QuickLinks -- Click here to rapidly navigate through this document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended September 30, 2002

Commission file number 1-7196

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

Washington
(State or other jurisdiction of incorporation or organization)		   91-0599090
(IRS Employer Identification No.)

222 Fairview Avenue North
Seattle, WA 98109
(Address of principal executive offices)
 
(206) 624-3900
(Registrant's telephone number,
including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class
Common Stock, Par Value $1 per Share
Preferred Stock Purchase Rights
 
Name of Each Exchange on which Registered
New York Stock Exchange
New York Stock Exchange

        Securities registered pursuant to section 12(g) of the Act: None

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes ý No o

        Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý

        The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of the close of business on November 15, 2002, was $212,427,000.

        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   11,045,095 as of December 1, 2002

DOCUMENTS INCORPORATED BY REFERENCE

        Portions of the Registrant's definitive proxy statement for its 2003 Annual Meeting of Shareholders are incorporated by reference into Part III, Items 10, 11, 12, and 13.


CASCADE NATURAL GAS CORPORATION
Annual Report to the Securities and Exchange Commission on Form 10-K
For the Fiscal Year Ended September 30, 2002


Table of Contents

Number
    
    
    
   Page
Part I                
    Item 1   —   Business   3
    Item 2   —   Properties   7
    Item 3   —   Legal Proceedings   7
    Item 4   —   Submission of Matters to a Vote of Security Holders   8
    Executive Officers of the Registrant   8
Part II                
    Item 5   —   Market for Registrant's Common Equity and Related Stockholder Matters   9
    Item 6   —   Selected Financial Data   10
    Item 7   —   Management's Discussion and Analysis of Financial Condition and Results of Operations   12
    Item 7a   —   Quantitative and Qualitative Disclosures about Market Risk   19
    Item 8   —   Financial Statements and Supplementary Data   20
    Item 9   —   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure   41
Part III                
    Item 10   —   Directors and Executive Officers of the Registrant   41
    Item 11   —   Executive Compensation   41
    Item 12   —   Security Ownership of Certain Beneficial Owners and Management   41
    Item 13   —   Certain Relationships and Related Transactions   42
    Item 14   —   Controls and Procedures   42
    Item 15   —   Exhibits, Financial Statement Schedules and Reports on Form 8-K   42
Signatures   43
Certifications   45
Index to Exhibits   47

2


Part I

Item 1. Business

General

        Cascade Natural Gas Corporation (Cascade or the Company) was incorporated under the laws of the state of Washington on January 2, 1953. Its principal business is the distribution of natural gas to customers in the states of Washington and Oregon. Approximately 81% of its gas distribution revenues are from customers in the state of Washington.

        As of September 30, 2002, the Company had approximately 169,500 residential customers, 28,100 commercial customers, and 800 industrial and other customers. Residential, commercial, and most small industrial customers are generally core customers, who take traditional "bundled" natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation. Sales to core customers in fiscal 2002 accounted for approximately 22% of gas deliveries and 71% of operating margin. The Company's sales to its core residential and commercial customers are influenced by fluctuations in temperature, particularly during the winter season. A warm winter season will tend to reduce gas consumption. Over the longer term, these fluctuations tend to offset each other, as rates charged to customers are developed based on the assumption of normal weather.

        Non-core customers are generally large industrial and institutional customers who have chosen "unbundled" service, meaning that they select from among several supply upstream pipeline transportation options, and gas management service independent of the Company's distribution service. The Company's margin from non-core customers is derived primarily from distribution service and to a lesser extent from gas management service revenue. Gas management service revenue primarily includes fees charged to non-core customers in consideration of securing gas supplies and pipeline capacity for the customers.

State Regulation

        The Company's rates and practices are regulated by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC).

        Cascade's gas supply contracts contain pricing provisions for fixed periods of time. To the extent that prices are changed with respect to supplies purchased for core customers, Cascade is able to pass the effect of such changes, subject to regulatory review, to its customers by means of a periodic purchased gas cost adjustment (PGA) in each state. Gas price changes occurring between times when PGA rate changes become effective are deferred for pass through in the next PGA.

        With respect to such gas supplies delivered to Oregon customers, 67% of the incremental change in the actual cost of gas supplies, as compared to the forecasted cost reflected in the PGA, is deferred. The remaining 33% (increase or decrease) is absorbed by the Company. This mechanism is intended to encourage the Company to seek opportunities to lower its cost of supplies and to be innovative in its management of the supply portfolio to avoid price spikes. Cascade's gas supply portfolio for Oregon core customers is comprised mostly of gas supplies that have a fixed commodity price, therefore management believes the risk or opportunity for the Company is not significant under the 67%/33% sharing arrangement during the coming year. For the fiscal year ended September 2002, under this arrangement, Cascade's 33% share of savings achieved totaled $1,072,000.

        Cascade has an earnings sharing mechanism with respect to its Oregon jurisdictional operations. See "Regulatory Matters" under Item 7 for a description of the mechanism.

        The Company is also subject to state regulation with respect to integrated resource planning, and its most recent update of its Integrated Resource Plan (IRP) was filed in 2002 with both the WUTC and the OPUC. The IRP shows the Company's optimum set of supply and demand side resources that

3


minimizes costs and risk over the twenty-year planning horizon. The IRP also sets forth possible core customer growth scenarios for a twenty-year period. In addition, the IRP sets forth the Company's demand side management goals of achieving certain conservation levels in customer usage.

        The IRP also sets forth the Company's supply side management plans regarding transportation capacity and gas supply acquisition over a twenty-year period. The Company develops updates of the IRP every two years. These updated documents take into account input solicited from the public and the WUTC and OPUC staffs. While the filing of the IRP with both commissions gives the Company no advance assurance that its acquisitions of pipeline transportation capacity and gas supplies will be recognized in rates, management believes that the integrated resource planning process benefits the Company by giving it the opportunity to obtain input from regulators and the public concurrently with making these important strategic decisions. Until the Company receives final regulatory approval of these decisions in the context of the rate-making process, the Company cannot predict with certainty the extent to which the integrated resource planning process will affect its rates.

Natural Gas Supply

        The majority of Cascade's supply of natural gas is transported via Williams Gas Pipelines—West (Williams). Williams owns and operates a transmission system extending from points of interconnection with El Paso Natural Gas Company and Transwestern Pipeline Company near Blanco, New Mexico through the states of New Mexico, Colorado, Utah, Wyoming, Idaho, Oregon and Washington to the Canadian border near Sumas, Washington. Natural gas is transported north from the Colorado and New Mexico area, and south from British Columbia, Canada. The Company is also a shipper on the PG&E Gas Transmission system. PG&E Gas Transmission owns and operates a gas transmission line that connects with the facilities of the TransCanada Pipeline at the international border near Kingsgate, British Columbia and extends through Washington and central Oregon into California. Cascade also receives natural gas directly from Duke Energy Gas Transmission at the Canadian border near Sumas, Washington.

        Presently, baseload requirements for Cascade's core market are provided by six major gas supply contracts with various expiration dates from 2003 through 2008 and totaling 650,000 therms per day of Canadian supply. These contracts are supplemented by various service agreements to cover periods of peak demand including three storage agreements. One such agreement, with Williams, extends to October 31, 2014 and provides for 167,890 therms per day and a maximum, renewable inventory of 6,043,510 therms. The second storage agreement is with Avista Energy, and has a primary term ending April 30, 2003 and entitles Cascade to receive up to 150,000 therms per day and a maximum, renewable inventory of 4,800,000 therms. A third contract, also with Williams, for liquefied natural gas (LNG) storage is effective through October 31, 2014. Under this LNG agreement, Cascade is entitled to receive up to 600,000 therms per day to a maximum inventory of 5,622,000 therms. In addition to withdrawal and inventory capacity, Cascade maintains a corresponding amount of firm transportation from the storage facility to the city gate for each of these agreements.

        During 2002, Cascade purchased approximately 94% of its gas supplies from firm gas supply contracts and 6% from 30-day spot market contracts. In addition, 782,000,000 therms of customer purchased supplies were transported through Cascade facilities.

        Cascade's total cost of gas depends primarily on the prices negotiated with producers and brokers, coupled with the cost of interstate and Canadian pipeline transportation. Substantially all gas supplies for Oregon core customers and the majority of gas supplies for Washington core customers are currently purchased on contracts with supplies and prices fixed through the 2003–2004 heating season. Management believes that this, together with use of storage volumes, provides Cascade with the ability to mitigate the effects on Cascade and its customers of spikes in the market price of natural gas.

4


Federal Energy Regulatory Commission (FERC) Matters

        Cascade is not subject to regulation by the FERC, however FERC actions can affect the amounts Cascade pays to interstate pipeline companies for interstate deliveries of natural gas supplies. Several issues are pending before FERC, or are on appeal before the U.S. Court of Appeals. The final outcome may affect prices Cascade pays. Since the policies of the WUTC and OPUC provide for 100% pass through of costs subject to FERC regulation, the Company expects that the final resolution of pending issues will not significantly affect net income.

Curtailment Procedures

        In previous heating seasons, cold weather has required Cascade to significantly curtail deliveries to its interruptible customers. Cascade has not curtailed any firm customers, except under force majeure conditions. Cascade's tariffs effective in Washington and Oregon allow for curtailment of interruptible services, which are provided at rates lower than for firm services. In the event of curtailment by Cascade of firm service due to force majeure, Cascade's tariffs provide that it will not be liable for damages to any customer for failure to deliver gas curtailed in accordance with the provisions of the tariffs. The tariffs provide for appropriate adjustment of the monthly charges to firm customers curtailed by reason of an insufficient supply of gas.

Territory Served and Franchises

        The population of communities served by Cascade totals approximately 900,000. At the end of September 2002, Cascade had the franchises necessary for the distribution of natural gas in all but one of the communities it serves in Washington and Oregon. That franchise expired during fiscal 2002. Negotiations for that franchise are expected to be completed by the end of the calendar year. Under the laws of those states, incorporated municipalities and counties may grant non-exclusive franchises for a fixed term of years conferring upon the grantee certain rights with respect to public streets and highways in the location, construction, operation, maintenance and removal of gas distribution facilities.

        In the opinion of Cascade's management, none of its franchises contain any restrictions or requirements that are of a materially burdensome nature, and such franchises are adequate for the conduct of Cascade's present business. Franchises expire on various dates from fiscal 2003 to 2065. Management has not incurred significant difficulties in renewing franchises when they expire and does not expect any significant problems in the future.

Customers

        Residential and commercial customers principally use natural gas for space heating and water heating. This market is very weather-sensitive. See "Seasonality" below.

        Agreements with Cascade's principal industrial customers are for fixed terms of not less than one year and provide for automatic extension from year to year unless terminated by either party on at least 30-days' notice.

        The principal industrial activities in Cascade's service area include the production of pulp, paper and converted paper products, plywood, chemical fertilizers, industrial chemicals, clay and ceramic products; refining of crude oil; producing and forming of aluminum; the processing, flash freezing and canning of many types of vegetable, fruit and fish products; processing of milk products; meat processing; drying and curing of wood and agricultural products; and electric power generation. Electric generation customers represent a significant portion of industrial revenues. The demand for gas fired generation tends to decrease as the availability of hydroelectric generation increases.

5


Seasonality

        Weather is an important factor affecting gas revenues because of the large number of customers using gas for space heating. For the fiscal year ended September 30, 2002, 70% of operating revenues and 106% of income from operations were derived from the first two quarters (October 2001 through March 2002). Because of the seasonality of space heating revenues, financial results for interim periods are not indicative of results to be expected for an entire year. To mitigate the seasonality of space heating revenues, the Company pursues a marketing strategy of encouraging the installation of gas water heaters by customers, since they are not as influenced by weather conditions.

Competitive Conditions

        Cascade operates in a competitive market for natural gas service. Cascade competes with residual fuel oil and other alternative energy sources for industrial boiler uses, and oil, propane, and electricity for residential and commercial space heating, and electricity for water heating.

        Competition is primarily based on price. Though wholesale natural gas prices increased significantly in the 2000–2001 heating season, for residential and commercial space heating use, Cascade continues to maintain a price advantage over oil in its entire service territory and has an advantage over electricity in the vast majority of its territory. In the remaining areas of its service territory served by public electric utilities with their own hydro power supply, Cascade is almost equal in cost with respect to electricity furnished by those utilities for space heating and water heating uses. In addition, natural gas enjoys the advantage of being the preferred energy choice by builders for new home construction.

        Historically, the large volume industrial market was very sensitive to price fluctuations between the comparable cost of natural gas and alternate fuels, principally residual fuel oil used in boiler applications. However, the advent of open access transportation in the late 1980's and early 1990's and the subsequent restructuring of gas supply and contractual provisions with these customers have improved the Company's competitive position. Cascade has not experienced any significant loss of sales to alternate fuels to these customers during the last ten years, except for the 2000–2001 heating season, even though there have been periods when the residual fuel oil prices were lower than natural gas. With the escalation of wholesale natural gas prices that occurred in the 2000–2001 heating season, the Company experienced some movement of its gas load to alternative fuels and some plant curtailments by industrial customers.

