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 December 31, 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		(I.R.S. Employer
incorporation or organization)		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		11,293,156 as of January 24, 2005

PART I. Financial Information

Item 1. Financial Statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(unaudited)

	THREE MONTHS ENDED
	Dec 31, 2004		Dec 31, 2003
	(thousands except per share data)

Operating revenues	$	104,613	$	104,884

Less: Gas purchases	69,122		67,525
Revenue taxes	6,569		6,666
Operating margin	28,922		30,693

Cost of operations:
Operating expenses	10,420		10,278
Depreciation and amortization	4,205		3,921
Property and miscellaneous taxes	959		930
	15,584		15,129

Income from operations	13,338		15,564
Less interest and other deductions - net	2,894		3,116
Income before income taxes	10,444		12,448

Income taxes	3,812		4,543
Net Income	$	6,632	$	7,905

Weighted average common shares outstanding	11,279		11,158

Net earnings per common share
Basic	$	0.59	$	0.71
Diluted	$	0.59	$	0.71

Cash dividends per share	$	0.24	$	0.24

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

	Dec 31, 2004		Sep 30, 2004
	(Unaudited)
ASSETS
Utility Plant, net of accumulated depreciation of $246,843 and $242,691	$	330,552	$	327,345
Construction work in progress	7,196		7,229
	337,748		334,574
Other Assets:
Investments in non-utility property	202		202
Notes receivable, less current maturities	46		43
	248		245
Current Assets:
Cash and cash equivalents	2,447		499
Accounts receivable and current maturities of notes receivable, less allowance of $943 and $1,028 for doubtful accounts	50,764		15,001
Prepaid expenses and other assets	17,728		18,674
Derivative instrument assets - energy commodity	1,330		17,983
Materials, supplies and inventories	12,773		13,268
Deferred income taxes	982		955
	86,024		66,380
Deferred Charges and Other
Gas cost changes	10,395		12,288
Derivative instrument assets - energy commodity	2,292		3,952
Other	5,316		5,183
	18,003		21,423

	$	442,023	$	422,622

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)

(Dollars in Thousands)

	Dec 31, 2004			Sep 30, 2004
	(Unaudited)
COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES
Common Shareholders’ Equity:
Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,292,120 and 11,268,069 shares	$	11,292		$	11,268
Additional paid-in capital	101,834			101,354
Accumulated other comprehensive income (loss)	(12,608		)	(12,608		)
Retained earnings	22,422			18,500
	122,940			118,514

Long-term Debt	128,900			128,900

Current Liabilities:
Notes payable and commercial paper	45,000			33,500
Current maturities of long-term debt	10,000			14,000
Accounts payable	34,214			12,923
Property, payroll and excise taxes	8,167			5,287
Dividends and interest payable	5,049			7,125
Regulatory liabilities	1,330			17,209
Other current liabilities	11,858			8,972
	115,618			99,016

Deferred Credits and Other Non-current Liabilities
Deferred income taxes and investment tax credits	38,836			38,392
Retirement plan obligations	20,658			20,780
Regulatory liabilities	8,845			10,515
Other	6,226			6,505
	74,565			76,192

Commitments and Contingencies	—			—
	$	442,023		$	422,622

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	THREE MONTHS ENDED
	(dollars in thousands)
	Dec 31, 2004			Dec 31, 2003
Operating Activities
Net income	$	6,632		$	7,905
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	4,205			3,921
Deferrals of gas cost changes	100			(752		)
Amortization of gas cost changes	1,794			1,774
Other deferrals and amortizations	(154		)	321
Deferred income taxes and tax credits - net	418			1,367
Change in current assets and liabilities	(8,571		)	(7,488		)
Net cash provided by operating activities	4,424			7,048

Investing Activities
Capital expenditures	(8,180		)	(10,456		)
Customer contributions in aid of construction	410			240
Net cash used by investing activities	(7,770		)	(10,216		)

