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, 2007

Commission file number: 1-7196

CASCADE NATURAL GAS CORPORATION

(Exact name of Registrant as specified in its charter)

 

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 x   No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer x

Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).          Yes o  No x

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 and Comprehensive 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 1.	Legal Proceedings
		Item 6.	Exhibits
Signature

 

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PART I.   Financial Information

Item 1.  Financial Statements

 

CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

AND COMPREHENSIVE INCOME

(unaudited)

		THREE MONTHS ENDED						SIX MONTHS ENDED
		Mar 31, 2007			Mar 31, 2006			Mar 31, 2007			Mar 31, 2006
		(thousands except per-share data)
Operating revenues		$	177,909		$	163,018		$	335,093		$	322,226
Less:
Gas purchases and other costs of sales		129,167			118,232			244,168			236,873
Revenue taxes		12,893			11,555			22,795			21,331
Operating margin		35,849			33,231			68,130			64,022
Cost of operations:
Operating expenses		11,794			10,755			23,562			20,398
Depreciation and amortization		4,570			4,435			9,112			8,849
Property and miscellaneous taxes		855			870			1,824			1,856
		17,219			16,060			34,498			31,103
Income from operations		18,630			17,171			33,632			32,919
Less interest and other deductions — net		2,903			2,884			5,935			5,855
Income before income taxes		15,727			14,287			27,697			27,064
Income tax		5,360			5,301			10,541			10,038
Net Income		10,367			8,986			17,156			17,026
Other Comprehensive Income (Loss)
Unrealized gain (loss) on derivative commodity instruments		1,879			(890		)	2,068			(985		)
Income tax		(673		)	319			(741		)	353
Other Comprehensive Income (Loss)		1,206			(571		)	1,327			(632		)
Comprehensive Income		$	11,573		$	8,415		$	18,483		$	16,394
Weighted average commonshares outstanding		11,507			11,455			11,507			11,441
Earnings per common share, basic and diluted		$	0.90		$	0.78		$	1.49		$	1.49
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

(Unaudited)

		Mar 31, 2007			Sep 30, 2006
ASSETS		(dollars in thousands)
Utility Plant, net of accumulated depreciation of $281,817 and $273,138		$	339,437		$	341,046
Construction work in progress		1,405			380
		340,842			341,426
Other Assets:
Investments in non-utility property		202			202
Notes receivable, less current maturities		447			488
		649			690
Current Assets:
Cash and cash equivalents		26,348			8,593
Accounts receivable and current maturities of notes receivable, less allowance of $2,751 and $2,143 for doubtful accounts		59,853			22,796
Prepaid expenses and other assets		5,594			4,671
Derivative instrument assets - energy commodity		8,819			4,135
Materials, supplies and inventories		11,196			17,495
Deferred income taxes		1,541			1,779
Regulatory assets		6,678			26,504
		120,029			85,973
Deferred Charges and Other
Derivative instrument assets - energy commodity		2,558			3,269
Regulatory assets		3,728			18,261
Other		7,224			7,087
		13,510			28,617
		$	475,030		$	456,706

 

Continued

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS (Continued)

(Unaudited)

		Mar 31, 2007			Sep 30, 2006
COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES		(dollars in thousands)
Common Shareholders’ Equity:
Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,506,996 and 11,505,996 shares		$	11,507		$	11,506
Additional paid-in capital		105,746			105,702
Accumulated other comprehensive loss		(11,126		)	(12,453		)
Retained earnings		29,004			17,372
		135,131			122,127
Long-term Debt		165,190			165,123
Current Liabilities:
Current maturities of long-term debt		—			8,000
Accounts payable		33,664			14,647
Property, payroll and excise taxes		10,471			5,776
Dividends and interest payable		6,403			6,939
Derivative instrument liability — energy commodity		8,319			29,496
Regulatory liabilities		8,645			4,132
Other current liabilities		17,554			12,888
		85,056			81,878
Deferred Credits and Other Non-current Liabilities:
Deferred income taxes and investment tax credits		41,702			39,381
Retirement plan obligations		9,283			11,067
Derivative instrument liability — energy commodity		3,922			18,939
Regulatory liabilities		11,975			12,035
Deferred gas cost credit		17,494			602
Other		5,277			5,554
		89,653			87,578
Commitments and Contingencies (Note 5)		—			—
		$	475,030		$	456,706

 

The accompanying notes are an integral part of these financial statements.