        In addition to multiple alternative fuels, the Company is subject to bypass. Bypass refers to actual or prospective customers who install their own facilities and connect directly to an upstream pipeline and thereby "bypass" the distribution company's service. The Company has in the past experienced bypass, but has also experienced success in offering competitive rates to reduce economic incentives to bypass. In addition, other sellers of natural gas compete to sell the natural gas commodity over the Company's pipelines to its distribution customers.

        The Bonneville Power Administration (BPA) is a major supplier of hydro-electric power in the Pacific Northwest including Cascade's service area. BPA significantly influences the electric rates of all classes of customers including those applications in direct competition with natural gas marketed by Cascade.

Environmental

        The Company is subject to federal and state environmental regulation of its operations and properties through the United States Environmental Protection Agency, the Washington Department of Ecology and the Oregon Department of Environmental Quality. Such regulation may, at times, result in the imposition of liability or responsibility for the clean up or treatment of existing environmental

6


problems or for the prevention of future environmental problems. For detailed descriptions of specific environmental issues, see "Environmental Matters" under Item 7.

Capital Expenditures

        Capital expenditures are primarily used to expand the Company's distribution system to serve its expanding customer base, as well as to increase deliverability on its existing system to accommodate increased customer utilization. Capital expenditures for the five fiscal years ended September 30, 2002 totaled approximately $99.4 million, and the budget for fiscal 2003 is $24.5 million.

        The Company is currently forecasting that capital expenditures will total approximately $110 million over the next five years, reflecting expectations that intensified marketing and sales efforts will lead to customer growth at a pace exceeding recent experience. Management performs quantitative and qualitative analyses to assure that the Company's goals and strategies are met. The overall objective is to invest limited capital to generate the highest possible returns within the shortest possible time, while assuming prudent risk, anticipating customer needs and complying with the requirements of regulators.

Non-Utility Subsidiaries

        Cascade has four non-utility subsidiaries, only two of which are actively engaged in business at present. Cascade Land Leasing is engaged in the servicing of loans that were made to Cascade's gas customers to finance their purchases of energy-efficient appliances. The subsidiary ceased making new loans in September 1997. Beginning in November 1998, CGC Resources began serving as an entity engaged in pipeline capacity management, with the objective of mitigating gas costs for Cascade. The subsidiaries, which in the aggregate account for less than 1% of the consolidated assets of the Company, do not currently have a significant impact on Cascade's financial statements.

Personnel

        At September 30, 2002, Cascade had 444 employees. Of the total employees, 198 are represented by the International Chemical Workers Union. The present contract with the union extends to April 1, 2006, and remains in force thereafter from year to year unless terminated by either party by written notice sixty days prior to the expiration date.


Item 2. Properties

        At September 30, 2002, Cascade's utility plant investments included approximately 4,818 miles of distribution mains ranging in diameter from two inches to sixteen inches, 214 miles of transmission mains ranging in diameter from two inches to sixteen inches, and 3,339 miles of service lines.

        The distribution and transmission mains are located under public property such as streets and highways or on private property with the permission or consent of the individual owner.

        Cascade owns twenty buildings used for operations, office space and warehousing in Washington and seven such buildings in Oregon. It leases seven commercial offices and warehouse buildings. Cascade considers its properties well maintained and in good operating condition, and adequate for Cascade's present and anticipated needs. All facilities are substantially utilized.


Item 3. Legal Proceedings

Enron Contract Termination:

        During the quarter ended December 31, 2001, the Company exercised its right to terminate its two gas supply contracts with Enron based on Enron's insolvency and other reasons, including concerns

7


about its ability to perform. These contracts supplied part of the natural gas portfolio used to serve certain non-core customers. The supply has been replaced with contracts with other suppliers. Enron Canada Corp., a Canadian entity, is disputing Cascade's right to terminate one of the Enron gas supply contracts. On February 6, 2002, Enron Canada sent a letter to the Company claiming that the Company owes it a termination payment in the amount of $3.7 million. Management believes the termination was fully justified and intends to vigorously contest any payment. However, the circumstances surrounding the termination are complex, and the ultimate result is uncertain. Based on management's analysis of the latest information, the Company recorded a fiscal third-quarter charge to earnings in the amount of $2.8 million with respect to Enron Canada's claim.

        On December 2, 2002, a representative of the Enron bankruptcy estate, although not contesting Cascade's right to terminate its contract with Enron North America, asserted a claim for a termination payment under that contract in the amount of $1,400,000. The Enron Canada and the Enron North America claims are separate, and while they involve some similar issues, there are also differences significant enough to require an independent assessment of the Enron North America claim. Management has not yet received written details of the claim but is currently in the process of conducting that assessment and intends to vigorously contest any payment.

        Neither Enron Canada nor Enron North America has commenced any arbitration or court proceedings.

Settlement in Fatality Case:

        In the fourth quarter of fiscal 2002 a child suffered a fatal injury while playing on a meter barrier owned by the Company, located on the property of one of the Company's commercial customers. In December 2002 a settlement of all plaintiffs' claims was agreed to in consideration of a $750,000 payment. The Company and its co-defendant have agreed to each pay $375,000 currently, and to resolve the allocation of the total settlement payment between them in future negotiations or proceedings.

        Other: Incorporated herein by reference is the information under "Environmental Matters" in Item 7.


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

        None.

Executive Officers of the Registrant

        The executive officers of the Company, as of December 1, 2002, are as follows:

Name
   Office
   Age
   Year
Became
Officer
W. Brian Matsuyama   Chairman of the Board, President and Chief Executive Officer   56   1987
Jon T. Stoltz   Senior Vice President—Gas Supply and Regulatory Affairs   55   1981
J. D. Wessling   Senior Vice President—Finance and Chief Financial Officer   59   1995
Larry E. Anderson   Vice President—Safety & Engineering   54   1995
King C. Oberg   Vice President—Business Development   61   1993
James E. Haug   Controller   53   1981
Larry C. Rosok   Vice President—Human Resources and Corporate Secretary   46   1995
William H. Odell   Vice President—District Operations   40   2000

        None of the above officers is related by blood, marriage or adoption to any other of the above named officers. Each of the above named officers has been employed by the Company in a management capacity for at least the past five years. None of the above officers hold directorships in other public corporations. All officers serve at the pleasure of the Board of Directors.

8


Part II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

        The Common Stock is traded on the New York Stock Exchange under the symbol CGC. The following table states the per share high and low sales prices of the Common Stock.

 
   Fiscal 2002
   Fiscal 2001
Quarter
  High
   Low
   High
   Low
December 31   $ 22.77   $ 19.62   $ 20.88   $ 16.75
March 31     21.98     18.21     20.70     17.38
June 30     24.17     19.90     21.70     18.70
September 30     23.8     15.53     22.50     19.10

        At September 30, 2002, there were 8,495 holders of the Common Stock. The following table shows for the periods indicated the dividends paid per share on the Common Stock.

Quarter
   2002
   2001
December 31   $ 0.24   $ 0.24
March 31   $ 0.24   $ 0.24
June 30   $ 0.24   $ 0.24
September 30   $ 0.24   $ 0.24

9


Item 6. Selected Financial Data

 
   Year Ended
Sep 30
2002
   Year Ended
Sep 30
2001
   Year Ended
Sep 30
2000
   Year Ended
Sep 30
1999
   Year Ended
Sep 30
1998
  
 
   (dollars in thousands except per share data)

  
Statements of Income and Comprehensive Income:                                
Operating Revenues   $ 320,978   $ 335,814   $ 241,936   $ 208,610   $ 189,656  
Less: Gas Purchases     209,225     219,795     136,681     109,263     97,382  
  Revenue taxes     21,251     20,987     15,261     13,280     12,037  
   
 
 
 
 
 
Operating Margin     90,502     95,032     89,994     86,067     80,237  
   
 
 
 
 
 
Cost of Operations:                                
  Operating expenses     40,926     39,182     36,970     36,313     37,310  
  Depreciation and amortization     14,926     13,839     13,293     12,841     13,470  
  Property and payroll taxes     5,487     5,027     4,734     4,574     4,420  
   
 
 
 
 
 
      61,339     58,048     54,997     53,728     55,200  
   
 
 
 
 
 
Income From Operations     29,163     36,984     34,997     32,339     25,037  
   
 
 
 
 
 
Nonoperating Expense (Income):                                
  Interest     12,384     10,509     10,936     10,486     10,132  
  Interest charged to construction     (219 )   (333 )   (322 )   (383 )   (550 )
   
 
 
 
 
 
      12,165     10,176     10,614     10,103     9,582  
  Amortization of debt issuance expense     652     607     607     603     605  
  Other     (197 )   (313 )   (649 )   (495 )   (388 )
   
 
 
 
 
 
      12,620     10,470     10,572     10,211     9,799  
   
 
 
 
 
 
Income Before Income Taxes     16,543     26,514     24,425     22,128     15,238  
Income Taxes     5,781     9,278     9,051     8,075     5,694  
   
 
 
 
 
 
Net Income Before Preferred Dividends     10,762     17,236     15,374     14,053     9,544  
Preferred Dividends     —     —     4     483     497  
   
 
 
 
 
 
Net Income   $ 10,762   $ 17,236   $ 15,370   $ 13,570   $ 9,047  
   
 
 
 
 
 
Other Comprehensive Income (Loss)                                
  Minimum pension liability adjustment   $ (11,792 ) $ (6,502 ) $ —   $ —   $ —  
  Income tax (benefit)     4,205     2,341     —     —     —  
   
 
 
 
 
 
Other Comprehensive Income (Loss)   $ (7,587 ) $ (4,161 ) $ —   $ —   $ —  
   
 
 
 
 
 

Comprehensive Income
 
$
3,175
 
$
13,075
 
$
15,370
 
$
13,570
 
$
9,047
 
   
 
 
 
 
 

Earnings Per Common Share, Basic and Diluted
 
$
0.97
 
$
1.56
 
$
1.39
 
$
1.23
 
$
0.82
 

10

 
   At September 30
  
 
   2002
   2001
   2000
   1999
   1998
  
 
   (dollars in thousands except per share data)

  
Retained Earnings:                                
  Beginning of the year   $ 17,369   $ 10,736   $ 5,970   $ 3,003   $ 4,553  
  Net income     10,762     17,236     15,370     13,570     9,047  
  Exercise of stock options     (4 )   —     —     —     —  
  Common dividends     (10,603 )   (10,603 )   (10,604 )   (10,603 )   (10,597 )
   
 
 
 
 
 
  End of the year   $ 17,524   $ 17,369   $ 10,736   $ 5,970   $ 3,003  
   
 
 
 
 
 

Capital Structure:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Common shareholders' equity   $ 114,181   $ 121,633   $ 119,161   $ 114,395   $ 111,428  
  Redeemable preferred stocks     —     —     62     6,186     6,408  
   
 
 
 
 
 
  Debt:                                
    Long-term debt     164,930     125,000     125,000     125,000     110,650  
    Notes payable and commercial paper     —     40,000     1,500     —     6,929  
    Current maturities of long-term debt     —     —     —     —     10,000  
   
 
 
 
 
 
      164,930     165,000     126,500     125,000     127,579  
   
 
 
 
 
 
  Total capital   $ 279,111   $ 286,633   $ 245,723   $ 245,581   $ 245,415  
   
 
 
 
 
 

Financial Ratios:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Return on common shareholders' equity     8.49 %   13.45 %   12.51 %   11.52 %   7.77 %
  Common stock dividend payout ratio     99 %   62 %   69 %   78 %   117 %
  Cash dividends declared per common share   $ 0.96   $ 0.96   $ 0.96   $ 0.96   $ 0.96  
 
Fixed charge coverage (before income tax deduction):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Times interest earned     2.27     3.39     3.12     3.00     2.42  
    Times interest and preferred dividends earned     2.27     3.39     3.12     2.80     2.26  
 
Book value per year-end share of common stock
 
$
10.34
 
$
11.01
 
$
10.79
 
$
10.33
 
$
10.09
 
 
Capitalization Ratios at End of Year
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
    Common shareholders' equity     40.9 %   42.4 %   48.5 %   46.6 %   45.4 %
    Preferred stock     0.0 %   0.0 %   0.0 %   2.5 %   2.6 %
    Long-term debt (incl. current)     59.1 %   43.6 %   50.9 %   50.9 %   49.2 %
    Short-term debt     0.0 %   14.0 %   0.6 %   0.0 %   2.8 %
   
 
 
 
 
 
      100.0 %   100.0 %   100.0 %   100.0 %   100.0 %
   
 
 
 
 
 

Utility Plant:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Utility plant—end of year   $ 505,126   $ 488,231   $ 468,789   $ 453,278   $ 433,568  
  Accumulated depreciation     213,476     201,530     189,058     177,878     167,356  
   
 
 
 
 
 
Net plant   $ 291,650   $ 286,701   $ 279,731   $ 275,400   $ 266,212  
   
 
 
 
 
 
 
Capital expenditures, net of contributions in aid
 
$
20,734
 
$
21,649
 
$
15,937
 
$
17,262
 
$
23,780
 
   
 
 
 
 
 
  Total assets   $ 367,663   $ 364,253   $ 328,336   $ 315,569   $ 311,511  
   
 
 
 
 
 

11


Item 7.    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 affect consolidated results of operations and cash flows for the fiscal years ended September 30, 2002, 2001, and 2000. References herein to 2002, 2001, and 2000 refer to these fiscal years.