Financing Activities
Proceeds from issuance of common stock	504			842
Repayment of long-term debt	(4,000		)	—
Changes in notes payable and commercial paper, net	11,500			(1,300		)
Dividends paid	(2,710		)	(2,687		)
Net cash provided (used) by financing activities	5,294			(3,145		)

Net Increase (Decrease) in Cash and Cash Equivalents	1,948			(6,313		)

Cash and Cash Equivalents
Beginning of year	499			7,452
End of period	$	2,447		$	1,139

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

THREE-MONTH PERIOD ENDED DECEMBER 31, 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 2004 Annual Report on Form 10-K for the fiscal year ended September 30, 2004, and comments included therein under “Management’s Discussion and Analysis of Financial Condition and Results of Operations”.

Note 1. Earnings Per Share

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

	Three Months Ended December 31
	2004		2003
	(in thousands except per-share data)
Net income (loss)	$	6,632	$	7,905

Weighted average shares outstanding	11,279		11,158
Basic earnings (loss) per share	$	0.59	$	0.71

Weighted average shares outstanding	11,279		11,158
Plus: Issued on assumed exercise of stock options	13		14
Weighted average shares outstanding assuming dilution	11,292		11,172

Diluted earnings (loss) per share	$	0.59	$	0.71

Note 2. Retirement Plan Information

The following table sets forth the components of net periodic benefit costs recognized in the three-month periods ended December 31, 2004 and 2003.

Net Periodic Benefits Cost

	Three Months Ended
	Dec 31, 2004			Dec 31, 2003
	(Thousands of Dollars)
DEFINED BENEFIT PENSION PLANS
Service cost	$	197		$	192
Interest cost	961			932
Expected return on plan assets	(1,041		)	(978		)
Recognized gains or losses	386			349
Prior service cost	46			57
Net Periodic Benefit Cost Recognized	$	549		$	552

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost	$	35		$	44
Interest cost	275			348
Expected return on plan assets	(211		)	(213		)
Recognized gains or losses	187			308
Prior service cost	(330		)	(330		)
Net Periodic Benefit Cost Recognized	$	(44	)	$	157

DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized	$	243		$	242

Retirement Plan Funding

For the three months ended December 31, 2004, $625,000 of contributions have been made to the Company’s defined benefit pension plans. The Company presently anticipates contributing an additional $2,900,000 to fund its pension plans for a total of $3,525,000 in fiscal 2005.

Note 3. 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-month periods ended December 31:

	Three Months Ended
	Dec 31, 2004		Dec 31, 2003
	(in thousands except per-share data)
Net income
As reported	$	6,632	$	7,905
Less total stock-based employee compensation expense determined under the fair value method, net of tax	$	13	13
Pro forma net income	$	6,619	$	7,892

Earnings per share, basic and diluted
As reported	$	0.59	$	0.71
Pro forma	$	0.59	$	0.71

Note 4. 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 quarter 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. 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-month periods ended December 31, 2004 and December 31, 2003.

OVERVIEW

The Company is a local distribution company (LDC) serving approximately 225,000 customers in the States of Washington and Oregon. Our 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 and minimize the need to seek rate increases by:

• Expanding our customer base

• Increasing operating efficiencies

• Exploit opportunities to expand our service offerings inside and outside our service territory

Opportunities and Challenges

The Company operates in a diverse service territory over a wide geographic area relative to its 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

The Company’s net income was $6,632,000, or $0.59 per share, basic and diluted, for the fiscal 2005 first quarter (quarter ended December 31, 2004), compared to $7,905,000, or $0.71 per share, basic and diluted, for the quarter ended December 31, 2003. Primary factors influencing the quarterly comparisons were:

• Unfavorable non-core mark-to-market valuations in fiscal 2005 compared to favorable valuations in fiscal 2004 – ($0.06) per share

• Decline in margin from gas management services – ($0.04) per share

• Decline in residential and commercial per-customer gas consumption – ($0.05) per share

• Increase in margin from new residential and commercial customers - $0.06 per share

Operating Margin

Operating margins by customer category for the first quarter of fiscal years 2005 and 2004 are set forth in the following tables:

Residential and Commercial Margin

	First Quarter of Fiscal				Percent
	2005		2004		Change
	(dollars in thousands)
Degree Days
Actual	1,945		2,106		-7.6	%
5-Year Average	2,091		2,044
Average Number of Customers Billed
Residential	191,100		182,397		4.8	%
Commercial	29,840		29,131		2.4	%
Average Therm Usage per Customer
Residential	251		272		-7.7	%
Commercial	1,161		1,252		-7.3	%
Operating Margin
Residential	$	14,225	$	14,056	1.2	%
Commercial	$	7,461	$	7,538	-1.0	%

Margin from sales to residential and commercial customers increased by $92,000 on an aggregate basis, and the net increase was influenced by two primary factors. An overall increase of 9,412 in the number of residential and commercial customers, assuming the same average consumption per customer as last year, contributed $990,000 in additional margin. The combined growth rate for residential and commercial customers was 4.4%, more than two times the national average for natural gas distribution companies. However, the decrease in average gas usage per customer largely offset the contribution from

new customers, resulting in the net increase of $92,000. The primary use of gas by residential customers is for space and water heating, therefore average consumption per customer is very sensitive to weather, particularly during the Company’s first and second fiscal quarters. 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.

Industrial and Other Margin

	First Quarter of Fiscal					Percent
	2005			2004		Change
	(dollars in thousands)
Average Number of Customers
Electric Generation	14			14		0.0	%
Industrial	736			744		-1.1	%
	750			758		-1.1	%
Therms Delivered (thousands)
Electric Generation	117,365			145,145		-19.1	%
Industrial	110,414			115,742		-4.6	%
	227,779			260,887		-12.7	%
Operating Margin ($ thousands)
Electric Generation	$	2,007		$	2,241	-10.4	%
Industrial	5,306			5,432		-2.3	%
Gas Management Services	391			1,132		-65.5	%
Mark-to-Market Valuations	(668		)	406		-264.5	%
Other	200			139		43.9	%
	$	7,236		$	9,350	-22.6	%

Electric Generation: The decline in margin from electric generation customers is attributed to adequate supplies of lower cost hydroelectric power and weaker demand resulting, in part, from the high wholesale price of natural gas. Looking ahead, gas usage by generation customers will continue to depend on regional demand for power, availability of hydro resources, and the relationship between the market price of electricity and the cost of gas.

Gas Management Services: The $741,000 decline in margin from gas management services is attributed to fewer gas management customers and lower per-therm margin on gas supply sales compared to last year. 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.

Mark-to-Market Valuations: These valuations result from periodic changes in the fair value of the derivative instruments used to hedge the cost of supplies for gas management customers. The hedging instruments are in place to effectively fix the price of those supplies. As market prices of natural gas forward contracts increase, the value of the instruments increases. Conversely, when market prices decrease, the value of the instruments also decreases. During the fiscal 2005 first quarter, forward natural gas prices decreased from the beginning of the quarter to the end of the quarter, hence the $668,000 charge for the quarter. During the first quarter last year, these prices increased, resulting in the $406,000 credit. These hedging instruments are for fixed periods that correspond to the periods of the physical supply contracts to serve these customers. The hedged volumes also correspond to the volumes expected to be purchased under these contracts. At the end of the life of the hedging instruments the cumulative income statement effects of the mark-to-market valuations will net to zero. But market fluctuations in interim periods do result in mark-to-market valuation effects in those periods’ income statements.

Oregon Earnings Sharing: In addition to the above described margin differences, the comparison of first quarter 2005 versus 2004 is affected by accruals of estimated liability for Oregon Earnings Sharing. In the first quarter of 2004 we accrued $250,000 as an estimate of a liability to be paid back to Oregon customers. No additional amount was accrued in the first quarter of fiscal 2005.

