FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2006

Commission file number: 1-7196

CASCADE NATURAL GAS CORPORATION
(Exact name of Registrant as specified in its charter)

(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  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.

Title		Outstanding
Common Stock, Par Value $1 per Share		11,505,996 as of July 31, 2006

 

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						NINE MONTHS ENDED
			Jun 30, 2006			Jun 30, 2005			Jun 30, 2006			Jun 30, 2005
			(thousands except per-share data)
Operating revenues			$	76,400		$	56,315		$	397,828		$	278,638
Less:       Gas purchases			52,488			34,646			288,562			182,098
	Revenue taxes		5,514			3,995			26,845			19,103
Operating margin			18,398			17,674			82,421			77,437
Cost of operations:
Operating expenses			11,378			10,977			31,776			32,418
Depreciation and amortization			4,489			4,326			13,338			12,811
Property and miscellaneous taxes			1,003			1,109			2,859			3,011
			16,870			16,412			47,973			48,240
Income from operations			1,528			1,262			34,448			29,197
Less interest and other deductions - net			2,142			2,891			7,997			8,761
Income (loss) before income taxes			(614		)	(1,629		)	26,451			20,436
Income tax (benefit)			(87		)	(502		)	9,951			7,579
Net Income (Loss)			(527		)	(1,127		)	16,500			12,857
Other Comprehensive Income (Loss)
Unrealized losses on derivative commodity instruments			(2		)	—			(987		)	—
Income tax benefit			18			—			370			—
Other Comprehensive Income (Loss)			16			—			(617		)	—
Comprehensive Income (Loss)			$	(511	)	$	(1,127	)	$	15,883		$	12,857
Weighted average common shares outstanding			11,487			11,367			11,456			11,319
Earnings (loss) per common share, basic and diluted			$	(0.05	)	$	(0.10	)	$	1.44		$	1.14
Cash dividends per share			$	0.24		$	0.24		$	0.72		$	0.72

 

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

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CASCADE NATURAL GAS CORPORATION

CONSOLIDATED CONDENSED BALANCE SHEETS

(Unaudited)

		Jun 30, 2006			Sep 30, 2005
		(dollars in thousands)
ASSETS
Utility Plant, net of accumulated depreciation of $269,579 and $257,008		$	340,966		$	340,461
Construction work in progress		960			2,021
		341,926			342,482
Other Assets:
Investments in non-utility property		202			202
Notes receivable, less current maturities		2			46
		204			248
Current Assets:
Cash and cash equivalents		22,364			1,128
Accounts receivable and current maturities of notes receivable, less allowance of $1,691 and $1,319 for doubtful accounts		26,298			23,163
Prepaid expenses and other assets		7,606			9,463
Derivative instrument assets - energy commodity		13,171			91,957
Materials, supplies and inventories		8,638			14,142
Deferred income taxes		2,271			2,292
		80,348			142,145
Deferred Charges and Other
Gas cost changes		527			16,630
Derivative instrument assets - energy commodity		9,698			43,440
Other		9,240			7,960
		19,465			68,030
		$	441,943		$	552,905

 

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		Jun 30, 2006			Sep 30, 2005
		(dollars in thousands)
COMMON SHAREHOLDERS’ EQUITY AND LIABILITIES
Common Shareholders’ Equity:
Common stock, par value $1 per share, authorized 15,000,000 shares, issued and outstanding 11,498,523 and 11,413,019 shares		$	11,499		$	11,413
Additional paid-in capital		105,540			103,781
Accumulated other comprehensive loss		(13,103		)	(12,487		)
Retained earnings		24,145			15,908
		128,081			118,615
Long-term Debt		165,333			173,840
Current Liabilities:
Short-term debt		—			12,500
Current maturities of long-term debt		8,000			—
Accounts payable		15,178			17,841
Property, payroll and excise taxes		5,243			5,520
Dividends and interest payable		5,421			6,920
Regulatory liabilities		13,171			91,217
Other current liabilities		19,961			8,209
		66,974			142,207
Deferred Credits and Other Non-current Liabilities:
Deferred income taxes and investment tax credits		40,675			43,429
Retirement plan obligations		15,909			19,042
Regulatory liabilities		17,250			50,584
Other		7,721			5,188
		81,555			118,243
Commitments and Contingencies		—			—
		$	441,943		$	552,905

 

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)