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.

Regulatory Accounting

        The Company's accounting policies and practices are generally the same as used by unregulated companies for financial reporting under GAAP. However, Statement of Financial Accounting Standards (FAS) No. 71, "Accounting for the Effects of Certain Types of Regulation", requires regulated companies to apply special accounting treatment to reflect the financial impact of regulation. For example, in establishing the rates to be charged to the Company's retail customers, the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC) may not allow the Company to charge its customers for recovery of certain expenses in the same period they are incurred. Instead, rates are established in the future to recover costs that were incurred in a prior period. In this situation, FAS No. 71 requires the Company to defer these costs and include them as regulatory assets on the balance sheet. In the subsequent period when these costs are recovered from customers, the Company then amortizes these costs as expense in the income statement, in an amount equivalent to the amounts recovered. Similarly, certain revenue items, or cost reductions may be deferred as regulatory liabilities, which are later amortized to the income statement as customer rates are reduced.

        In order to apply the provisions of FAS No. 71, the following conditions must apply:

        The Company periodically assesses whether conditions merit the continued applicability of FAS No. 71. In the event the Company should determine in the future that all or a portion of its regulatory assets and liabilities no longer meet the above criteria, it would be required to write off the related balances of its regulatory assets and liabilities, and reflect the write off in its income statement. At September 30, 2002 there were $21,883,000 of regulatory assets and $4,576,000 of regulatory liabilities.

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and

12


the OPUC. Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, estimates of unbilled revenue, and in the determination of depreciable lives of utility plant. On an ongoing basis, management evaluates the estimates used, based on historical experience, current conditions and on various other assumptions believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

Derivatives

        The company records derivative transactions according to the provisions of FAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by FAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". These standards require that the fair value of all derivative financial instruments be recognized as either assets or liabilities on the Company's balance sheet. Changes during a period in the fair value of a derivative instrument would be included in earnings or other comprehensive income for the period.

        The Company did not enter into derivative transactions during fiscal 2002, and as of September 30, 2002, does not have any derivative assets or liabilities. The Company's contracts for purchase of natural gas are not derivative instruments because they are considered normal purchases under the provisions of FAS Nos. 133 and 138.

NEW ACCOUNTING STANDARDS

        FAS No. 142.    The FASB has issued FAS No. 142, titled "Goodwill and Other Intangible Assets." This standard is effective for fiscal years beginning after December 15, 2001. The Company adopted this standard effective October 1, 2002. Adoption of this standard did not have an impact on the Company's financial statements.

        FAS No. 143.    The FASB has issued FAS No. 143, titled "Accounting for Asset Retirement Obligations." This standard is effective for fiscal years beginning after June 15, 2002, and has been adopted by the Company effective October 1, 2002. The standard requires companies to record a liability to recognize future obligations to remove assets. The Company has reviewed its significant franchises and easements and other documents to determine whether any include provisions requiring removal of assets. No significant obligations have been identified, and adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 144.    The FASB has issued FAS No. 144, titled "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard is effective for fiscal years beginning after December 15, 2001, and has been adopted by the Company effective October 1, 2002. The standard provides for the recognition and measurement of an impairment loss if it is determined the carrying amount of a long-lived asset is not recoverable, and exceeds its fair value. It also identifies events or changes in circumstances that would require a test for recoverability. Adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 145.    The FASB has issued FAS No. 145, titled "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This standard is effective for fiscal years beginning after May 15, 2002, and has been adopted by the Company effective October 1, 2002. Adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 146.    The FASB has issued FAS No. 146, titled "Accounting for costs associated with exit or disposal activities". This standard is effective for exit or disposal activities initiated after December 31, 2002, and will be adopted by the Company effective January 1, 2003. The Company has

13


not determined whether the adoption of this statement will have a significant impact on its financial statements.

EARNINGS PER SHARE

        Net income for 2002 was $10,762,000 compared to $17,236,000 for 2001. Basic and diluted earnings per share for 2002 were $0.97, a 38% decrease from the $1.56 per share earnings for 2001.

        2001 versus 2000.    Net income was $17,236,000 for 2001, compared to $15,370,000 for 2000. Basic and diluted earnings per share for 2001 were $1.56, a 12% improvement over the $1.39 reported for 2000.

OPERATING MARGIN

        Operating margin for the year declined $4,530,000, with $2,738,000 of the decline attributed to two unusual revenue transactions in 2001 from off-system interstate pipeline capacity transactions, and another $2,800,000 million contract termination charge recorded in 2002. Other components of changes in operating margin are described in the paragraphs below.

        Residential and Commercial Margin for the fiscal years ended September 30, 2002, 2001, and 2000 are set forth in the table below:

 
   (12 months ended September 30)
 
   2002
   2001
   2000
 
   ($ in thousands)
Degree Days     5,455     5,793     5,372
Average Number of Customers:                  
  Residential     169,454     163,427     157,116
  Commercial     28,216     27,796     27,186
Average Therm Usage Per Customer:                  
  Residential     763     776     776
  Commercial     3,802     4,023     3,926
Operating Margin:                  
  Residential   $ 38,433   $ 37,619   $ 36,003
  Commercial   $ 22,329   $ 23,073   $ 21,948

        Operating margins from residential and commercial customers were essentially even with fiscal year 2001. Increases in the number of residential and commercial customers contributed approximately $1,990,000 of new margin. Temperatures, 6% warmer than last year, contributed to a consumption decline, the effect of which substantially offset the improvement from new customer additions.

        2001 versus 2000.    Operating margins from sales to residential and commercial customers were up $2,740,000, or 4.7%, in 2001 compared to 2000. The primary factors contributing to this improvement were increased deliveries to residential customers resulting from growth in the number of customers, and higher average consumption per commercial customer.

        Increases in the number of residential and commercial customers contributed approximately $1,620,000 and $546,000 respectively of new margin. Higher per-customer gas usage, primarily by commercial customers, contributed most of the remaining improvement. Average residential customer consumption in 2001 was the same as in 2000 despite the fact that weather was 7% colder in 2001. This lack of increased consumption is attributed to rate increases in January, and general conservation efforts by customers in response to the West Coast power crisis in the winter of 2000–2001.

14


Industrial and Other Margin.

        Operating margins from electric generation customers were $2,128,000 lower than fiscal year 2001. The slow economy, mild temperatures, and higher than normal hydroelectric generation dramatically affected demand for gas-fired generation throughout the year but particularly during the third and fourth quarters. The fourth quarter alone was down $979,000 from the prior year.

        Other industrial margins were $853,000 higher in fiscal year 2002 compared to 2001, in large part, attributable to recovery from depressed consumption levels following the 2000–2001 winter energy crisis. Additionally, margin from gas management and other services provided to existing and new customers increased $2,213,000 for the year.

        2001 versus 2000.    Total margin from industrial and other customers in 2001 declined $777,000 from 2000. Increased consumption by electric generation customers resulted in a $600,000 margin increase from that sector, but this was offset by approximately $2,200,000 decline in margin from customers in other industries. The energy crisis on the West Coast during the winter and spring of 2000–2001 was the major contributing factor in both these changes. There was increased demand for electric generation, but higher energy prices influenced decisions by other customers to reduce their consumption. The Company also earned $842,000 of increased margins from providing gas management services to industrial customers, as well as providing miscellaneous services to existing and new customers. Other margin in 2001 was reduced by a charge resulting from an Oregon earnings sharing mechanism. Under this arrangement between the Company and the OPUC, Cascade refunds to its Oregon customers one third of earnings that exceed a return on equity ceiling. The amount recorded as an estimate attributable to 2001 was $657,000.

Capacity Contracts.

        During 2001, the Company benefited from one-time opportunities to enter into two off-system interstate pipeline transactions. These transactions resulted in $3,074,000 of operating margin. The Company has no expectation of additional revenues from such sources, and this is not an on-going part of Cascade's business.

Contract Termination Charge.

        During the quarter ended December 31, 2001, the Company exercised its contractual rights and terminated all of its gas supply contracts with Enron based on Enron's insolvency and other reasons, including concerns about its ability to perform. These contracts supplied part of the natural gas portfolio used to serve certain non-core customers. The supply has been replaced with contracts with another supplier. Enron Canada Corp., a Canadian entity, is disputing Cascade's right to terminate one of the Enron gas supply contracts. On February 6, 2002, Enron Canada sent a letter to the Company claiming that the Company owes it a termination payment in the amount of $3,700,000. Management believes the termination was fully justified and intends to vigorously contest any payment. However, the circumstances surrounding the termination are complex, and the ultimate result is uncertain. Based on management's analysis of the latest information, the Company recorded a fiscal third-quarter charge to earnings in the amount of $2,800,000 with respect to Enron Canada's claim. The effect of this charge to gas costs was a reduction of $0.16 per share in 2002 earnings.

COST OF OPERATIONS

        Cost of operations, which consists of operating expenses, depreciation and amortization, and property and payroll taxes, was $61,339,000, $58,048,000, and $54,997,000 for the fiscal years ended September 30, 2002, 2001, and 2000, respectively.

15


        Operating Expenses for 2002, which are primarily labor and benefits expenses, increased $1,744,000, or 4.5% from 2001. Employee benefits expense increased $2,030,000 over 2001. The bulk of the increase is due to increasing costs of the Company's medical benefit plans for active and retired employees. In the aggregate, other expense categories decreased, due primarily to the inclusion in 2001 of $857,000 related to the installation of a new integrated work management system. Also included in 2002 operating expenses is a $250,000 charge for the settlement of a lawsuit filed against the Company in 1998 in connection with personal injury claims.

        2001 versus 2000.    Operating expenses for 2001 increased $2,212,000, or 6.0% from 2000. Of this increase, $857,000 is attributable to one-time expenses related to the installation of a new integrated work management system. Excluding these one-time costs, ongoing expenses increased 3.7% for the year, due in large part to increases in regular compensation, and in profit sharing related to achievement of goals.

        Depreciation and Amortization for 2002 increased $1,087,000 or 7.9% over 2001. The increase is primarily attributable to the depreciation on computer system investments in fiscal 2001 and natural gas distribution assets added since last year. Fiscal 2002 was the first full-year of depreciation on the integrated work management system installed at the end of 2001. For 2001, the increase was $546,000, or 4.1% over 2000, related to new depreciable assets placed in service.

        Property and Payroll Taxes for 2002 increased $460,000 or 9.2% over 2001. For 2001, the increase was $293,000, or 6.2% over 2000. For both years, the increases were related to higher property assessments and higher payroll.

NONOPERATING EXPENSE (INCOME)

        Interest expense in 2002, net of interest capitalized, increased $1,989,000 (19.5%) from 2001, due to the issuance of $40,000,000, 7.5% 30 year notes in November of 2001. Interest on these notes exceeded interest on the short-term debt they replaced.

        2001 versus 2000.    Interest expense in 2001, net of interest capitalized, decreased $438,000 (4.1%) from 2000, mainly because of the interest benefit accrued on deferred gas costs. Other non-operating income decreased $336,000 mainly because of lower interest income on deposits of cash and cash equivalents.

INCOME TAXES

        The changes in the provision for income taxes from 2001 to 2002, and from 2000 to 2001 are directly attributable to the changes in pre-tax earnings.

OTHER COMPREHENSIVE INCOME (LOSS)

        During 2002 and 2001, the value of the assets in the Company's pension plan declined, reflecting the general downward trend in common stock values. The decline in asset values, along with a decrease in the assumed discount rate to 6.75% from 7.50% and a reduction in the earnings assumption rate to 8.25% from 9.0%, resulted in an unfunded accumulated benefit obligation. To recognize this liability, the Company recorded a minimum pension liability adjustment in accordance with the provisions of Statement of Financial Accounting Standards No. 87. This adjustment included charges to other comprehensive income (loss) of $11,792,000 in 2002, and $6,502,000 in 2001. Other comprehensive loss also includes credits for the deferred income tax effect of $4,205,000 and $2,341,000 for 2002 and 2001 respectively.