 

Concluded

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

		SIX MONTHS ENDED
		(dollars in thousands)
		Mar 31, 2007			Mar 31, 2006
Operating Activities:
Net income		$	17,156		$	17,026
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		9,112			8,849
Deferrals of gas cost changes		8,649			2,232
Amortization of gas cost changes		8,242			7,937
Other deferrals and amortizations		(1,551		)	(951		)
Deferred income taxes and tax credits - net		2,559			(2,305		)
Change in current assets and liabilities		(4,076		)	(2,180		)
Net cash provided by operating activities		40,091			30,608
Investing Activities:
Capital expenditures		(10,416		)	(9,492		)
Customer contributions in aid of construction		1,679			1,430
Net cash used by investing activities		(8,737		)	(8,062		)
Financing Activities:
Proceeds from issuance of long-term debt, net		39,812			—
Proceeds from issuance of common stock		45			1,255
Repayment of long-term debt		(47,933		)	(239		)
Changes in short-term debt, net		—			(12,500		)
Dividends paid		(5,523		)	(5,501		)
Other		—			(11		)
Net cash used by financing activities		(13,599		)	(16,996		)
Net Increase in Cash and Cash Equivalents		17,755			5,550
Cash and Cash Equivalent:
Beginning of year		8,593			1,128
End of period		$	26,348		$	6,678

 

The accompanying notes are an integral part of these financial statements.

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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 that 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 2006 Annual Report on Form 10-K for the fiscal year ended September 30, 2006.

Note 1.  New Accounting Standards

FAS No. 154:  In May 2005, The Financial Accounting Standards Board (FASB) issued FAS No. 154, “Accounting for Changes and Error Corrections”.  This standard replaces APB Opinion No. 20 and FAS No. 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. FAS No. 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle. The Company adopted this standard October 1, 2006 but has not had occasion to apply its requirements.

FAS No. 155: In February 2006, FASB issued FAS No 155, “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140.” This standard is effective for all financial instruments acquired after the beginning of an entity’s first fiscal year beginning after September 15, 2006. Adoption of this standard as of October 1, 2006 has not had a significant impact on the Company’s financial statements.

FAS No. 157: In September 2006, FASB issued FAS No. 157, “Fair Value Measurements”. This standard defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This standard is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company has not determined the impact this standard will have on its financial statements.

FAS No. 158: In September 2006, FASB issued FAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)”.  This standard requires a sponsor of defined benefit retirement plans to: (a) recognize the funded status of a benefit plan in its balance sheet; (b) recognize as a component of other comprehensive income, net of tax, the gains or losses and prior service costs of credits that arise during the period but are not recognized as components of net periodic benefit cost; (c) measure the defined benefit plan assets and obligations as of the date of the employer’s fiscal year end; and (d) disclose in the notes to financial statements additional information about certain effects on net periodic benefit cost for the next fiscal year that arise from the delayed recognition of the gains or losses, prior service costs or credits, and transition asset or obligation. The Company will be required to initially recognize the funded status of its defined benefit plans and to provide the required disclosures as of the end of its fiscal year ending September 30, 2007. The Company has not yet determined the impact of this standard on its financial statements.

FAS No. 159: In February 2007, FASB issued FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115”.  This standard provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This standard is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company has not determined the impact this standard will have on its financial statements.

FIN 48: In June 2006, FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109”.  This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”.  This Interpretation prescribes a recognition threshold and

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measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. This Interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company has not determined the impact of this interpretation on its financial statements.

Note 2.  Earnings Per Share

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

 

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, 2007			Mar 31, 2006			Mar 31, 2007			Mar 31, 2006
		(Dollars in Thousands)						(Dollars in Thousands)
DEFINED BENEFIT PENSION PLANS
Service cost		$	242		$	216		$	485		$	433
Interest cost		964			965			1,928			1,930
Expected return on plan assets		(1,231		)	(1,101		)	(2,462		)	(2,202		)
Recognized gains or losses		278			421			555			842
Prior service cost		(39		)	38			(78		)	76
Net Periodic Benefit Cost Recognized		$	214		$	539		$	428		$	1,079
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost		$	20		$	28		$	40		$	56
Interest cost		163			164			327			329
Expected return on plan assets		(225		)	(219		)	(450		)	(439		)
Recognized gains or losses		195			181			389			362
Prior service cost		(673		)	(615		)	(1,346		)	(1,231		)
Net Periodic Benefit Cost Recognized		$	(520	)	$	(461	)	$	(1,040	)	$	(923	)
DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized		$	195		$	203		$	381		$	408

 

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Retirement Plan Funding

For the six months ended March 31, 2007, $1,260,000 of contributions were made to the Company’s defined benefit pension plans.  The Company presently anticipates contributing an additional $2,240,000 to fund its pension plans for a total of $3,500,000 in fiscal 2007.