		NINE MONTHS ENDED
		(dollars in thousands)
		Jun 30, 2006			Jun 30, 2005
Operating Activities:
Net income		$	16,500		$	12,857
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		13,338			12,811
Deferrals of gas cost changes		6,388			(5,445		)
Amortization of gas cost changes		9,715			4,561
Other deferrals and amortizations		(2,577		)	(1,581		)
Deferred income taxes and tax credits - net		(2,733		)	2,728
Change in current assets and liabilities		12,524			(524		)
Net cash provided by operating activities		53,155			25,407
Investing Activities:
Capital expenditures		(15,457		)	(22,417		)
Customer contributions in aid of construction		2,974			850
Net cash used by investing activities		(12,483		)	(21,567		)
Financing Activities:
Proceeds from issuance of long-term debt, net		—			28,121
Proceeds from issuance of common stock		1,845			1,937
Repayment of long-term debt		(507		)	(9,000		)
Changes in short-term debt, net		(12,500		)	(16,500		)
Dividends paid		(8,262		)	(8,169		)
Other		(12		)	—
Net cash used by financing activities		(19,436		)	(3,611		)
Net Increase in Cash and Cash Equivalents		21,236			229
Cash and Cash Equivalent:
Beginning of year		1,128			499
End of period		$	22,364		$	728

 

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

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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
THREE-AND NINE-MONTH PERIODS ENDED JUNE 30

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 2005 Annual Report on Form 10-K for the fiscal year ended September 30, 2005.

Note 1.  New Accounting Standards

FAS No. 151:  As of October 1, 2005, the Company adopted Statement of Financial Accounting Standards (FAS) No. 151, “Inventory Costs”.  This standard is an amendment of Accounting Research Bulletin (ARB) No. 43, clarifying the requirement that abnormal amounts of idle facility expense, freight, handling costs, and spoilage be recognized as current period costs.  Adoption of this standard did not have a significant impact on the Company’s financial statements.

FAS No. 123 (revised 2004):  As of October 1, 2005, the Company adopted FAS No. 123 (revised 2004), “Share-Based Payment” {FAS No. 123(R)}. This statement is a revision of FAS No. 123, “Accounting for Stock-Based Compensation”, and supersedes Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees”.  Under FAS No. 123(R) the Company is required to recognize as expense the fair value of equity instruments, including stock options, to be issued in exchange for goods or services.  Adoption of this standard did not have a significant impact on the Company’s financial statements, but additional footnote disclosure is required and is included in Note 4 below.

Note 2.  Earnings Per Share

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

		Three Months Ended						Nine Months Ended
		Jun 30, 2006			Jun 30, 2005			Jun 30, 2006			Jun 30, 2005
		(in thousands except per-share data)
Net income (loss)		$	(527	)	$	(1,127	)	$	16,500		$	12,857
Weighted average shares outstanding		11,487			11,367			11,456			11,319
Basic earnings (loss) per share		$	(0.05	)	$	(0.10	)	$	1.44		$	1.14
Weighted average shares outstanding		11,487			11,367			11,456			11,319
Plus: Issued on assumed exercise of stock options		—			2			—			3
Weighted average shares outstanding assuming dilution		11,487			11,369			11,456			11,322
Diluted earnings (loss) per share		$	(0.05	)	$	(0.10	)	$	1.44		$	1.14

 

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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						Nine Months Ended
		Jun 30 2006			Jun 30 2005			Jun 30 2006			Jun 30 2005
		(Dollars in Thousands)
DEFINED BENEFIT PENSION PLANS
Service cost		$	216		$	197		$	649		$	591
Interest cost		965			961			2,895			2,882
Expected return on plan assets		(1,101		)	(1,041		)	(3,304		)	(3,122		)
Recognized gains or losses		421			386			1,264			1,158
Prior service cost		38			46			114			137
Net Periodic Benefit Cost Recognized		$	539		$	549		$	1,618		$	1,646
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Service cost		$	28		$	35		$	85		$	105
Interest cost		164			275			493			826
Expected return on plan assets		(219		)	(211		)	(658		)	(634		)
Recognized gains or losses		181			187			543			560
Prior service cost		(615		)	(330		)	(1,847		)	(990		)
Net Periodic Benefit Cost Recognized		$	(461	)	$	(44	)	$	(1,384	)	$	(133	)
DEFINED CONTRIBUTION PENSION PLAN
Net Periodic Benefit Cost Recognized		$	213		$	229		$	621		$	721

 

Retirement Plan Funding

For the three months ended June 30, 2006, $2,050,000 of contributions were made to the Company’s defined benefit pension plans, and the nine-month total is $3,310,000.  The Company presently anticipates contributing an additional $630,000 to fund its pension plans for a total of $3,940,000 in fiscal 2006.