16


LIQUIDITY AND CAPITAL RESOURCES

        The seasonal nature of the Company's business creates short-term cash requirements to finance customer accounts receivable and construction expenditures. To provide working capital for these requirements, the Company has a $50,000,000 bank revolving credit commitment. This agreement has an annual 0.16% commitment fee, and a term that expires in 2004. The Company also has a $10,000,000 uncommitted bank credit line. As of September 30, 2002, there was no outstanding debt under these credit lines.

        To provide longer-term financing, the Company in 2001 filed an omnibus registration statement under the Securities Act of 1933 providing the ability to issue up to $150,000,000 of new debt and equity securities. On November 26, 2001, the Company issued $40,000,000 of 7.5% 30-year debt under the omnibus registration statement, leaving $110,000,000 available under that registration statement for future financing. The proceeds of the $40,000,000 offering were used to pay down outstanding short-term debt.

        Because of the availability of short-term credit and the ability to issue long-term debt and additional equity, management believes it has adequate financial flexibility to meet its anticipated cash needs.

OPERATING ACTIVITIES

        For fiscal 2002, operating activities provided cash of $36,004,000, compared to a cash use of $7,996,000 for 2001. This represents a $44,000,000 improvement in operating cash flow between the two years. The negative operating cash flow in 2001 was due to higher costs of natural gas purchases not passed through to customers, but deferred, while in 2002 customer rates were increased to more closely match current purchase prices. The 2002 rate increase also included a component to recover a portion of the under-recovered gas cost from 2001. For 2002, approximately $9,000,000 of 2001 under-recovered gas costs were collected. Current rates, approved by the WUTC in November 2001, are designed to recover the remainder of the 2001 under-recovery by October 2004.

INVESTING ACTIVITIES

        Cash used by investing activities in 2002 was $20,551,000, compared to $21,549,000 in 2001. Investing activities are substantially all capital expenditures. Seventy-nine percent of 2002 capital expenditures were dedicated to connecting new customers. Capital expenditures in 2001 included $4,500,000 spent to install a new integrated work management system.

        Budgeted capital expenditures for fiscal 2003 are approximately $24,500,000, which includes $16,100,000 for new customer connections and $2,400,000 for distribution system reinforcement and replacement projects. The remainder is for equipment, facilities upgrades, and various technology projects.

FINANCING ACTIVITIES

        Financing activities for 2002 used cash of $12,187,000, compared to adding cash of $27,835,000 from short-term borrowing in 2001. Other than the payment of dividends, the primary financing activity in 2002 was the replacement of $40,000,000 short-term debt with proceeds from issuance of new 7.5% 30-year notes.

ENVIRONMENTAL MATTERS

        In 1995, the Company received a claim from a property owner in Eugene, Oregon requesting that the Company assume responsibility for investigation and possible clean up of alleged contamination on property previously owned by a predecessor of Cascade. The predecessor company conducted a

17


manufactured gas business on the property from approximately 1929 to 1948. Manufactured gas operations apparently were conducted on the site by several operators beginning about 1907. The site was used for other purposes beginning in 1949.

        The present owner has retained an environmental consultant, which is investigating possible contamination on the property. To date the consultant has reported that it believes contamination is present. The contamination is consistent with that which might originate from a manufactured gas operation. There have been no estimates as to possible clean up costs. The consultant's initial report has been furnished to the Oregon Department of Environmental Quality (DEQ). The owner has reached an intergovernmental agreement with the DEQ with respect to further investigation and possible remediation of contamination on the property under the voluntary cleanup program.

        Another northwest utility, which purchased the property from Cascade in 1958, has declined to participate in the site investigation, although it may, as a onetime owner of the property, bear some share of the responsibility as well.

        The Company has notified its insurance carriers of the claim and is keeping them advised as to the investigation. On one occasion in the past when hazardous materials on property formerly owned by a predecessor of the Company required clean up, the OPUC allowed the clean up costs to be passed on to customers. In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking for reimbursement through rates for such costs.

        In 1997, a property owner in Washington notified the Company that there is contamination on his property, and that he believes it comes from a former manufactured gas site, owned at one time by a predecessor company, which was merged with Cascade in 1953. The State of Washington Department of Ecology has categorized this site as a "listed site" ranked in its most hazardous category. As a former owner of the site, the Company may be strictly liable to the State of Washington for investigation and remediation of the contamination of the site, but may share that cost or allocate all the cost to others who actually caused or contributed to the contamination.

        The Company retained an environmental consultant who conducted a preliminary investigation of possible contamination at the site. There is evidence of contamination at the site, and there is also evidence of an oil line across the site property owned and operated by others, which may be a contributor to the contamination. There have been no estimates as to possible clean up costs. The Company has investigated title and other government records to identify other potentially liable parties. The Company has notified the other identified parties of the contamination claims, and has requested cooperation and financial contribution.

        In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking the WUTC for reimbursement for such costs, through rates charged to customers.

18


Item 7A. Quantitative and Qualitative Disclosures About Market Risk

        Cascade has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The Company has fixed-rate debt obligations, but does not have derivative financial instruments subject to interest rate risk. Cascade makes interest and principal payments on these obligations in the normal course of its business, and does not plan to redeem these obligations prior to normal maturities.

        The Company's natural gas purchase commodity prices are subject to fluctuations resulting from weather, congestion on interstate pipelines, and other unpredictable factors. The Company's PGA mechanisms assure the recovery of prudently incurred wholesale gas cost, therefore management believes the Company's commodity price risk is immaterial.

FORWARD-LOOKING STATEMENTS

        Statements contained in this report that are not historical in nature are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are subject to risks and uncertainties that may cause actual future results to differ materially. Such risks and uncertainties with respect to the Company include, among others, its ability to successfully implement internal performance goals, competition from alternative forms of energy, consolidation in the energy industry, performance issues with key natural gas suppliers, the capital-intensive nature of the Company's business, regulatory issues, including the need for adequate and timely rate relief to recover increased capital and operating costs resulting from customer growth and to sustain dividend levels, the weather, increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, the potential loss of large volume industrial customers due to "bypass" or the shift by such customers to special competitive contracts at lower per unit margins, exposure to environmental cleanup requirements, and economic conditions, particularly in the Company's service area.

19


Item 8. Financial Statements and Supplementary Data

INDEPENDENT AUDITORS' REPORT

Board of Directors
Cascade Natural Gas Corporation
Seattle, Washington

        We have audited the accompanying consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the Corporation) as of September 30, 2002 and 2001, and the related consolidated statements of income and comprehensive income, common shareholders' equity, and cash flows for each of the three years in the period ended September 30, 2002. Our audits also included the financial statement schedule contained in Item 15(a)2. These financial statements and financial statement schedule are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements and financial statement schedule present fairly, in all material respects, the financial position of Cascade Natural Gas Corporation and subsidiaries as of September 30, 2002 and 2001, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

DELOITTE & TOUCHE LLP

Seattle, Washington
November 8, 2002

20


CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 
   Year Ended September 30,
  
 
   2002
   2001
   2000
  
 
   (Dollars in thousands except per share data)

  
Operating Revenues   $ 320,978   $ 335,814   $ 241,936  
  Less                    
    Gas purchases     209,225     219,795     136,681  
    Revenue taxes     21,251     20,987     15,261  
   
 
 
 
Operating Margin     90,502     95,032     89,994  
   
 
 
 
Cost of Operations                    
  Operating expenses     40,926     39,182     36,970  
  Depreciation and amortization     14,926     13,839     13,293  
  Property and payroll taxes     5,487     5,027     4,734  
   
 
 
 
      61,339     58,048     54,997  
   
 
 
 
  Income from operations     29,163     36,984     34,997  
   
 
 
 
Nonoperating Expense (Income)                    
  Interest     12,384     10,509     10,936  
  Interest charged to construction     (219 )   (333 )   (322 )
   
 
 
 
      12,165     10,176     10,614  
  Amortization of debt issuance expense     652     607     607  
  Other     (197 )   (313 )   (649 )
   
 
 
 
      12,620     10,470     10,572  
   
 
 
 
Income Before Income Taxes     16,543     26,514     24,425  
Income Taxes     5,781     9,278     9,051  
   
 
 
 
Net Income Before Preferred Dividends     10,762     17,236     15,374  
Preferred Dividends     —     —     4  
   
 
 
 
Net Income   $ 10,762   $ 17,236   $ 15,370  
   
 
 
 
Other Comprehensive Income (Loss):                    
  Minimum pension liability adjustment   $ (11,792 ) $ (6,502 ) $ —  
  Income tax benefit     4,205     2,341     —  
   
 
 
 
Other Comprehensive Income (Loss)   $ (7,587 ) $ (4,161 ) $ —  
   
 
 
 
Comprehensive Income   $ 3,175   $ 13,075   $ 15,370  
   
 
 
 
Earnings Per Common Share, Basic and Diluted   $ 0.97   $ 1.56   $ 1.39  
   
 
 
 

The accompanying notes are an integral part of these financial statements

21



CASCADE NATURAL GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

 
   September 30,
  
 
   2002
   2001
  
 
   (Dollars in thousands)

  
ASSETS              
Utility Plant   $ 505,126   $ 488,231  
  Less accumulated depreciation     213,476     201,530  
   
 
 
      291,650     286,701  
  Construction work in progress     7,974     7,485  
   
 
 
      299,624     294,186  
   
 
 
Other Assets              
  Investments in non utility property     202     202  
  Notes receivable, less current maturities     127     311  
   
 
 
      329     513  
   
 
 
Current Assets              
  Cash and cash equivalents     3,688     422  
  Accounts receivable and current maturities of notes receivable, less allowance of $1,126 and $1,421 for doubtful accounts     14,547     18,865  
  Materials, supplies, and inventories     14,556     8,870  
  Prepaid expenses and other assets     6,515     3,783  
  Deferred income taxes     1,648     559  
   
 
 
      40,954     32,499  
   
 
 
Deferred Charges              
  Gas cost changes     18,788     28,861  
  Other     7,968     8,194  
   
 
 
      26,756     37,055  
   
 
 
    $ 367,663   $ 364,253  
   
 
 
COMMON SHAREHOLDERS' EQUITY AND LIABILITIES              
Common Shareholders' Equity              
  Common stock, par value $1 per share; Authorized, 15,000,000 shares Issued and outstanding, 11,045,095 shares   $ 11,045   $ 11,045  
  Additional paid-in capital     97,360     97,380  
  Accumulated other comprehensive income (loss)     (11,748 )   (4,161 )
  Retained earnings     17,524     17,369  
   
 
 
      114,181     121,633  
   
 
 
Long-Term Debt     164,930     125,000  
   
 
 
Current Liabilities              
  Notes payable and commercial paper     —     40,000  
  Accounts payable     12,597     13,466  
  Property, payroll, and excise taxes     5,777     4,921  
  Dividends and interest payable     7,872     7,539  
  Other current liabilities     9,466     6,426  
   
 
 
      35,712     72,352  
   
 
 
Deferred Credits and Other              
  Income taxes     20,299     19,649  
  Investment tax credits     1,669     1,896  
  Other     30,872     23,723  
   
 
 
      52,840     45,268  
   
 
 
Commitments and Contingencies (Note 11)     —     —  
   
 
 
    $ 367,663   $ 364,253  
   
 
 

The accompanying notes are an integral part of these financial statements

22


CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

 
   Common Stock
    
   Accumulated
Other
Comprehensive
Income
    
  
 
   Paid-In
Capital
   Retained
Earnings
  
 
   Shares
   Par Value
  
 
   (Dollars in thousands except per share data)

  
Balance, September 30, 1999   11,045,095   $ 11,045   $ 97,380   $ —   $ 5,970  
  Cash dividends:                              
    Common stock, $.96 per share                           (10,604 )
    Preferred stock, senior, $.55 per share                           (4 )
  Net Income Before Preferred Dividends                           15,374  
   
 
 
 
 
 
Balance, September 30, 2000   11,045,095   $ 11,045   $ 97,380   $ —   $ 10,736  
   
 
 
 
 
 
  Cash dividends:                              
    Common stock, $.96 per share                           (10,603 )
  Other comprehensive income (loss)                     (4,161 )      
  Net Income                           17,236  
   
 
 
 
 
 
Balance, September 30, 2001   11,045,095   $ 11,045   $ 97,380   $ (4,161 ) $ 17,369  
   
 
 
 
 
 
  Cash dividends:                              
    Common stock, $.96 per share                           (10,603 )
  Other comprehensive income (loss)                     (7,587 )      
  Exercise of stock options               (20 )         (4 )
  Net Income                           10,762  
   
 
 
 
 
 
Balance, September 30, 2002   11,045,095   $ 11,045   $ 97,360   $ (11,748 ) $ 17,524  
   
 
 
 
 
 

The accompanying notes are an integral part of these financial statements

23


CASCADE NATURAL GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

 
   Year Ended September 30,
  
 
   2002
   2001
   2000
  
 
   (Dollars in thousands)