Note 4.  Share-Based Payment

Director Stock Award Plan

Following approval by the shareholders in February 2006, the annual stock award for each non-employee director was increased from 500 to 1,000 shares of the Company’s common stock, under the Company’s 2000 Director Stock Award Plan. During the quarters ended March 31, 2007 and 2006, the Company recognized $56,000 and $97,000 as expense under this plan. For the respective six-month periods the amounts were $106,000 and $119,000.  The value of the stock granted under this plan is based on the market value on the date of the award.

Stock Incentive Plan

Under the Company’s 1998 Stock Incentive Plan, 24,000 stock options granted in 2002 are exercisable at $20.84.  The 2002 options expire in 2012.  All options are fully vested.  When the options were granted and during the vesting periods, the Company applied the intrinsic value method under Accounting Principles Board (APB) Opinion 25, and no expense has been recognized.

Restricted Stock Grants

The Company’s employment contracts entered in 2005 with its Chief Executive Officer (CEO) and its former Chief Financial Officer (CFO) contained grants of restricted stock.  Under the CEO grant, 5,000 shares were restricted until the CEO completed one year of employment, and another 5,000 shares were restricted until he completed two years of employment on March 31, 2007.  During this period, the executive was restricted from selling his shares. Under the CFO grant, 5,000 shares were restricted until he completed one year of employment. The value of the shares granted was based on the market value as of the grant date. During the quarters ended March 31, 2007 and 2006, the Company recognized $13,000 and $62,000 as compensation expense under this plan. For the respective six-month periods the amounts were $25,000 and $124,000. As of March 31, 2007, there is no remaining expense to be recognized in future periods for these grants.

Note 5.  Commitments and Contingencies

Environmental Matters

There are two claims against the Company for cleanup of alleged environmental contamination related to manufactured gas plant sites previously operated by companies that 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 soil and groundwater contamination exists at the site.  There are parties in addition to the Company that are potentially liable for cleanup of the contamination.  Some of these other parties have shared in the costs expended to date to investigate the site, and it is expected that these and potentially other parties will share in the cleanup costs.  Several alternatives for remediation of the site have been identified, with preliminary estimates for cleanup ranging from approximately $500,000 to $11,000,000.  It is not known at this time what share of the cleanup costs will actually be borne by the Company.

The second claim was received in 1997 and relates to a site in Washington.  A preliminary investigation has determined that there is evidence of contamination at the site, but there is also evidence that other property owners may have contributed to the contamination.  There is currently not enough information available to estimate the potential liability associated with this claim, but the Company and other parties may become

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involved in future investigation or remediation of the site as increased interest has been expressed concerning its potential for redevelopment. In particular, the Company is aware that the local city government has secured federal grants for further investigation of the site. At this time, no formal investigation plan has been communicated to the Company.

Management has completed a review of the Company’s insurance coverage and believes it has adequate insurance to cover the costs of the above two claims.  In the event the insurance proceeds do not completely cover the costs, management intends to seek recovery from its customers through increased rates.  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 cover 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 such 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-month and six-month periods ended March 31, 2007 and 2006.

OVERVIEW

The Company is a local distribution company (LDC) serving approximately 246,000 customers in the states of Washington and Oregon.  Its service area consists primarily of relatively small cities and rural communities rather than larger urban areas.  The Company’s primary source of revenue and operating margin is the distribution of natural gas to end-use residential, commercial, industrial, and institutional customers.  Revenues are also derived from providing gas management and other services to some of its large industrial and commercial customers.  The Company’s rates and practices are regulated by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC). As previously announced, the Company entered into a definitive merger agreement with MDU Resources Group, Inc. (MDU) on July 8, 2006, to be acquired for cash consideration of $26.50 per share. The following paragraphs contain information regarding the status of the proposed merger.

Key elements of the Company’s strategy are as follows:

·                  Continue to efficiently and effectively operate the Company to achieve business goals and maintain full compliance with the terms of the merger agreement with MDU. Remain focused on the natural gas distribution business.

