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, 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.

 

 

 

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 4. Submission of Matters to a Vote of Security Holders
		Item 5. Other Information
		Item 6. Exhibits and Reports on Form 8-K
Signature

 

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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, 2004			Mar 31, 2003			Mar 31, 2004			Mar 31, 2003
			(thousands except per share data)
Operating revenues			$	119,454		$	109,286		$	224,339		$	209,782
Less:	Gas purchases		78,598			72,126			146,123			136,829
	Revenue taxes		8,714			7,513			15,381			13,797
Operating margin			32,142			29,647			62,835			59,156
Cost of operations:
Operating expenses			10,807			10,984			21,085			22,137
Depreciation and amortization			3,935			3,842			7,855			7,620
Property and miscellaneous taxes			876			923			1,807			1,781
			15,618			15,749			30,747			31,538
Income from operations			16,524			13,898			32,088			27,618
Less interest and other deductions - net			3,121			3,112			6,237			6,311
Income before income taxes			13,403			10,786			25,851			21,307
Income taxes			4,892			3,937			9,436			7,777
Net Income			$	8,511		$	6,849		$	16,415		$	13,530
Weighted average common shares outstanding			11,196			11,057			11,177			11,051
Net earnings per common share
Basic			$	0.76		$	0.62		$	1.47		$	1.22
Diluted			$	0.76		$	0.62		$	1.47		$	1.22
Cash dividends per share			$	0.24		$	0.24		$	0.48		$	0.48

 

The accompanying notes are an integral part of these financial statements

 

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(Dollars in Thousands)

 

		Mar 31, 2004			Sep 30, 2003
		(Unaudited)
ASSETS
Utility Plant, net of accumulated depreciation of $235,363 and $227,582		$	312,019		$	302,225
Construction work in progress		12,348			10,078
		324,367			312,303
Other Assets:
Investments in non-utility property		202			202
Notes receivable, less current maturities		50			52
		252			254
Current Assets:
Cash and cash equivalents		11,424			7,452
Accounts receivable and current maturities of notes receivable, less allowance of $1,028 and $877 for doubtful accounts		36,974			12,296
Materials, supplies and inventories		9,573			14,737
Prepaid expenses and other assets		4,975			6,144
Deferred income taxes		860			755
		63,806			41,384
Deferred Charges
Gas cost changes		8,488			11,584
Other		5,579			5,931
		14,067			17,515
		$	402,492		$	371,456

 

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)

(Dollars in Thousands)

 

		Mar 31, 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 11,210,375 and 11,131,860 shares		$	11,210		$	11,132
Additional paid-in capital		100,238			98,877
Accumulated other comprehensive income (loss)		(13,430		)	(13,430		)
Retained earnings		27,019			15,981
		125,037			112,560
Long-term Debt		133,930			142,930
Current Liabilities:
Notes payable and commercial paper		—			3,800
Current maturities of long-term debt		31,000			22,000
Accounts payable		23,012			10,501
Property, payroll and excise taxes		8,644			5,387
Dividends and interest payable		7,911			7,884
Other current liabilities		9,786			6,431
		80,353			56,003
Deferred Credits and Other Liabilities		63,172			59,963
Commitments and Contingencies		—			—
		$	402,492		$	371,456

 

The accompanying notes are an integral part of these financial statements

 

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		SIX MONTHS ENDED
		(dollars in thousands)
		Mar 31, 2004			Mar 31, 2003
Operating Activities
Net income		$	16,415		$	13,530
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,855			7,620
Deferrals of gas cost changes		(1,730		)	3,727
Amortization of gas cost changes		4,825			4,035
Other deferrals and amortizations		799			2,488
Deferred income taxes and tax credits - net		2,629			1,850
Change in current assets and liabilities		805			890
Net cash provided by operating activities		31,598			34,140
Investing Activities
Capital expenditures		(20,206		)	(10,808		)
Customer contributions in aid of construction		318			30
Other		—			7
Net cash used by investing activities		(19,888		)	(10,771		)
Financing Activities
Proceeds from issuance of common stock		1,440			481
Changes in notes payable and commercial paper, net		(3,800		)	—
Dividends paid		(5,378		)	(5,308		)
Net cash used by financing activities		(7,738		)	(4,827		)
Net Increase in Cash and Cash Equivalents		3,972			18,542
Cash and Cash Equivalents
Beginning of year		7,452			3,688
End of period		$	11,424		$	22,230