  
Operating Activities                    
  Net Income Before Preferred Dividends   $ 10,762   $ 17,236   $ 15,374  
  Adjustments to reconcile net income before preferred dividends to net cash provided by operating activities:                    
    Depreciation and amortization     14,926     13,839     13,293  
    Deferrals of gas cost changes     1,804     (40,801 )   1,298  
    Amortization of gas cost changes     8,270     (3,108 )   1,539  
    Other deferrals and amortizations     (2,559 )   3,706     2,310  
    Deferred income taxes and tax credits—net     3,541     1,403     783  
    Other           —     (212 )
    Change in current assets and liabilities     (740 )   (271 )   (2,129 )
   
 
 
 
  Net cash provided (used) by operating activities     36,004     (7,996 )   32,256  
   
 
 
 
Investing Activities                    
  Capital expenditures     (21,117 )   (23,829 )   (18,252 )
  Customer contributions in aid of construction     383     2,180     2,315  
  Other     183     100     635  
   
 
 
 
  Net cash used by investing activities     (20,551 )   (21,549 )   (15,302 )
   
 
 
 
Financing Activities                    
  Proceeds from long-term debt, net     38,510     —     —  
  Repayment of long-term debt     (70 )   —     —  
  Changes in notes payable and commercial paper, net     (40,000 )   38,500     1,500  
  Dividends paid     (10,603 )   (10,603 )   (10,608 )
  Redemption of preferred stock     —     (62 )   (6,124 )
  Other     (24 )   —     —  
   
 
 
 
  Net cash provided (used) by financing activities     (12,187 )   27,835     (15,232 )
   
 
 
 
Net Increase (Decrease) in Cash and Cash Equivalents     3,266     (1,710 )   1,722  
Cash and Cash Equivalents                    
  Beginning of year     422     2,132     410  
   
 
 
 
  End of year   $ 3,688   $ 422   $ 2,132  
   
 
 
 

The accompanying notes are an integral part of these financial statements

24



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Nature of Business

        Cascade Natural Gas Corporation (the Company) is a local distribution company (LDC) engaged in the distribution of natural gas. The Company's service territory consists of towns in Washington and Oregon, ranging from the Canadian border in northwestern Washington to the Idaho border in eastern Oregon.

        As of September 30, 2002, the Company had approximately 198,000 billed core customers and 199 non-core customers. Core customers are principally residential and small commercial and industrial customers who take traditional "bundled" natural gas service, which includes supply, peaking service, and upstream interstate pipeline transportation. Sales to core customers account for approximately 22% of gas deliveries and 71% of operating margin. The Company's sales to its core residential and commercial customers are influenced by fluctuations in temperature, particularly during the winter season. A warm winter season will tend to reduce gas consumption. Over the longer term, these fluctuations tend to offset each other, as rates charged to customers are developed based on the assumption of normal weather.

        Non-core customers are generally large industrial and institutional customers who have chosen "unbundled" service, meaning that they select from among several supply and upstream pipeline transportation options, independent of the Company's distribution service. The Company's margin from non-core customers is derived primarily from this distribution service, as well as gas management services. The principal industrial activities of its customers include the generation of electricity, processing of food, processing of forest products, production of chemicals, refining of crude oil, and production of aluminum.

        The Company is subject to regulation of most aspects of its operations by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC). It is subject to regulatory risk primarily with respect to recovery of costs incurred. Various deferred charges and deferred credits reflect assumptions regarding recovery of certain costs through temporary customer rate adjustments during future periods.

Note 2—Summary of Significant Accounting Policies

        The Company's accounting records and practices conform to the requirements of the uniform system of accounts prescribed by the WUTC and the OPUC.

        Principles of consolidation:    The consolidated financial statements include the accounts of Cascade Natural Gas Corporation and its wholly owned subsidiaries: Cascade Land Leasing Co.; CGC Properties, Inc.; CGC Energy, Inc.; and CGC Resources, Inc. All intercompany transactions are eliminated in consolidation.

        Utility plant:    Utility plant is stated at the historical cost of construction or purchase. These costs include payroll-related costs such as taxes and other employee benefits, general and administrative costs, and the estimated cost of funds used during construction. Maintenance and repairs of property, and replacements and renewals of items deemed to be less than units of property, are charged to operations. Units of utility plant retired or replaced are credited to property accounts at cost. Such amounts plus removal cost, less salvage, are charged to accumulated depreciation. In the case of a sale of non-depreciable property or major operating units, the resulting gain or loss on the sale is included in other income or expense.

        Depreciation of utility plant is computed using the straight-line method. The Company periodically conducts depreciation studies to establish and update asset depreciation lives. Asset lives used for computing depreciation range from six to seventy years, and the weighted average annual depreciation

25


rate is approximately 3.0%. The Company periodically reviews the carrying amount of its utility plant and other long-lived assets for impairment. An asset is considered impaired when estimated future cash flows are less than the carrying amount of the asset. In the event the carrying amount of such asset is deemed not recoverable, the asset is adjusted to its fair value. Fair value is generally determined based on discounted future cash flow.

        Investments in non-utility property:    Real estate, carried at the lower of cost or estimated net realizable value is the primary investment.

        Notes receivable:    Notes receivable includes loans made to customers for the purchase of energy efficient appliances, which are generally the security for the loan. The loans have terms ranging from one to ten years at interest rates varying from 6.5% to 12%.

        Cash and cash equivalents:    For purposes of reporting cash flows, the Company accounts for all liquid investments, with a purchased maturity of three months or less, as cash equivalents. The following provides additional information to the Consolidated Statements of Cash Flows:

 
   2002
   2001
   2000
  
 
   (Dollars in thousands)

  
Changes in current assets and current liabilities:                    
  Accounts receivable   $ 4,318   $ 2,208   $ (8,133 )
  Income taxes     (4,031 )   936     563  
  Inventories     (5,686 )   (2,632 )   12  
  Prepaid expenses and other assets     12     (363 )   (1,163 )
  Accounts payable and accrued expenses     4,647     (847 )   7,016  
  Other     —     427     (424 )
   
 
 
 
  Net change in current assets and current liabilities   $ (740 ) $ (271 ) $ (2,129 )
   
 
 
 
Cash payments:                    
  Interest (net of amounts capitalized)   $ 11,074   $ 10,868   $ 9,501  
  Income taxes   $ 6,938   $ 6,911   $ 7,664  

        Materials, supplies and inventories:    Materials and supplies for construction, operations, and maintenance, and inventories of natural gas are recorded at cost.

        Regulatory accounts:    The Company's financial statements are prepared in accordance with Statement of Financial Accounting Standards (FAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement provides for the deferral of certain costs and benefits that would otherwise be recognized in revenue or expense, if it is probable that future rates will result in recovery from customers or refund to customers of such amounts.

        Regulatory assets (liabilities) at September 30, 2002 and 2001 include the following:

 
   2002
   2001
  
 
   (Dollars in thousands)

  
Unamortized loss on reacquired debt   $ 2,908   $ 3,438  
Gas cost changes     18,788     28,861  
Deferred income taxes     (4,138 )   (4,769 )
Postretirement benefits other than pensions     187     937  
Other, net     (438 )   (1,307 )
   
 
 
Net   $ 17,307   $ 27,160  
   
 
 

26

        Revenue recognition:    The Company recognizes operating revenues based on deliveries of gas to customers. This includes estimated revenues for gas delivered but not billed to residential and commercial customers from the latest meter reading date to the end of the accounting period.

        Leases:    The Company leases a majority of its vehicle fleet. These leases are classified as operating leases. The Company's primary obligation under these leases is for a twelve-month period, with options to extend the lease thereafter. Commitments beyond one year are not material. Rent expense under operating leases totaled $813,000, $980,000, and $919,000 for fiscal years ended September 30, 2002, 2001, and 2000, respectively.

        Federal income taxes:    The Company normalizes temporary differences between book income and taxable income, with the exception of depreciation differences on assets placed in service prior to 1981, consistent with the policies of the WUTC and OPUC. Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using current tax rates.

        Investment tax credits:    Investment tax credits were deferred and are amortized over the remaining life of the properties that gave rise to the credits.

        Use of estimates:    The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC. Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, allowances for doubtful accounts, and in the determination of depreciable lives of utility plant.

        Stock-Based Compensation:    Compensation cost for stock options is measured as the excess of the market price of the Company's stock at the date of the grant over the price the employee must pay to acquire the stock. The Company accounts for its stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" rather than using the fair-value-based method prescribed under FAS No. 123, "Accounting for Stock-Based Compensation." The Company has adopted the disclosure requirements of FAS No. 123. See Note 6 for more information about the Company's stock-based compensation plan.

        Comprehensive Income (Loss):    Comprehensive income for the fiscal years ended September 30, 2002 and 2001, included a charge to Other Comprehensive Income in the amount of $7,587,000 and $4,161,000, net of income tax. The charges are related to a minimum pension liability adjustment. See Note 10 for more information. For the fiscal year ended September 30, 2000 there was no difference between net income and comprehensive income.

        Segment Reporting:    Management views the Company as operating as a single segment, that of a local distribution company in the Pacific Northwest. Therefore the financial statements do not include disclosure of segment information.

        Derivatives:    The company records derivative transactions according to the provisions of FAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by FAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities". These standards require that the fair value of all derivative financial instruments be recognized as either assets or liabilities on

27


the Company's balance sheet. Changes during a period in the fair value of a derivative instrument would be included in earnings or other comprehensive income for the period.

        The Company did not enter into derivative transactions during fiscal 2002, and as of September 30, 2002, does not have any derivative assets or liabilities. During fiscal 2001, the Company entered into a contract for pipeline capacity unrelated to its regulated natural gas distribution operations. As of September 30, 2001, the value of this derivative asset was $87,000.

New Accounting Standards:

        FAS No. 142.    The FASB has issued FAS No. 142, titled "Goodwill and Other Intangible Assets." This standard is effective for fiscal years beginning after December 15, 2001. The Company adopted this standard effective October 1, 2002. Adoption of this standard did not have an impact on the Company's financial statements.

        FAS No. 143.    The FASB has issued FAS No. 143, titled "Accounting for Asset Retirement Obligations." This standard is effective for fiscal years beginning after June 15, 2002, and has been adopted by the Company effective October 1, 2002. The standard requires companies to record a liability to recognize future obligations to remove assets. The Company has reviewed its significant franchises and easements and other documents to determine whether any include provisions requiring removal of assets. No significant obligations have been identified, and adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 144.    The FASB has issued FAS No. 144, titled "Accounting for the Impairment or Disposal of Long-Lived Assets." This standard is effective for fiscal years beginning after December 15, 2001, and has been adopted by the Company effective October 1, 2002. The standard provides for the recognition and measurement of an impairment loss if it is determined the carrying amount of a long-lived asset is not recoverable, and exceeds its fair value. It also identifies events or changes in circumstances that would require a test for recoverability. Adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 145.    The FASB has issued FAS No. 145, titled "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." This standard is effective for fiscal years beginning after May 15, 2002, and has been adopted by the Company effective October 1, 2002. Adoption of this standard did not have a significant impact on the Company's financial statements.

        FAS No. 146.    The FASB has issued FAS No. 146, titled "Accounting for costs associated with exit or disposal activities." This standard is effective for exit or disposal activities initiated after December 31, 2002, and will be adopted by the Company effective January 1, 2003. The Company has not determined whether the adoption of this statement will have a significant impact on its financial statements.

28


Note 3—Earnings per Share

        The following table sets forth the calculation of earnings per share as prescribed in FAS No. 128.

 
   2002
   2001
   2000
 
   (In thousands except per share data)
Net income before preferred dividends   $ 10,762   $ 17,236   $ 15,374
Less: Preferred dividends     —     —     4
   
 
 
Net Income   $ 10,762   $ 17,236   $ 15,370
   
 
 
Weighted average shares outstanding     11,045     11,045     11,045
Plus: Issued on assumed exercise of stock options     19     22     5
   
 
 
Weighted average shares outstanding assuming dilution     11,064     11,067     11,050
   
 
 
Earnings per common share, basic   $ 0.97   $ 1.56   $ 1.39
   
 
 
Earnings per common share, diluted   $ 0.97   $ 1.56   $ 1.39
   
 
 

        The only dilutive securities are the stock options described in Note 6.

Note 4—Utility Plant

        Utility plant at September 30, 2002 and 2001 consists of the following components:

 
   2002
   2001
 
   (Dollars in thousands)
Distribution plant   $ 449,430   $ 432,101
Transmission plant     14,693     14,693
General plant     36,784     37,215
Intangible plant     212     212
Nondepreciable plant     4,007     4,010
   
 
    $ 505,126   $ 488,231
   
 

Note 5—Common Stock

        At September 30, 2002, shares of common stock are reserved for issuance as follows:

 
   Number
of shares
Employee Savings Plan and Retirement Trust (401(k) plan)   119,764
Dividend Reinvestment Plan   51,340
Director Stock Award Plan   4,112
Stock Incentive Plan (Note 6)   437,596
   
    612,812
   

        The price of shares issued to the above plans is determined by the market price of shares on the day of, or immediately preceding the issuance date. The Company's practice is to purchase shares on the open market for these plans rather than issue new shares.