Note 4.  Share-Based Payment

In the first quarter of fiscal 2006, the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), (FAS 123(R)), Share-Based Payment.  See Note 1 above. Following are disclosures under FAS 123(R) for share-based payment arrangements that were in effect during the three- and nine-month periods ended June 30, 2006 and 2005.

Under the Company’s 2000 Director Stock Award Plan, each non-employee director is awarded 1,000 shares of the Company’s common stock annually following shareholder approval at the February 2006 annual meeting.  During the quarters ended June 30, 2006 and June 30, 2005, the Company recognized $42,000 and $0 as expense under this plan. For the respective nine-month periods, the Company recognized $161,000 and $37,000.  The value of the stock granted under this plan is based on the market value on the date of the award.

Under the Company’s 1998 Stock Incentive Plan, 33,000 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

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during the vesting periods, the Company applied the intrinsic value method under Accounting Principles Board (APB) Opinion 25, and no expense has been recognized.

The Company’s employment contracts with its Chief Executive Officer (CEO) and its Chief Financial Officer (CFO) contain 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 are restricted until he completes two years of employment. Under the CFO grant, 5,000 shares were restricted until he completed one year of employment.  During this period, each executive is restricted from selling his shares. The value of the shares granted was based on the market value as of the grant date. During the quarter ended June 30, 2006, the Company recognized $38,000 as compensation expense under this plan. For the nine-month period, the Company recognized $162,000. In fiscal 2005, $135,000 was recognized in the third quarter.

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 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 recently 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

On July 31, 2006, a complaint was filed with the Washington Utilities and Transportation Commission (WUTC) by Cost Management Services, Inc., against the Company. The complaint contends the Company’s sales to customers under its gas management program are not allowed. The complainant is in the gas management business and is a competitor of the Company for this business with the same customers. The complaint requests that the Company be directed to cease and desist from making such sales. It further requests the WUTC determine whether the Company’s contracts with its gas management customers are void or voidable under Washington statutes and to provide other relief or penalties as the WUTC may consider appropriate under the circumstances. The Company is currently assessing how to respond to the complaint, but believes that its gas management business is in compliance with applicable laws.

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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- and nine-month periods ended June 30, 2006 and 2005.

OVERVIEW

The Company is a local distribution company (LDC) serving approximately 237,000 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 reported in the Company’s Current Report on Form 8-K filed July 10, 2006, the Company has entered into a definitive merger agreement with MDU Resources Group, Inc.  Under terms of the agreement, MDU Resources will acquire the Company for $26.50 per share in cash.  The completion of the acquisition is subject to the approval of the Company’s shareholders and various regulatory authorities.  The required approvals are anticipated to be obtained by mid-year 2007.

Until the completion of the proposed merger, the Company continues to operate, focusing on the same initiatives and targets as before the merger agreement, subject to limitations set forth in the merger agreement.

Key elements of the Company’s operating strategy:

·                  Remain focused on the natural gas distribution business.

·                  Pursue appropriate regulatory treatment, including initiatives to decouple the Company’s earnings from weather fluctuations and changing customer consumption patterns.

·                  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 to acquire the customers.

·                  Continue to focus on operational efficiencies.

·                  Generate earnings and manage cash flow to maintain and strengthen the Company’s ability to attract the funding needed to reliably serve new and existing customers.

Opportunities and Challenges

The Company operates in a diverse service territory over a wide geographic area relative to the Company’s overall size and number of customers.  The economies of various parts of the service area are supported by a variety of industries and are affected by the conditions that impact those industries.  Management believes there are growth opportunities in the Company’s service area, 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 many of the communities served.

Overall revenues and margins are negatively impacted by higher efficiency in new home and commercial building construction, higher efficiency in gas-burning equipment, and customers taking additional measures to reduce energy usage.  The increasing cost of energy in recent years, including the wholesale

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cost of natural gas, continues to encourage such measures.  However, the Company continues to believe 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. This traditional rate design creates a financial disincentive for utilities to promote conservation.  The Company has filed a rate case in the State of Washington along with a request to decouple the margin recovery from volume. The Company continues to work with the regulatory staff and other stakeholders in this case to develop an acceptable decoupling mechanism that will enable the Company to promote conservation while still recovering its operating costs and earning a fair return on its invested capital.  Similar approaches have been implemented in many states, including Oregon (see below), and are endorsed by a variety of organizations, including the recent endorsement by the National Association of Regulatory Utility Commissions.  The results of such rate requests and other initiatives for regulatory relief are subject to significant uncertainties.