·                  Pursue appropriate regulatory treatment.

·                  Economic expansion of its customer base by prudently managing capital expenditures and ensuring new customers provide sufficient margins for an appropriate return on the new investment required.

·                  Continue to seek operational efficiencies.

·                  Manage cash flow to minimize the need for additional external financing.

Opportunities and Challenges

The Company operates in a diverse service territory over a wide geographic area relative to the Company’s overall size and number of customers.  The economies of various parts of the service area are supported by a variety of industries and are affected by the conditions that impact those industries.  Management believes there are continued growth opportunities in the Company’s service area, especially in the residential and commercial segments.  Factors contributing to these opportunities include general population growth in the service area, including some areas of very rapid growth, and to a lesser extent, low market penetration in

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many of the communities served. Residential and commercial customer count growth has been more than double the average of U.S. gas utilities.

Overall revenues and margins have been historically negatively impacted by higher efficiency in new home and commercial building construction, higher efficiency in gas-burning equipment, and customers taking additional measures to conserve energy usage.  The increasing cost of energy in recent years, including the wholesale cost of natural gas, continues to encourage such measures.  However, the Company believes that energy efficiency and conservation are the most viable near-term tactics for reducing customer bills and influencing wholesale natural gas prices.  They also form a vital strategy for stabilizing the cost of gas over the long term.  The traditional regulatory establishment of rate recovery tied to volumetric sales no longer seems prudent.  Therefore, the Company’s recent rate case in the State of Washington included a request to decouple the margin recovery from volume. On January 12, 2007, the Company received the order from the WUTC on its rate case. The WUTC conditionally accepted the settlement agreement worked out by all parties relating to its rate case that will allow the Company to collect an additional $7 million in revenues less $800,000 in Low Income Assistance to be provided by the Company.  The new rates were implemented on January 19, 2007. The WUTC order also requires that prior to final implementation of the Company’s Conservation Alliance Plan (decoupling), the Company must file a full conservation plan that includes an earnings cap that will limit the operation of the decoupling mechanism if the Company is already achieving its newly allowed 8.85% overall rate of return. The Company has formed a Conservation Advisory Group that has assisted the Company with finalizing the conservation plan that will be filed with the Commission on May 7, 2007.   An additional provision of the rate order is a requirement to defer 50% of Gas Management margins earned in Washington for refund to all customers other than Special Contract customers.

The Company’s Oregon Conservation Alliance Program, as approved by the OPUC in 2006, effectively decouples operating margin from the impacts of conservation and weather on gas usage by Oregon residential and commercial customers. This program provides a mechanism where the Company’s earnings reflect full recovery of the Commission-granted level of earnings per customer.  This is done via a deferral mechanism for both conservation and weather.  In simple terms, the Company books the actual earnings and a deferral for both conservation and weather margin variance each month.  The next year, depending on the amount of conservation and level of weather, the Company will adjust its rates either downward or upward to ensure recovery at the allowed level.  The Company agreed to lower its earnings sharing mechanism cap by 125 basis points in exchange for approval of the Conservation Alliance Program. The Company expects to share earnings during this fiscal year due to this lowering of the cap.

In August 2006 the OPUC opened an investigation into the Company’s level of earnings in Oregon operations. OPUC staff and various interested parties agreed to a settlement of the investigation into the Company’s level of earnings in Oregon in conjunction with the settlement of the merger docket with MDU. This settlement is subject to OPUC approval of the settlement of both the merger and the earnings investigation dockets.  If approved, the Company will decrease Oregon rates by $700,000 under the settlement of the earnings investigation docket.

As indicated above, MDU, the Company, OPUC staff and several interested parties have also agreed to a settlement of the merger docket and filed it with the OPUC.  The parties are in the process of developing joint testimony supporting both of the settlements.  It is expected that the joint testimony will be filed for the Commission’s consideration by the third week of May 2007.

MDU, the Company, WUTC staff, Public Counsel and several other interested parties have also agreed in principle to a settlement in the merger docket in the State of Washington.  The parties are in the process of writing a stipulation and developing a narrative statement supporting the settlement.  It is expected that the stipulation and narrative statement will be filed for the Commission’s consideration by the second week of May 2007.