 

The accompanying notes are an integral part of these financial statements

 

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CASCADE NATURAL GAS CORPORATION

                NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

THREE- AND SIX-MONTH PERIODS ENDED MARCH 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 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. Reclassifications

 

Certain reclassifications have been made in the financial statements for the quarter and year-to-date periods ended March 31, 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 No. 106-1

 

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 provides guidance which permits 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). Regardless of whether the sponsor elects the deferral, the FSP requires certain disclosures pending further consideration of the underlying accounting issues. The guidance in this FSP is effective for quarterly and annual financial statements for fiscal years ending after December 7, 2003.

 

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. The Company has not developed estimates of the impact of the Act on its cash flows, accumulated postretirement benefit obligation (APBO), or net periodic postretirement benefit cost. Neither has it determined whether to change its postretirement medical plan in response to the Act. FAS No. 106 does not provide accounting guidance on the treatment or timing of the federal subsidy. As provided under the FSP, the Company has elected to defer accounting for the impact of the Act until such guidance is provided by the FASB. This election will expire if, subsequent to January 31, 2004, but prior to the issuance of authoritative guidance, a significant event occurs, such as a plan amendment, settlement, or curtailment that would ordinarily call for remeasurement of the postretirement medical plan’s assets and obligations.

 

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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 as prescribed in Statement of Financial Accounting Standards (FAS) No. 128.

 

		Three Months Ended March 31						Six Months Ended March 31
		2004			2003			2004			2003
		(in thousands except per-share data)
Net income (loss)		$	8,511		$	6,849		$	16,415		$	13,530
Weighted average shares outstanding		11,196			11,057			11,177			11,051
Basic earnings per share		$	0.76		$	0.62		$	1.47		$	1.22
Weighted average shares outstanding		11,196			11,057			11,177			11,051
Plus: Issued on assumed exercise of stock options		18			19			14			18
Weighted average shares outstanding assuming dilution		11,214			11,076			11,191			11,069
Diluted earnings per share		$	0.76		$	0.62		$	1.47		$	1.22

 

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Note 4. Retirement Plan Information

 

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

 

Net Periodic Benefits Cost

 

		Three Months Ended						Six Months Ended
		Mar 31, 2004			Mar, 31, 2003			Mar 31, 2004			Mar, 31, 2003
		(Thousands of Dollars)
DEFINED BENEFIT PENSION PLANS
Service cost		$	192		$	439		$	384		$	877
Interest cost		932			943			1,864			1,887
Expected return on plan assets		(978		)	(922		)	(1,956		)	(1,843		)
Amortization of unrecognized transition obligation		—			25			—			50
Recognized gains or losses		349			280			699			561
Prior service cost		57			114			114			227
Net Periodic Benefit Cost Recognized		$	552		$	879		$	1,105		$	1,759
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost		$	46		$	148		$	92		$	296
Interest cost		365			593			731			1,186
Expected return on plan assets		(203		)	(181		)	(406		)	(362		)
Amortization of unrecognized transition obligation		164			164			328			328
Recognized gains or losses		322			285			644			570
Prior service cost		(337		)	(18		)	(675		)	(36		)
Net Periodic Benefit Cost Recognized		$	357		$	991		$	714		$	1,982
DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized		$	245		$	—		$	487		$	—

 

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 based 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

 

The Company previously disclosed in its Quarterly Report on Form 10-Q for the quarter ended December 31, 2003, that it expected to contribute $3,500,000 to its defined benefit pension plans in fiscal 2004. As of March 31, 2004, $1,350,000 of contributions have been made. The Company presently

 

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anticipates contributing an additional $2,150,000 to fund its pension plans for a total of $3,500,000 in fiscal 2004.

