-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, HP2I5pkJmCNo0F5cMaFTwb1WQA3puOki9ODgz68LvIAjJp5GkwcVOvNVVepfniwa AA1tHR734JoUJJqgU6YurQ== 0001047469-97-008938.txt : 19971230 0001047469-97-008938.hdr.sgml : 19971230 ACCESSION NUMBER: 0001047469-97-008938 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 11 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971229 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CASCADE NATURAL GAS CORP CENTRAL INDEX KEY: 0000018072 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 910599090 STATE OF INCORPORATION: WA FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-07196 FILM NUMBER: 97745142 BUSINESS ADDRESS: STREET 1: 222 FAIRVIEW AVE N CITY: SEATTLE STATE: WA ZIP: 98109 BUSINESS PHONE: 2066243900 MAIL ADDRESS: STREET 1: 222 FAIRVIEW AVENUE N CITY: SEATTLE STATE: WA ZIP: 98109 10-K 1 FORM 10-K FORM 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 /X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 1997 Commission file number: 1-7196 CASCADE NATURAL GAS CORPORATION (Exact name of Registrant as specified in its charter) Washington 91-0599090 ---------- ---------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 222 Fairview Avenue North Seattle, WA 98109 (206) 624-3900 ------------------ -------------- (Address of principal executive offices) (Registrant's telephone number including area code) Securities registered pursuant to Section 12(b) of the Act: Title of Each Class Name of Each Exchange on which Registered - ------------------- ----------------------------------------- Common Stock, Par Value $1 per Share New York Stock Exchange Preferred Stock Purchase Rights 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 X No ____ 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. ___ 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 30, 1997, was $184,028,000 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 11,000,737 as of November 30, 1997 DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's definitive proxy statement for its 1998 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, 1997 Table of Contents Page ---- Number - ------ Part I Item 1 - Business 3 Item 2 - Properties 10 Item 3 - Legal Proceedings 11 Item 4 - Submission of Matters to a Vote of Security Holders 11 Executive Officers of the Registrant 12 Part II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters 13 Item 6 - Selected Financial Data 14 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 7a- Quantitative and Qualitative Disclosures about Market Risk 21 Item 8 - Financial Statements and Supplementary Data 22 Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 43 Part III Item 10 - Directors and Executive Officers of the Registrant 43 Item 11 - Executive Compensation 43 Item 12 - Security Ownership of Certain Beneficial Owners and Management 43 Item 13 - Certain Relationships and Related Transactions 43 Part IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K 44 Signatures 45 Index to Exhibits 46 2 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 16% of its gas distribution revenues are from the state of Oregon. At September 30, 1997, there were 135,126 residential customers, 24,591 commercial customers, 347 firm industrial customers and 21 traditional interruptible customers, all of which are classified as core customers. In addition, there were 162 non-core customers. In the twelve month periods ended September 30, 1997 and September 30, 1996, residential and commercial customers accounted for 64% of the operating margin, and 20% of the total gas deliveries. The non-core customers (including transportation service) provided the remaining operating margin and throughput. 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 provide for annual review of gas prices for possible adjustment. To the extent that prices are changed 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, 80% of the cost changes between PGA effective dates is so deferred. The remaining 20% (increase or decrease) is absorbed by the Company. 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 1996 with both the WUTC and the OPUC. The IRP shows the Company's plan for the best set of supply and demand side resources that minimizes costs and has acceptable levels of deliverability risk over the twenty-year planning horizon. The IRP also sets forth possible growth scenarios for core customers and throughput 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 Company's investments in cost-effective demand side resources are recoverable in rates in both Washington and Oregon. 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 a general 3 rate case, 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), formerly Northwest Pipeline Corporation. 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 Pacific Gas Transmission Company (PGT) system. PGT owns and operates a gas transmission line that connects with the facilities of the Alberta Natural Gas Company, Ltd. at the international border near Kingsgate, British Columbia and extends through Washington and central Oregon into California. Presently, baseload requirements for Cascade's core market group are provided by six major gas supply contracts with various expiration dates from 1998 through 2008 and totaling 714,830 therms per day. Approximately 93% of the gas supplied pursuant to the contracts is from Canadian sources. The remainder is domestic. These contracts are supplemented by various service agreements to cover periods of peak demand including three storage agreements with Williams. One extends to October 31, 2014 and provides for 165,950 therms per day and a maximum, renewable inventory of 5,973,780 therms. The second with the Washington Water Power Company (WWP) has a primary term ending April 30, 2001 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 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. In addition to underground and LNG storage, Cascade has entered into contracts with two of its major industrial customers whereby each customer agrees to switch to alternate fuel allowing Cascade to reduce firm deliveries to that customer. Cascade then takes the end-user's firm gas supply and pipeline capacity to serve its core markets. In return, Cascade reimburses the end-user for the cost of its alternate fuel and pipeline capacity. Since the end-user is also a distribution customer of Cascade, the supply is already being delivered to Cascade's system and is merely diverted to other, core customers, allowing for even greater accommodation of late day demand spikes. Because the end-user's response is dictated by contract and firm gas supply and firm pipeline capacity is involved, this type of resource is highly flexible and reliable. The associated costs of this resource, including the loss of distribution revenue and depending upon the relative price of the alternate fuel, may be less expensive than the cycle cost of storage or maintaining pipeline capacity on a year-round basis, plus a seasonal firm gas supply in order to meet growth in peak day demand. Both of these agreements have met the test for the "least cost resource alternative" under Cascade's Integrated Resource Plan ("IRP") process. One such peak shaving agreement entitles Cascade to call on 150,000 therms per day up to a seasonal total of 3,000,000 therms. This contract expires on September 30, 2014. The second peak shaving agreement, which expires on April 30, 2014, entitles Cascade to call on a maximum of 500,000 therms per day and up to a seasonal total of 3,000,000 therms. 4 Commencing December, 1995, Cascade entered into two peaking service agreements with Canadian gas suppliers. These agreements provide for a maximum daily quantity of 250,000 therms on peak days and a renewable inventory of 6,000,000 therms. Cascade can call upon these two service agreements any day during the peak winter months of December, January and February. These service agreements, while less reliable than firm storage service, are more flexible than baseload gas supply contracts. Both agreements allow for same day nomination and city gate delivery at a competitive cost. Each agreement has a primary term of three years ending February, 1998. Cascade maintains a diversified portfolio of natural gas supplies. During 1997, Cascade purchased approximately 79% of its gas supplies from firm gas supply contracts and 21% from 30-day spot market contracts. In addition, 642,059,914 therms of customer purchased supplies were transported across Cascade facilities. CURRENT FEDERAL ENERGY REGULATORY COMMISSION (FERC) MATTERS The following is a summary of current issues subject to FERC regulation that will affect the amount the Company pays for interstate transportation of natural gas supplies. Since the policies of the WUTC and the OPUC provide for 100% pass through of costs subject to FERC regulation, the Company expects that the final resolution of these issues will not affect its net earnings. On October 16, 1997 the FERC issued an order denying rehearing of the June 11 order on Williams' oldest pending rate case, RP93-5. In the June order, FERC set policy on a method for determining a pipeline's rate of return on equity. The policy set Williams' rate of return on equity at 12.59%. The FERC had originally allowed Williams a 13.2% rate of return. The rates from RP93-5 were in effect, subject to refund, from April 1, 1993 until November 1, 1994. The lower rate of return will ultimately result in refunds from that period. The FERC has not yet acted on the single issue under contention in the Williams RP94-220 case. The issue involves the desire of the Canadian Association of Petroleum Producers (CAPP) to have a mileage based zonal rate replace Williams' current "postage stamp" rate which does not recognize distance of flow. The Administrative Law Judge filed his initial decision in March, 1997 rejecting CAPP's arguments. RP94-220 rates were in effect from November 1, 1994 until February 1, 1996. The initial decision from the Administrative Law Judge following litigation of the Williams rate case RP95-409 is still pending. Final briefs were submitted in March, 1997. One of the primary issues involves the FERC policy for calculating the pipeline's rate of return on equity established in RP93-5 and its application in this case. The rates from RP95-409 were in effect, subject to refund, from February 1, 1996 until March 1, 1997. A settlement of Williams' most recent rate case, RP96-367, was filed with the FERC in July 1997 and approved by the Commission on November 25, 1997. In its approval, the FERC noted that the settlement not only eliminated the rate increase in RP96-367 but reduced rates below the earlier RP95-409 level. Under terms of the settlement, Williams cannot file for another general rate case before December 31, 1999. In the six rate cases filed by Williams in the last seven years, this is the first total settlement and avoids expensive and protracted litigation of past and present issues. 5 COST OF PURCHASED GAS Cascade's cost of gas depends primarily on the prices negotiated with producers and brokers, coupled with the cost of interstate and Canadian pipeline transportation. Currently core gas prices are based 28% on firm or fixed pricing and 72% on index based prices. This diversity, together with use of storage volumes at a value determined at the time of injection, provides Cascade with the ability to mitigate the effects of short term, unexpected spikes in the market price of natural gas. 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 provisions. 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 shall not be liable for damages or otherwise 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 bill of firm customers curtailed by reason of an insufficient supply of gas. OREGON RATE SETTLEMENT For a description of the settlement, effective September 1, 1997, of a reduction of rates charged to customers in Oregon, see "Regulatory Matters" under Item 7. TERRITORY SERVED AND FRANCHISES The population of communities served by Cascade totals approximately 744,000. Cascade has all the franchises necessary for the distribution of natural gas in the communities it serves in Washington and Oregon. 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 which 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 1998 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 30-days' notice. 6 The principal industrial activities in Cascade's service area include the production of pulp, paper and converted paper products, plywood, chemical fertilizers, industrial chemicals, cement, clay and ceramic products, textiles, refining of crude oil, producing and forming of aluminum, the processing and canning of many types of vegetable, fruit and fish products, processing of milk products, meat processing and the drying and curing of wood and agricultural products. 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, 1997, 67% of operating revenues and 102% of earnings from operations were derived from the first two quarters (October 1996 through March 1997). Because of the seasonality of space heating revenues, Cascade believes financial results for interim periods are not indicative of results to be expected for the year. 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 and electricity for residential and commercial space heating, and electricity for water heating. Competition is primarily based on price. 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. 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 and the restructuring of gas supply and contractual provisions with these customers has improved the Company's competitive position. From December 1991 through January 1992 and again from December 1992 through May 1994, except for a brief period in June 1993, residual fuel oil prices were lower than natural gas, but Cascade did not experience any significant loss of sales to alternate fuels during those periods. In addition to multiple alternative fuels, the Company competes with other sellers of natural gas because of the potential for bypass of the Company's facilities. Bypass refers to actual or prospective customers which install their own facilities and connect directly to an upstream pipeline and thereby "bypass" the distribution company's service. The Company has experienced bypass but has also experienced success in offering competitive rates to reduce economic incentives to bypass. 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. 7 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 problems or for the prevention of future environmental problems. In the early 1950's, the Company acquired other corporations that owned several of the gas distribution systems Cascade operates today. Among these acquisitions, the Company has identified to date twelve small manufactured gas plants which had used oil or coal as feedstock to produce manufactured gas. Some of the waste byproducts of the manufacturing process contain hazardous substances which, if found in sufficient concentrations, could pose environmental problems. Almost all of these plants were either dismantled or converted to propane air prior to 1956. In 1956, when natural gas became available, the remaining plants were dismantled. The plant sites were cleaned up when the plants were dismantled and the sites are currently being used for other purposes. Environmental agencies have monitored three of the plant sites and have found no hazardous substances at levels requiring remediation. During 1995, a claim related to environmental contamination from a former manufactured gas plant site in Oregon, previously operated by a predecessor corporation of the Company, was filed by the present property owner, which is a municipal corporation. The claim requested that the Company assume responsibility for investigation and possible cleanup of alleged contamination on the property. The property owner and its consultants, working with the Oregon Department of Environmental Quality (DEQ), have been in charge of the site investigation and its pace. The original consultant's study was completed in December 1995, and disclosed to the DEQ by the owner in January 1996. Since August 1996, DEQ and the owner have been negotiating an intragovernmental agreement for how the next steps in the site investigation will be administered. At this date it appears that contamination is present at the site, but there is no estimate of the extent of possible clean-up costs. Further, there has been no agreement reached as to how such costs will be shared by the various parties. At such time as the Company's obligation for remediation costs can be reasonably estimated, accruals will be recorded and disclosures will be made in accordance with applicable accounting standards. To the extent the Company may be responsible for any portion of such costs, it intends to seek contribution from other responsible parties, recovery from its insurers and appropriate rate relief. See Note 10 under Notes to Consolidated Financial Statements. As reported in the 10-Q report for the quarter ended March 31, 1997, the Company has received notice of, and is investigating allegations of, environmental contamination from a former manufactured gas plant site in Washington previously operated by the Company. The Company has begun an investigation, but has not yet determined the existence or extent of the alleged contamination. To the extent the Company may be responsible for all or part of the cost relating to such contamination, it expects to seek contribution from other site owners and its insurers, and would seek appropriate rate relief to the extent of remaining expense incurred. Based on information received to date, the Company is not aware of hazardous substances present at any of the other plant sites at levels that would require remediation. 8 CAPITAL EXPENDITURES Capital expenditures for fiscal 1998 are budgeted at $31.1 million. Including the 1998 budget, the Company will have spent over $160,000,000 in new plant in the five years ending in 1998, which is roughly equivalent to the amount expended during the nine year period from 1985 through 1993. Capital expenditures are primarily 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. The Company is currently forecasting that capital expenditures will total approximately $150,000,000 over the next five years, reflecting expectations that growth in the number of customers will continue at a pace similar to recent experience. NON-UTILITY SUBSIDIARIES Cascade has four non-utility subsidiaries, only one of which is actively engaged in business at present. This subsidiary is engaged in the servicing of loans which were made to Cascade's gas customers to finance their purchases of energy-efficient appliances. As of September 1997, the subsidiary no longer makes new loans. 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, 1997, Cascade had 484 employees. Of the total employees, 217 are represented by the International Chemical Workers Union. The present contract with the union extends to April 1, 1999, and thereafter until terminated by either party on sixty days notice. 9 Historical Summary of Operating Statistics Fiscal Years Ended September 30