        Holders of Common Stock have rights ("Rights") to purchase shares of Series Z Preferred Stock on the basis of one Right for each share of Common Stock. The Rights may not be exercised and will be attached to and trade with shares of Common Stock until the Distribution Date, which will occur on the earlier of (i) the tenth day following a public announcement that there has been a "Share Acquisition", i.e., that a person or group (other than the Company and certain other persons) has

29


acquired or obtained the right to acquire 20% or more of the outstanding Common Stock and (ii) the tenth business day following the commencement or announcement of certain offers to acquire beneficial ownership of 30% or more of the outstanding Common Stock. Subject to restrictions on exercisability while the Rights are redeemable, each Right entitles the holder to buy from the Company one one-hundredth of a share of Series Z Preferred Stock at a price of $85, subject to adjustment. Upon the occurrence of a Share Acquisition, and provided that all necessary regulatory approvals have been obtained, each Right will thereafter entitle the holder (other than the acquiring person or group and transferees) to buy from the Company for $85, shares of Common Stock having a market value of $170, subject to adjustment.

Note 6—Stock Compensation Plan

        Under the Company's stock incentive plan, officers and other key management employees may be granted options to purchase stock. The grants vest 1/3 per year over three years. Options granted in 1999, 2000, and 2001 expire five years after the grant date. Options granted in 2002 expire ten years from the grant date. The weighted average remaining life of options outstanding at September 30, 2002 is 2.8 years.

        The following table summarizes the grants under option at September 30:

 
   2002
   2001
   2000
 
   Wtd. Avg.
Exercise
Price
   No. Shares
Under
Option
   Wtd. Avg.
Exercise
Price
   No. Shares
Under
Option
   Wtd. Avg.
Exercise
Price
   No. Shares
Under
Option
Balance at October 1   $ 16.81   142,966   $ 15.90   90,100   $ 16.50   38,000
Options granted   $ 20.84   63,000   $ 18.57   58,900   $ 14.94   53,100
Options cancelled         7,166                   1,000
Options exercised   $ 16.62   6,370   $ 15.63   6,034   $ —   —
   
 
 
 
 
 
Balance at September 30   $ 18.04   192,430   $ 16.81   142,966   $ 15.90   90,100
   
 
 
 
 
 
Exercisable at September 30   $ 16.39   79,989   $ 15.86   43,033   $ 16.50   12,667
   
 
 
 
 
 
Weighted average fair value of options granted during the fiscal year   $ 2.51       $ 2.90       $ 2.56    
   
     
     
   

        The fair value was estimated at the date of the grants using a Black-Scholes option pricing model using the following assumptions:

 
   Options granted during
 
   2002
   2001
   2000
Dividend yield   4.61%   4.79%   5.49%
Expected volatility   17%   24%   23%
Expected life   7.5 years   5 years   5 years
Risk-Free interest rate   4.09%   4.12%   5.73%

        The Company accounts for stock-based compensation using APB Opinion No. 25, "Accounting for Stock Issued to Employees". Under this method, compensation cost is recognized on the excess, if any, of the market price of the stock at grant date over the exercise price of the option. The exercise price of each grant was equal to the market price at the respective grant date, therefore no compensation expense has been recorded in connection with the Plan. Under FAS No. 123, "Accounting for Stock-Based Compensation," compensation expense is determined based on the fair value of the award and is

30


recognized over the vesting period. Had compensation expense been determined in accordance with FAS 123, the Company's net income would have been as follows:

 
   2002
   2001
   2000
Proforma net income   $ 10,633   $ 17,103   $ 15,294
Proforma earnings per share                  
  Basic   $ 0.96   $ 1.55   $ 1.38
  Diluted   $ 0.96   $ 1.55   $ 1.38

Note 7—Notes Payable and Commercial Paper

        The Company's short-term borrowing needs are met with a $50,000,000 revolving credit agreement with one of its banks. This agreement has a 0.16% annual commitment fee and a term that expires in 2004. The Company also has a $10,000,000 uncommitted bank credit line.

 
   2002
   2001
   2000
 
   (Dollars in thousands)
Amount outstanding at September 30   $ —   $ 40,000   $ 1,500
Average daily balance outstanding   $ 7,973   $ 23,699   $ 2,670
Average interest rate, excluding commitment fee     3.01%     5.01%     6.08%
Maximum month end amount outstanding   $ 46,000   $ 44,500   $ 10,213

        Various debt and credit agreements restrict the Company and its subsidiaries as to indebtedness, payment of cash dividends on common stock, and other matters. Under the most conservative restriction, approximately $12,368,000 is available for payment of dividends as of September 30, 2002.

Note 8—Long-Term Debt

        Long-term debt at September 30, 2002 and 2001 consists of the following:

 
   2002
   2001
 
   (Dollars in thousands)
Medium-term notes:            
  7.32% due Aug. 2004     22,000     22,000
  7.18% due Oct. 2004     4,000     4,000
  8.38% due Jan. 2005     5,000     5,000
  8.35% due Jul. 2005     5,000     5,000
  8.50% due Oct. 2006     8,000     8,000
  8.06% due Sep. 2012     14,000     14,000
  8.10% due Oct. 2012     5,000     5,000
  8.11% due Oct. 2012     3,000     3,000
  7.95% due Feb. 2013     4,000     4,000
  8.01% due Feb. 2013     10,000     10,000
  7.95% due Feb. 2013     10,000     10,000
  7.48% due Sep. 2027     20,000     20,000
  7.098% due Mar. 2029     15,000     15,000
  7.50% Thirty-year notes due November 2031     39,930     —
   
 
Total long-term debt   $ 164,930   $ 125,000
   
 

        None of the long-term debt includes sinking fund requirements. Annual obligations for redemption of long-term debt are as follows: None in fiscal year 2003, $22,000,000 in fiscal year 2004, $14,000,000 in fiscal year 2005, none in fiscal year 2006, $8,000,000 in fiscal year 2007, and $120,930,000 thereafter.

31

        There are $125 million Medium-Term Notes (MTN's) outstanding as of September 30, 2002. The $40 million Thirty-Year Notes were issued under a 2001 shelf registration providing ability to issue up to $150 million long-term debt and equity securities. That registration statement has $110 million remain available for issuance.

Note 9—Income Taxes

        The provision for income tax expense consists of the following:

 
   2002
   2001
   2000
  
 
   (Dollars in thousands)

  
Current tax expense   $ 2,850   $ 7,875   $ 8,269  
Deferred tax expense     3,137     1,606     984  
Amortization of deferred investment tax credits     (206 )   (203 )   (202 )
   
 
 
 
    $ 5,781   $ 9,278   $ 9,051  
   
 
 
 

        A $4,205,000 tax benefit associated with a charge related to accrual of minimum pension liability has been recorded in Other Comprehensive Income (OCI) for the year ended September 30, 2002. For fiscal year 2001 a tax benefit of $2,341,000 was included in OCI. See Note 10 for more information.

        A reconciliation between income taxes calculated at the statutory federal tax rate and income taxes reflected in the financial statements is as follows:

 
   2002
   2001
   2000
  
 
   (Dollars in thousands)

  
Statutory federal income tax rate     35 %   35 %   35 %
Income tax calculated at statutory federal rate   $ 5,790   $ 9,282   $ 8,549  
Increase (decrease) resulting from:                    
  State income tax, net of federal tax benefit     130     200     191  
  Non-normalized depreciation differences     355     343     407  
  Amortization of investment tax credits     (206 )   (203 )   (202 )
  Other     (288 )   (344 )   106  
   
 
 
 
    $ 5,781   $ 9,278   $ 9,051  
   
 
 
 
Effective tax rate     34.9 %   35.0 %   37.1 %

        Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. There is no deferred tax provision for temporary differences related to depreciation of pre-1981 assets because with respect to those assets, there is no regulatory recognition of deferred tax accounting.

        Deferred tax assets and liabilities are calculated under FAS No. 109, "Accounting for Income Taxes". FAS No. 109 requires recording deferred tax balances, at the currently enacted tax rate, for all temporary differences between the book and tax bases of assets and liabilities, including temporary differences for which no deferred taxes had been previously provided because of use of flow-through tax accounting for rate-making purposes. Because of prior and expected future rate-making treatment of temporary differences for which flow-through accounting has been utilized, a regulatory liability for income taxes payable through future rates related to those temporary differences has been established. At September 30, 2002, the balance of this regulatory liability is $4,138,000.

32


        The tax effects of significant items comprising the Company's net deferred tax liability at September 30, 2002 and 2001 are as follows:

 
   2002
   2001
 
   (Dollars in thousands)
Current Amount:            
  Deferred assets:            
    Allowance for doubtful accounts   $ 425   $ 559
    Accrued liabilities     1,148     —
    Other     75     —
   
 
    $ 1,648   $ 559
   
 
Non-current Amounts:            
  Deferred tax liabilities:            
    Basis differences on net fixed assets   $ 26,385   $ 21,506
    Debt refinancing costs     1,041     1,229
    Retirement benefit obligations     1,360     845
   
 
      28,786     23,580
   
 
  Deferred tax assets:            
    Retirement benefit obligations     1,911     1,477
    Other comprehensive income     6,532     2,341
    Other     44     113
   
 
      8,487     3,931
   
 
  Net non-current deferred tax liability   $ 20,299   $ 19,649
   
 

Note 10—Retirement Plans

        The Company's noncontributory defined benefit pension plan covers substantially all employees over 21 years of age with one year of service. The benefits are based on a formula which includes credited years of service and the employee's annual compensation. The Company also provides executive officers with supplemental retirement, death, and disability benefits. Under the plan, vesting occurs on a stepped basis, with full vesting at age 55 and completing either five years of participation under the plan or seventeen years of employment with the Company, upon death, or upon a change in control. The plan supplements the benefit received through Social Security and the defined benefit pension plan so that the total retirement benefits are equal to 70% of the executive's highest salary during any of the five years preceding retirement. The plan also provides a death benefit equivalent to ten years of vested benefits.

        The Company's health care plan provides Postretirement Benefits Other than Pensions (PBOP), consisting of medical and prescription drug benefits, to its retired employees hired prior to June 1, 1992, and their eligible dependents.

        The pension plan was amended, effective January 1, 2000, so that for salaried employees, the past service benefit calculation was changed to the five-year period ended December 31, 1998 from the five-year period ended December 31, 1994. In fiscal 2001, the retiree medical plan was amended to increase the amount of health care and prescription drugs costs paid by plan participants.

33


        The following tables set forth the pension and health care plan disclosures:

Components of net periodic benefit cost

 
   Pension Benefits
   Other Benefits
  
 
   2002
   2001
   2000
   2002
   2001
   2000
  
Service cost   $ 1,569   $ 1,928   $ 1,765   $ 522   $ 484   $ 469  
Interest cost     3,630     3,373     3,187     2,153     1,949     1,739  
Expected return on plan assets     (3,927 )   (4,171 )   (3,841 )   (721 )   (903 )   (833 )
Amortization of transition obligation     100     100     102     657     657     657  
Amortization of prior service cost     499     500     481     (72 )   —     —  
Recognized net actuarial loss/(gain)     24     —     1     298     (124 )   (218 )
   
 
 
 
 
 
 
Net periodic benefit cost   $ 1,895   $ 1,730   $ 1,695   $ 2,837   $ 2,063   $ 1,814  
   
 
 
 
 
 
 
 
   Pension Benefits
   Other Benefits
  
 
   2002
   2001
   2002
   2001
  
 
   (Dollars in thousands)

  
Change in benefit obligations                          
Projected benefit obligation at beginning of year   $ 49,400   $ 44,407   $ 29,266   $ 24,401  
Service Cost     1,569     1,928     522     484  
Interest Cost     3,630     3,373     2,153     1,949  
Plan participants' contributions     —     —     —     —  
Amendments     4     —     (827 )      
Benefits paid     (2,222 )   (1,920 )   (1,339 )   (1,264 )
Changes in assumptions     3,568     2,356     —     —  
Actuarial (gain)/loss     940     (748 )   5,218     4,523  
   
 
 
 
 
Projected benefit obligation at end of year   $ 56,885   $ 49,400   $ 35,820   $ 29,266  
   
 
 
 
 
Change in Plan Assets                          
Fair value of plan assets at beginning of year   $ 40,566   $ 48,299   $ 8,695   $ 10,280  
Actual return on plan assets     (4,858 )   (8,250 )   (696 )   (1,188 )
Employer contributions     4,412     2,437     2,584     867  
Plan participants' contributions     —     —     —     —  
Benefits Paid     (2,222 )   (1,920 )   (1,338 )   (1,264 )
   
 
 
 
 