 

 

Note 5. Stock-Based Compensation

 

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

 

		Three Months Ended March 31						Six Months Ended March 31
		2004			2003			2004			2003
		(in thousands except per-share data)
Amounts as reported, reflecting stock-based employee compensation cost determined under APB No. 25:
Stock-based employee compensation cost, net of tax effect		$	—		$	—		$	—		$	—
Net income (loss)		$	8,511		$	6,849		$	16,415		$	13,530
Basic earnings (loss) per share		$	0.76		$	0.62		$	1.47		$	1.22
Diluted earnings (loss) per share		$	0.76		$	0.62		$	1.47		$	1.22
Proforma amounts, reflecting stock-based employee compensation cost as if determined under fair value (FAS 123) method:
Stock-based employee compensation cost, net of tax effect		$	13		$	27		$	26		$	55
Net income (loss)		$	8,498		$	6,822		$	16,389		$	13,475
Basic earnings (loss) per share		$	0.76		$	0.62		$	1.47		$	1.22
Diluted earnings (loss) per share		$	0.76		$	0.62		$	1.46		$	1.22

 

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.

 

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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. No claims now pending, in the opinion of management, are expected to have a material effect on the Company’s financial position, results of operations, or liquidity.

 

Litigation and Other Contingencies

 

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

 

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 six-month periods ended March 31, 2004 and March 31, 2003.

 

OVERVIEW

 

The Company is a local distribution company (LDC) serving approximately 218,000 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 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. 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. This balance can somewhat shield the Company from economic downturns in a given part of its service area.

 

The Company earns more than one third of its operating margin from industrial 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.

 

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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.

 

RESULTS OF OPERATIONS

 

Net income for the second quarter of fiscal 2004 (quarter ended March 31, 2004) was $8,511,000, or $0.76 per share, basic and diluted, compared to $6,849,000, or $0.62 per share, basic and diluted, for the quarter ended March 31, 2003, representing a 23% improvement in per share earnings. Primary factors influencing the quarterly comparisons were:

 

•                  Higher operating margins from residential and commercial customers.

•                  Increased margins from providing gas management services, though this increase stems from a charge recorded in the second quarter last year.

•                  Cost controls.

 

These improvements were partially offset by declines in margin from electric generation customers.

 

On a year-to-date basis, basic and diluted earnings per share improved 20%, to $1.47 from $1.22, on net income of $16,415,000, compared to $13,530,000. The year-to-date comparisons were influenced by similar factors to the second quarter comparisons.

 

Operating Margin

 

Operating margins by customer category for the second 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 March 31						Percent Change		Six Months Ended March 31						Percent Change
		2004			2003					2004			2003
		(dollars in thousands)								(dollars in thousands)
Degree Days
Actual		2,249			2,049			9.8	%	4,355			4,076			6.8	%
5-Year Average		2,275			2,272					4,319			4,314
Average Number of Customers Billed
Residential		187,042			178,586			4.7	%	184,730			176,880			4.4	%
Commercial		29,665			29,107			1.9	%	29,398			28,864			1.9	%
Average Therm Usage per Customer
Residential		286			267			7.1	%	558			525			6.3	%
Commercial		1,434			1,280			12.0	%	2,688			2,489			8.0	%
Operating Margin
Residential		$	15,178		$	13,548		12.0	%	$	29,234		$	26,540		10.2	%
Commercial		$	8,650		$	7,601		13.8	%	$	16,187		$	14,875		8.8	%

 

Residential and commercial operating margin increased $2,679,000. Approximately $1.7 million of the improvement was due to higher per-customer consumption attributable, in large part, to temperatures 9.8% colder than last year. The addition of 9,014 more residential and commercial customers, a 4.3% growth rate, added another $907,000. Second quarter last year was unusually warm. This year, stretches of warm weather were offset by an Arctic outbreak in January, so that degree days for the three months were relatively close to the average experienced over the prior five years. 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. Consumption by commercial customers is also sensitive to weather, but to a lesser extent than 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 4.3%, more than two times the average for natural gas distribution companies.

 

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Of the $4,006,000 increase in year-to-date residential and commercial margins, approximately $2,320,000 resulted from higher per-customer consumption, and the remainder primarily from the addition of new customers.