1997 1996 1995 1994 1993 Natural Gas Deliveries to Customers (thousands of therms) Residential 110,137 101,779 93,524 83,912 86,284 Commercial 107,310 103,433 101,145 95,695 101,057 Industrial and other 851,357 834,363 768,537 666,698 507,957 ----------- ----------- ----------- ----------- ----------- 1,068,804 1,039,575 963,206 846,305 695,298 ----------- ----------- ----------- ----------- ----------- Average Number of Customers Residential 134,857 127,089 119,633 111,055 102,354 Commercial 24,682 23,741 22,755 21,794 20,968 Industrial and other 500 482 462 447 428 ----------- ----------- ----------- ----------- ----------- 160,039 151,312 142,850 133,296 123,750 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total Customers at End of Year 160,247 152,116 143,372 134,823 124,963 Average Annual Therm Usage per Customer Residential 817 801 782 756 843 Commercial 4,348 4,357 4,445 4,391 4,820 Industrial and other 1,702,714 1,731,044 1,663,500 1,491,494 1,186,815 Heating Degree Days (30-year avg. 5,675) 5,525 5,620 5,607 5,301 6,129 Daily Sendout (thousands of therms) Peak day for the year 4,832 4,863 3,955 3,341 3,134 Average day for the year 2,928 2,840 2,639 2,319 1,905 Employees at End of Year 484 478 479 473 465 Customers Per Employee at End of Year 331 318 299 285 269 Capitalization Ratios at End of Year Common shareholders' equity 44.3% 50.1% 39.6% 42.7% 46.7% Preferred stock 2.6% 3.1% 3.3% 3.8% 4.5% Long-term debt (incl. current maturities) 48.0% 46.8% 48.4% 41.4% 40.9% Short-term debt 5.1% 0.0% 8.7% 12.1% 7.9% ----------- ----------- ----------- ----------- ----------- 100.0% 100.0% 100.0% 100.0% 100.0% ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
ITEM 2. PROPERTIES. At September 30, 1997, Cascade's utility plant investments included approximately 4,113 miles of distribution mains ranging in diameter from two inches to sixteen inches, 240 miles of transmission mains ranging in diameter from two inches to sixteen inches and 2,630 miles of service lines. 10 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 at present twenty-two buildings used for operations, office space and warehousing in Washington and eight such buildings in Oregon. It leases an additional five commercial offices. 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 See Item 1, Business, under "Environmental". ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. 11 EXECUTIVE OFFICERS OF THE REGISTRANT The Executive Officers of the Company, as of December 1, 1997, are as follows:
Year Became Name Office Age Officer - --------------------------------------------------------------------------------------- W. Brian Matsuyama Chairman of the Board and Chief Executive Officer 51 1987 Ralph E. Boyd President and Chief Operating Officer 60 1988 Jon T. Stoltz Senior Vice President - Planning and Rates 50 1981 Larry E. Anderson Vice President - Operations 49 1995 O. LeRoy Beaudry Vice President - Consumer and Public Affairs 59 1981 King C. Oberg Vice President - Gas Supply 56 1993 Larry C. Rosok Vice President - Human Resources, and Corporate Secretary 41 1995 Calvin R. Steele Vice President - Information Technology 58 1991 J. D. Wessling Vice President - Finance, and Chief Financial Officer 54 1995 James E. Haug Controller and Chief Accounting Officer 48 1981
None of the above officers is related by blood, marriage or adoption to any other of the above named officers. Except as discussed below, 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. J. D. Wessling was employed by the Company on January 6, 1994 as Director-Finance. From 1989 through 1993, he was chief financial officer for a retail drug chain based in Phoenix, Arizona. From 1986 to 1989, he was chief financial officer of a computer distribution company. Prior to that, Mr. Wessling spent twelve years in the oil and gas industry, seven of which were with Atlantic Richfield Company where he held various financial positions. 12 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 1997 Fiscal 1996 ----------- ----------- Quarter High Low High Low ------- ---- --- ---- --- December 31 17-1/2 15-5/8 17-3/8 14-5/8 March 31 17-1/8 15-3/8 16-5/8 15 June 30 17 15-1/4 16 13-3/8 September 30 17-11/16 15-7/8 16-1/2 13-3/4 At November 30, 1997, there were approximately 10,035 holders of the Common Stock. The following table shows for the periods indicated the dividends paid per share on the Common Stock. Fiscal Fiscal Quarter 1997 1996 ------- ---- ---- December 31 $ 0.24 $ 0.24 March 31 $ 0.24 $ 0.24 June 30 $ 0.24 $ 0.24 September 30 $ 0.24 $ 0.24 13 ITEM 6. SELECTED FINANCIAL DATA. (dollars in thousands except per share data)
Year Ended Nine Months Sep 30 Ended Sep 30 Twelve Months Ended December 31 --------- -------------- ------------------------------------- 1997 1996 1995 1994 1993 STATEMENTS OF OPERATIONS: Operating Revenues 195,786 127,665 182,744 192,410 187,454 Less: Gas Purchases 104,342 69,679 102,858 118,083 113,500 Revenue Taxes 12,430 8,420 11,480 11,500 11,095 --------- --------- --------- --------- --------- Operating Margin 79,014 49,566 68,406 62,827 62,859 --------- --------- --------- --------- --------- Cost of Operations: Operating expenses 35,670 25,058 30,818 30,202 27,856 Depreciation and amortization 13,416 9,362 11,733 10,921 9,964 Property and payroll taxes 3,989 3,181 4,051 4,039 3,757 --------- --------- --------- --------- --------- 53,075 37,601 46,602 45,162 41,577 --------- --------- --------- --------- --------- Earnings From Operations 25,939 11,965 21,804 17,665 21,282 --------- --------- --------- --------- --------- Nonoperating Expense (Income): Interest 9,436 7,459 9,938 8,090 7,038 Interest charged to construction (532) (569) (394) (203) (323) --------- --------- --------- --------- --------- 8,904 6,890 9,544 7,887 6,715 Amortization of debt issuance expense 612 459 606 593 562 Other (467) (2) (586) (80) (113) --------- --------- --------- --------- --------- 9,049 7,347 9,564 8,400 7,164 --------- --------- --------- --------- --------- Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Method 16,890 4,618 12,240 9,265 14,118 Income Taxes 6,263 1,606 4,508 3,505 5,224 --------- --------- --------- --------- --------- Earnings Before Cumulative Effect of Change in Accounting Method 10,627 3,012 7,732 5,760 8,894 Cumulative effect of change in accounting method - - - - 209 --------- --------- --------- --------- --------- Net Earnings 10,627 3,012 7,732 5,760 9,103 Preferred Dividends 510 393 539 558 580 --------- --------- --------- --------- --------- Net Earnings Available to Common Shareholders $ 10,117 $ 2,619 $ 7,193 $ 5,202 $ 8,523 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Common Stock Outstanding (thousands of shares): End of year 10,967 10,787 9,144 8,912 8,566 Average 10,843 9,266 8,997 8,707 7,915 Earnings per Common Share Before cumulative effect of change in accounting method $ 0.93 $ 0.28 $ 0.80 $ 0.60 $ 1.05 Cumulative effect of change in accounting method - - - - 0.03 --------- --------- --------- --------- --------- Net Earnings per Common Share $ 0.93 $ 0.28 $ 0.80 $ 0.60 $ 1.08 --------- --------- --------- --------- ---------
14
ITEM 6. SELECTED FINANCIAL DATA. (CONTINUED) (dollars in thousands except per share data) At September 30 At December 31 ------------------------ --------------------------------------- 1997 1996 1995 1994 1993 RETAINED EARNINGS: Beginning of the year $ 4,901 $ 9,297 $ 10,806 $ 14,076 $ 13,455 Net earnings available to common shareholders 10,117 2,619 7,193 5,202 8,523 Common dividends (10,465) (7,015) (8,702) (8,472) (7,902) ----------- ----------- ----------- ----------- ----------- End of the year $ 4,553 $ 4,901 $ 9,297 $ 10,806 $ 14,076 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- CAPITAL STRUCTURE: Common shareholders' equity $ 111,662 $ 109,126 $ 89,539 $ 87,710 $ 85,702 Redeemable preferred stocks 6,630 6,851 6,851 7,217 7,528 ----------- ----------- ----------- ----------- ----------- Debt: Long-term debt 121,150 101,850 102,100 100,000 87,000 Notes Payable and Commercial Paper 12,900 - 32,000 14,501 13,502 Current maturities of long-term debt - - - 5,000 - ----------- ----------- ----------- ----------- ----------- 134,050 101,850 134,100 119,501 100,502 ----------- ----------- ----------- ----------- ----------- Total capital $ 252,342 $ 217,827 $ 230,490 $ 214,428 $ 193,732 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- FINANCIAL RATIOS: Return on common shareholders' equity 9.16% 7.88% 8.12% 6.00% 11.00% Common stock dividend payout ratio 103% 257% 120% 161% 87% Dividends declared per common share $ 0.96 $ 0.72 $ 0.96 $ 0.96 $ 0.94 Fixed charge coverage (before income tax deduction): Times interest earned 2.68 2.17 2.16 2.07 2.86 Times interest and preferred dividends earned 2.48 2.01 2.00 1.87 2.55 Book value per year-end share of common stock $ 10.18 $ 10.12 $ 9.79 $ 9.84 $ 10.00 UTILITY PLANT: Utility plant - end of year $ 416,365 $ 383,771 $ 362,924 $ 333,863 $ 310,288 Accumulated depreciation 160,332 147,599 138,831 127,806 117,925 ----------- ----------- ----------- ----------- ----------- Net plant $ 256,033 $ 236,172 $ 224,093 $ 206,057 $ 192,363 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Construction expenditures, net of contributions in aid $ 21,626 $ 26,053 $ 37,637 $ 27,251 $ 32,990 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total assets $ 307,703 $ 296,381 $ 296,898 $ 273,090 $ 252,690 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
15 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION 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 for the 12-month period ended September 30, 1997, and the unaudited twelve month periods ended September 30, 1996, and 1995, and cash flows for the 12-month period ended September 30, 1997, the nine-month transition period ended September 30, 1996, and the year ended December 31, 1995. As of September 30, 1996, the Company adopted a fiscal year ending September 30. Previously, the fiscal year coincided with the calendar year. The new year end is more compatible with the Company's business cycle, and provides for reporting of a heating season (October through March) in a single fiscal year. RESULTS OF OPERATIONS Results of operations for the three fiscal periods were as follows:
12 months ended September 30 (THOUSANDS EXCEPT PER SHARE DATA) 1997 1996* 1995* ------------------------------------------ Operating Revenues $ 195,786 $ 184,572 $ 188,370 Less: Gas purchases 104,342 101,299 108,600 Revenue taxes 12,430 11,692 11,682 ------------------------------------------ Operating Margin 79,014 71,581 68,088 ------------------------------------------ Cost of Operations Operating expenses 35,670 32,776 30,456 Depreciation and amortization 13,416 12,389 12,141 Property and payroll taxes 3,989 4,115 3,986 ------------------------------------------ 53,075 49,280 46,583 ------------------------------------------ Earnings from operations 25,939 22,301 21,505 Nonoperating Expense (Income) Interest 9,436 10,101 9,632 Interest charged to construction (532) (753) (292) ------------------------------------------ 8,904 9,348 9,340 Amortization of debt issuance expense 612 612 603 Other (467) (142) (115) ------------------------------------------ 9,049 9,818 9,828 ------------------------------------------ Earnings Before Income Taxes 16,890 12,483 11,677 Income Taxes 6,263 4,272 4,590 ------------------------------------------ Net Earnings 10,627 8,211 7,087 Preferred Dividends 510 524 544 ------------------------------------------ Net Earnings Available to Common Shareholders $ 10,117 $ 7,687 $ 6,543 Common Shares Outstanding: Weighted average 10,843 9,204 8,936 End of period 10,967 10,787 9,098 Net Earnings per Common Share $ 0.93 $ 0.84 $ 0.73 *unaudited *unaudited
16 EARNINGS PER SHARE Per share results for the 12 months ended September 30, 1997 were 10.7% greater than the twelve months ended September 30, 1996. Earnings were affected primarily by operating margins. In fiscal year 1997 earnings were reduced $.06 per share from gas cost increases in the state of Oregon. In fiscal year 1996 earnings were negatively affected $.10 per share due to a second-quarter (ended June 30, 1996) charge against income for unrecovered gas costs and valuation adjustments to non-utility assets. OPERATING MARGIN RESIDENTIAL AND COMMERCIAL MARGIN. Operating margins derived from sales to residential and commercial customers were as set forth in the following table. RESIDENTIAL AND COMMERCIAL OPERATING MARGINS (DOLLARS IN THOUSANDS) (12 MONTHS ENDED SEPTEMBER 30) 1997 1996 1995 - ---------------------------------------------------------------------------- DEGREE DAYS 5,525 5,620 5,607 AVERAGE NUMBER OF CUSTOMERS Residential 134,857 127,089 119,633 Commercial 24,682 23,741 22,755 AVERAGE THERM USAGE PER CUSTOMER Residential 817 801 782 Commercial 4,348 4,357 4,445 OPERATING MARGIN Residential $ 29,725 $ 26,100 $ 23,586 Commercial $ 20,523 $ 19,794 $ 18,255 Fiscal 1997 operating margins from sales to residential and commercial customers were up $4,355,000, or 9.5% over the twelve months ended September 30, 1996 (fiscal 1996). Factors contributing to this increase were customer growth, higher therm usage per residential customer, and new state of Washington tariff rates effective August 1, 1996. These factors resulted in margin increases of approximately $2,426,000, $452,000 and $3,612,000, respectively. Somewhat offsetting these increases were two factors. First, $1,652,000 of gas cost increases were absorbed in the state of Oregon. Second, rates to Oregon customers were decreased to recognize decreased property tax expense (see "Cost of Operations"), reducing margins by approximately $470,000. Consumption per customer is driven by the mix of customers, particularly in the commercial class, the number and type of appliances used, and weather. Weather for 1997, as measured by estimated degree days, was approximately 1.7% warmer than fiscal 1996. Fiscal 1996 margins from residential and commercial customers increased by $4,053,000 over the twelve months ended September 30, 1995 (fiscal 1995), primarily due to 8,442 new customers, coupled with a moderate increase in the average gas usage per residential customer. 17 INDUSTRIAL AND OTHER MARGIN. The comparison of operating margin from industrial and other customers is affected by the charge of $1,253,000, related to unrecovered gas cost, recorded in the June 1996 quarter. Other than the effect of this charge, margins increased by $1,826,000, or 6.8%, for fiscal 1997. These increases are primarily due to the addition of 20 new customers, including service to a new cogeneration customer that began commercial operation in June 1996. Fiscal 1996 margins from industrial and other customers declined by approximately $560,000 from fiscal 1995, due primarily to the 1996 charge mentioned above. Other than this charge, margins increased by approximately $693,000 attributable to the cogeneration customer that started in June 1996 and another one that commenced June 1995. COST OF OPERATIONS Cost of operations consists of operating expenses, depreciation and amortization, and property and payroll taxes. For the twelve-month periods ended September 30, 1997, 1996, and 1995, these amounts were $53,075,000, $49,280,000, and $46,583,000, respectively. OPERATING EXPENSES for fiscal 1997, which are primarily labor and benefits expenses, increased by $2,894,000, or 8.8%, over fiscal 1996. Of this increase, $1,269,000 is attributable to deferred recognition of Postretirement Benefits Other than Pensions (PBOP). From January 1993 through July 1996, a portion of PBOP expenses were deferred, in accordance with a policy statement issued by the Washington Utilities and Transportation Commission in 1992. Concurrent with the settlement of the Washington rate case, effective August 1, 1996, ongoing PBOP expenses are no longer deferred, and amortization of the previously deferred amounts is also included in operating expenses, resulting in the expense increase. The new customer rates include recognition of this higher level of PBOP expenses. Labor costs increased by $990,000, or 4.5%, related to normal wage and salary rate adjustments, as well as to higher compensation levels commensurate with a more highly skilled work force. Fiscal 1996 expenses increased by $2,320,000 or 7.6% over fiscal 1995. These increases were primarily attributable to payroll and benefit plan cost increases, as well as additional costs related to the change in the Company's fiscal year. DEPRECIATION AND AMORTIZATION for fiscal 1997 increased by $1,027,000, or 8.3% over fiscal 1996, which is attributable to increases in depreciable utility plant to serve a growing customer base. PROPERTY AND PAYROLL TAXES for fiscal 1997 decreased by $126,000, or 3.1%, compared to fiscal 1996. Higher property taxes related to increases in assets are more than offset by reductions in Oregon tax rates resulting from a 1990 voter referendum. These Oregon rate reductions have no significant effect on net earnings because the effect of reductions had previously been deferred in accordance with the policy established by the Oregon Public Utility Commission. These deferrals are currently being amortized, resulting in current recognition of the effect of the reductions, and rates charged to Oregon customers have been reduced accordingly (see "Operating Margin"). Increases in depreciation and amortization and in property and payroll taxes in fiscal 1996 over fiscal 1995 are primarily due to increases in utility plant. 