Fair value of plan assets at end of year   $ 37,898   $ 40,566   $ 9,245   $ 8,695  
   
 
 
 
 
Funded Status   $ (18,987 ) $ (8,834 ) $ (26,575 ) $ (20,571 )
Unrecognized prior service cost     2,505     3,004     (755 )   (827 )
Unrecognized net (gain)/loss     24,698     11,429     16,300     9,964  
Unrecognized transition obligation/(asset)     426     526     6,734     7,391  
   
 
 
 
 
Net amount recognized   $ 8,642   $ 6,125   $ (4,296 ) $ (4,043 )
   
 
 
 
 
Amounts recognized in the balance sheet consist of:                          
  Prepaid pension cost   $ 3,276   $ 3,047   $ —   $ —  
  Accrued pension (liability)     (15,526 )   (6,569 )   (4,296 )   (4,043 )
  Intangible asset     2,598     3,145           —  
  Accumulated other comprehensive (income) loss     18,294     6,502           —  
   
 
 
 
 
  Net amount recognized   $ 8,642   $ 6,125   $ (4,296 ) $ (4,043 )
   
 
 
 
 

34

Weighted Average Assumptions

   2002
   2001
Discount rate   6.75%   7.50%
Average compensation increase   3.50%   4.50%
Expected rate of return on plan assets        
  Pension plan   8.25%   9.00%
  Supplemental executive retirement plan   8.25%   8.50%
  Postretirement medical benefit plan   8.25%   8.75%

        The assumed health care cost trend rate used in measuring the APBO at September 30, 2002 for medical costs is 9.0% for fiscal 2003, trending down to 5.5% in 2008. For prescription drug costs, the rate is 14.0% for 2003, trending down to 5.5% in 2010. A one percent change in the assumed health care cost trend rate would have the following effects as of September 30, 2002:

 
   One Percentage Point
  
 
   Increase
   Decrease
  
 
   (thousands)

  
Effect on service and interest cost   $ 468   $ (380 )
Effect on postretirement benefit obligation as of 10/1/2001   $ 4,449   $ (3,667 )
Effect on postretirement benefit obligation as of 9/30/2002   $ 5,490   $ (4,521 )

        During fiscal years 2001 and 2002, the value of the pension plan assets declined, reflecting the general downward trend in common stock values. The decline in asset values, along with a decrease in the assumed discount rate to 6.75% from 7.50% and a reduction in the earnings assumption rate to 8.25% from 9.0%, resulted in an unfunded accumulated benefit obligation. To recognize this liability, the Company recorded a minimum pension liability adjustment of $9,647,000 in 2001 and $11,875,000 in 2002 in accordance with the provisions of FAS No. 87.

        The Company has an Employee Savings Plan and Retirement Trust (401(k) plan). All employees 21 years of age or older with one full year of service are eligible to enroll in the plan. Under the terms of the plan, the Company will match contributions at a rate of 75% of each employee's contribution up to 6% of the employee's compensation, as defined. The Company recognized costs for contributions to this plan of $755,000, $842,000, and $889,000, for 2002, 2001 and 2000, respectively.

Note 11—Commitments and Contingencies

Gas Service Contracts

        The Company has entered into various long-term contracts for natural gas supply, transportation, storage, and peaking services. These contracts are intended to provide adequate supplies of gas firm service to core customers and to meet obligations under long-term non-core customer agreements, and to provide that adequate capacity is available on interstate pipelines for the delivery of these supplies. These contracts have maturities ranging up to 25 years, and generally provide for monthly and annual fixed demand charges and minimum purchase obligations.

35


        The Company's minimum obligations under these contracts are set forth in the following table. The amounts are based on current contract price terms and estimated commodity prices, which are subject to change:

Fical Year Ending September 30
   Firm Gas
Supply
   Interstate
Pipeline
Transportation
   Storage
and Peaking
Service
   Total
 
   (Dollars in thousands)
2003   $ 159,028   $ 26,206   $ 2,140   $ 187,374
2004     153,734     26,206     1,870     181,810
2005     33,465     26,206     1,491     61,162
2006     27,448     26,206     1,491     55,145
2007     27,448     26,206     1,491     55,145
Thereafter     27,448     216,105     10,563     254,116
   
 
 
 
    $ 428,571   $ 347,135   $ 19,046   $ 794,752
   
 
 
 

        Purchases under these contracts for fiscal 2002, 2001, and 2000, including commodity purchases, as well as demand charges have been as follows:

 
   Firm Gas
Supply
   Interstate
Pipeline
Transportation
   Storage
and Peaking
Service
   Total
 
   (Dollars in thousands)
2002   $ 141,093   $ 25,210   $ 2,140   $ 168,443
2001   $ 166,912   $ 35,276   $ 3,030   $ 205,218
2000   $ 69,168   $ 31,852   $ 3,423   $ 104,443

        During the quarter ended December 31, 2001, the Company exercised its right to terminate its gas supply contracts with Enron based on Enron's insolvency and other reasons, including concerns about its ability to perform. These contracts supplied part of the natural gas portfolio used to serve certain non-core customers. The supply has been replaced with contracts with other suppliers. Enron Canada Corp., a Canadian entity, is disputing Cascade's right to terminate one of the Enron gas supply contracts. On February 6, 2002, Enron Canada sent a letter to the Company claiming that the Company owes it a termination payment in the amount of $3.7 million. Management believes the termination was fully justified and intends to vigorously contest any payment. However, the circumstances surrounding the termination are complex, and the ultimate result is uncertain. Based on management's analysis of the latest information, the Company recorded a fiscal third-quarter charge to earnings in the amount of $2.8 million with respect to Enron Canada's claim. Also refer to Note 14 "Subsequent Events (Unaudited)".

Environmental Matters

        There are two claims against the Company for as yet unknown costs for clean up of alleged environmental contamination related to manufactured gas plant sites that were previously operated by companies, which were subsequently merged into Cascade.

        The first claim was received in 1995, and relates to a site in Oregon. An investigation has shown that contamination does exist, but there is currently not enough information available to estimate the potential liability associated with this claim. It is expected that other parties will participate in the clean up costs. Through the end of the fiscal year the amounts spent, primarily on investigation and containment, have been immaterial.

        The second claim was received in 1997, and relates to a site in Washington. An investigation has determined there is evidence of contamination at the site, but there is also evidence of an oil line

36


crossing the property, operated by an unrelated party, which may have also contributed to the contamination. There is currently not enough information available to estimate the potential liability associated with this claim. The party who originally made this claim has not been actively pursuing it.

        Management intends to pursue reimbursement from its insurance carriers, and recovery from its customers through increased rates, for any remediation costs for which the Company is determined to be liable. There is precedent for such recovery through increased rates, as both the WUTC and OPUC have previously allowed regulated utilities to increase customer rates to recover similar costs. No claims now pending, in the opinion of management, are expected to have a material effect on the Company's financial position, results of operations, or liquidity.

Litigation and Other Contingencies

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

        In the fourth quarter of fiscal 2002 a child suffered a fatal injury while playing on a meter barrier owned by the Company, located on the property of one of the Company's commercial customers. Circumstances surrounding the accident are currently being investigated, and there is currently not enough information available to estimate the Company's potential liability associated with this accident, but its self-insured exposure with respect to such claims is $1 million. Also refer to Note 14 "Subsequent Events (Unaudited)".

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

Note 12—Fair Value of Financial Instruments

        The following estimated fair value amounts have been determined by the Company, using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, these estimates are not necessarily indicative of the amounts that the Company could realize in a current market exchange. Thus, the use of different market assumptions or estimation methodologies may have a material effect on the estimated fair value amounts. The estimated fair values have been determined by using interest rates that are currently available to the Company for issuance of instruments with similar terms and remaining maturities. The estimated fair value amounts, at September 30, 2002 and 2001, of financial instruments whose values are sensitive to market conditions are set forth in the following table:

 
   2002
   2001
 
   Carrying
Amount
   Estimated
Fair Value
   Carrying
Amount
   Estimated
Fair Value
 
   (Dollars in thousands)
Long-term Debt   $ 164,930   $ 191,231   $ 125,000   $ 142,585

37

Note 13—Interim Results of Operations (unaudited)

 
   Quarter Ended
 
   9/30/2002
   6/30/2002
   3/31/2002
   12/31/2001
 
   (thousands except per share data)
Operating revenues   $ 39,041   $ 56,815   $ 122,361   $ 102,761
Gas costs and revenue taxes     24,891     42,562     88,905     74,118
   
 
 
 
Operating margin     14,150     14,253     33,456     28,643
Cost of operations     15,256     14,890     15,282     15,911
   
 
 
 
Income (loss) from operations     (1,106 )   (637 )   18,174     12,732
Interest and other, net     3,248     3,224     3,247     2,901
   
 
 
 
Income (loss) before income taxes     (4,354 )   (3,861 )   14,927     9,831
Income taxes     (1,846 )   (1,409 )   5,448     3,588
   
 
 
 
Net income (loss)   $ (2,508 ) $ (2,452 ) $ 9,479   $ 6,243
Other comprehensive income (loss)     (7,587 )   —     —     —
   
 
 
 
Comprehensive Income (loss)   $ (10,095 ) $ (2,452 ) $ 9,479   $ 6,243
   
 
 
 
Earnings (loss) per common share                        
  Basic   $ (0.23 ) $ (0.22 ) $ 0.86   $ 0.57
   
 
 
 
  Diluted   $ (0.23 ) $ (0.22 ) $ 0.86   $ 0.56
   
 
 
 

 
 
Quarter Ended
 
   9/30/2001
   6/30/2001
   3/31/2001
   12/31/2000
Operating revenues   $ 42,036   $ 64,085   $ 124,728   $ 104,965
Gas costs and revenue taxes     28,544     42,960     93,933     75,345
   
 
 
 
Operating margin     13,492     21,125     30,795     29,620
Cost of operations     14,958     15,244     14,172     13,674
   
 
 
 
Income (loss) from operations     (1,466 )   5,881     16,623     15,946
Interest and other, net     2,629     2,643     2,472     2,726
   
 
 
 
Income (loss) before income taxes     (4,095 )   3,238     14,151     13,220
Income taxes     (1,894 )   1,182     5,165     4,825
   
 
 
 
Net income (loss)   $ (2,201 ) $ 2,056   $ 8,986   $ 8,395
Other comprehensive income (loss)     (4,161 )   —     —     —
   
 
 
 
Comprehensive Income (loss)   $ (6,362 ) $ 2,056   $ 8,986   $ 8,395
   
 
 
 
Earnings (loss) per common share—basic and diluted   $ (0.20 ) $ 0.19   $ 0.81   $ 0.76
   
 
 
 

Note 14—Subsequent Events (unaudited)

        Enron Contract Termination:    The following information is supplemental to disclosures in Note 11 regarding the termination of the Company's two gas supply contracts with Enron.

        On December 2, 2002, a representative of the Enron bankruptcy estate, although not contesting Cascade's right to terminate its contract with Enron North America, asserted a claim for a termination payment under that contract in the amount of $1,400,000. The Enron Canada and the Enron North America claims are separate, and while they involve some similar issues, there are also differences significant enough to require an independent assessment of the Enron North America claim.

38


Management has not received any written details of the claim but is currently in the process of conducting that assessment and intends to vigorously contest this claim.

        Neither Enron Canada nor Enron North America has commenced any arbitration or court proceedings.

Settlement in Fatality Case:

        In the fourth quarter of fiscal 2002 a child suffered a fatal injury while playing on a meter barrier owned by the Company, located on the property of one of the Company's commercial customers. In December 2002 a settlement of all plaintiffs' claims was agreed to in consideration of a $750,000 payment. The Company and its co-defendant have agreed to each pay $375,000 currently, and to resolve the allocation of the total settlement payment between them in future negotiations or proceedings.

39



SCHEDULE II


CASCADE NATURAL GAS CORPORATION

VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)

Column A

   Column B

   Column C

   Column D

   Column E
 
    
  
Additions
    
    
Description
   Balance at
Beginning
of Period
   Charged to
Costs and
Expenses
   Charged to
Other
Accounts
   Deductions
(Note)
   Balance at
End of
Period
Allowance for Doubtful Accounts:                        
  Year ended:                        
    September 30, 2000   $ 622   561   —   476   $ 707
    September 30, 2001   $ 707   713       516   $ 904
    September 30, 2002   $ 904   1,250       1,028   $ 1,126

Reserve—Notes Receivable
 
 
 
 
 
 
 
 
 
 
 
 
    September 30, 2000   $ 119   520   —   —   $ 639
    September 30, 2001   $ 639   4           $ 643
    September 30, 2002   $ 643   (155 )     388   $ 100

        Note: Accounts written off, net of recoveries.

40


Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

        None.