 

Industrial and Other Margin

 

		Three Months Ended March 31						Percent Change		Six Months Ended March 31						Percent Change
		2004			2003					2004			2003
		(dollars in thousands)								(dollars in thousands)
Average Number of Customers
Electric Generation		14			14			0.0	%	14			14			0.0		%
Industrial		740			739			0.1	%	743			740			0.4		%
Therms Delivered (thousands)
Electric Generation		108,672			144,895			-25.0	%	253,817			297,108			-14.6		%
Industrial		115,221			107,130			7.6	%	230,963			215,286			7.3		%
Operating Margin ($thousands)
Electric Generation		$	1,895		$	2,491		-23.9	%	$	4,136		$	5,012		-17.5		%
Industrial		$	5,678		$	5,502		3.2	%	$	11,119		$	10,793		3.0		%
Gas Management Services		$	886		$	594		49.2	%	$	2,416		$	1,880		28.5		%
Other		$	133		$	107		24.3	%	$	271		$	251		8.0		%

 

Margin derived from electric generation customers declined $596,000 for the quarter and $876,000 year-to-date. The decline can be attributed to the effects of the slow economy and weather conditions on the demand for electricity, as well as on increased availability of hydroelectric resources so far this year. Use of gas for electric generation continues to be difficult to predict. There is currently concern that hydro availability in the Western states this summer may be much lower than previously expected, and that demand for electricity may be higher, especially in California – both factors that could increase demand for gas-fired generation. But the situation remains highly uncertain.

 

The small increase in margin from delivering gas to other industrial customers is attributable generally to more gas usage in a number of industries, rather than a major customer addition or other single factor. Gas utilization by this customer class has been adversely affected for the past two years by the slow economy and high energy prices. Challenges for this sector continue. More customer plants will be closing in coming months. At the same time, a closed fruit and vegetable processing plant is expected to reopen and another plant is expected to expand.  Demand for forest products, including pulp and paper, another major Northwest industry, is increasing. And a weapons incineration plant that has been testing its furnaces during the past year expects to go into actual operation in July.

 

The $292,000 quarterly, and $536,000 year-to-date increase in margin from providing gas management services to a group of industrial customers is due to a gas contract termination charge of $865,000 recorded in the second quarter of fiscal 2003. Absent this charge, there was a decrease in gas management margin.  A significant portion of gas management service margins is derived from arranging gas supplies for these customers. As these arrangements expire and new ones entered into, margins will fluctuate. The lower margins in 2004 reflect tighter market conditions and increased competition for gas management services. The lower margins also result from changes in how the Company provides those services.  The Company no longer relies solely on physical gas supply contracts to meet the demands of  customers, but now makes greater use of financial derivatives.  While the cost of those instruments narrows the margins available to the Company, they also reduce the risks inherent in these transactions, such as the supplier performance risks that led to the contract termination charges incurred in past fiscal years.

 

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Gas management margins for fiscal 2004 include favorable mark-to-market swap and cap valuations of $69,000 for the second quarter, and $475,000 year-to-date. The value of these derivative instruments as of March 31, 2004 was $286,000 and is included under current assets in prepaid expenses and other assets. The valuation of these instruments, which expire in October 2004, are primarily affected by forward natural gas prices and remaining natural gas deliveries subject to the instruments. Increases in market prices of natural gas cause the value of the derivative instrument to increase. Correspondingly, decreases in market prices of natural gas will cause the value of the derivative to decrease. These increases or decreases in market value may continue to result in volatility in earnings on a quarter-to-quarter basis. Quarterly changes in the value of the instruments do not change the underlying economics of the transactions. Over the lives of the derivative arrangements, the effect on earnings is expected to be $127,000, the amount of premium paid for the cap.

 

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 March 31						Six Months Ended March 31
		2004			2003			2004			2003
		(dollars in thousands)						(dollars in thousands)
Oregon Earnings Sharing		$	(279	)	$	(195	)	$	(529	)	$	(195	)

 

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. Early in the third quarter of fiscal 2004, the OPUC issued an Order that raises the earnings-sharing threshold to an ROE 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  $131,000 lower for the quarter and $791,000 lower for the year-to-date period. Within Cost of Operations, notable changes in Operating Expenses included a reduction in employee benefits expenses of $588,000 for the quarter and $1,404,000 year-to-date. These reductions were partially offset in both periods by increases in labor expense and other categories of expense. The benefit expense reductions result from plan changes implemented beginning in July 2003.

 

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. The Company also has a $10,000,000 uncommitted bank credit line. As of March 31, 2004, there was no outstanding debt under these credit lines. The Company has begun discussions with its bank to renew its credit line, and is considering increasing the line. Management considers its relationship with its bank to be excellent, and does not anticipate problems in renewing the 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

 

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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

 

Cash provided by operating activities in fiscal 2004 continues to benefit from Amortization of Gas Cost Changes. 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 higher costs. This temporary rate component is set to expire in November 2004, and as a result, in subsequent periods, cash from operating activities is expected to decrease by approximately $8 million to $10 million per year. There is no impact on operating margin or net income from Amortization of Gas Cost Changes.