18 NONOPERATING EXPENSE (INCOME) Interest expense decreased by $665,000 or 6.6% from fiscal 1996. This is due to lower average amounts of short-term debt outstanding, and interest accruals on deferred gas cost savings, partially offset by lower interest accruals on deferred gas cost increases. Other non-operating income increased by $325,000 to $467,000. The primary factors resulting in this increase were a 1997 gain of $140,000 on the sale of a parcel of land, compared to a 1996 charge of $311,000 relating to valuation reserves against other assets. Additionally, there was less interest income in fiscal 1997 because of fewer amounts of appliance loans outstanding. INCOME TAXES The increase in the provision for federal and state income taxes is primarily attributable to the increase in pre-tax earnings. 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 five-year credit commitment for $40 million from three banks. The committed lines also support a money market facility of a similar amount and a regional commercial paper program. A subsidiary company has a $5 million five-year revolving credit facility used for non-regulated business, and at September 30, 1997, $1.15 million was outstanding. The Company also has $30 million of uncommitted lines from three banks. The balance of Medium-Term Notes at September 30, 1997 was $120 million. There is remaining $30 million registered under the Securities Act of 1933 and available for issuance. 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 Operating activities resulted in a net cash flow of $46,000 for fiscal 1997, compared to $39,230,000 for the nine-month transition period ended September 30, 1996, in spite of increased net earnings. The reduction is primarily due to higher gas costs incurred during the 1996 - 1997 heating season. For 1997, the cost of gas purchased exceeded the gas cost used to establish the Company's sales tariffs, resulting in a negative cash flow of $15,288,000. For the nine months ended September 30, 1996, the cost of gas was less than the gas cost level established in the Company's sales tariffs, resulting in a positive cash flow of $10,644,000. This represents a difference of $25,932,000 between the two periods. The effect of these differences in gas costs, except the Oregon amounts absorbed by the Company, as discussed above under "Operating Margin", has been deferred, and thus had no effect on net earnings. The Company will file for recovery of these deferred amounts from customers through purchased gas rate adjustments over future periods. By the end of fiscal 1997, gas costs returned to a level approximately equivalent to the base cost level established in the Company's tariffs. 19 Operating Activities were also affected by seasonal changes in accounts receivable, accounts payable, accrued expenses, prepaid expenses, and other, resulting in decreased cash flow of $21,775,000 from the nine-month transition period ended September 30, 1996. INVESTING ACTIVITIES Cash used by investing activities in fiscal 1997 was $21,166,000, compared to $25,208,000 for the 1996 transition period. The reduction in investing activities is the result of an unusually high amount, $7,540,000, of customer contributions in aid and advances for construction primarily related to expenditures on a project completed in fiscal 1996. In the prior period, the level of customer contributions in aid and advances for construction was a more normal $405,000. Budgeted capital expenditures for fiscal 1998 are approximately $31.1 million, which is expected to be financed approximately 50% from operating activities, and 50% from a combination of debt and equity financing. FINANCING ACTIVITIES The principal financing activity for 1997 was the issuance of $20,000,000 of new medium-term notes, completed in September. In addition the Company raised $1,747,000 of new equity capital through its dividend reinvestment program and through sales of common stock to its 401(k) plan. REGULATORY MATTERS For the past seven years, the Company has been able to achieve normalized results in Oregon greater than its allowed rate of return. Recognizing that the limitations inherent in traditional utility regulation could, at some point, inhibit further productivity improvements in that state, the Company has been cooperatively exploring alternatives with the staff of the Oregon Public Utility Commission. Ideally, both shareholders and customers should be able to benefit fairly from efficiency gains. In September, 1997, the Company decreased Oregon rates by $800,000 annually. The lower rates share with customers some of the benefits of increased productivity and lower capital costs since the Company's last general rate case in 1990, and can better serve as a starting point for new methods it may develop for sharing future improvements. The new rates are expected to reduce net income by $556,800 annually and to produce an implied return on equity of 11.8% in Oregon. ENVIRONMENTAL MATTERS As reported in the Company's 10-Q reports for the quarters ended March 31 and June 30, 1997, the Company has received notice and is investigating allegations of environmental contamination from a former manufactured gas plant site in Washington previously operated by the Company. The Company has not yet determined the existence or extent of the alleged contamination. To the extent the Company may be responsible for all or part of the cost relating to such contamination, it expects to seek contribution from other site owners and its insurers, and would seek appropriate rate relief. 20 CONTINGENT LIABILITIES Like most entities that are heavily reliant on business application computer software, the Company is affected by the fact that many of its computer programs are not Year 2000 compliant. The result would be that in the year 2000, the computer programs would not operate as intended. The Company is currently in the process of identifying and correcting computer programs which are not Year 2000 compliant. The implementation plan will involve a combination of correcting existing program code, and acquiring new programs to replace non-compliant programs. Much of this effort will coincide with the Company's plan to upgrade its applications software over the next few years. The conversion is not expected to have a material adverse effect on the Company's results of operations, cash flows, or financial position. FORWARD-LOOKING STATEMENTS Statements contained in this report which 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. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not applicable. 21 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, 1997 and 1996, and the related consolidated statements of net earnings available to common shareholders, common shareholders' equity, and cash flows for the year ended September 30, 1997, the nine months ended September 30, 1996, and the year ended December 31, 1995. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. 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 present fairly, in all material respects, the financial position of Cascade Natural Gas Corporation and subsidiaries as of September 30, 1997 and 1996, and the results of their operations and their cash flows for the year ended September 30, 1997, the nine months ended September 30, 1996, and the year ended December 31, 1995, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Seattle, Washington November 7, 1997 22 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF NET EARNINGS AVAILABLE TO COMMON SHAREHOLDERS
(Dollars in thousands except per share data) Year Ended Nine Months Ended Year Ended September 30 September 30 December 31 1997 1996 1995 (Note 2) Operating Revenues $ 195,786 $ 127,665 $ 182,744 Less Gas purchases 104,342 69,679 102,858 Revenue taxes 12,430 8,420 11,480 ---------- ---------- ---------- Operating Margin 79,014 49,566 68,406 ---------- ---------- ---------- Cost of Operations Operating expenses 35,670 25,058 30,818 Depreciation and amortization 13,416 9,362 11,733 Property and payroll taxes 3,989 3,181 4,051 ---------- ---------- ---------- 53,075 37,601 46,602 ---------- ---------- ---------- Earnings from operations 25,939 11,965 21,804 ---------- ---------- ---------- Nonoperating Expense (Income) Interest 9,436 7,459 9,938 Interest charged to construction (532) (569) (394) ---------- ---------- ---------- 8,904 6,890 9,544 Amortization of debt issuance expense 612 459 606 Other (467) (2) (586) ---------- ---------- ---------- 9,049 7,347 9,564 ---------- ---------- ---------- Earnings Before Income Taxes 16,890 4,618 12,240 Income Taxes 6,263 1,606 4,508 ---------- ---------- ---------- Net Earnings 10,627 3,012 7,732 Preferred Dividends 510 393 539 ---------- ---------- ---------- Net Earnings Available to Common Shareholders $ 10,117 $ 2,619 $ 7,193 ---------- ---------- ---------- ---------- ---------- ---------- Net Earnings Per Common Share $ 0.93 $ 0.28 $ 0.80 ---------- ---------- ---------- ---------- ---------- ---------- Average Shares Outstanding 10,843 9,266 8,997 ---------- ---------- ---------- ---------- ---------- ----------
The accompanying notes are an integral part of these financial statements 23 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
1997 1996 ASSETS (Dollars in thousands) Utility Plant (Note 3) $ 416,365 $ 383,771 Less accumulated depreciation 160,332 147,599 ----------- ----------- 256,033 236,172 Construction work in progress 9,192 19,497 ----------- ----------- 265,225 255,669 ----------- ----------- Other Assets Investments in non utility property 668 667 Notes receivable, less current maturities 1,493 1,777 ----------- ----------- 2,161 2,444 ----------- ----------- Current Assets Cash and cash equivalents 3,162 543 Accounts receivable, less allowance of $529 and $439 for doubtful accounts 11,865 11,646 Current maturities of notes receivable 536 631 Materials, supplies, and inventories 5,886 6,063 Prepaid expenses and other assets 7,382 5,723 ----------- ----------- 28,831 24,606 ----------- ----------- Deferred Charges 11,486 13,662 ----------- ----------- $ 307,703 $ 296,381 ----------- ----------- ----------- ----------- COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES Common Shareholders' Equity Common stock, par value $1 per share (Note 5) Authorized, 15,000,000 shares; issued and outstanding, 10,966,732 and 10,786,585 shares $ 10,967 $ 10,787 Additional paid-in capital 96,142 93,438 Retained earnings 4,553 4,901 ----------- ----------- 111,662 109,126 ----------- ----------- Redeemable Preferred Stocks, aggregate redemption amount of $6,845 and $7,097 (Note 4) 6,630 6,851 ----------- ----------- Long-Term Debt (Note 7) 121,150 101,850 ----------- ----------- Current Liabilities Notes payable and commercial paper (Note 6) 12,900 - Accounts payable 7,753 17,599 Property, payroll, and excise taxes 3,958 3,113 Dividends and interest payable 6,691 6,570 Other current liabilities 3,680 2,931 ----------- ----------- 34,982 30,213 ----------- ----------- Deferred Credits and Other Gas cost changes 6,290 21,578 Income taxes (Note 8) 16,080 16,184 Investment tax credits 2,764 3,031 Other 8,145 7,548 ----------- ----------- 33,279 48,341 ----------- ----------- Commitments and Contingencies (Note 10) - - ----------- ----------- $ 307,703 $ 296,381 ----------- ----------- ----------- -----------
The accompanying notes are an integral part of these financial statements 24 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
Common Stock (Dollars in thousands except per share data) ------------ Paid-In Retained Shares Par Value Capital Earnings ------ --------- ------- -------- Balance, December 31, 1994 8,911,661 $ 8,912 $ 67,992 $ 10,806 Common stock issued: Employee savings plan and retirement trust (401(k)) 50,373 50 677 Director stock award plan 1,200 1 15 Dividend reinvestment plan 181,214 181 2,409 Redemption of preferred stock 5 Cash dividends: Common stock, $.96 per share (8,702) Preferred stock, senior, $.55 per share (68) 7.85% cumulative preferred stock, $7.85 per share (471) Net earnings 7,732 ------------ ------------ ------------ ------------ Balance, December 31, 1995 9,144,448 9,144 71,098 9,297 Common stock issued: Public offering 1,487,700 1,488 20,108 Employee savings plan and retirement trust (401(k)) 33,893 34 492 Director stock award plan 1,800 2 26 Dividend reinvestment plan 118,744 119 1,714 Cash dividends: Common stock, $.96 per share (7,015) Preferred stock, senior, $.55 per share (40) 7.85% cumulative preferred stock, $7.85 per share (353) Net earnings 3,012 ------------ ------------ ------------ ------------ Balance, September 30, 1996 10,786,585 10,787 93,438 4,901 Common stock issued: Additional costs of 1996 public offering (34) Employee savings plan and retirement trust (401(k)) 51,834 52 794 Director stock award plan 3,688 4 54 Dividend reinvestment plan 124,625 124 1,887 Redemption of preferred stock 3 Cash dividends: Common stock, $.96 per share (10,465) Preferred stock, senior, $.55 per share (39) 7.85% cumulative preferred stock, $7.85 per share (471) Net earnings 10,627 ------------ ------------ ------------ ------------ Balance, September 30, 1997 10,966,732 $ 10,967 $ 96,142 $ 4,553 ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------
The accompanying notes are an integral part of these financial statements 25 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended Nine Months Ended Year Ended September 30 September 30 December 31 1997 1996 1995 Operating Activities Net earnings $ 10,627 $ 3,012 $ 7,732 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation and amortization 13,416 9,362 12,131 Write-down of assets - 154 - Amortization of gas cost changes (2,473) 1,308 3,508 Increase (decrease) in deferred income taxes (105) (276) 1,079 Decrease in deferred investment tax credits (267) (175) (265) Cash provided (used) by changes in operating assets and liabilities: Accounts receivable (221) 14,835 2,400 Income taxes 1,183 (2,905) 105 Inventories 45 481 201 Gas cost changes (12,815) 9,336 2,226 Deferred items 1,710 4,345 (4,144) Accounts payable and accrued expenses (8,115) 281 1,560 Prepaid expenses and other assets (2,858) (512) (1,111) Other (81) (16) (399) ----------- ----------- ----------- Net cash provided by operating activities 46 39,230 25,023 ----------- ----------- ----------- Investing Activities Capital expenditures (29,166) (26,458) (38,486) Customer contributions in aid of construction 7,540 405 849 New consumer loans (968) (666) (1,243) Receipts on consumer loans 1,428 1,511 2,277 Purchase of securities available for sale - - (4,107) Proceeds from securities available for sale - - 5,605 ----------- ----------- ----------- Net cash used by investing activities (21,166) (25,208) (35,105) ----------- ----------- ----------- Financing Activities Issuance of common stock 1,747 23,155 2,293 Redemption of preferred stock (216) - (362) Proceeds from long-term debt, net 19,850 - 2,100 Repayment of long-term debt (700) (250) (5,000) Changes in notes payable and commercial paper, net 12,900 (32,000) 17,499 Dividends paid (9,842) (6,581) (8,200) ----------- ----------- ----------- Net cash provided (used) by financing activities 23,739 (15,676) 8,330 ----------- ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents 2,619 (1,654) (1,752) Cash and Cash Equivalents Beginning of year 543 2,197 3,949 ----------- ----------- ----------- End of year $ 3,162 $ 543 $ 2,197 ----------- ----------- ----------- ----------- ----------- ----------- Supplemental Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 7,938 $ 6,890 $ 8,597 Income taxes $ 5,606 $ 1,606 $ 2,786