In April 2006, the OPUC approved the Company’s request to implement its Conservation Alliance Program, which effectively decouples operating margin from the impacts of conservation and weather on gas usage by residential and commercial customers in its Oregon service area.  The filing provides a mechanism where the Company will adjust its earnings recovery to fully recover 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 will book the actual earnings and a deferral for both conservation and normal weather each month.  The next year, depending on the amount of conservation and level of weather, the Company will adjust its rate either downward or upward to ensure recovery at the allowed level.  The Company agreed to lower its 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.

Revenues and margins from the Company’s residential and small commercial customers in Washington are highly weather-sensitive.  In a cold year, the Company’s earnings are boosted by the effects of the weather, and conversely in a warm year, the Company’s earnings suffer.  Peak requirements also drive the need to reinforce our systems (i.e., increase 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.

Prospects for continuing strong residential and commercial customer growth are excellent.  The pace of new home and commercial construction remains steady in communities served by the Company.  Good potential also exists for converting homes and businesses located on or near the Company’s current lines to gas from other fuels, as well as for expanding the system into adjacent areas.  Customer count growth in this sector has been more than double the average of U.S. gas utilities.

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 attempting to negotiate an agreement that will support our efforts to cost-effectively provide superior customer service.  The timing and results of negotiations are uncertain.

We carefully analyze the economics of our spending to support growth.  When justified under our tariffs, we work with developers, business owners and residents to share certain construction costs to assure a fair return to the Company.  Non-revenue-generating spending is also managed to assure that we use the most

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economically attractive solutions while providing for a safe and reliable system.  Where possible, we work with developers and customers to utilize shared trenches, significantly reducing the cost of main extensions and service connections.  We also maintain the flexibility through variable overtime and the use of outside contractors to adjust our capital construction levels to each period’s requirements. These changes, combined with a reduction in non-revenue-generating initiatives as compared to a year ago, are expected to result in a significant reduction in capital spending during the current fiscal year.

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 subject to limitations set forth in the merger agreement.

RESULTS OF OPERATIONS

The Company’s net loss was $527,000, or $0.05 per share, basic and diluted, for the fiscal 2006 third quarter (quarter ended June 30, 2006), compared to a net loss of $1,127,000, or $0.10 per share, basic and diluted, for the quarter ended June 30, 2005. Year-to-date net income was $16,500,000, or $1.44 per share, basic and diluted, compared to $12,857,000, or $1.14 per share, basic and diluted, for the same period last year.  The largest factors influencing the quarterly comparisons were:

 

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

Operating Margin

Operating margins by customer category for the third quarter and year-to-date for fiscal years 2006 and 2005 are set forth in the following tables:

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Residential and Commercial Margin

		Quarter Ended Jun 30						Percent		Year-to-Date						Percent
		2006			2005			Change		2006			2005			Change
		(dollars in thousands)
Degree Days
Actual		900			769			17.0	%	5,419			4,944			9.6	%
5-Year Average		925			806					5,330			5,168
Average Number of Customers Billed
Residential		204,771			195,561			4.7	%	203,838			194,252			4.9	%
Commercial		30,964			30,256			2.3	%	30,899			30,191			2.3	%
Average Therm Usage per Customer
Residential		107			111			-3.6	%	649			628			3.3	%
Commercial		592			590			0.3	%	3,270			3,079			6.2	%
Operating Margin
Residential		$	8,314		$	7,623		9.1	%	$	39,826		$	36,079		10.4	%
Commercial		$	4,341		$	4,015		8.1	%	$	20,831		$	19,200		8.5	%

 

Quarter-to-Quarter

Residential and commercial margins increased by $1.0 million for the quarter. Customer growth at 4.4% contributed $529,000 million to margins while lower average consumption reduced margins $208,000.  Miscellaneous services and other revenues added $359,000. Also contributing to the favorable comparison was the impact of changes to the Company’s Oregon purchased gas adjustment filing (PGA) last fall. This change has the effect of reallocating the recognition of certain demand charge recoveries within each fiscal year. For the third quarter, this change increased the reported margin by $409,000 when compared to the same quarter in fiscal 2005, but it is not expected to impact the full year earnings comparison.