Revenues and margins from the Company’s residential and small commercial customers in Washington are highly weather-sensitive.  Without weather normalization rate making provisions, 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. Peak requirements also drive the need to reinforce our systems (i.e., increase

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capacity).  Our operations group considers innovative approaches such as temporarily utilizing mobile gas supply rather than making large investments in long-term capacity increases which may not be fully utilized.

The Company earns approximately one third of its operating margin from industrial and electric generation customers.  Loss of major industrial customers, or unfavorable conditions affecting an industry segment, would have a detrimental impact on the Company’s earnings.  Many external factors over which the Company has no control can significantly impact the amount of gas consumed by industrial and electric generation customers and, consequently, the margins earned by the Company.  Such factors may include base-load electricity demand, refinery operations and electricity price in a market impacted significantly by hydroelectric generation.  Additional electric generation and industrial customers may be active if there is peaking demand for electricity.  Other external factors that impact different segments of the industrial market include weather, temperature, seasonality of processes, energy commodity pricing, price of natural gas supplies, profitability of industrial segments and regional economic conditions.

In November 2005, our customer service call center organization voted to accept union representation.  The Company is in the process of negotiating an agreement that will support our efforts to cost-effectively provide superior customer service.  The outcome of negotiations is uncertain.

We carefully analyze the economics of our capital spending to support growth.  When justified under our tariffs, we work with developers, business owners and residents to share certain construction costs that will assure a fair return to the Company.  Where possible, we work with developers and customers to utilize shared trenches, significantly reducing the cost of main extensions and service connections.  Non-revenue-generating spending is also managed to assure that we use the most economically attractive solutions while providing for a safe and reliable gas distribution system.  We also maintain flexibility through variable overtime and the use of outside contractors to adjust our capital construction levels to each period’s requirements.

Management continuously seeks improvement opportunities in all areas.  Our discussion above covering regulatory change, labor relations, operating practices, our organization and our investment to maintain and expand our gas delivery system are examples. Concurrent with supporting the required activities to complete the proposed merger, management will continue these efforts to maintain and continuously improve Cascade’s operational performance within the terms of the merger agreement.

RESULTS OF OPERATIONS

The Company’s net income was $10,367,000, or $0.90 per share, basic and diluted, for the fiscal 2007 second quarter (quarter ended March 31, 2007), compared to a net income of $8,986,000, or $0.78 per share, basic and diluted, for the quarter ended March 31, 2006. For the six-month period, net income was $17,156,000, or $1.49 per share, compared to $17,026,000, or $1.49 per share for the six months ended March 31, 2006. The primary factor affecting the quarterly comparison was a $2.6 million increase in operating margins, partially offset by higher uncollectible accounts expense and other costs of operations. For the six-month period, the improved margins were largely offset by higher costs of operations, including $1.6 million in costs related to the Company’s pending merger. Significant factors are summarized below:

 

These above items are discussed in more detail in the paragraphs that follow.

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Operating Margin

Operating margins by customer category for the second quarter and year-to-date periods are set forth in the following tables:

Residential and Commercial Margin
		Quarter Ended Mar 31						Percent		Year-to-Date Mar 31						Percent
		2007			2006			Change		2007			2006			Change
		(dollars in thousands)								(dollars in thousands)
Degree Days
Actual		2,346			2,269			3.4	%	4,481			4,520			-0.9	%
5-Year Average		2,275			2,299			4,391		4,406
Average Number of Customers Billed
Residential		213,624			205,537			3.9	%	211,699			203,371			4.1	%
Commercial		31,538			31,150			1.2	%	31,281			30,867			1.3	%
Average Therm Usage per Customer
Residential		286			268			6.7	%	547			542			0.9	%
Commercial		1,470			1,354			8.6	%	2,725			2,680			1.7	%
Operating Margin
Residential		$	18,676		$	16,043		16.4	%	$	34,919		$	31,512		10.8	%
Commercial		$	10,315		$	8,602		19.9	%	$	18,436		$	16,490		11.8	%

 

Quarter-to-Quarter

Residential and commercial margins increased by $4.3 million for the quarter. Of this improvement, approximately $2.0 million resulted from the increase in Washington rates effective January 19, following the settlement of the rate case previously filed in Washington. $1.1 million of the improvement resulted from a 6.6% increase in average gas usage per customer. Weather in the quarter was 3.4% colder than last year, pushing up the per-customer gas usage. An additional $930,000 was provided by a 3.6% increase in the number of customers.