The accompanying notes are an integral part of these financial statements 26 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 primarily 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, 1997, the Company had approximately 160,000 core customers and 162 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 68% 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 generally derived only from this distribution service. The principal industrial activities of its customers include the processing of forest products, production of chemicals, refining of crude oil, production of aluminum, generation of electricity, and processing of food. 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 amortization during future periods. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The Company's accounting records and practices conform to the requirements and uniform system of accounts prescribed by the WUTC and the OPUC. Change in year end: Beginning in 1996, the Company changed its fiscal year end to September 30 to include the fall-winter heating season within a single financial reporting period. As a result of this change, the reporting period for 1996, unless otherwise noted, is the nine month transition period ended September 30, 1996. Because of the seasonal nature of the business, the period ended September 30, 1996 is not indicative of a full year with respect to operations and cash flow. 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 have been 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 expense, 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. 27 Depreciation of utility plant is computed using the straight-line method. The asset lives used for computing depreciation range from five to forty years, and the weighted average annual depreciation rate is approximately 3.5%. Investments: Investments consist primarily of real estate, classified as nonutility property carried at the lower of cost or estimated net realizable value. Notes receivable: Notes receivable include loans made to customers for the purchase of energy efficient appliances, which are generally the security for the loan. Loans are made for a term of five years at interest rates varying from 6.5% to 12%. Materials, supplies and inventories: Materials and supplies for construction and maintenance are recorded at cost. Inventories of natural gas are stated at the lower of average cost or market. Regulatory accounts: The Company's financial statements are prepared in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement provides for the deferral of certain costs and benefits which 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. A regulated enterprise may prepare its financial statements according to the provisions of SFAS No. 71 only as long as: (i) the enterprise's rates for regulated services are established by or are subject to approval by an independent third party regulator; (ii) the regulated rates are designed to recover the enterprise's cost of providing the regulated services, and (iii) in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates set at levels to recover the enterprise's costs can be charged to and collected from customers. If at some point in the future, the Company determines that all or a portion of the utility operations no longer meets the criteria for continued application of SFAS No. 71, the Company would be required to adopt the provisions of SFAS No. 101, "Regulated Enterprises-Accounting for the Discontinuation of Application of FASB Statement No. 71". Adoption of SFAS No. 101 would require the Company to write off the regulatory assets and liabilities related to those operations not meeting the criteria of SFAS No. 71. Regulatory assets (liabilities) at September 30, 1997 and 1996 include the following: (dollars in thousands) 1997 1996 - -------------------------------------------------------------------------- Unamortized loss on reacquired debt $ 5,556 $ 6,086 Gas cost changes (6,290) (21,578) Deferred income taxes (3,128) (3,279) Postretirement benefits other than pensions 3,936 4,685 Other, net 1,007 686 ---------- ---------- Net $ 1,081 $(13,400) ---------- ---------- ---------- ---------- Revenue recognition: The Company accrues estimated revenues for gas delivered but not billed to residential and commercial customers from the meter reading dates to month end. Leases: The Company leases mainframe computer equipment and 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. The Company has no capital leases. Federal income taxes: The Company deducts depreciation computed on an accelerated basis for federal income tax purposes, and as a result, deductions exceed the amounts included in the financial statements. 28 In 1981, the Company elected to record depreciation on 1981 and subsequent utility plant additions under the Accelerated Cost Recovery System. This election required the Company to provide deferred income taxes on the difference between depreciation computed for financial statement and tax reporting purposes beginning in 1981 (Note 8). This procedure has been accepted by the WUTC and the OPUC. It is expected that any future increases in federal income taxes resulting from the reversal of accelerated depreciation on additions to utility plant in 1980 and prior will be allowed in future rate determinations. Investment tax credits: Investment tax credits were deferred and are amortized over the life of the property giving rise to the credit. 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. Use of estimates: The preparation of financial statements in conformity with generally accepted accounting principles 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 significant estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC. Significant estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, and in the determination of depreciable lives of utility plant. New accounting standards: In February, 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (FAS) No. 128, entitled "EARNINGS PER SHARE" and FAS No. 129, entitled "DISCLOSURE OF INFORMATION ABOUT CAPITAL STRUCTURE," which are effective for periods ending after December 15, 1997. FAS No. 128 prescribes the method of calculating and reporting earnings per share (EPS) amounts. It replaces the presentation of primary EPS with a presentation of basic EPS. For entities with other than a simple capital structure, it requires the dual presentation of basic and diluted EPS on the face of the income statement. The Company does not expect implementation of this standard to have a material effect on reported earnings per share. FAS No. 129 establishes standards for disclosing information about the Company's capital structure, including dividend and liquidation preferences, participation rights, call prices and disclosure of the dates and the number of shares issued upon conversion, exercise, or satisfaction of required conditions during at least the most recent annual fiscal period and any subsequent interim period presented. The Company does not expect implementation of this standard to have a material effect on the reporting of the Company's capital structure. In June, 1997, the Financial Accounting Standards Board issued FAS No. 130, entitled "REPORTING COMPREHENSIVE INCOME," and FAS No. 131, entitled "DISCLOSURE ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION," which are effective for fiscal years beginning after December 15, 1997. FAS No. 130 requires companies to (a) classify items of other comprehensive income by their nature in a financial statement and (b) display the accumulated balance of other comprehensive income separately from retained earnings and additional paid-in-capital in the equity section of a statement of financial position. The Company does not expect implementation of this standard to have a material effect on the reporting of its financial information. FAS No. 131 requires public enterprises to report financial and descriptive information on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company does not expect implementation of this standard to have a material effect on the reporting of its financial information. 29 NOTE 3 - UTILITY PLANT Utility plant at September 30, 1997 and 1996 consists of the following components: (dollars in thousands) 1997 1996 - ------------------------------------------------------------------------ Distribution plant $ 363,275 $ 332,094 Transmission plant 14,086 14,086 Production plant 1,053 1,053 General plant 32,414 30,999 Intangible plant 212 212 Nondepreciable plant 5,325 5,327 ------------ ------------ $ 416,365 $ 383,771 ------------ ------------ NOTE 4 - REDEEMABLE PREFERRED STOCKS Redeemable preferred stock at September 30, 1997 and 1996 consists of the following: (dollars in thousands) 1997 1996 - -------------------------------------------------------------------------------- Shares Amount Shares Amount 7.85% cumulative, $1.00 par value 60,000 $ 6,000 60,000 $ 6,000 $.55 cumulative senior, series B and C, without par value 71,750 630 96,560 851 ---------------------- -------------------- 131,750 $ 6,630 156,560 $ 6,851 ---------------------- -------------------- The 7.85% cumulative preferred stock is subject to redemption in November, 1999. The $.55 cumulative senior preferred stock is subject to minimum annual redemption requirements, with Series B being fully redeemed in fiscal 1999, and Series C in 2001. The shares may be purchased on the open market, or redeemed at $10 per share plus accrued dividends. Redemption in excess of the required number of shares of preferred stock can be made only if all cumulative dividends on preferred stock have been paid. The aggregate annual preferred stock redemption requirements for the next five years are set forth in the following table: Preferred stock redemption requirements (dollars in thousands) - ---------------------------------- Fiscal Shares Amount 1998 25,000 $ 250 1999 25,000 250 2000 74,500 6,145 2001 7,250 73 2002 - - 30 NOTE 5 - COMMON STOCK At September 30, 1997, shares of common stock are reserved for issuance as follows: Number of shares - ---------------------------------------------------------- Employee Savings Plan and Retirement Trust (401(k) plan) 145,211 Dividend Reinvestment Plan 104,255 Director Stock Award Plan 4,112 ------------ 253,578 ------------ 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. In May 1993, the Company distributed to holders of Common Stock 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 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 - NOTES PAYABLE AND COMMERCIAL PAPER The Company's short-term borrowing needs are met with a $40,000,000 five year revolving credit agreement with three of its banks. The annual commitment fee is 1/8 of 1% and the committed lines of credit also support a money market facility and a commercial paper facility of a similar amount. The Company also has $30,000,000 of uncommitted lines from three banks. A subsidiary company has a $5,000,000 revolving credit facility used for non-regulated business, and at September 30, 1997, $1,150,000 was outstanding for a fixed term of five years.
September 30 December 31 (dollars in thousands) 1997 1996 1995 - ---------------------------------------------------------------------------------------------- Amount outstanding $ 12,900 $ - $ 32,000 Average daily balance outstanding 13,666 15,664 13,170 Average interest rate, excluding commitment fee 5.94% 5.77% 6.29% Maximum month end amount outstanding 21,650 27,500 32,000
31 NOTE 7 - LONG-TERM DEBT Long -term debt at September 30, 1997 and 1996 consists of the following: (dollars in thousands) 1997 1996 - --------------------------------------------------- 6.53% Five Year Term Note due 2001 $ 1,150 $ 1,850 Medium-term notes: 5.77% due 1999 5,000 5,000 5.78% due 1999 5,000 5,000 7.18% due 2005 4,000 4,000 7.32% due 2004 22,000 22,000 8.38% due 2005 5,000 5,000 8.35% due 2005 5,000 5,000 8.50% due 2007 8,000 8,000 8.06% due 2012 14,000 14,000 8.10% due 2013 5,000 5,000 8.11% due 2013 3,000 3,000 7.95% due 2013 4,000 4,000 8.01% due 2013 10,000 10,000 7.95% due 2013 10,000 10,000 7.48% due 2027 20,000 - ------------ ------------ $ 121,150 $ 101,850 ------------ ------------ None of the long-term debt includes sinking fund requirements, and there are no current maturities at September 30, 1997. Annual obligations for redemption of long-term debt are as follows: none in 1998, $10,000,000 in 1999, none in 2000, $1,150,000 in 2001, none in 2002, and $110,000,000 thereafter. 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 these restrictions, approximately $25,756,000 is available for payment of dividends as of September 30, 1997. NOTE 8 - INCOME TAXES Pursuant to the provisions of SFAS No. 109, the Company has recorded a deferred tax liability for the cumulative tax effect of basis differences on utility plant placed in service prior to 1981. Flow through accounting had previously been recorded with respect to these temporary differences. In addition, the Company has adjusted previously recorded deferred tax liabilities related to plant placed in service after 1980, due to reductions in tax rates. Due to regulatory policies regarding recovery of deferred taxes charged to customers through rates, a regulatory liability was recorded which offsets the effect of these adjustments to the deferred tax balances. Therefore these adjustments have had no effect on net earnings. The provision for income tax expense consists of the following: (dollars in thousands) 1997 1996 1995 - ---------------------------------------------------------------------------- Current tax expense $6,785 $1,108 $2,661 Deferred tax expense (256) 673 2,112 Amortization of deferred investment tax credits (266) (175) (265) --------- ---------- --------- $6,263 $1,606 $4,508 --------- ---------- --------- 32 A reconciliation between income taxes calculated at the statutory federal tax rate and income taxes reflected in the financial statements is as follows: (dollars in thousands) 1997 1996 1995 - -------------------------------------------------------------------------------- Statutory federal income tax rate 35% 35% 35% Income tax calculated at statutory federal rate $ 5,911 $ 1,616 $ 4,284 Increase (decrease) resulting from: State income tax, net of federal tax benefit 122 34 86 Non-normalized depreciation differences 380 251 339 Amortization of investment tax credits (266) (175) (265) Other 116 (120) 64 --------- --------- ---------- $ 6,263 $ 1,606 $ 4,508 --------- --------- ---------- 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. The tax effects of significant items comprising the Company's net deferred tax liability at September 30, 1997 and 1996 are as follows: (dollars in thousands) 1997 1996 - ----------------------------------------------------------------------- Deferred tax liabilities: Basis differences on net fixed assets $ 14,230 $ 14,173 Debt refinancing costs 1,985 2,175 Retirement benefit obligations 986 1,066 ----------- ----------- 17,201 17,414 ----------- ----------- Deferred tax assets: Valuation reserves 458 363 Retirement benefit obligations 406 420 Provision for doubtful accounts 213 179 Other 44 268 ----------- ----------- 1,121 1,230 ----------- ----------- Net deferred tax liability $ 16,080 $ 16,184 ----------- ----------- NOTE 9 - 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's policy is generally to fund the plan to the extent allowable under Internal Revenue Service rules. The Company provides executive officers with supplemental retirement, death, and disability benefits. Under the plan, vesting occurs on a stepped basis, with full vesting upon the executive reaching 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 equal 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 funds the plan by making contributions to the Trust sufficient to assure assets held by the Trust always exceed the accumulated benefit obligation for benefits payable by the plan. The funded status of the defined benefit pension and supplemental retirement plans and amounts recognized in the Company's financial statements at September 30, 1997 and 1996 are set forth in the following table: 33
Supplemental Pension Plan Retirement Plan (dollars in thousands) 1997 1996 1997 1996 - ------------------------------------------------------------------------------------------------------------------------------- Actuarial present value of accumulated benefit obligations: Vested $ 25,130 $ 21,960 $ 3,692 $ 2,875 Nonvested 767 208 465 219 --------------------------- --------------------------- $ 25,897 $ 22,168 $ 4,157 $ 3,094 --------------------------- --------------------------- --------------------------- --------------------------- Projected benefit obligation for services rendered to date $ (29,767) $ (25,837) $ (4,445) $ (3,636) Plan assets, at fair value, primarily common stocks, corporate bonds, and life insurance policies 29,158 21,432 4,888 4,131 --------------------------- --------------------------- Projected benefit obligation (in excess of) less than plan assets (609) (4,405) 443 495 Unrecognized amounts: Prior service cost 3,399 3,464 (223) (257) Loss (gain) from past experience different from that assumed (2,167) 871 1,082 704 Net transition obligation 13 18 927 1,028 Adjustment to recognize minimum liability - (684) - - --------------------------- --------------------------- Prepaid (accrued) pension cost $ 636 $ (736) $ 2,229 $ 1,970 --------------------------- ---------------------------
Net pension cost for both plans included the following components:
(dollars in thousands) 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------------ Service cost of benefits earned during the period $ 1,367 $ 1,095 $ 1,171 Interest cost on projected benefit obligation 2,398 1,684 1,936 Actual return on plan assets (6,771) (2,274) (4,057) Deferral of unrecognized loss (gain) and amortization, net 4,975 1,179 2,916 --------- --------- ---------- $ 1,969 $ 1,684 $ 1,966 --------- --------- ----------
