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 March 31, 2005

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		11,359,612 as of April 29, 2005

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 4. Submission of Matters to a Vote of Security Holders

		Item 5. Other Information

		Item 6. Exhibits

Signature

PART I. Financial Information

Item 1. Financial Statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

(unaudited)

	THREE MONTHS ENDED				SIX MONTHS ENDED
	Mar 31, 2005		Mar 31, 2004		Mar 31, 2005		Mar 31, 2004
	(thousands except per share data)

Operating revenues	$	117,711	$	119,454	$	222,324	$	224,339

Less: Gas purchases	78,331		78,598		147,452		146,123
Revenue taxes	8,538		8,714		15,108		15,381
Operating margin	30,842		32,142		59,764		62,835

Cost of operations:
Operating expenses	11,021		10,649		21,441		20,927
Depreciation and amortization	4,280		3,935		8,485		7,855
Property and miscellaneous taxes	944		876		1,903		1,807
	16,245		15,460		31,829		30,589

Income from operations	14,597		16,682		27,935		32,246
Less interest and other deductions - net	2,976		3,121		5,870		6,237
Income before income taxes	11,621		13,561		22,065		26,009

Income taxes	4,269		4,892		8,081		9,436
Net Income	7,352		8,669		13,984		16,573

Weighted average common shares outstanding	11,312		11,196		11,296		11,177

Net earnings per common share
Basic	$	0.65	$	0.77	$	1.24	$	1.48
Diluted	$	0.65	$	0.77	$	1.24	$	1.48

Cash dividends per share	$	0.24	$	0.24	$	0.48	$	0.48

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(unaudited)

	Mar 31, 2005		Sep 30, 2004
	(dollars in thousands)
ASSETS
Utility Plant, net of accumulated depreciation of $251,061 and $242,691	$	334,767	$	327,345
Construction work in progress	6,433		7,229
	341,200		334,574
Other Assets:
Investments in non-utility property	202		202
Notes receivable, less current maturities	50		43
	252		245
Current Assets:
Cash and cash equivalents	6,105		499
Accounts receivable and current maturities of notes receivable, less allowance of $1,139 and $1,028 for doubtful accounts	48,780		15,001
Prepaid expenses and other assets	4,977		18,674
Derivative instrument assets - energy commodity	26,551		17,983
Materials, supplies and inventories	5,772		13,268
Deferred income taxes	1,009		955
	93,194		66,380
Deferred Charges and Other
Gas cost changes	10,804		12,288
Derivative instrument assets - energy commodity	9,942		3,952
Other	6,869		5,183
	27,615		21,423

	$	462,261	$	422,622

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)

(unaudited)

	Mar 31, 2005			Sep 30, 2004
	(dollars in thousands)
COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES
Common Shareholders’ Equity:
Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,337,642 and 11,268,069 shares	$	11,337		$	11,268
Additional paid-in capital	102,575			101,354
Accumulated other comprehensive income (loss)	(12,608		)	(12,608		)
Retained earnings	27,052			18,500
	128,356			118,514

Long-term Debt	158,900			128,900

Current Liabilities:
Notes payable and commercial paper	13,500			33,500
Current maturities of long-term debt	5,000			14,000
Accounts payable	22,887			12,923
Property, payroll and excise taxes	8,645			5,287
Dividends and interest payable	7,081			7,125
Regulatory liabilities	26,023			17,209
Other current liabilities	9,901			8,972
	93,037			99,016

Deferred Credits and Other Non-current Liabilities
Deferred income taxes and investment tax credits	39,281			38,392
Retirement plan obligations	20,731			20,780
Regulatory liabilities	15,930			10,515
Other	6,026			6,505
	81,968			76,192