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

Residential and commercial margins increased by $5.4 million for the year-to-date period.  Primary contributors were customer growth adding $2.7 million and higher consumption per customer adding another $1.9 million.  Average consumption was 3.8% higher for the period primarily due to colder weather than last year.  Reductions in incurred Oregon Gas cost and increased miscellaneous services revenue contributed $1.6 million to the improvement.  Partially offsetting these items was an $824,000 reduction resulting from the Oregon PGA changes.

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Industrial and Other Margin

		Quarter Ended Jun 30						Percent		Year-to-Date						Percent
		2006			2005			Change		2006			2005			Change
		(dollars in thousands)
Average Number of Customers
Electric Generation		11			13			-15.4	%	11			13			-15.4	%
Industrial		690			705			-2.1	%	696			722			-3.6	%
		701			718			-2.4	%	707			735			-3.8	%
Therms Delivered (thousands)
Electric Generation		33,877			83,392			-59.4	%	253,185			314,734			-19.6	%
Industrial		96,090			92,786			3.6	%	319,052			318,112			0.3	%
		129,967			176,178			-26.2	%	572,237			632,846			-9.6	%
Operating Margin ($ thousands)
Electric Generation		$	1,500		$	1,591		-5.7	%	$	6,538		$	5,625		16.2	%
Industrial		4,340			4,198			3.4	%	14,521			14,688			-1.1	%
Gas Management Services		273			39			600.0	%	1,236			753			64.1	%
Mark-to-Market Valuations		—			(232		)	-100.0	%	(579		)	(351		)	65.0	%
Other		115			440			-73.9	%	533			918			-41.9	%
Oregon Earnings Sharing		(485		)	—			N/A		(485		)	525			-192.4	%
		$	5,743		$	6,036		-4.9	%	$	21,764		$	22,158		-1.8	%

 

Quarter-to-Quarter

Margins from sales to industrial customers and electric generation plants were relatively flat compared to last year. The primary driver over the rest of the fiscal year for changes in gas usage by generation customers will be power demands in the Southwest United States due to air-conditioner usage.

No Mark-to-Market adjustment was recorded in the third quarter of fiscal 2006 as compared to a negative adjustment of $232,000 in the same period in the prior year.

In an April agreement with the OPUC in connection with the Company’s filing for a decoupling mechanism, the Company agreed to lower its threshold for earnings sharing with its Oregon customers. As a result, in the third quarter $485,000 was recorded as an estimate of fiscal 2006 earnings to be shared with Oregon customers.

Year-to-Date

Margins from sales to electric generation plants were $913,000 million higher year-to-date as the result of settlements for early termination of sales agreements with two customers. The comparison of the Oregon earnings sharing amounts was affected by the $485,000 recorded in the third quarter of 2006 and the 2005 reversal of a $525,000 estimate recorded in 2004. In 2005 it was determined that no sharing of 2004 earnings would be required.

Cost of Operations

Quarter-to-Quarter

Cost of operations (operating expense, depreciation and amortization, and property and miscellaneous taxes) increased by $458,000 compared to the third quarter of fiscal year 2005. Primary contributors to the higher cost included $317,000 in increased bad debt expense reflecting increased residential and commercial accounts receivable delinquencies partially stemming from higher natural gas prices, reduced capitalization of operating costs of $261,000 due to lower capital expenditures, and $226,000 increase in compensation costs.

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Year-to-Date

Year-to-date cost of operations was down $268,000 reflecting $808,000 in compensation cost reductions and savings of $991,000 in various corporate and administrative areas. These savings were mostly offset by reductions in capitalized operating costs of $1.0 million and $527,000 in increased depreciation. Affecting the year-to-year comparison in compensation costs were $1.1 million in executive transition costs incurred in 2005.

Interest and Other Deductions – Net

Improvements stemmed primarily from $ 716,000 interest received on a refund of income taxes related to amended prior year federal income tax returns.

LIQUIDITY AND CAPITAL RESOURCES

The seasonal nature of the Company’s business creates short-term cash requirements to finance customer receivables, deferred gas costs and other business needs. To provide working capital for these requirements, the Company has a $60 million bank revolving credit commitment.  This agreement has a variable commitment fee and a term that expires in October 2007.  The Company also has a $10 million uncommitted line of credit.  As of June 30, 2006, there was no outstanding debt under these credit lines. The Company anticipates that use of these short-term facilities will be limited in the near future.