The following assumptions were used to determine the projected benefit obligation and expected return on assets at September 30, 1997 and 1996, and December 31, 1995: September 30 December 31 1997 1996 1995 - -------------------------------------------------------------------------------- Pension plan: Discount rate 7.75% 8.25% 7.25% Long-term rate of return on plan assets 9.00% 9.00% 9.00% Rate of increase in future compensation levels 5.00% 5.00% 5.00% Supplemental retirement plan: Discount rate 7.75% 8.25% 7.25% Long-term rate of return on plan assets 8.50% 8.50% 8.50% Rate of increase in future compensation levels 5.00% 5.00% 5.00% 401(k) PLAN. 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 each employee's contribution at a rate of 75% of the 34 employee's contribution up to 6% of the employee's compensation, as defined. Prior to January 1, 1997, the matching rate was 50%. The increased contribution is in the form of Company stock. The Company recognized costs for contributions to this plan of $703,000, $377,000, and $458,000, for 1997, 1996 and 1995, respectively. RETIREE MEDICAL PLAN. 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 Company has been recording PBOP expense, as provided in SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions", since January 1, 1993. The Company deferred the portion of the annual PBOP accrual attributable to Washington regulated operations in excess of the cash basis of recording these expenses through July 31, 1996. The amounts so deferred were $767,000, and $1,028,000 in 1996 and 1995, respectively. On August 1, 1996 new customer tariff rates were approved by the WUTC in the general rate case. Accordingly, the PBOP deferrals ceased and the balance is being amortized concurrently with the new rates. Amounts accrued for PBOP, not including the above mentioned deferrals, consist of the following components: (dollars in thousands) 1997 1996 1995 - ------------------------------------------------------------------- Service cost $ 369 $ 326 $ 366 Net interest cost 1,211 939 1,114 Actual return on plan assets (1,417) (317) (627) Net amortization and deferral 1,480 492 934 ---------- ---------- ---------- $ 1,643 $ 1,440 $ 1,787 ---------- ---------- ---------- The Company's policy is generally to fund the plan to the extent allowable under Internal Revenue Service rules. The following table sets forth the health care plan's funded status at September 30, 1997 and 1996: (dollars in thousands) 1997 1996 - -------------------------------------------------------------------------- Accumulated postretirement benefit obligation (APBO): Retirees $ 5,814 $ 4,811 Fully eligible active plan participants 5,389 5,416 Other active plan participants 6,292 5,796 ----------- ----------- 17,495 16,023 Plan assets, at fair value, primarily common stocks and corporate bonds 7,741 5,376 ----------- ----------- Funded status (9,754) (10,647) Unrecognized transition obligation 10,019 10,676 Unrecognized (gain) loss (1,976) (1,678) ----------- ----------- Accrued postretirement benefit cost $ (1,711) $ (1,649) ----------- ----------- At October 1, 1996, the per capita claims cost assumption was updated, resulting in a 6.7% decrease in the APBO. For the valuation at September 30, 1997, the discount rate was decreased from 8.25% to 7.75% and the census data was updated. These, together with the passage of time, resulted in a 17.1% increase in the APBO. In addition, plan assets increased substantially due to contributions to the plan's assets, and returns on assets. The assumed health care cost trend rate used in measuring the APBO is 9.0% for 1998, trending down to 5.5% at 2005. A one percentage point increase in the assumed health care cost trend rate for each year 35 would increase the APBO by approximately 15.2% and the service and interest cost components of net postretirement health care cost by approximately 17.0%. NOTE 10- COMMITMENTS AND CONTINGENCIES Gas Service Contracts The Company has entered into various transportation, supply, storage, and peaking service contracts to assure that adequate supplies of gas will be available to provide firm service to its core customers and to meet its obligations under long-term non-core customer agreements, and to assure that adequate capacity is available on interstate pipelines for the delivery of these supplies. These contracts have maturities ranging from one to 26 years, and generally provide for monthly and annual fixed demand charges and minimum purchase obligations. 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: Interstate Storage Firm Gas Pipeline and Peaking (dollars in thousands) Supply Transportation Service Total - ------------------------------------------------------------------------------ 1998 $ 29,445 $ 29,030 $ 5,604 $ 64,079 1999 16,483 28,893 3,903 49,279 2000 15,691 28,893 3,903 48,487 2001 12,633 28,893 4,165 45,691 2002 12,350 28,741 3,515 44,606 Thereafter 33,761 339,073 42,182 415,016 ---------- ---------- --------- -------- $ 120,363 $ 483,523 $ 63,272 $667,158 ---------- ---------- --------- -------- Purchases under these contracts for 1997, 1996, and 1995, including commodity purchases, as well as demand charges have been as follows: Interstate Storage Firm Gas Pipeline and Peaking (dollars in thousands) Supply Transportation Service Total - ------------------------------------------------------------------------------ 1997 $ 67,329 $ 30,547 $ 4,626 $ 102,502 1996 (nine months) $ 32,075 $ 19,002 $ 3,718 $ 54,795 1995 $ 45,223 $ 28,548 $ 4,722 $ 78,493 Environmental Matters During the first quarter of 1995, a claim related to environmental contamination from a manufactured gas plant site in Oregon previously operated by a predecessor corporation of the Company was filed by the present property owner. The claim requested that the Company assume responsibility for investigation and possible cleanup of alleged contamination on the property. A consultant has been retained by the property owner to evaluate the nature and extent of any contamination. To date the consultant has reported that contamination consistent with manufactured gas operations is present, but there is no estimate of possible costs of remediation. To the extent the Company may be responsible for all or part of such cost, it expects to seek contribution from other site owners and its insurers, and would seek appropriate rate relief to the extent of any remaining expense incurred. 36 As reported in the 10-Q report for the quarter ended March 31, 1997, the Company has received notice of, and is investigating allegations of, environmental contamination from a former manufactured gas plant site in Washington previously operated by the Company. The Company has begun an investigation, but has not yet determined the existence or extent of the alleged contamination. To the extent the Company may be responsible for all or part of the cost relating to such contamination, it expects to seek contribution from other site owners and its insurers, and would seek appropriate rate relief to the extent of remaining expense incurred. Litigation Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Company's business. None of those now pending, in the opinion of management, is expected to have a material effect on the Company's financial position, results of operations, or liquidity. Technology Risk Like most entities that are heavily reliant on business application computer software, the Company is affected by the fact that many of its computer programs are not Year 2000 compliant. The result would be that in the year 2000, the computer programs would not operate as intended. The Company is currently in the process of identifying and correcting computer programs which are not Year 2000 compliant. The implementation plan will involve a combination of correcting existing program code, and acquiring new programs to replace non compliant programs. Much of this effort will coincide with the Company's plan to upgrade its applications software over the next few years. The conversion is not expected to have a material adverse impact on the Company's results of operations, cash flows, or financial position. NOTE 11 - 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, 1997 and 1996, of financial instruments whose values are sensitive to market conditions are set forth in the following table: 1997 1996 Carrying Estimated Carrying Estimated (dollars in thousands) Amount Fair Value Amount Fair Value - -------------------------------------------------------------------------------- Redeemable Preferred Stock $ 6,630 $ 6,815 $ 6,851 $ 6,757 Long-term Debt $ 121,150 $ 127,983 $ 101,850 $ 103,867 37 NOTE 12 - INTERIM RESULTS OF OPERATIONS (UNAUDITED)
(thousands except Quarter Ended Quarter Ended per share data) 9/30/97 6/30/97 3/31/97 12/31/96 9/30/96 6/30/96 3/31/96 - ---------------------------------------------------------------------------------------- ------------------------------------ Operating revenues $25,911 $33,730 $71,174 $64,971 $26,584 $33,461 $67,620 Gas costs and revenue taxes 14,547 19,317 43,548 39,360 15,082 21,034 41,983 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Operating margin 11,364 14,413 27,626 25,611 11,502 12,427 25,637 Cost of operations 12,943 13,455 13,441 13,236 12,635 12,374 12,592 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Earnings (loss) from operations (1,579) 958 14,185 12,375 (1,133) 53 13,045 Interest and other, net 2,229 2,241 2,249 2,330 2,373 2,524 2,450 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Earnings (loss) before income taxes (3,808) (1,283) 11,936 10,045 (3,506) (2,471) 10,595 Income taxes (1,396) (274) 4,336 3,597 (1,504) (715) 3,825 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Net earnings (loss) (2,412) (1,009) 7,600 6,448 (2,002) (1,756) 6,770 Preferred dividends 126 128 128 128 131 131 131 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Net earnings (loss) available to Common Shareholders ($2,538) ($1,137) $7,472 $6,320 ($2,133) ($1,887) $6,639 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Weighted average shares outstanding 10,936 10,883 10,840 10,800 9,764 9,218 9,163 ----------- ----------- ----------- ------------ ----------- ----------- ------------ Net earnings (loss) per share ($0.23) ($0.10) $0.69 $0.59 ($0.22) ($0.20) $0.72 ----------- ----------- ----------- ------------ ----------- ----------- ------------
38 NOTE 13 - COMPARABLE PERIOD INFORMATION (UNAUDITED) The following unaudited information on earnings and cash flows is presented to provide financial information on periods comparable to those presented in the audited financial statements. This information is taken from the books and records of the Company and reflects all adjustments which are, in the opinion of management, necessary for a fair statement of the results for the periods presented. CONSOLIDATED CONDENSED STATEMENTS OF NET EARNINGS AVAILABLE TO COMMON SHAREHOLDERS
Nine Months Nine Months Nine Months Twelve Months Ended Ended Ended Ended 9/30/97 9/30/96 9/30/95 9/30/96 (Dollars in thousands except per share data) (unaudited) (unaudited) (unaudited) Operating Revenues $ 130,815 $ 127,665 $ 125,837 $ 184,572 Less Gas purchases 68,653 69,679 71,238 101,299 Revenue taxes 8,759 8,420 8,208 11,692 ------------ ------------ ------------ ------------ Operating Margin 53,403 49,566 46,391 71,581 ------------ ------------ ------------ ------------ Cost of Operations Operating expenses 26,685 25,058 23,470 32,776 Depreciation and amortization 10,193 9,362 8,273 12,389 Property and payroll taxes 2,961 3,181 3,116 4,115 ------------ ------------ ------------ ------------ 39,839 37,601 34,859 49,280 ------------ ------------ ------------ ------------ Earnings from operations 13,564 11,965 11,532 22,301 ------------ ------------ ------------ ------------ Interest and other deductions, net 6,719 7,347 7,157 9,818 ------------ ------------ ------------ ------------ Earnings Before Income Taxes 6,845 4,618 4,375 12,483 Income Taxes 2,666 1,606 1,842 4,272 ------------ ------------ ------------ ------------ Net Earnings 4,179 3,012 2,533 8,211 Preferred Dividends 382 393 408 524 ------------ ------------ ------------ ------------ Net Earnings Available to Common Shareholders $ 3,797 $ 2,619 $ 2,125 $ 7,687 ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ Net Earnings Per Common Share $ 0.35 $ 0.28 $ 0.24 $ 0.84 ------------ ------------ ------------ ------------ ------------ ------------ ------------ ------------ Average Shares Outstanding 10,871 9,266 8,977 9,204 ------------ ------------ ------------ ------------
39 NOTE 13 - COMPARABLE PERIOD INFORMATION (UNAUDITED) - CONTINUED CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
Nine Months Nine Months Nine Months Twelve Months Ended Ended Ended Ended 9/30/97 9/30/96 9/30/95 9/30/96 (Dollars in thousands except per share data) (unaudited) (unaudited) (unaudited) Operating Activities Net earnings $ 4,179 $ 3,012 $ 2,533 $ 8,211 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation and amortization 10,193 9,362 8,998 12,496 Write-down of assets - 154 - 154 Amortization of gas cost changes (1,871) 1,308 2,520 1,691 Increase (decrease) in deferred income taxes 503 (276) 1,506 (703) Decrease in deferred investment tax credits (209) (175) (180) (261) Cash provided (used) by changes in operating assets and liabilities: Current assets and liabilities (3,136) 12,180 7,239 8,098 Gas cost changes (7,772) 9,336 (1,740) 14,701 Other deferrals and non-current liabilities 873 4,329 (1,797) 788 ---------- ---------- ---------- ---------- Net cash provided by operating activities 2,760 39,230 19,079 45,175 ---------- ---------- ---------- ---------- Investing Activities Capital expenditures (22,182) (26,458) (23,118) (41,730) Customer contributions in aid of construction 1,565 405 532 624 New consumer loans (724) (666) (793) (1,116) Receipts on consumer loans 1,162 1,511 1,492 2,297 Purchase of securities available for sale - - (1,813) (2,293) Proceeds from securities available for sale - - 1,230 4,375 ---------- ---------- ---------- ---------- Net cash used by investing activities (20,179) (25,208) (22,470) (37,843) ---------- ---------- ---------- ---------- Financing Activities Issuance of common stock 1,465 23,155 1,821 23,625 Redemption of preferred stock - - (17) (345) Proceeds from long-term debt, net 19,850 - - - Repayment of long-term debt (400) (250) - (3,150) Changes in notes payable and commercial paper, net 6,706 (32,000) 4,500 (19,001) Dividends paid (7,399) (6,581) (6,144) (8,636) ---------- ---------- ---------- ---------- Net cash provided (used) by financing activities 20,222 (15,676) 160 (7,507) ---------- ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents 2,803 (1,654) (3,231) (175) Cash and Cash Equivalents Beginning of period 359 2,197 3,949 718 ---------- ---------- ---------- ---------- End of period $ 3,162 $ 543 $ 718 $ 543 ---------- ---------- ---------- ----------
40 INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULES Cascade Natural Gas Corporation and Subsidiaries We have audited the consolidated financial statements of Cascade Natural Gas Corporation and subsidiaries as of September 30, 1997 and 1996, and for the year ended September 30, 1997, the nine months ended September 30, 1996, and the year ended December 31, 1995, and have issued our report thereon dated November 7, 1997; such consolidated financial statements and report are included in Part II of this Annual Report on Form 10-K. Our audits also included the consolidated financial statement schedule of Cascade Natural Gas Corporation, listed in Item 14(a)2. This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information shown therein. DELOITTE & TOUCHE LLP Seattle, Washington November 7, 1997 41 SCHEDULE II CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
Column A Column B Column C Column D Column E ------------------------------ Additions ------------------------------ Balance at Charged to Charged to Balance at Beginning Costs and Other Deductions End of Description of Period Expenses Accounts (Note) Period - --------------------- ---------------- ------------- --------------- ------------- ------------- Allowance for Doubtful Accounts: Year ended: December 31, 1995 $461 330 366 $425 September 30, 1996 $425 440 426 $439 September 30, 1997 $439 507 417 $529 Note: Accounts receivable written off, net of recoveries Valuation Reserve - Notes Receivable December 31, 1995 $1,127 122 $1,249 September 30, 1996 $1,249 288 $1,537 September 30, 1997 $1,537 183 $1,720 Valuation Reserve - Investments December 31, 1995 $150 0 $150 September 30, 1996 $150 154 304 $0 September 30, 1997 $0 $0