Commitments and Contingencies	—			—
	$	462,261		$	422,622

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	SIX MONTHS ENDED
	(dollars in thousands)
	Mar 31, 2005			Mar 31, 2004
Operating Activities
Net income	$	13,984		$	16,573
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	8,485			7,855
Deferrals of gas cost changes	(2,266		)	(1,730		)
Amortization of gas cost changes	3,750			4,825
Other deferrals and amortizations	(491		)	641
Deferred income taxes and tax credits - net	835			2,629
Change in current assets and liabilities	1,860			805
Net cash provided by operating activities	26,157			31,598

Investing Activities
Capital expenditures	(16,130		)	(20,206		)
Customer contributions in aid of construction	601			318
Net cash used by investing activities	(15,529		)	(19,888		)

Financing Activities
Proceeds from issuance of long-term debt, net	28,119			—
Proceeds from issuance of common stock	1,290			1,440
Repayment of long-term debt	(9,000		)	—
Changes in notes payable and commercial paper, net	(20,000		)	(3,800		)
Dividends paid	(5,431		)	(5,378		)
Net cash used by financing activities	(5,022		)	(7,738		)

Net Increase in Cash and Cash Equivalents	5,606			3,972

Cash and Cash Equivalents
Beginning of year	499			7,452
End of period	$	6,105		$	11,424

The accompanying notes are an integral part of these financial statements

CASCADE NATURAL GAS CORPORATION

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

THREE-AND SIX-MONTH PERIODS ENDED MARCH 31

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. 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. Restatement

As disclosed in the Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, the Company restated its earnings for the quarter ended March 31, 2004. This restatement was a result of the remeasurement of retiree medical expense, with a remeasurement date of December 31, 2003. This remeasurement reduced operating expenses by $158,000 for the three- and six-month periods ended March 31, 2004.

Fiscal year 2004 amounts reported in this quarterly report, including amounts in the following footnotes, reflect the restated amounts.

Note 2. Earnings Per Share

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

	Three Months Ended				Six Months Ended
	Mar 31, 2005		Mar 31, 2004		Mar 31, 2005		Mar 31, 2004
	(in thousands except per-share data)
Net income	$	7,352	$	8,669	$	13,984	$	16,573

Weighted average shares outstanding	11,312		11,196		11,296		11,177
Basic earnings per share	$	0.65	$	0.77	$	1.24	$	1.48

Weighted average shares outstanding	11,312		11,196		11,296		11,177
Plus: Issued on assumed exercise of stock options	3		18		4		14
Weighted average shares outstanding assuming dilution	11,315		11,214		11,300		11,191

Diluted earnings per share	$	0.65	$	0.77	$	1.24	$	1.48

Note 3. Retirement Plan Information

The following table sets forth the components of net periodic benefit costs recognized.

Net Periodic Benefits Cost

	Three Months Ended						Six Months Ended
	Mar 31, 2005			Mar 31, 2004			Mar 31, 2005			Mar 31, 2004
	(in thousands)
DEFINED BENEFIT PENSION PLANS
Service cost	$	197		$	192		$	394		$	384
Interest cost	961			932			1,922			1,864
Expected return on plan assets	(1,041		)	(978		)	(2,081		)	(1,956		)
Recognized gains or losses	386			349			772			699
Prior service cost	46			57			91			114
Net Periodic Benefit Cost Recognized	$	549		$	552		$	1,098		$	1,105

POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost	$	35		$	38		$	70		$	83
Interest cost	275			308			550			655
Expected return on plan assets	(211		)	(213		)	(423		)	(426		)
Recognized gains or losses	187			218			374			526
Prior service cost	(330		)	(330		)	(660		)	(660		)
Net Periodic Benefit Cost Recognized	$	(44	)	$	21		$	(89	)	$	178

DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized	$	250		$	245		$	492		$	487

Retirement Plan Funding

For the six months ended March 31, 2005, $1,025,000 of contributions have been made to the Company’s defined benefit pension plans. The Company presently anticipates contributing an additional $2,295,000 to fund its pension plans for a total of $3,320,000 in fiscal 2005.