PART III

Item 10. Directors and Executive Officers of the Registrant

        Reference is made to the information regarding directors under the caption "Election of Directors" on pages 1 through 3 and the caption "Section 16(a) Beneficial Ownership Reporting Compliance" on page 5 of the Proxy Statement sent to shareholders for the 2003 Annual Meeting (the 2003 Proxy Statement), which information is incorporated herein by reference. Certain information concerning the executive officers of the Company is set forth in Part I, under the caption "Executive Officers of the Registrant."


Item 11. Executive Compensation

        Reference is made to the information regarding executive compensation set forth in the 2003 Proxy Statement under "Executive Compensation" on pages 9 through 10, "Retirement Plan" on page 11, "Executive Supplemental Retirement Income Plan" on pages 11 and 12, "Employment Agreements" on page 12, "Supplemental Benefit Trust" on pages 12 and 13, "Director Compensation" on page 13, and under "Compensation Committee Interlocks and Insider Participation" on page 13, which information is incorporated herein by reference.


Item 12. Security Ownership of Certain Beneficial Owners and Management

        Reference is made to the information regarding security ownership of certain beneficial owners and management under the caption "Security Ownership of Certain Beneficial Owners and Management" on pages 4 and 5 of the 2003 Proxy Statement (excluding the information under the subheading "Section 16(a) Beneficial Ownership Reporting Compliance"), which information is incorporated herein by reference.

        The following table sets forth information as of September 30, 2002 with respect to compensation plans (including individual compensation arrangements) under which equity securities of the registrant are authorized for issuance:


Equity Compensation Plan Information

Plan Category
   Number of securities to be issued upon exercise of outstanding options, warrants and rights
(a)
   Weighted-average exercise price of outstanding options, warrants and rights
(b)
   Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(c)
Equity compensation plans approved by security holders   192,430   $ 18.04   245,166
Equity compensation plans not approved by security holders   None     None   None
   
 
 
Total   192,430   $ 18.04   245,166
   
 
 

41


Item 13. Certain Relationships and Related Transactions

        Reference is made to the information regarding certain relationships and transactions under the caption "Compensation Committee Interlocks and Insider Participation" on page 13 of the 2003 Proxy Statement, which information is incorporated herein by reference.


Item 14. Controls and Procedures

        The Company maintains controls and procedures designed to ensure that information required to be disclosed in the reports that 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 performed within 90 days of the filing date of this report, the Chief Executive Officer and Chief Financial Officer of the Company concluded that the Company's disclosure controls and procedures were effective.

        The Company made no significant changes in its internal controls or in other factors that could significantly affect those controls subsequent to the date of the evaluation of those controls by the Chief Executive Officer and Chief Financial Officer.


Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K

(a)
1.    Financial Statements (Included in Part II of this report):
(a)
2.    Financial Statement Schedule (Included in Part II of this report):
(a)
3.    Exhibits:

        Reference is directed to the index to exhibits following the signature page of this report. Each management contract or compensatory plan or arrangement required to be filed as an exhibit to this report is identified in the list.

(b)
Reports on Form 8-K:

        The registrant did not file any reports on Form 8-K during the fourth quarter of fiscal 2002.

42


SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) 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

Date: December 23, 2002
 
By:
J. D. Wessling

 Sr. Vice President—Finance, Chief Financial Officer

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Name
   Title
   Date

 
 
 
 
 
W. Brian Matsuyama
 		  Chairman of the Board,
President and Chief Executive Officer and Director
(Principal Executive Officer)		   December 23, 2002

J. D. Wessling
 
Sr. Vice President—Finance,
Chief Financial Officer
(Principal Financial Officer)
 
December 23, 2002

James E. Haug
 
Controller
(Principal Accounting Officer)
 
December 23, 2002

Douglas G. Thomas
 
Director
 
December 23, 2002

Thomas E. Cronin
 
Director
 
December 23, 2002

David A. Ederer
 
Director
 
December 23, 2002

Howard L. Hubbard
 
Director
 
December 23, 2002

 
 
 
 
 

43


Larry L. Pinnt
 
Director
 
December 23, 2002

Brooks G. Ragen
 
Director
 
December 23, 2002

Carl Burnham, Jr.
 
Director
 
December 23, 2002

Mary E. Pugh
 
Director
 
December 23, 2002

44

CERTIFICATION ACCOMPANYING PERIODIC REPORT
PURSUANT TO SECTION 302
OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. 1350)

        I, W. Brian Matsuyama, certify that:

        1. I have reviewed this annual report on Form 10-K of Cascade Natural Gas Corporation;

        2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

        3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operation and cash flows of the registrant as of, and for, the periods presented in this annual report;

        4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

        a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

        b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

        c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

        a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

        b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: December 23, 2002


By:
W. Brian Matsuyama

 Chairman, President and CEO
(Principal Executive Officer)

45

        I, J. D. Wessling, certify that:

        1. I have reviewed this annual report on Form 10-K of Cascade Natural Gas Corporation;

        2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

        3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operation and cash flows of the registrant as of, and for, the periods presented in this annual report;

        4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

        a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

        b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

        c) Presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

        5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

        a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

        b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

        6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: December 23, 2002


By:
J. D. Wessling

 Senior Vice President—Finance and CFO
(Principal Financial Officer)

46


INDEX TO EXHIBITS

Exhibit
No.
   Description
3.1   Restated Articles of Incorporation of the Registrant as amended through March 28, 1996. Incorporated by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed July 19, 1996.

3.2
 
Restated Bylaws of the Registrant. Incorporated by reference to Exhibit 3.2 to the Registrant's current report on Form 8-K filed July 19, 1996.

4.1
 
Indenture dated as of August 1, 1992, between the Registrant and The Bank of New York relating to Medium-Term Notes. Incorporated by reference to Exhibit 4 to the Registrant's current report on Form 8-K dated August 12, 1992.

4.2
 
First Supplemental Indenture dated as of October 25, 1993, between the Registrant and The Bank of New York relating to Medium-Term Notes. Incorporated by reference to Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the quarter ended June 30, 1993.

4.3
 
Rights Agreement dated as of March 19, 1993, between the Registrant and Harris Trust and Savings Bank. Incorporated by reference to Exhibit 2 to the Registrant's registration statement on Form 8-A dated April 21, 1993.

4.4
 
First Amendment to Rights Agreement dated June 15, 1993, between the Registrant and The Bank of New York. Incorporated by reference to Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the quarter ended June 30, 1993.

10.1
 
1998 Stock Incentive Plan of the Registrant.* Incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1998.

10.2
 
Service Agreement (Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (1993 Form 10-K).

10.3
 
Service agreement (assigned Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.3 to the Registrant's 1993 Form 10-K.

10.4
 
Service Agreement (Liquefaction—Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.4 to the Registrant's 1993 Form 10-K.

10.5
 
Gas Purchase Agreement dated November 1, 1990, between Mobil Oil Canada and the Registrant. Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991.

10.5.1
 
Amended dated August 30, 2001, to the Gas Purchase Agreement dated November 1, 1990, between Duke Energy Trading and Marketing, L.L.C. (successor to Mobil Oil Canada) and the Registrant. Incorporated by reference to Exhibit 10.5.1 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

 
 
 

47


10.6
 
Consent to Assignments, Dated June 1, 1997, which assigns from Westcoast Gas Services Inc. (WGSI), to Engage Energy Canada, L.P. (Engage) all the rights and obligations as specified in the contracts contained herein as Exhibit Nos. 10.7, and 10.22. Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1997 (1997 Form 10-K).

10.7
 
Natural Gas Sales Agreement dated November 1, 1998, between Engage Energy US L.P., and the Registrant. Incorporated by reference to Exhibit 10.7 to the Registrant's 1999 Form 10-K.

10.8
 
Natural Gas Transaction Confirmation (GTC) dated November 21, 2001, and executed on April 3, 2002, between Engage Energy Canada, L.P., and the Registrant, covering the period November 1, 2003 to November 1, 2008. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

10.9
 
Intentionally omitted.

10.10
 
Base Contract for Short-Term Sale and Purchase of Natural Gas dated August 1, 1999, between Kimball Energy Corporation and the Registrant. Incorporated by reference to Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001.

10.11
 
Gas transportation agreement between Pacific Gas Transmission Company and the Registrant dated as of April 30, 1997. Incorporated by reference to Exhibit 10.11 to the Registrant's 1997 10-K.

10.12
 
Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(1) to the Registrant's registration statement on Form S-2, No. 33-52672 (1992 Form S-2).

10.12.1
 
Amendments dated August 20, 1992, November 1, 1992, October 20, 1993, and December 17, 1993, to Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.12.1 to the Registrant's 1993 Form 10-K.

10.13
 
Firm Transportation Service Agreement dated April 25, 1991, between Pacific Gas Transmission Company and the Registrant (1993 expansion). Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2.

10.14
 
Firm Transportation Service Agreement dated October 27, 1993, between Pacific Gas Transmission Company and the Registrant. Incorporated by reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K.

10.15
 
Intentionally omitted.

10.16
 
Natural gas purchase agreement dated April 26, 2001, between Sempra Energy and the Registrant. Incorporated by reference to Exhibit 10.16 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

10.17
 
Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10(v) to the 1992 Form S-2.

10.17.1
 
Second amendment to the agreement for the release of Jackson Prairie Storage Capacity dated as of July 30, 1997, amending the Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10.17.1 to the Registrant's 1997 Form 10-K.

 
 
 

48


10.18
 
Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by Reference to Exhibit 10.18 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (1994 Form 10-K).

10.19
 
Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant.Incorporated by reference to Exhibit 10.19 to the Registrant's 1994 Form 10-K.

10.20
 
Service Agreement (Firm Redelivery Transportation Agreement under rate Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.20 to the Registrant's 1994 Form 10-K.

10.21
 
Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant. Incorporated by reference to Exhibit 10.21 to the Registrant's 1994 Form 10-K.

10.21.2
 
Amended Exhibit A, effective October 1, 2002, to Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant. Incorporated by reference to Exhibit 10.21.2 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

10.21.3
 
Amended Exhibit A, effective October 1, 2003, to Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant. Incorporated by reference to Exhibit 10.21.3 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

10.22
 
Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Westcoast Gas Services, Inc. and the Registrant Incorporated by reference to Exhibit 10.22 to the Registrant's 1994 Form 10-K.

10.22.1
 
Amendment dated November 20, 2001, to Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Engage Energy Canada L.P. and Registrant. Incorporated by reference to Exhibit 10.22.1 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 2001. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT.

10.23
 
Firm Transportation Service Agreement dated November 4, 1994, between Pacific Gas Transmission and the Registrant, effective November 1, 1995. Incorporated by reference to Exhibit 10.23 to the Registrant's 1994 Form 10-K.

10.24
 
Firm Transportation Agreement dated August 1, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.24 to the Registrant's 1994 Form 10-K.

10.25
 
Prearranged Permanent Capacity Release of Firm Natural Gas Transportation Agreements dated November 30, 1993 between Tenaska Gas Co., Tenaska Washington Partners, L.P. and the Registrant. Incorporated by reference to Exhibit 10.25 to the Registrant's 1994 Form 10-K.

10.26
 
Agreement for Peak Gas Supply Service dated August 1, 1992, between Tenaska Gas Co., Tenaska Washington Partners, L.P., and the Registrant. Incorporated by reference to Exhibit 10.26 to the Registrant's 1994 Form 10-K.

 
 
 

49


10.27
 
Intentionally omitted.

10.28
 
Intentionally omitted.

10.29
 
1991 Director Stock Award Plan of the Registrant.* Incorporated by reference to Exhibit 10(n) to the 1992 Form S-2.

10.30
 
Executive Supplemental Retirement Income Plan of the Registrant and Supplemental Benefit Trust as amended and restated as of May 1, 1989, as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by reference to Exhibit 10(o) to the 1992 Form S-2.

10.31
 
Form of employment agreement between the Registrant and W. Brian Matsuyama, and each other executive officer of the Registrant.* Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.

10.32
 
Intentionally omitted.

12.
 
Statement regarding computation of ratio of earnings to fixed charges and preferred dividend requirements.

21.
 
A list of the Registrant's subsidiaries is omitted because the subsidiaries considered in the aggregate as a single subsidiary do not constitute a significant subsidiary.

23.
 
Consent of Deloitte & Touche LLP to the incorporation of their report in the Registrant's registration statements.

99.1
 
Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*
Management contract or compensatory plan or arrangement.

50



QuickLinks

CASCADE NATURAL GAS CORPORATION Annual Report to the Securities and Exchange Commission on Form 10-K For the Fiscal Year Ended September 30, 2002
Table of Contents
Part I
Part II
CASCADE NATURAL GAS CORPORATION CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
CASCADE NATURAL GAS CORPORATION CONSOLIDATED BALANCE SHEETS
CASCADE NATURAL GAS CORPORATION CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
CASCADE NATURAL GAS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CASCADE NATURAL GAS CORPORATION VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
PART III
Equity Compensation Plan Information
SIGNATURES
CERTIFICATION ACCOMPANYING PERIODIC REPORT
INDEX TO EXHIBITS