42 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 directed to the information regarding directors under the caption "Election of Directors" on pages 1 through 3 of the Proxy Statement issued to Shareholders for the 1998 Annual Meeting (the 1998 Proxy Statement), which information is incorporated herein by reference. Under Section 16 of the Securities Exchange Act of 1934, holders of more than 10 percent of the Common Stock and directors and certain officers of the Company are required to file reports ("Section 16(a) Statements") of beneficial ownership of Common Stock and changes in such ownership with the Securities and Exchange Commission. The Company is required to identify in its proxy statements those persons who to the Company's knowledge were required to file Section 16(a) Statements and did not do so in a timely basis. Based solely on a review of copies of Section 16(a) Statements furnished to the Company during and with respect to its most recent fiscal year and on written representations from reporting persons, the Company believes that each person who at any time during the most recent fiscal year was a reporting person filed all required Section 16(a) Statements on a timely basis, except one report on Form 4 was filed late for J. D. Wessling and for Thomas E. Cronin. The Report on Form 5 was filed late for Ralph E. Boyd, Carl Burnham, Jr., Melvin C. Clapp, W. Brian Matsuyama, Brooks G. Ragen, and Mary A. Williams. ITEM 11. EXECUTIVE COMPENSATION Reference is directed to the information regarding executive compensation set forth in the 1998 Proxy Statement, under "Executive Compensation" on pages 7, 8, and 9, and under "Compensation Committee Interlocks and Insider Participation" on page 9, 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 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. Reference is directed to the information regarding security ownership of certain beneficial owners and management under the caption "Security Ownership of Certain Beneficial Owners and Management" on page 4 of the 1998 Proxy Statement (excluding the information under the subheading "Section 16(a) Beneficial Ownership Reporting Compliance"), which information is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. Reference is directed to the information regarding certain relationships and transactions under the caption "Compensation Committee Interlocks and Insider Participation" on page 9 of the 1998 Proxy Statement, which information is incorporated herein by reference 43 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) 1. Financial Statements (Included in Part II of this report): Independent Auditors' Report Consolidated Statements of Net Earnings Available to Common Shareholders or the Year Ended September 30, 1997, Nine Months Ended September 30, 1996, and the Year Ended December 31, 1995 Consolidated Balance Sheets, September 30, 1997, and September 30, 1996 Consolidated Statements of Common Shareholders' Equity for the Year Ended September 30, 1997, Nine Months Ended September 30, 1996, and the Year Ended December 31, 1995 Consolidated Statements of Cash Flows for the Year Ended September 30, 1997, Nine Months Ended September 30, 1996, and the Year Ended December 31, 1995 Notes to Consolidated Financial Statements (a) 2. Financial Statement Schedules (Included in Part II of this report): Independent Auditors' Report on Financial Statement Schedule Schedule II - Valuation and Qualifying Accounts (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: None. 44 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 December 22, 1997 By /s/ J. D. Wessling - ------------------------ -------------------- Date J. D. Wessling 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. Chairman of the Board, Chief Executive Officer /s/ W. Brian Matsuyama and Director December 22, 1997 - -------------------------- (Principal Executive Officer) ----------------- W. Brian Matsuyama Date President and /s/ Ralph E. Boyd Chief Operating Officer December 22, 1997 - -------------------------- ----------------- Ralph E. Boyd Date Vice President - Finance, /s/ J. D. Wessling Chief Financial Officer December 22, 1997 - -------------------------- (Principal Financial Officer) ----------------- J. D. Wessling Date Controller and Chief /s/ James E. Haug Accounting Officer December 22, 1997 - -------------------------- (Principal Accounting Officer) ----------------- James E. Haug Date /s/ Carl Burnham, Jr. Director December 22, 1997 - -------------------------- ----------------- Carl Burnham, Jr. Date /s/ Melvin C. Clapp Director December 22, 1997 - -------------------------- ----------------- Melvin C. Clapp Date /s/ Thomas E. Cronin Director December 22, 1997 - -------------------------- ----------------- Thomas E. Cronin Date /s/ David A. Ederer Director December 22, 1997 - -------------------------- ----------------- David A. Ederer Date /s/ Howard L. Hubbard Director December 22, 1997 - -------------------------- ----------------- Howard L. Hubbard Date /s/ Larry L. Pinnt Director December 22, 1997 - -------------------------- ----------------- Larry L. Pinnt Date /s/ Brooks G. Ragen Director December 22, 1997 - -------------------------- ----------------- Brooks G. Ragen Date /s/ Mary A. Williams Director December 22, 1997 - -------------------------- ----------------- Mary A. Williams Date 45 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 dated July 18, 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 dated July 18, 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 Letter Agreement dated April 28, 1995 between CanWest Gas Supply U.S.A., Inc. and the Registrant for Winter Peaking Supply - 1995 through 1998. Incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995. 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 1991 Form 10-K. 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, 10.9, and 10.22. 10.7 Amendment dated October 9, 1997 to Natural Gas Sales Agreement dated November 1, 1990, between Canadian Hydrocarbons Marketing, Inc., and the Registrant, as amended by the Consent 46 to Assignments dated June 1, 1997. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT. 10.9 Long Term Gas Sales Agreement dated August 26, 1993, between Canadian Hydrocarbons Marketing Inc., and the Registrant, as amended by the Consent to Assignments dated June 1, 1997. Incorporated by reference to Exhibit 10.2 to amendment no. 1 to the Registrant's quarterly report on Form 10-Q/A for the quarter ended September 30, 1993. 10.11 Gas transportation agreement between Pacific Gas Transmission Company and the Registrant dated as of April 30, 1997. 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 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. 10.17 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 Annual Report on Form 10-K for the year ended December 31, 1995. 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. 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 Annual Report on Form 10-K for the year ended December 31, 1994. 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 Annual Report on Form 10-K for the year ended December 31, 1994. 10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant, as amended by Amended Exhibit A, effective October 1, 1997. Incorporated by reference to Exhibit 10.21 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 47 10.21.1 Amended Exhibit A, effective October 1, 1997, to Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant. 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 Registrant which replaces and substitutes for the Kingsgate Gas Sales Agreement dated September 23, 1960, as amended by the Consent to Assignments dated June 1, 1997, and the letter amendment dated October 8, 1997. Incorporated by reference to Exhibit 10.22 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 10.22.1 Letter amendment dated October 8, 1997, to Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Westcoast Gas Services, Inc. and Registrant which replaces and substitutes for the Kingsgate Gas Sales Agreement dated September 23, 1961. 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 Annual Report on Form 10-K for the year ended December 31, 1994. 10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest Pipeline Corporation and Registrant. Incorporated by reference to Exhibit 10.24 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 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 Registrant. Incorporated by reference to Exhibit 10.25 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between Tenaska Gas Co., Tenaska Washington Partners, L.P., and Registrant. Incorporated by reference to Exhibit 10.26 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 10.27 Agreement for Peaking Gas Supply Service dated November 22, 1991, between Longview Fibre Company and Registrant, as amended by the Amendment No. 3 to Agreement for Peaking Gas Service, dated as of October 2, 1997. Incorporated by reference to Exhibit 10.27 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994. 10.27.1 Amendment No. 3 to Agreement for Peaking Gas Service, dated as of October 2, 1997. 10.28 Letter Agreement dated October 24, 1995 between Westcoast Gas Services, Inc. and the Registrant for Winter Peaking Supply - 1995 through 1998. Incorporated by reference to Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1995. 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 Income Retirement 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 Employment agreement between the Registrant and W. Brian Matsuyama.* Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2. 10.32 Employment agreement between the Registrant and Jon T. Stoltz.* Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2. 48 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. 27. Financial Data Schedule. - ------------------------ * Management contract or compensatory plan or arrangement. 49 EX-10.6 2 EXH 10.6 EXHIBIT 10.6 CONSENT TO ASSIGNMENTS DATED JUNE 1, 1997 In this document, "Agreements" means all natural gas, power marketing, energy services, transportation, storage, or other form of merchant agreements or transactions in effect as of June 1, 1997, between Westcoast Gas Services Inc. (WGSI), and Cascade Natural Gas Corporation, (the "COMPANY") including without limitation the agreements or transactions listed on the attached Schedule I. Company hereby consents to the assignment and conveyance by WGSI of all of WGSI's rights under the respective Agreements, and delegation by WGSI of all of its obligations under the Agreements, to Engage Energy Canada, L.P. (Engage), effective as of June 1, 1997. Engage agrees that, on receipt of such assignment and delegation, from and after June 1, 1997, it will assume all of WGSI's rights and obligations under the Agreements. The Agreements so assigned to Engage shall remain in full force and effect between Engage and the Company. Engage and Company hereby each ratify and confirm the terms of the Agreements for all purposes, effective June 1, 1997. This Consent document may be signed in any number of counterparts, and upon each party having executed and delivered to Engage, and Engage having executed all of those counterparts, all counterparts will have the same force and effect and if all parties had executed and delivered the same Consent document. ENGAGE ENERGY CANADA, L.P. CASCADE NATURAL GAS CORPORATION By: By: ------------------------------ ------------------------- Name: Peter Leier Name: ------------------------- Title: Vice President and General Counsel Title: -------------------------
- ----------------------------------------------------------------------------------------------------------- Cascade Natural Gas Corp MERCHANT 1872 Gas Transaction 01-Jul-94 01-Jul-94 evergreen Agreement - ----------------------------------------------------------------------------------------------------------- Cascade Natural Gas Corp MERCHANT Gas Sales Agreement 17-Aug-94 17-Aug-94 31-Oct-04 (Kingsgate - 27,037 MMBtu/d) - ----------------------------------------------------------------------------------------------------------- Cascade Natural Gas Corp MERCHANT 1934 Gas Sales Agreement 01-Nov-90 01-Nov-90 31-Oct-97 (Cascade #1 - 5,000 MMBtu/d) - ----------------------------------------------------------------------------------------------------------- Cascade Natural Gas Corp MERCHANT 1958 Gas Sales Agreement 26-Aug-93 01-Nov-93 31-Oct-98 (Cascade #2 - 10,000 MMBtu/d) - -----------------------------------------------------------------------------------------------------------
EX-10.7 3 EXH 10.7 [*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION EXHIBIT 10.7 October 9, 1997 CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue North Seattle, Washington 98109 ATTENTION: MS. MELISSA WHITTEN - ---------------------------------- Dear Melissa: RE: NATURAL GAS SALES AGREEMENT DATED NOVEMBER 1, 1990 AS AMENDED BETWEEN BETWEEN ENGAGE ENERGY CANADA, L.P. (SUCCESSOR TO CANADIAN HYDROCARBONS MARKETING INC./WESTCOAST GAS SERVICES INC.) ("ENGAGE") AND CASCADE NATURAL GAS CORPORATION ("CASCADE") - -------------------------------------------------------------------------------- Pursuant to Section 7.09 of the above noted agreement, this letter shall confirm that the Gas Commodity Price and Reserves Standby Fee for the contract year November 1, 1997 through October 31, 1998 be established as follows: (a) GAS COMMODITY PRICE (i) FOR THE PERIOD NOVEMBER 1, 1997 - DECEMBER 31, 1997 The Gas Commodity Price payable by Cascade per MMBtu of gas delivered shall be U.S$[*]/MMBtu. MINUS those related Westcoast Energy Inc. Demand Charges paid by Cascade for the applicable contract month converted to U.S$/MMBtu unit rate assuming a 100% load factor. MINUS a Reserves Standby Charge credit of U.S$[*]/MMBtu. (ii) FOR THE PERIOD JANUARY 1, 1998 - OCTOBER 31, 1998 The Gas Commodity Price payable by Cascade per MMBtu of gas delivered shall be calculated monthly based upon the following: The first of the month index as quoted in the publication "Inside F.E.R.C.'s Gas Market Report, Price of Spot Gas Delivered in Pipelines (MMBtu/day)" under the heading "Northwest Pipeline Corporation-Canadian Border" Plus $[*] U.S/ MMBtu. MINUS those related Westcoast Energy Inc. Demand Charges paid by Cascade for the applicable contract month converted to U.S$/MMBtu unit rate assuming a 100% load factor. MINUS a Reserves Standby Charge credit of U.S$[*]/MMBtu. (b) RESERVES STANDBY FEE The Reserves Standby Fee shall be rolled over at the existing fee of U.S$[*]/MMBtu. Please indicate your acceptance of the foregoing by signing both copies of this letter and return one copy to us for our files. If you require any further information please give me a call at (403) 297-1838. Yours truly, ENGAGE ENERGY CANADA, L.P.. Jeff A. Thompson, Vice President Supply and Marketing British Columbia and Pacific Northwest Region JAT/tw c.c. Lydia Sloan ACCEPTED AND AGREED TO this ______ day of ___________________,1997 CASCADE NATURAL GAS CORPORATION Per: ------------------------ Title: ---------------------- October 9, 1997 CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue North Seattle, Washington 98109 ATTENTION: MS. MELISSA WHITTEN - ---------------------------------- Dear Melissa: RE: (WGSI 5K AGREEMENT) NATURAL GAS SALES AGREEMENT DATED NOVEMBER 1, 1990 AS AMENDED BETWEEN BETWEEN ENGAGE ENERGY CANADA, L.P. (SUCCESSOR TO CANADIAN HYDROCARBONS MARKETING INC./WESTCOAST GAS SERVICES INC.) ("ENGAGE") AND CASCADE NATURAL GAS CORPORATION ("CASCADE") - -------------------------------------------------------------------------------- Enclosed for signature are duplicate originals of the above noted agreement amending Section 7.09 of the Gas Commodity Price for the period November 1, 1997 to October 31, 1998. Please sign both copies and return one copy for our files. If you require any further information please give me a call at (403) 297-1838. Yours truly, ENGAGE ENERGY CANADA, L.P.. Jeff A. Thompson, Vice President Supply and Marketing British Columbia and Pacific Northwest Region Att. JAT/tw c.c. Lydia Sloan EX-10.11 4 EXH 10.11 EXHIBIT 10.11 GAS TRANSPORTATION AGREEMENT THIS AGREEMENT is made and entered into this 30th day of April, 1997, by and between PACIFIC GAS TRANSMISSION COMPANY, a California Corporation (hereinafter referred to as "PGT"), and CASCADE NATURAL GAS CORPORATION, a corporation existing under the laws of the State of Washington (hereinafter referred to as "Shipper"). WHEREAS, PGT owns and operates a natural gas pipeline transmission system which extends from a point of interconnection with the pipeline facilities of Alberta Natural Gas Company Ltd. (ANG) at the International Boundary near Kingsgate, British Columbia, through the states of Idaho, Washington and Oregon to a point of interconnection with Pacific Gas and Electric Company at the Oregon-California border near Malin, Oregon; and WHEREAS, Shipper desires PGT, on an interruptible basis, to transport certain quantities of natural gas as indicated in Exhibit A and WHEREAS, PGT is willing to transport certain quantities of natural gas for Shipper, on an interruptible basis, NOW, THEREFORE, the parties agree as follows: I GOVERNMENTAL AUTHORITY 1.1 This Interruptible Transportation Agreement ("Agreement") is made pursuant to the regulations of the Federal Energy Regulatory Commission (FERC) contained in 18 CFR Part 284, Subpart G, as amended from time to time. 1.2 This Agreement is subject to all valid legislation with respect to the subject matters hereof, either state or federal, and to all valid present and future decisions, orders, rules, regulations and ordinances of all duly constituted governmental authorities having jurisdiction. 1.3 Shipper shall reimburse PGT for any and all filing fees incurred by PGT in seeking governmental authorization for the initiation, extension, or termination of service under this Agreement and Rate Schedule ITS-1. Shipper shall reimburse PGT for such fees at PGT's designated office within ten (10) days of receipt of notice from PGT that such fees are due and payable. Additionally, Shipper shall reimburse PGT for any and all penalty fees or fines assessed PGT caused by the negligence of Shipper in not obtaining all proper Canadian and domestic import/export licenses, surety bonds or any other documents and approvals related to the Canadian exportation and subsequent domestic importation of natural gas transported by PGT hereunder. II QUANTITY OF GAS AND PRIORITY OF SERVICE 2.1 Subject to the terms and provisions of this Agreement and PGT's Transportation General Terms and Conditions applicable to Rate Schedule ITS-1, daily receipts of gas by PGT from Shipper at the point(s) of receipt shall be equal to daily deliveries of gas by PGT to Shipper at the point(s) of delivery; provided, however, Shipper shall deliver to PGT an additional quantity of natural gas at the point(s) of receipt as compressor station fuel, line loss and unaccounted for gas as specified in the Exhibit A attached hereto. Any limitations of the quantities to be received from each point of receipt and/or delivered to each point of delivery shall be as specified on the Exhibit A attached hereto. The service under this Agreement shall be conditioned upon the availability of capacity sufficient to provide the service without detriment or disadvantage to those customers of PGT that have a higher priority of service. 