Note 4. Stock-Based Compensation

The Company follows the disclosure-only provisions of Statement of Financial Accounting Standards (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 FAS No. 123, net income and earnings per common share would have been the following pro forma amounts for the three- and six-month periods ended March 31:

	Three Months Ended				Six Months Ended
	Mar 31, 2005		Mar 31, 2004		Mar 31, 2005		Mar 31, 2004
	(in thousands except per-share data)
Net income
As reported	$	7,352	$	8,669	$	13,984	$	16,573
Less total stock-based employee compensation expense determined under the fair value method, net of tax	$	13	13		$	26	26
Pro forma net income	$	7,339	$	8,656	$	13,958	$	16,547

Earnings per share, basic and diluted
As reported	$	0.65	$	0.77	$	1.24	$	1.48
Pro forma	$	0.65	$	0.77	$	1.24	$	1.48

Note 5. Commitments and Contingencies

Unregistered Shares of Common Stock Under DRIP

In connection with modifying administrative procedures and updating the prospectus for the Company’s Automatic Dividend Reinvestment Plan (the DRIP), the Company has learned that the number of shares of its common stock issued pursuant to the DRIP exceeded the number of shares previously registered for such purpose under the Securities Act of 1933, as amended (the Securities Act). As a result, the Company may have failed to comply with the registration or qualification requirements of federal and applicable state securities laws with respect to such shares.

Based upon the Company’s investigation, it appears that approximately 122,800 shares of its common stock were issued to approximately 3,500 DRIP participants between August 2003 and April 2005 in excess of the number of shares registered specifically for such purpose. Such shares were issued at prices ranging from $18.18 to $22.95 per share.

The Company is continuing to investigate details concerning the DRIP participants affected and is evaluating appropriate actions to be taken, including a possible rescission offer, to rectify this oversight. Should the Company repurchase all of the unregistered shares at the purchase prices for which they were issued, cash of approximately $2,508,000 would be used to retire approximately 122,800 outstanding shares. Should the Company repurchase only the unregistered shares sold since May 1, 2004 (approximately the period covered by the one-year statute of limitations applicable to sales of unregistered shares under the Securities Act), cash of approximately $1,493,000 would be used to retire approximately 73,000 outstanding shares.

The Company has not yet obtained all of the necessary information concerning individual DRIP participants to determine whether a rescission offer is the appropriate action to take and, if so, how it should be structured. If the Company should proceed with a rescission offer, additional costs, including interest, legal, accounting, data processing, printing, mailing and related administrative expenses, will be incurred. Depending on the specific terms of a rescission offer, the Company’s current estimates of such costs, after offsetting dividends paid on shares repurchased, range from $200,000 to $300,000.

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 the Company.

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, cash flows, 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 six-month periods ended March 31, 2005 and March 31, 2004.

OVERVIEW

The Company is a local distribution company (LDC) serving approximately 228,000 customers in the States of Washington and Oregon. The Company’s 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 Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).

Key elements of the Company’s strategy include:

• Remain focused on delivering natural gas to a growing residential, commercial, and industrial customer base in Washington and Oregon.

• Provide gas management, engineering, construction and maintenance services for customer-owned natural gas facilities when the risk / reward ratio is appropriate.

• Pursue additional opportunities closely aligned with the Company’s core business by building on its existing resources and customers.

• Continuously evaluate the most effective utilization of corporate resources.

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 natural 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. 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 continues to explore alternatives such as weather normalization or decoupling mechanisms that utility regulators in many jurisdictions have approved. The WUTC has opened a Rulemaking Docket to investigate decoupling. A workshop under this docket is set for May 12, 2005. The Company will be presenting its proposed mechanism at this workshop.

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

RESULTS OF OPERATIONS

Net income for the second quarter of fiscal 2005 (quarter ended March 31, 2005) was $7,352,000, or $0.65 per share, basic and diluted, compared to $8,669,000, or $0.77 per share, basic and diluted, for the quarter ended March 31, 2004. Primary factors negatively impacting the quarterly comparisons were:

• Lower 2005 operating margins from residential and commercial customers.

• Lower 2005 distribution and gas management margins from industrial customers.