The primary use of gas by residential customers is for space and water heating; therefore, average consumption per customer is very sensitive to weather, particularly during the Company’s first and second fiscal quarters.  Consumption by commercial customers is also sensitive to weather.  The sensitivity is more difficult to isolate and measure than for residential customers because of a variety of uses in addition to space and water heating.

Year-to-Date

For the six months, residential and commercial margins increased $5.4 million over last year. In addition to the $2.0 million increased margin from higher rates in Washington, the 3.6% increase in the number of billed customers produced $1.9 million of increased margin. Small increases in average gas usage per customer added $764,000 of margin. Gas cost savings related to Oregon regulatory incentives provided most of the remaining improvement in margin from residential and commercial customers.

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Industrial and Other Margin
		Quarter Ended Mar 31						Percent		Year-to-Date Mar 31						Percent
		2007			2006			Change		2007			2006			Change
		(dollars in thousands)								(dollars in thousands)
Average Number of Customers
Electric Generation		11			11			0.0	%	10			12			-16.7	%
Industrial		680			696			-2.3	%	684			699			-2.1	%
		691			707			-2.3	%	694			711			-2.4	%
Therms Delivered (thousands)
Electric Generation		97,905			98,118			-0.2	%	221,166			219,308			0.8	%
Industrial		112,990			113,756			-0.7	%	231,361			222,962			3.8	%
		210,895			211,874			-0.5	%	452,527			442,270			2.3	%
Operating Margin
Electric Generation		$	1,916		$	2,771		-30.9	%	$	4,206		$	5,038		-16.5	%
Industrial		4,616			5,048			-8.6	%	9,686			10,182			-4.9	%
Gas Management Services		260			625			-58.4	%	851			963			-11.6	%
Mark-to-Market Valuations		—			—			N/A		—			(579		)	-100.0	%
Other		161			142			13.4	%	317			416			-23.8	%
Oregon Earnings Sharing		(95		)	—			N/A		(285		)	—			N/A
		$	6,858		$	8,586		-20.1	%	$	14,775		$	16,020		-7.8	%

 

Quarter-to-Quarter

The reduction in margins from electric generation customers is related to $900,000 collected last year in settlement of a terminated customer contract. The reduction in margins from industrial customers is related to lower rates. The settlement of the Company’s Washington rate case included a reduction in rates for non-core customers, partially offsetting the increases in core residential and commercial rates.

Year-to-Date

The same factors that affected the quarterly comparisons also cause the year-to-date comparisons for margins from electric generation and industrial customers. Additionally, the first quarter of fiscal 2006 included a $579,000 charge for mark-to-market valuations. Subsequent mark-to-market valuations have been recorded in Other Comprehensive Income and have not affected operating margins or earnings.

Cost of Operations

Quarter-to-Quarter

Second quarter Cost of Operations (operating expense, depreciation and amortization, and property and miscellaneous taxes) increased by $1.2 million compared to the same quarter in fiscal year 2006.  Most of the increase was in uncollectible accounts expense, which increased $936,000. During the first winter of consolidated call center operations (2005/2006), the Company utilized all call center personnel to handle high incoming call volume and therefore had limited call center collection efforts. This, combined with higher customer bills contributed to the increase. Since this time, the Company has established a dedicated call center collections group as well as hired an outside vendor to make collections calls.  In addition, the quarter includes $394,000 costs of funding public purpose and low-income programs, as required under the Oregon decoupling mechanism and the Washington rate case settlement. These increases were partially offset by a reduction in Employee Benefits of $586,000 based on an increase in the market value of pension plan assets and a 2006 pension plan amendment affecting bargaining-unit employees, as well as lower medical and dental expenses.

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Year-to-Date

Year-to-date Cost of Operations increased $3.4 million. The increase included $1.5 million of merger-related costs and $793,000 of charges relating to first quarter organizational changes. For the six months, uncollectible accounts increased $876,000. Public purpose and low-income funding accounted for $591,000 of the increase. These increases were partly offset by $955,000 reduction in employee benefits expenses.

Income Taxes

The change in the provision for income taxes from 2006 to 2007 is attributable to the changes in pre-tax earnings, as well as an increase in the effective tax rate. In the second quarter, the Company increased its estimate of the amount of costs incurred in connection with its pending merger that can be deducted on its income tax returns. Certain of those costs are not deductible on the Company’s tax return, and are permanent differences between book and tax income. As a result of the revised estimate of deductibility, the Company’s provision for income taxes was reduced approximately $500,000 in the second quarter.