2.2 The maximum quantities of gas to be received for Shipper's account at the point(s) of receipt and to be delivered by PGT to the point(s) of delivery are set forth in Exhibit A. 2.3 In providing service to its existing or new customers, PGT will use the priorities of service specified in Paragraph 18 of PGT's Transportation General Terms and Conditions on file with the FERC. 2.4 Prior to initiation of service, Shipper shall provide PGT with any information required by the FERC, as well as all information identified in PGT's Transportation General Terms and Conditions applicable to Rate Schedule ITS-1. III TERM OF AGREEMENT 3.1 This Agreement shall become effective May 1, 1997, and shall continue in full force and effect until May 1, 2007, and year to year thereafter until canceled by ninety (90) day prior written notice given by either party to the other. IV POINTS OF RECEIPT AND DELIVERY 4.1 The point(s) of receipt of gas deliveries to PGT is as designated in Exhibit A, attached hereto. 4.2 The point(s) of delivery of gas to Shipper is as designated in Exhibit A, attached hereto. 4.3 Shipper shall deliver or cause to be delivered to PGT the gas to be transported hereunder at pressures sufficient to deliver such gas into PGT's system at the point(s) of receipt. PGT shall deliver the gas to be transported hereunder to or for the account of Shipper at the pressures existing in PGT's system at the point(s) of delivery. V OPERATING PROCEDURES 5.1 Shipper shall conform to the operating procedures set forth in PGT's Transportation General Terms and Conditions. 5.2 Nothing in Section 5.1 shall compel PGT to transport gas pursuant to Shipper's request on any given day. PGT shall have the right to interrupt or curtail the transport of gas for the account of Shipper pursuant to PGT's Transportation General Terms and Conditions applicable to Rate Schedule ITS-1. VI RATE(S), RATE SCHEDULES, AND GENERAL TERMS AND CONDITIONS OF SERVICE 6.1 Shipper shall pay PGT each month for services rendered pursuant to this Agreement in accordance with PGT's Rate Schedule ITS-1, or superseding rate schedule(s), on file with and subject to the jurisdiction of FERC. A summary of the transportation charges is provided on Exhibit A attached hereto. 6.2 Shipper shall compensate PGT each month for compressor station fuel, line loss and other unaccounted for gas associated with this transportation service provided herein in accordance with PGT's Rate Schedule ITS-1, or superseding rate schedule(s), on file with and subject to the jurisdiction of FERC. A summary of the percentages of gas to be furnished by Shipper for PGT's system fuel and losses is provided on Exhibit A attached hereto. 6.3 This Agreement in all respects shall be and remains subject to the applicable provisions of Rate Schedule ITS-1, or superseding rate schedule(s) and of the applicable Transportation General Terms and Conditions of PGT's FERC Gas Tariff Original Volume No. 1-A on file with the FERC, all of which are by this reference made a part hereof. 6.4 PGT shall have the unilateral right from time to time to propose and file with FERC such changes in the rates and charges applicable to transportation services pursuant to this Agreement, the rate schedule(s) under which this service is hereunder provided, or any provisions of PGT's Transportation General Terms and Conditions applicable to such services. Shipper shall have the right to protest any such changes proposed by PGT and to exercise any other rights that Shipper may have with respect thereto. VII MISCELLANEOUS 7.1 This Agreement shall be interpreted according to the laws of the State of California. 7.2 Shipper warrants that upstream and downstream transportation arrangements are in place, or will be in place as of the requested effective date of service, and that it has advised the upstream and downstream transporters of the receipt and delivery points under this Agreement and any quantity limitations for each point as specified on Exhibit A attached hereto. 7.3 Shipper agrees to indemnify and hold PGT harmless for refusal to transport gas hereunder in the event any upstream or downstream transporter fails to receive or deliver gas as contemplated by this Agreement. 1 7.4 Unless herein provided to the contrary, any notice called for in this Agreement shall be in writing and shall be considered as having been given if delivered by registered mail or telex with all postage or charges prepaid, to either PGT or Shipper at the place designated below. Routine communications, including monthly statements and payment, shall be considered as duly delivered when received by ordinary mail. Unless changed, the addresses of the parties are as follows: "PGT" PACIFIC GAS TRANSMISSION 2100 SW River Parkway Portland, Oregon 97201 Attention: James E. Robbins Manager, Gas Transportation & Services "Shipper" (Notices) CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue N. Seattle, WA 98109 Attention: Melissa Whitten (Invoices) CASCADE NATURAL GAS CORPORATION 222 Fairvew Avenue N. Seattle, WA 98109 Attention: King Oberg 7.5 A waiver by either party of any one or more defaults by the other hereunder shall not operate as a waiver of any future default or defaults, whether of a like or of a different character. 7.6 This Agreement may only be amended by an instrument in writing executed by both parties hereto. 7.7 Nothing in this Agreement shall be deemed to create any rights or obligations between the parties hereto after the expiration of the term set forth herein, except that termination of this Agreement shall not relieve either party of the obligation to correct any quantity imbalances or Shipper of the obligation to pay any amounts due hereunder to PGT. 7.8 Exhibit A attached hereto is incorporated herein by reference and made a part hereof for all purposes. IN WITNESS WHEREOF the parties hereto have caused this Agreement to be executed as of the day and year first above written. PACIFIC GAS TRANSMISSION COMPANY By: -------------------------- Name: James E. Robbins Title: Manager, Gas Transportation & Services CASCADE NATURAL GAS CORPORATION Contract electronically signed on Pacific Trail-TM- By: Mark Vaughan Date signed: 04/30/1997 3 EXHIBIT A TO THE INTERRUPTIBLE TRANSPORTATION AGREEMENT DATED APRIL 30, 1997, BETWEEN PACIFIC GAS TRANSMISSION COMPANY AND CASCADE NATURAL GAS CORPORATION (1) MDQ Delivered (2) Receipt Point Delivery Point Summer MMBtu/d Winter MMBtu/d - ------------- -------------- -------------- -------------- Kingsgate, B.C. Moyie Springs, ID 50,000 50,000 Kingsgate, B.C. Bonner's Ferry, ID 50,000 50,000 Kingsgate, B.C. Schweitzer, ID 50,000 50,000 Kingsgate, B.C. Sandpoint, ID 50,000 50,000 Kingsgate, B.C. Athol, ID 50,000 50,000 Kingsgate, B.C. Rathdrum, ID 50,000 50,000 Kingsgate, B.C. Rathdrum CT, ID 50,000 50,000 Kingsgate, B.C. Spokane NPC, WA 50,000 50,000 Kingsgate, B.C. Spokane WWP, WA 50,000 50,000 Kingsgate, B.C. Mica, WA 50,000 50,000 Kingsgate, B.C. Spangle, WA 50,000 50,000 Kingsgate, B.C. Rosalia, WA 50,000 50,000 Kingsgate, B.C. St. John, WA 50,000 50,000 Kingsgate, B.C. Palouse, WA 50,000 50,000 Kingsgate, B.C. Lacrosse, WA 50,000 50,000 Kingsgate, B.C. Wallula, WA 50,000 50,000 Kingsgate, B.C. Kosmos Farm, OR 50,000 50,000 Kingsgate, B.C. Stanfield Exchange, OR 50,000 50,000 Kingsgate, B.C. Stanfield City Tap, OR 50,000 50,000 Kingsgate, B.C. South Hermiston, OR 50,000 50,000 Kingsgate, B.C. Coyote Springs, OR 50,000 50,000 Kingsgate, B.C. Boardman, OR 50,000 50,000 Kingsgate, B.C. Madras, OR 50,000 50,000 Kingsgate, B.C. Prineville, OR 50,000 50,000 Kingsgate, B.C. Redmond, OR 50,000 50,000 Kingsgate, B.C. Bend, OR 50,000 50,000 Kingsgate, B.C. South Bend, OR 50,000 50,000 Kingsgate, B.C. Stearns, OR 50,000 50,000 Kingsgate, B.C. LaPine,OR 50,000 50,000 Kingsgate, B.C. Gilchrist, OR 50,000 50,000 Kingsgate, B.C. Chemult, OR 50,000 50,000 Kingsgate, B.C. Diamond Junction, OR 50,000 50,000 Kingsgate, B.C. Klamath Falls, OR 50,000 50,000 Kingsgate, B.C. Medford, OR 50,000 50,000 Kingsgate, B.C. Tuscarora, OR 50,000 50,000 Kingsgate, B.C. Malin, OR 50,000 50,000 Spokane NPC, WA Kingsgate, B.C. 50,000 50,000 Spokane NPC, WA Stanfield Exchange, OR 50,000 50,000 MDQ Delivered (2) Receipt Point Delivery Point Summer MMBtu/d Winter MMBtu/d - ------------- -------------- -------------- -------------- Spokane NPC, WA Tuscarora, OR 50,000 50,000 Spokane NPC, WA Malin, OR 50,000 50,000 Spokane WWP, WA Kingsgate, B.C. 50,000 50,000 Spokane WWP, WA Stanfield Exchange, OR 50,000 50,000 Spokane WWP, WA Tuscarora, OR 50,000 50,000 Spokane WWP, WA Malin, OR 50,000 50,000 Stanfield Exchange, OR Kingsgate, BC 50,000 50,000 Stanfield Exchange, OR Spokane NPC, WA 50,000 50,000 Stanfield Exchange, OR Spokane WWP, WA 50,000 50,000 Stanfield Exchange, OR Tuscarora, OR 50,000 50,000 Stanfield Exchange, OR Malin, OR 50,000 50,000 Tuscarora, OR Kingsgate, B.C. 50,000 50,000 Tuscarora, OR Spokane NPC, WA 50,000 50,000 Tuscarora, OR Spokane WWP, WA 50,000 50,000 Tuscarora, OR Stanfield Exchange, OR 50,000 50,000 Tuscarora, OR Malin, OR 50,000 50,000 Malin, OR Kingsgate, B.C. 50,000 50,000 Malin, OR Spokane NPC, WA 50,000 50,000 Malin, OR Spokane WWP, WA 50,000 50,000 Malin, OR Stanfield Exchange, OR 50,000 50,000 Malin, OR Stanfield City Tap, OR 50,000 50,000 Malin, OR Medford, OR 50,000 50,000 Malin, OR Tuscarora, OR 50,000 50,000 5 EFFECTIVE MAY 1,1997 1) Rates for transportation service under this Agreement and gas to be supplied by Shipper at Shipper's point(s) of receipt for fuels, line loss, and unaccounted for purposes are listed in the Statement of Effective Rates and Changes of PGT's FERC Gas Tariff, First Revised Volume 1-A, or superseding tariff. 2) Total Maximum Daily Contract Quantity (delivered) not to exceed 50,000 MMBtu/d. 6 EX-10.17-1 5 EXH 10.17.1 EXHIBIT 10.17.1 SECOND AMENDMENT TO THE AGREEMENT FOR THE RELEASE OF JACKSON PRAIRIE STORAGE CAPACITY On this 30th day of July, 1997, The Washington Water Power Company ("Water Power") and Cascade Natural Gas Corporation ("Cascade") (hereinafter collectively referred to as the "Parties") have entered into this Agreement ("Second Amendment") for the purpose of amending the Agreement for the Release of Jackson Prairie Storage Capacity ("Release Agreement") originally executed by the Parties on July 23, 1990. WITNESSETH: WHEREAS, Water Power and Cascade are parties to a Release Agreement, whereby Water Power will release a portion of its capacity and deliverability in the Jackson Prairie Storage Project to Cascade, for a primary term ending April 30, 1998; and WHEREAS, Water Power and Cascade desire to extend the primary term of the aforementioned Release Agreement to April 30, 2001, subject to the receipt of necessary regulatory approvals; NOW, THEREFORE, in consideration of their mutual covenants, the Parties hereby agree to amend the Release Agreement in the following respects: 1. Section 4.1 of the Release Agreement, as previously amended, is hereby revised to delete the references to "April 30, 1998" as the end of the primary term of the Agreement, and substitute therefore the date of "April 30, 2001", so that Section 4.1, as newly revised, reads as follows: 2. 4.1 Subject to the satisfaction of all conditions precedent, including the receipt of necessary regulatory approvals, the primary term of this Agreement shall continue until April 30, 2001, and thereafter, on a year-to-year basis unless terminated by either Party upon twelve (12) months' written notice of termination received prior to April 30, 2001, or any anniversary thereafter. 1. Section 5.3 of the Release Agreement, as previously amended, is hereby revised to delete the reference to "November 1, 1995" as the date by which all conditions precedent must be satisfied, and to substitute therefore the date of "November 1, 1998", so that Section 5.3, as newly revised, reads as follows: 2. 5.3 If all conditions precedent are not satisfied in time to allow for Cascade's use of the released Deliverability and Capacity by November 1, 1998, either Party may, upon fifteen (15) day's written notice, cancel this Agreement. 1. The Parties agree to substitute a revised version of the following Exhibit, which was previously attached to the Release Agreement: 2. Exhibit B: Consent of Northwest Pipeline and Puget Sound Energy Company to the Release. IN WITNESS WHEREOF each Party has caused this Second Amendment to be executed under the hands of its duly authorized representative. THE WASHINGTON WATER POWER CASCADE NATURAL GAS COMPANY CORPORATION By: /s/ By: /s/ --------------------------- --------- Don Kopczynski Jon Stoltz Manager, Resource Optimization Vice President, Planning and Rates EX-10.21-1 6 EXH 10.21.1 EXHIBIT 10.21.1 AMENDED EXHIBIT "A" To The GAS PURCHASE CONTRACT As Of: October 1, 1994 Between CASCADE NATURAL GAS CORPORATION ("BUYER") and IGI RESOURCES, INC. ("SELLER") Effective Date of this Exhibit "A": October 1, 1997 ------------------- Ending Date of this Exhibit "A": October 31, 1997 -------------------- DELIVERY POINT As defined in Section 1.01(g) of the Contract noted above MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446 DELIVERY POINT SELLING PRICE 1/ ------------- 1. The Delivery Point Selling Price shall be equal to [*] plus the actual cost of firm NOVA re-delivery service and firm ANG receipt and re-delivery service plus any applicable allowance for fuel-in-kind associated with such services. "BUYER" CASCADE NATURAL GAS CORPORATION By: -------------------------------- Name: ------------------------------- Title: ------------------------------ "SELLER" IGI RESOURCES, INC. By: --------------------------------- Randy Schultz Executive Vice President Chief Operating Officer [*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION AMENDED EXHIBIT "A" To The GAS PURCHASE CONTRACT As Of: October 1, 1994 Between CASCADE NATURAL GAS CORPORATION ("BUYER") and IGI RESOURCES, INC. ("SELLER") Effective Date of this Exhibit "A": March 1, 1998 ----------------- Ending Date of this Exhibit "A": September 30, 1998 ---------------------- DELIVERY POINT As defined in Section 1.01(g) of the Contract noted above MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446 DELIVERY POINT SELLING PRICE 1/ --------------- 1. The Delivery Point Selling Price shall be equal to [*] plus the actual cost of firm NOVA re-delivery service and firm ANG receipt and re-delivery service plus any applicable allowance for fuel-in-kind associated with such services. "BUYER" CASCADE NATURAL GAS CORPORATION By: -------------------------------- Name: ------------------------------- Title: ------------------------------ "SELLER" IGI RESOURCES, INC. By: --------------------------------- Randy Schultz Executive Vice President Chief Operating Officer [*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION AMENDED EXHIBIT "A" To The GAS PURCHASE CONTRACT As Of: October 1, 1994 Between CASCADE NATURAL GAS CORPORATION ("BUYER") and IGI RESOURCES, INC. ("SELLER") Effective Date of this Exhibit "A": November 1, 1997 -------------------- Ending Date of this Exhibit "A": February 28, 1998 --------------------- DELIVERY POINT As defined in Section 1.01(g) of the Contract noted above MAXIMUM DAILY CONTRACT QUANTITY(MMBTU) 7,446 DELIVERY POINT SELLING PRICE 1/ ----------------- 1. The Delivery Point Selling Price shall be equal to [*]($[*] U.S. dry) per MMBTU at AECO-C Hub plus the actual cost of firm NOVA re-delivery service and firm ANG receipt and re-delivery service plus any applicable allowance for fuel-in-kind associated with such services. "BUYER" CASCADE NATURAL GAS CORPORATION By: --------------------------------- Name: ------------------------------- Title: ------------------------------ "SELLER" IGI RESOURCES, INC. By: --------------------------------- Randy Schultz Executive Vice President Chief Operating Officer EX-10.22-1 7 EXH 10.22.1 [*]=CONFIDENTIAL INFORMATION OMITTED AND FILED SEPARATELY WITH THE COMMISSION EXHIBIT 10.22.1 VIA COURIER October 8, 1997 CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue North Seattle, Washington USA 98109 ATTENTION: MS. MELISSA WHITTEN Dear Ms. Whitten: RE: AMENDED AND RESTATED NATURAL GAS SALES AGREEMENT DATED AUGUST 17, 1994 BETWEEN ENGAGE ENERGY CANADA, L.P. ("ENGAGE") (SUCCESSOR TO WESTCOAST GAS SERVICES INC.) ("SELLER") AND CASCADE NATURAL GAS CORPORATION ("BUYER") (THE "GAS SALES AGREEMENT") - -------------------------------------------------------------------------------- This letter shall confirm the agreement between Engage and Cascade Natural Gas Corporation ("Cascade") to amend Section 7.8 of the Gas Sales Agreement as follows: 7.8 GAS COMMODITY PRICE a. The Gas Commodity Price to be paid for gas delivered each month during the period commencing on November 1, 1997 and expiring on October 31, 1998 shall be calculated as a percentage price determined under Subsection c below, based upon a weighted average of the following published prices (the "INDEX PRICE"): (i) the "ROCKY MOUNTAIN" designated supply source into the Northwest pipeline system, as that price is provided in the publication entitled, "INSIDE F.E.R.C.'S GAS MARKET REPORT" in the table entitled, "PRICES OF SPOT GAS DELIVERED TO PIPELINES.......