Cost of Operations

Compared to last year, overall Cost of Operations was $455,000 higher for the quarter. Within Cost of Operations, notable changes in Operating Expenses included a $347,000 increase in labor expense, including normal annual wage and salary increases and $151,000 in severance pay, stemming primarily from planned staffing reductions in connection with implementation of a new customer service call center in the second quarter of fiscal 2005. Included in operating expense is a $120,000 accrual for a penalty proposed by the staff of the Washington Utilities and Transportation Commission for pipeline safety audit weaknesses. Also reflected in operating expense changes for the quarter was a $480,000 reduction in employee benefits expense, reflecting the full impact of benefit plan changes initiated in 2003. Various smaller increases and decreases in other categories of expense, in the aggregate, accounted for the remainder of the change in Operating Expenses for the quarter.

The $284,000 increase in Depreciation and Amortization is related to the approximately $38 million increase in Utility Plant compared to a year ago. Included in the increased plant balance is approximately $15 million in equipment installed for our automated meter reading system.

Interest and Other Deductions – Net

The $222,000 reduction in Interest and Other Deductions-Net is a result of repayment of long-term debt and temporarily replacing that debt with lower cost short-term borrowing under our bank line of credit.

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 December 31, 2004, there was $45,000,000 outstanding debt under this 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 had $110,000,000 remaining available for issuance, as of December 31, 2004, subject to market conditions and other factors. On January 25, 2005, the Company issued $30,000,000 of 30-year 5.25% Insured Quarterly Notes under this registration statement, leaving $80,000,000 available for future issuance of securities. The proceeds were used to pay down the debt under the revolving credit line. In the remainder of fiscal 2005, the Company will repay $10,000,000 in current maturities of long-term debt, beginning with $5,000,000 in January. The Company expects to fund these repayments primarily through use of its bank credit lines, cash from operating activities, and long-term capital sources.

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

Cash provided by operating activities for the first quarter of fiscal 2005 declined $2,624,000 compared to last year. Other than net lower income, a significant contributing factor was higher current income tax. As a component of net income, this higher current income tax expense is offset by lower deferred income tax expense. Deferred income taxes represent a non-cash charge to expense, and effectively

offset lower cash payments for income taxes in the current period. Current Income Taxes were lower last year primarily from the effect of a temporary provision in the federal tax code that allowed a first-year bonus depreciation deduction in the amount of 50% of the cost of new assets placed in service. This provision expires in fiscal 2005. For the full year of fiscal 2004, current income taxes were lower by approximately $7 million resulting from first-year bonus depreciation..

Investing Activities

Net capital expenditures of $7,770,000 for the first quarter of fiscal 2005 were approximately 24% less than first quarter last year. The decrease is primarily attributable to approximately $2.9 million expended last year on the installation of electronic devices on all the Company’s customer meters to allow for automated meter reading (AMR). The AMR project was completed in 2004.

Financing Activities

Other than the payment of dividends, the Company’s primary financing activities during the first quarter of fiscal 2005 were the repayment of $4,000,000 in long-term debt and increasing its borrowing under its bank credit line by $11,500,000.

EFFICIENCY INITIATIVE – CUSTOMER SERVICE CALL CENTER

In January 2005 the Company began operation of a customer-service call center at our existing district office in Bellingham, Washington. This call center will consolidate in one location the customer service function, which has been 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. Activation of the call center is being phased in, and we plan for the center to be fully operational in March 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 to the pension and supplemental executive retirement plans, and expects to contribute $3,525,000 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. At September 30, 2004, the Company used a discount rate of 6.00%. This same rate is used in the development of pension expense for fiscal 2005. 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 2005 the Company’s assumed rate of return on plan assets is 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.

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, 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 Purchased Gas Cost Adjustment (PGA) mechanisms assure the recovery in customer rates 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 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.

Item 4. 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 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.

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. During 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. We did not make any other changes in our internal control over financial reporting during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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.

PART II. Other Information

Item 5. Other Information

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

No.		Description

10.1		Agreement and General Release between the Registrant and J.D. Wessling, Chief Financial Officer

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

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:	February 7, 2005	.

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 5. Other Information

		Item 6. Exhibits

Signature