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. The credit available under this credit line is reduced by an outstanding $1.9 million letter of credit issued to one of the Company’s suppliers to meet their credit requirements. The company also has a $20,000,000 uncommitted line of credit. As of March 31, 2007, there were no outstanding borrowings under these credit lines.

Due to the nature of Cascade’s business, which is characterized by reliable payments from a stable customer base and our expectations that capital spending will be primarily funded from internal sources, we expect to have limited need to source additional capital during fiscal 2007.  For this reason, combined with 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.

Operating Activities

Though year-to-date net income was comparable to last year, cash provided by operating activities improved $9.5 million over last year. The primary factor was a $17.0 million change in deferred gas costs, a $7.0 million improvement over the $10.0 million for the same period last year. The Company has been able to purchase gas at a lower cost than the current benchmark established in its latest PGA filings with the WUTC. We expect this advantage to diminish later this year as long-term hedges entered into in prior years expire. These hedges had the effect of fixing the cost of a portion of our gas supplies at a lower rate than in subsequent periods, and as they expire, the result is that our weighted average cost of gas purchased is likely to increase. In addition, approximately $4.8 million of this year’s gas cost related cash flow is from normal seasonality, and is expected to reverse later in the year.

Investing Activities

Year-to-date cash used by investing activities is up $675,000 from last year. The increase in capital spending is primarily a result of increased spending related to system expansion and reinforcement. Our current expectation is that we will end the year within our capital budget of $24.3 million.

Financing Activities

Other than the payment of dividends, the Company’s primary financing activities year-to-date were the $8.0 million repayment of 8.50% Medium-Term Notes that matured in October 2006, and the refinancing of the Company’s callable 7.50% Notes Due November 2031, replacing this debt with $40 million 5.79% notes due March 2037. The $8.0 million repayment was funded by cash flow from operating activities generated in 2006.

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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.  The Company’s critical accounting policies were described in its Annual Report on Form 10-K for the year ended September 30, 2006, under Part II, Item 7, and have not changed significantly since that report.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

The Company 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 currently 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 may redeem these obligations prior to normal maturities if warranted by market conditions.

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. The fair value of these derivatives as of March 31, 2007 is a net liability of $864,000. We monitor the liquidity of our financial derivative contracts.  Based on the existing open interest in the contracts held, we believe existing contracts to be liquid. All of our financial derivative contracts settle within the next four years, with the following estimated future cash receipts (payments): $501,000 by March 31, 2008, ($727,000) by March 31, 2009, and ($638,000) by March 31, 2010. These amounts will change based on market prices at the time contract settlements are fixed.

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 or in Other Comprehensive Income.

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 Accounting Officer of the Company concluded that the Company’s disclosure controls and procedures were effective. There were no changes in internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to affect, the Company’s internal controls over financial reporting.

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

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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”, “intend”, “plan”, “may”, 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:

·                  factors affecting regulatory approvals of the Company’s proposed merger with MDU

·                  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;

·                  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;

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·                  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.

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. You are also advised to consult the other reports we file with the Securities and Exchange Commission as well as the disclosure under “Risk Factors” in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the Year Ended September 30, 2006.

PART II.  Other Information

Item 1. Legal Proceedings

On January 12, 2007, the Company received an order from the WUTC resolving the parties’ motions for summary determination in the complaint proceeding commenced on July 31, 2006 by Cost Management Services, Inc. (CMS) relating to the Company’s gas management services, Docket No. UG-061256.  The WUTC ’ s order allows the Company to continue to make gas supply sales to non-core customers even though the Company will be required to file with the Commission its tariffs and contracts for these sales.  The Order also instructed Commission staff to investigate the Company’s current contracts to ensure that the Company is in compliance with state laws and regulations governing special contracts.  The Order reserved for hearing the issue of whether the Company’s contracts provided an undue preference or advantage after finding that the facts presented were not sufficient to grant summary determination.

The parties have filed a series of motions for clarification of the order and answering briefs and the parties are currently awaiting an official response from the Commission.

Item 6.  Exhibits

		No.		Description
		12		Computation of Ratio of Earnings to Fixed Charges
		31.1		Certification of Principal Executive Officer Accompanying Periodic Report Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
		31.2		Certification of Principal Financial Officer 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

 

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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/ James E. Haug
		James E. Haug
		Chief Accounting Officer
		(Principal Financial Officer)
Date:		May 8, 2007

 

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