• Executive transition costs in 2005.

• Increased uncollectible accounts expense in 2005.

• Severance and related expenses in 2005 of consolidating customer service operations.

Partially offsetting the above factors were the following items favorably impacting the earnings comparisons:

• Reduced labor and benefits expenses in 2005.

• 2005 adjustment of 2004 accrual of estimate of Oregon earnings sharing.

• Mark-to-market valuations of derivative instruments.

The year-to-date comparisons were affected by the same factors, except that on a year-to-date basis the mark-to-market valuations had a negative impact.

Operating Margin

Operating margins by customer category are set forth in the following tables:

Residential and Commercial Margin

	Second Quarter of Fiscal				Percent		Fiscal Year to Date				Percent
	2005		2004		Change		2005		2004		Change
	(dollars in thousands)
Degree Days
Actual	2,230		2,249		-0.8	%	4,175		4,355		-4.1	%
5-Year Average	2,271		2,275				4,362		4,319
Average Number of Customers Billed
Residential	196,094		187,042		4.8	%	193,597		184,730		4.8	%
Commercial	30,475		29,665		2.7	%	30,157		29,398		2.6	%
Average Therm Usage per Customer
Residential	266		286		-7.0	%	517		558		-7.3	%
Commercial	1,328		1,434		-7.4	%	2,491		2,688		-7.3	%
Operating Margin
Residential	$	14,231	$	15,178	-6.2	%	$	28,455	$	29,234	-2.7	%
Commercial	$	7,724	$	8,650	-10.7	%	$	15,185	$	16,187	-6.2	%

The decline in margin from sales to residential and commercial customers results from lower usage of natural gas on a per-customer basis for both the quarterly and year-to-date periods. The margin decline attributed to lower usage was $2,990,000 for the quarter and $3,884,000 year to date. Partially offsetting this decline was the favorable impact of the increase in the number of customers billed in 2005. Assuming the same average consumption per customer as last year, this growth in customers contributed $1,117,000 in additional margin for the quarter and $2,103,000 year to date. The primary use of natural 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. Other factors also have a negative impact on gas usage, including conservation efforts spurred by higher natural gas prices and higher energy efficiency in buildings and appliances.

Industrial and Other Margin

	Second Quarter of Fiscal				Percent		Fiscal Year to Date					Percent
	2005		2004		Change		2005			2004		Change

Average Number of Customers
Electric Generation	13		14		-7.1	%	13			14		-7.1	%
Industrial	724		740		-2.2	%	730			743		-1.7	%
	737		754		-2.3	%	743			757		-1.8	%
Therms Delivered (thousands)
Electric Generation	113,977		108,672		4.9	%	231,342			253,817		-8.9	%
Industrial	114,913		115,221		-0.3	%	225,327			230,963		-2.4	%
	228,890		223,893		2.2	%	456,669			484,780		-5.8	%
Operating Margin ($thousands)
Electric Generation	$	2,026	$	1,895	6.9	%	$	4,034		$	4,136	-2.5	%
Industrial	5,333		5,695		-6.4	%	10,544			11,100		-5.0	%
Gas Management Services	324		818		-60.4	%	715			1,942		-63.2	%
Mark-to-Market Valuations	549		69		695.7	%	(119		)	475		-125.1	%
Other	129		116		11.2	%	425			290		46.6	%
	$	8,361	$	8,593	-2.7	%	$	15,599		$	17,943	-13.1	%

Industrial Margin: The decline in margin from distribution services to industrial customers is primarily attributable to reduced usage.

