earnings.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CASCADE NATURAL GAS CORPORATION

By:	/s/ J. D. Wessling	.


	J. D. Wessling
	Chief Financial Officer
	(Principal Financial Officer)


Date:	August 9, 2004	.