 

Investing Activities

 

Net capital expenditures for the six months of $19,888,000 are approximately 85% greater than last year. The increase is primarily attributable to $6,764,000 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 $10,447,000 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 of our areas, disclosing the need for additional distribution capacity in a few localized parts of our system.  These factors could push full fiscal 2004 expenditures closer to $38 million.

 

Financing Activities

 

Other than the payment of dividends, the primary financing activity during fiscal 2004 was paying off $3,800,000 under the Company’s bank credit line. The Company also received $1,440,000 in proceeds from issuance of common stock. In the second quarter of fiscal 2003, the Company began issuing new stock to its dividend reinvestment plan, and 401(k) plan, and on exercise of stock options. The prior practice was to use funds received to purchase shares of stock on the open market.

 

Over the next ten 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 July 2004. The Company expects to fund these repayments primarily through use of its bank credit lines and with cash from operating activities.

 

EFFICIENCY INITIATIVES

 

The Company currently has two major projects underway to improve operating efficiency. The first is the AMR project discussed above under “Investing Activities”. Objectives 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. We are already using the new system to read over half of our customers’ meters.  When completed, the project will enable us to reduce the number of meter readers from thirty-two full time employees to three.  Many of these experienced employees will be 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.

 

The Company has also recently announced that it will be locating a customer-service call center at its present Bellingham, Washington district office location. This will consolidate under one roof our

 

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customer service function, which is now spread through fifteen local offices.  The new process will reduce expenses and will 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 special accounting treatment to reflect the financial impact of regulation. For example, in establishing the rates to be charged to the Company’s retail customers, the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (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

 

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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. At March 31, 2004 there were $11,011,000 of regulatory assets included in Deferred Gas Cost Changes and Other Deferred Charges, and $4,749,000 of regulatory liabilities included in Deferred Credits and Other Liabilities.

 

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 $3,500,000 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.

 

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 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.

 

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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 not determined what, if any, impact the Act will have on its cash flows, net periodic postretirement benefit cost, or accumulated postretirement benefit obligation, and the financial statements in this report do not reflect any impact of the Act. Please refer to the information contained under the caption “FSP FAS No. 106-1”, 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 assure the recovery of prudently incurred wholesale cost of gas purchased for the core market. The Company utilizes fixed price contracts and financial derivatives to manage risk associated with wholesale costs of gas purchased for 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, its 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

 

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timely rate relief to recover increased capital and operating costs resulting from customer growth 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 $108,126,000 as of March 31, 2004. Under this agreement, approximately $25,027,000 was available for payment of dividends at March 31, 2004.

 

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

 

At the annual meeting of shareholders on January 28, 2004, the following directors were elected by the vote indicated for terms of office expiring in 2005:

 

		For		Withheld
Pirkko H. Borland		8,897,752		264,569
Carl Burnham, Jr.		8,923,647		238,674
Thomas E. Cronin		8,905,169		257,152
David A. Ederer		8,925,118		237,203
W. Brian Matsuyama		8,912,386		249,935
Larry L. Pinnt		8,976,176		298,087
Mary Pugh (note)		8,914,045		248,276
Brooks G. Ragen		8,891,591		270,730
Douglas G. Thomas		8,913,988		248,333

 

In addition, a proposal to approve an increase in the number of shares of Common Stock available for issuance under the Company’s 2000 Director Stock Award Plan by 35,000 shares was approved by a vote of 5,323,991 for, and 963,864 against.

 

Note:                   Mary Pugh resigned effective April 30, 2004, and Scott M. Boggs was elected by the Board of Directors to fill that position.

 

Item 5.  Other Information

 

a)

 

 Ratio of Earnings to Fixed Charges:

 

Twelve Months Ended
3/31/2004		9/30/2003		9/30/2002		9/30/2001		9/30/2000		9/30/1999
2.40		2.06		2.27		3.39		3.12		3.00

 

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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 January 30, 2004, the Company filed a Report on Form 8-K to furnish its January 22, 2004 release of first quarter fiscal 2004 earnings.

 

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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, 2004		.

 

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