Gas Management Services: The decline in margin from gas management services is attributed to fewer gas management customers and lower per-therm margin on natural 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 natural gas supply sales to larger natural gas customers. The Company has lost some customers to such marketers, and margins that are available for any sales are smaller than in the past. The Company will continue to provide natural gas supply services to customers to facilitate their use of gas, but expects 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 second quarter, forward natural gas prices increased from the beginning of the quarter to the end of the quarter, hence the $549,000 credit to operating margin for the quarter. During the quarter last year, these prices increased much less dramatically, resulting in the smaller $69,000 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. Over the first two quarters of 2004 the Company accrued a total liability of $525,000 as an estimate of earnings that would be required to be shared with Oregon customers. However, based on an analysis of the results for the entire year, management has concluded that 2004 earnings in Oregon were not sufficient as to trigger a sharing with customers. As a result, in the second quarter of 2005 the Company recorded a reversal of the estimate accrued in 2004. The analysis is subject to final review and approval by the OPUC, which we expect prior to the end of fiscal 2005.

Cost of Operations

Compared to last year, overall Cost of Operations was $785,000 (5.1%) higher for the quarter. Year-to-date, the increase was $1,240,000 (4.1%). Within Cost of Operations, notable changes in Operating Expenses included charges for executive transition, as well as transition to the Company’s new customer service call center, as shown in the following table.

	Second Quarter		Year-to-date
	($000)
Call center consolidation	$	146	$	313
Executive transition	$	590	$	615

Call center consolidation costs are primarily severance and employee relocation compensation related to consolidating the customer service function in a single call center. Executive transition costs are primarily severance compensation accruals related to early retirements of the Chief Executive Officer and Chief Financial Officer. Also reflected in operating expense changes for the quarterly and year-to-date periods were $275,000 and $755,000 reductions in employee benefits expense, reflecting the full impact of benefit plan changes initiated in 2003. Bad debts expense increased $404,000 for the quarter and $125,000 year-to-date. Contributing to the higher bad debts expense is increased write-off experience. Actual bad

debt write-offs in the second quarter were $182,000 higher than second quarter 2004, with half of the increase attributable to a single commercial customer. Also affecting the comparison was a fiscal year 2004 second quarter favorable $135,000 impact due to a reduction in the reserve related to receivables from a group of customers where write-off experience was less than expected. 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 and year-to-date periods.

The increases in Depreciation & Amortization and in Property & Miscellaneous Taxes are related to ongoing investments in new utility plant, related primarily to expanding the Company’s distribution system to serve new customers, as well as investments related to automated meter reading.

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 March 31, 2005, there was $13,500,000 outstanding under this credit line. The Company also has a $10,000,000 uncommitted line of credit.

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. In the second quarter of fiscal 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, subject to market conditions and other factors. The proceeds were used to pay down debt under the revolving credit line. In the remainder of fiscal 2005, the Company will repay $5,000,000 in current maturities of long-term debt. 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 and for possible repurchase of unregistered shares issued under the Company’s DRIP (see Note 5 of Notes to Consolidated Condensed Financial Statements).

Operating Activities

Cash provided by operating activities for the first six months of fiscal 2005 declined $5,441,000 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. 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 $15,529,000 for the first six months of fiscal 2005 were approximately 22% less than the first six months of last year. Capital expenditures are lower due to the completion in 2004 of the Automated Meter Reading Project described in prior reports.

Financing Activities

Other than the payment of dividends, the Company’s primary financing activities during the first six months of fiscal 2005 were the issuance of $30,000,000 in new long-term debt as described in the preceding paragraphs under “Liquidity and Capital Resources”, repayment of $9,000,000 in current maturities of long-term debt and paying down borrowing under the bank credit line by $20,000,000.

EFFICIENCY INITIATIVE – CUSTOMER SERVICE CALL CENTER

In January 2005 the Company began operation of a customer-service call center at its existing district office in Bellingham, Washington. This call center consolidated in one location the Company’s customer service function, which had been spread through fifteen local offices. The new call center is expected to reduce future 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 was phased in, and it became 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 natural gas and other services to customers. This includes estimated revenues for natural 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. The Company follows FAS No. 87, “Employers’ Accounting for Pensions,” in accounting for these plans. 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 $3,320,000 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, “Accounting for Derivatives and Hedging Activities”, as amended. 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.