Due to the nature of the Company’s business, which is characterized by predictable payments from a growing customer base, and our expectations that capital spending will be reduced from the last few years, we expect to have limited need for additional capital during fiscal year 2006.  For this reason, management believes it has adequate liquidity to meet our anticipated needs and estimates that cash flow will be sufficient to support operations, fund capital spending, and pay dividends at their current level.

Operating Activities

For the nine-month period, cash provided by operating activities improved $27.7 million over last year.  In addition to improved net income, the primary factor was the net reduction in deferred gas cost funded by the Company, contributing to $17.0 million of the improvement.  Additionally, changes in current assets and liabilities contributed $13.0 million improvements, of which the largest item was the receipt of an income tax refund of $7.2 million.

Investing Activities

Year-to-date cash used by investing activities is down $9.1 million from $21.6 million when compared to fiscal year 2005.  Part of the difference was due to $2.2 million of one-time specific system reinforcement expenditures and $1.0 million relating to the completed AMR and call center centralization projects in the first three quarters of fiscal year 2005. The remainder reflects the Company’s new investment evaluation process implemented in the first quarter to assure that all capital spending provides an adequate return or is required for safety or regulatory compliance.  Our current expectation is that we will end the year below our fiscal 2006 capital budget of $22.0 million.

Financing Activities

Other than the payment of dividends, the Company’s primary financing activity year-to-date in fiscal 2006 was the $12.5 million net reduction in short-term debt. This reduction in debt was facilitated by favorable operating cash flow and reduced capital spending.

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

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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, 2005, 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.  The Company makes interest and principal payments on these obligations in the normal course of its business and may redeem its debt 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 generally result in the recovery in customer rates of prudently incurred wholesale cost of natural gas purchased for the core market.  The Company primarily utilizes financial derivatives, and to a lesser extent, fixed price physical supply contracts to manage risk associated with wholesale costs of natural gas purchased for customers.

With respect to derivative arrangements covering natural gas supplies for core customers, periodic changes in fair market value are recorded in regulatory asset or regulatory liability accounts, pursuant to authority granted by the WUTC and OPUC, recognizing that settlements of these arrangements will be recovered through the PGA mechanism.

For derivative arrangements related to supplies for non-core customers, which are not covered by a PGA mechanism, periodic changes in fair market value are recognized in earnings 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 Financial 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 statements concerning plans, objectives, goals, strategies, and future events or performance.  When used in Company documents or oral presentations, the words “anticipate”, “believe”, “estimate”, “expect”, “objective”, “projection”, “forecast”, “goal”, or similar words are intended to identify forward-looking statements.

These forward-looking statements reflect the Company’s current expectations, beliefs and projections about future events that we believe may affect the Company’s business, financial condition and results of operations, and are expressed in good faith and are believed to have a reasonable basis.  However, each such forward-looking statement involves risks, uncertainties and assumptions, and is qualified in its entirety

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by reference to the following important factors, among others, that could cause the Company’s actual results to differ materially from those projected in such forward-looking statements:

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

·                  weather conditions and other natural phenomena;

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

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

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

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

·                  the potential loss of large volume industrial customers due to “bypass” or the shift by such customers to special competitive contracts at lower per-unit margins;

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

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

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

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

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

·                  unanticipated changes in operating expenses and capital expenditures;

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

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

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

·                  legal and administrative proceedings and settlements.

In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this report, or in any information incorporated herein by reference, may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.  All

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subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, also are expressly qualified by these cautionary statements.

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

PART II.  Other Information

Item 1. Legal Proceedings

On July 31, 2006, a complaint was filed with the Washington Utilities and Transportation Commission (WUTC) by Cost Management Services, Inc., against the Company. The complaint contends the Company’s sales to customers under its gas management program are not allowed. The complainant is in the gas management business and is a competitor of the Company for this business with the same customers. The complaint requests that the Company be directed to cease and desist from making such sales. It further requests the WUTC determine whether the Company’s contracts with its gas management customers are void or voidable under Washington statutes and to provide other relief or penalties as the WUTC may consider appropriate under the circumstances. The Company is currently assessing how to respond to the complaint, but believes that its gas management business is in compliance with applicable laws.

Item 6.  Exhibits

 

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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/ Rick A. Davis
	Rick A. Davis
	Chief Financial Officer
	(Principal Financial Officer)
Date:	August 7, 2006

 

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