(per MMBtu dry), under the "NORTHWEST PIPELINE CORP." entry multiplied by [*]%; and (ii) the "CANADIAN BORDER" designated supply source into the Northwest pipeline system, as that price is provided in the publication entitled, "INSIDE F.E.R.C.'S GAS MARKET REPORT" in the table entitled, "PRICES OF SPOT GAS DELIVERED TO PIPELINES.......(per MMBtu dry), under the "NORTHWEST PIPELINE CORP" entry multiplied by [*]%; and (iii) the "AECO "C" & N.I.T. ONE-MONTH SPOT" price as published by the "CANADIAN GAS PRICE REPORTER" in the table entitled, "CANADIAN NATURAL GAS SUPPLY PRICES" under the column entitled "AVG" in U.S$/MMBtu multiplied by [*]%. b. The reference publication issue to determine the Gas Commodity Price for a month shall be the first issue which is published after the first day of the month. 12/23/97 Cascade Natural Gas Corporation Page 2 - -------------------------------------------------------------------------------- c. The percentage of the Index Price shall be determined based on the quantity of gas purchased by Buyer under this Agreement during a specified period, in accordance with the following table: "INDEX PRICE" PERCENTAGE TABLE Period Quantity of Gas Purchased Applicable Percentage During Period of "Index Price" - --------------- ------------------------- --------------------- Nov. 1, 1997 to 0 to 4,136,661 [*]% Oct. 31, 1998 4,136,662 to 7,029,620 [*]% 7,029,621 to 9,868,505 [*]% Engage and Cascade further agree that "Exchange Rate" shall mean the thirty (30) day average of the daily spot exchange rate, expressed as U.S$/Cdn.$1.00, and that this definition shall supersede the definition provided in subclause 1.1y of the Gas Sales Agreement. Terms or phrases defined or used in the Gas Sales Agreement shall have the same meaning herein unless specifically stated otherwise. Please indicate your agreement with the foregoing by signing both copies of this letter in the space provided below. Please retain one copy for your files and return the other copy to Engage at your earliest convenience. Yours truly, ENGAGE ENERGY CANADA, L.P. Jeff Thompson, Vice President, Supply and Marketing British Columbia and Pacific Northwest Region JAT/tw c.c. Lydia Sloan ACCEPTED AND AGREED TO THIS DAY OF , 1997. ------- ----------------------- CASCADE NATURAL GAS CORPORATION Per: ------------------------- Title: ----------------------- 12/23/97 Cascade Natural Gas Corporation Page 3 - -------------------------------------------------------------------------------- VIA COURIER October 8, 1997 CASCADE NATURAL GAS CORPORATION 222 Fairview Avenue North Seattle, Washington 98109 ATTENTION: MS. MELISSA WHITTEN - ---------------------------------- Dear Ms. Whitten: RE: AMENDED AND RESTATED NATURAL GAS SALES AGREEMENT DATED AUGUST 17, 1994 BETWEEN ENGAGE ENERGY CANADA, L.P. ("ENGAGE") (SUCCESSOR TO WESTCOAST GAS SERVICES INC.) ("SELLER") AND CASCADE NATURAL GAS CORPORATION ("BUYER") (THE "GAS SALES AGREEMENT") (KINGSGATE AGREEMENT) - -------------------------------------------------------------------------------- Enclosed for signature are duplicate originals of the above noted agreement extending the Gas Commodity Price under Section 7.8 for an additional one year term. Please sign both copies and return one for our files. If you have any questions please give me a call at (403) 297-1838. Yours truly, ENGAGE ENERGY CANADA, L.P. Jeff Thompson, Vice President, Supply and Marketing British Columbia and Pacific Northwest Region Att. JAT/tw c.c. Lydia Sloan EX-10.27-1 8 EXH 10.27.1 EXHIBIT 10.27.1 SETTLEMENT AGREEMENT OCTOBER 2, 1997 The undersigned, Longview Fibre Company ("Fibre") and Cascade Natural Gas Corporation ("Cascade"), are parties to the Agreement for Peaking Gas Service dated as of March 22, 1991 ("PGS Agreement"). The parties have disagreed over the amount properly payable by Cascade to Fibre for service under the PGS Agreement for the period beginning October 1, 1996. In the interest of compromise and settlement, the parties have entered into this Settlement Agreement to resolve their differences without need for arbitration or litigation. This Settlement Agreement is a compromise reached between the parties after negotiation relating to pricing to the service rendered and to be rendered by Fibre to Cascade under the PGS Agreement. The applicable period of agreement for the PGS Fee is from October 1996, to September 30, 2001. The parties agree as follows: 1. The settlement proposal of Fibre to Cascade contained in its September 4, 1997, letter, a copy of which is attached hereto as Exhibit A and incorporated herein by this reference, is agreed to by the parties with one correction. On page 2, next to last paragraph, the ending time for the reduced PGS fee is to be the Contract Year October 2000 to September 2001. This correction is noted on Exhibit A. 2. In order to implement this agreement, the PGS Agreement will be amended in the form attached as Exhibit B. This Settlement Agreement is entered into as of the date first set forth above. LONGVIEW FIBRE COMPANY CASCADE NATURAL GAS CORPORATION By ------------------------ Its By --------------------- ------------------------------ King C. Oberg Vice President - Gas Supply AMENDMENT NO. 3 TO AGREEMENT FOR PEAKING GAS SERVICE (PGS) OCTOBER 2, 1997 This Amendment No. 3 is dated as of October 2, 1997, by and between Cascade Natural Gas Corporation ("Cascade") and Longview Fibre Company ("Longview"). WHEREAS, Cascade and Longview executed an Agreement For Peaking Gas Service (PGS) ("Agreement") dated as of November 22, 1991, and WHEREAS, Cascade and Longview desire to amend the Agreement, NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, it is agreed as follows: 1. Section 4 of the Agreement shall be amended to add the following: PROVIDED, HOWEVER, that pursuant to a Settlement Agreement dated October 2, 1997, the parties have agreed that the PGS Fee for the period starting with the Contract Year October 1996 to September 1997, and ending with the Contract Year October 2000 to September 2001, the PGS Fee shall be $708,984.44 per year. The parties also agree to renegotiate the PGS Fee in good faith in the event of a material gas and/or transportation rate increase with respect to Cascade's Washington Water Power Storage Agreement. As additional consideration for this Agreement, Cascade shall provide Longview with the following fuel management services for the remaining term of the Agreement: a. an aggressive program, with daily consultations between Cascade and Longview, to release any part of the 48,000 dt/day of capacity on Northwest Pipeline for which Longview currently pays the reservation fees and which is not needed by Longview, with the proceeds from such releases going to Longview; b. an aggressive program, with daily consultations between Cascade and Longview, to resale any part of the 18,000 dt/day of natural gas (or additional supplies purchased by Longview) which Longview currently buys from Duke or other supplier and which is not needed by Longview, with the revenue from such resale going to Longview; c. an aggressive program, with daily consultations between Cascade and Longview, to purchase gas at locations agreed to by Cascade and Longview and to have such gas delivered to Longview; d. monthly reporting of the savings to Longview under the above-stated programs; and e. monthly balancing and reporting of all gas and transportation activities related to Longview. 2. Capitalized terms used in this Amendment shall have the meanings as defined in the Agreement. 3. Except as modified by the foregoing amendment, the Agreement, as amended to date, shall remain in full force and effect in accordance with its terms. IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 3 to be duly executed in counterparts by their duly authorized representatives as of the date first above written. CASCADE NATURAL GAS CORPORATION LONGVIEW FIBRE COMPANY By By ---------------------------- ----------------------------- King C. Oberg Its Vice President, Gas Supply ---------------- September 4, 1997 Mr. King Oberg PRIVILEGED AND Vice President, Gas Supply CONFIDENTIAL; Cascade Natural Gas Corporation FOR SETTLEMENT PURPOSES 222 Fairview Avenue North ONLY Seattle, WA 98109 Dear King: This letter is in response to (1) the proposal of Cascade Natural Gas ("Cascade") to adjust the annual fee under the Agreement for Peaking Gas Service ("PGS") between Longview Fibre Company ("Fibre") and Cascade from $970,350.00 to $708,894.44 beginning the October 1996 to September 1997 period, and (2) your August 8 reply to our letter expressing concerns with your proposal. At the outset, Fibre must respectfully point out that the storage service is not comparable to the PGS. Although Cascade can change the scheduled quantity for withdrawals from storage up to four times per day, Cascade can make up to 6 changes (initiating or terminating) and up to 12 changes (rate of taking) per day under the PGS. Moreover, in order to effect delivery of the storage gas to the city gate, Cascade must comply with the transportation nomination procedures of Northwest, which in all cases do not assure that Cascade can arrange for delivery of the storage gas on 4 hours' notice or change the rate of delivery of the storage gas on 2 hours' notice as Cascade can under the PGS. The 4-hour and 2-hour notice provisions of the PGS are features that Fibre does not believe can be duplicated by other alternative peaking services, especially not the storage service obtained by Cascade. Furthermore, Fibre respectfully disagrees with the methodology used in Cascade's proposal. Under the Agreement for PGS, the annual fee is adjusted "to ensure the PGS fee is COMPARABLE to the least cost alternative sources of peaking service reasonably available to Cascade." As set forth in detail below, Fibre does not believe that the $708,894.44 figure proposed by Cascade represents a comparable level of the full costs to Cascade for the storage service received through Washington Water Power. First, once Cascade withdraws 192,000 dekatherms of its gas in storage, Cascade can no longer receive 15, 000 dt/day of gas as it does under the PGS. To adjust the features of the storage service to make them comparable to the PGS, Cascade would have to either (1) obtain 405,000 additional dekatherms of annual storage service, or (2) inject quantities into storage during the winter season. Fibre believes that the first option would increase Cascade's storage costs by at least $588,912.00 per year, while the second option would increase the costs by at least $229,608.00 per year. Second, under the storage service, Cascade incurs a cost of carrying the gas held in storage until it is delivered. Fibre calculates this cost to be at least $43,815.67 per year. Third, Fibre believes that the cost to Cascade of the fuel charges for storage withdrawals and in transporting gas from storage were omitted. Fibre calculates these charges to be at least $23,066.44 per year. Fourth, Cascade did not calculate any costs for transporting gas to storage. Fibre calculates this cost to be at least $172,339.07 per year. If the costs referred to above are added, the full costs of the storage service received by Cascade would be at least $1,273,324.90 per year: OPTION A OPTION B ------------- ------------- Withdrawal Rate $588,912.00 $229,608.00 Adjustment Carrying Cost of Gas 43,815.67 43,815.67 Transportation/Storage 23,066.44 23,066.44 Fuel Charges Transportation In 172,339.07 172,339.07 Cascade's Storage Cost 804,495.76 804,495.76 Calculation ------------- ------------- Total $1,632,628.90 $1,273,324.90 DESPITE THE FOREGOING, WITHOUT PREJUDICE TO FIBRE'S POSITION IN ANY ARBITRATION (AND OTHER POSSIBLE PROCEEDING) AND IN A GOOD FAITH EFFORT TO REACH SETTLEMENT OF THIS MATTER, FIBRE MAKES THE FOLLOWING NON-SEVERABLE SETTLEMENT OFFER: - - the PGS fee would be reduced to $708,984.44 per year; - - the reduced PGS fee would be applicable starting with the contract year October 1996 to September 1997 and ending for the contract year October 2001 to September 2002; - - amend the Peaking Gas Service Agreement to reflect the new five year firm price with the option to renegotiate should gas and/or transportation rate increase, affecting the agreement with Cascade's Washington Water Power Storage Agreement; and - - Cascade would provide Fibre with the following fuel management services for the remaining term of the Agreement for PGS: - an aggressive program, with daily consultations between Cascade and Fibre, to release any part of the 48,000 dt/day of capacity on Northwest Pipeline for which Fibre currently pays the reservation fees and which is not needed by Fibre, with the proceeds from such releases going to Fibre; - an aggressive program, with daily consultations between Cascade and Fibre, to resale any part of the 18,000 dt/day of natural gas (or additional supplies purchased by Fibre) which Fibre currently buys from Duke or other supplier and which is not needed by Fibre, with the revenue from such resale going to Fibre; - an aggressive program, with daily consultations between Cascade and Fibre, to purchase gas at locations agreed to by Cascade and Fibre and to have such gas delivered to Fibre; - monthly reporting of the savings to Fibre under the above-stated programs; and - monthly balancing and reporting of all gas and transportation activities related to Fibre. If Cascade agrees with this settlement offer, please prepare and forward the appropriate documents. If you have any questions regarding the above, do not hesitate to contact me. Sincerely, M. Smith, Jr. Purchasing Manager jr cc: R. J. Parker AGREEMENT FOR PEAKING GAS SERVICE (PGS) EXHIBIT B OCTOBER 7, 1997 PGC FEE: CONTRACT YEAR: OCTOBER 1, 1996 THROUGH SEPTEMBER 30, 1997 PAYMENT SCHEDULE: OCTOBER, 1996 $ 80,862.50 November 80,862.50 December 80,862.50 January, 1997 80,862.50 February 80,862.50 March 80,862.50 April 80,862.50 MAY 80,862.50 June 0.00 July 0.00 August 0.00 September $ 80,862.50 ------------ Total Paid Contract Year 1996-97 $ 727,762.50 Total Due Contract Year 1996-97 $ 708,894.44 ------------ CREDIT $ 18,868.06 CONTRACT YEAR: OCTOBER 1, 1997 THROUGH SEPTEMBER 30, 1998 Payment Schedule: October, 1997 PREVIOUS YEAR'S CREDIT $18,868.06 Payment 40,206.48 ----------- $ 59,074.54 NOVEMBER 1, 1997 THROUGH SEPTEMBER 30, 1998 59,074.54 PER MONTH Total Contract Year $708,894.44 Contract Year: October 1, 1998 through September 30, 1999 per month $ 59,074.54 Total Contract Year $708,894.44 Contract Year: October 1, 1999 through September 30, 2000 per month $ 59,074.54 Total Contract Year $708,894.44 Contract Year: October 1, 2000 through September 30, 2001 per month $ 59,074.54 Total Contract Year $708,894.44 EX-12 9 EXH 12 EXHIBIT 12 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDEND REQUIREMENTS
Twelve Months Ended ---------------------- ------------------------------------- 9/30/97 9/30/96 12/31/95 12/31/94 12/31/93 ------- ------- -------- -------- -------- (dollars in thousands) Fixed charges, as defined: Interest expense $ 9,436 10,101 9,938 8,090 7,038 Amortization of debt issuance expense 612 612 606 593 562 -------- -------- -------- -------- -------- Total fixed charges $10,048 10,713 10,544 8,683 7,600 -------- -------- -------- -------- -------- Earnings, as defined: Net earnings $10,627 8,211 7,732 5,760 9,103 Add (deduct): Income taxes 6,263 4,272 4,508 3,505 5,224 Cumulative effect of change in accounting method - - - - (209) Fixed charges 10,048 10,713 10,544 8,683 7,600 -------- -------- -------- -------- -------- Total earnings $26,938 23,196 22,784 17,948 21,718 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Ratio of earnings to fixed charges 2.68 2.17 2.16 2.07 2.86 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Fixed charges and preferred dividend requirements: Fixed charges $10,048 10,713 10,544 8,683 7,600 Preferred dividend requirements 811 819 853 898 913 -------- -------- -------- -------- -------- Total $10,859 11,532 11,397 9,581 8,513 -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- Ratio of earnings to fixed charges and preferred dividend requirements 2.48 2.01 2.00 1.87 2.55 -------- -------- -------- -------- -------- -------- -------- -------- -------- --------
EX-23 10 EXH. 23 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT - -------------------------------------------------------------------------------- We consent to the incorporation by reference in Registration Statement No. 33-71286, No. 33-51377, No. 33-38501, and No. 33-29801 on Forms S-3, and No. 33-61035 and No. 33-39873 on Form S-8 of Cascade Natural Gas Corporation, of our reports dated November 7, 1997, appearing in this Annual Report on Form 10-K of Cascade Natural Gas Corporation for the year ended September 30, 1997. DELOITTE & TOUCHE LLP Seattle, Washington December 29, 1997 EX-27 11 EXH 27, FDS
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF CASCADE NATURAL GAS CORPORATION, INCLUDED IN THE ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 1997 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR SEP-30-1997 SEP-30-1997 PER-BOOK 265,225 2,161 28,831 11,486 0 307,703 10,967 96,142 4,553 111,662 6,630 0 121,150 7,500 0 5,400 0 0 0 0 55,361 307,703 195,786 6,263 169,847 169,847 25,939 467 20,143 9,516 10,627 510 10,117 10,465 0 46 0.93 0.93
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