Forward-Looking Statements

The Company’s discussion in this report, or in any information incorporated herein by reference, may contain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, are forward-looking statements, including statements concerning plans, objectives, goals, strategies, and future events or performance. When used in Company documents or oral presentations, the words “anticipate,” “believe,” “estimate,” “expect,” “objective,” “projection,” “forecast,” “goal”, or similar words are intended to identify forward-looking statements.

These forward-looking statements reflect the Company’s current expectations, beliefs and projections about future events that we believe may affect the Company’s business, financial condition and results of operations, and are expressed in good faith and are believed to have a reasonable basis. However, each such forward-looking statement involves risks, uncertainties and assumptions, and is qualified in its entirety by reference to the following important factors, among others, that could cause the Company’s actual results to differ materially from those projected in such forward-looking statements:

• prevailing state and federal governmental policies and regulatory actions, including those of the Washington Utilities and Transportation Commission, the Oregon Public Utility Commission, and the U.S. Department of Transportation’s Office of Pipeline Safety, with respect to allowed rates of return, industry and rate structure, purchased gas cost and investment recovery, acquisitions and dispositions of assets and facilities, operation and construction of plant facilities, the maintenance of pipeline integrity, and present or prospective wholesale and retail competition;

• weather conditions and other natural phenomena;

• unanticipated population growth or decline, and changes in market demand caused by changes in demographic or customer consumption patterns;

• changes in and compliance with environmental and safety laws, regulations and policies, including environmental cleanup requirements;

• competition from alternative forms of energy and other sellers of energy;

• increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, as well as consolidation in the energy industry;

• 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;

• risks, including creditworthiness, relating to performance issues with customers and suppliers;

• risks resulting from uninsured damage to the Company’s property, intentional or otherwise, or from acts of terrorism;

• unanticipated changes that may affect the Company’s liquidity or access to capital markets;

• the Company’s ability to complete its assessment and, if necessary, remediation of internal controls over financial reporting in compliance with Section 404 of the Sarbanes-Oxley Act of 2002;

• unanticipated changes in interest rates or in rates of inflation;

• economic factors that could cause a severe downturn in certain key industries, thus affecting demand for natural gas;

• unanticipated changes in operating expenses and capital expenditures;

• unanticipated changes in capital market conditions, including their impact on future expenses and liabilities relating to employee benefit plans;

• potential inability to obtain permits, rights of way, easements, leases, or other interests or necessary authority to construct pipelines, or complete other system expansions;

• changes in the availability and price of natural gas; and

• legal and administrative proceedings and settlements.

In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this report, or in any information incorporated herein by reference, may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. All subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements.

Any forward-looking statement by the Company is made only as of the date on which such statement is made. The Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of any unanticipated events. New factors emerge from time-to–time, and the Company is not able to predict all such factors, nor can it assess the impact of each such factor or the extent to which such factors may cause results to differ materially from those contained in any forward-looking statement.

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 natural gas purchased for the core market. The Company primarily utilizes financial derivatives, and to a lesser extent, fixed price physical supply contracts to manage risk associated with wholesale costs of natural gas purchased for customers.

With respect to derivative arrangements covering natural 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.

PART II. Other Information

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

At the annual meeting of shareholders on February 11, 2005, the following directors were elected by the vote indicated for terms of office expiring in 2006:

	For	Withheld

Scott M. Boggs	9,329,313	195,829
Pirkko H. Borland	9,210,345	314,797
Carl Burnham, Jr.	9,325,916	199,226
Thomas E. Cronin	9,417,303	107,839
David E. Ederer	9,318,468	206,674
W. Brian Matsuyama (note)	9,327,727	197,415
Larry L. Pinnt	9,308,303	216,839
Brooks G. Ragen	9,317,229	207,913
Douglas G. Thomas	9,413,739	111,403

Note: W. Brian Matsuyama resigned as a director effective March 31, 2005, and David W. Stevens was elected by the Board of Directors to serve the remainder of his term.

Item 5. Other Information

a) None

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

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:	May 10, 2005