-----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, MfHvKgjAEeXxO1rKw7sz5KitWReB7nWzLpC0iMdxejpgkU8l5cONhbmOfl/q30Hs 0MeVK6zag4cp8TmP+m0Njg== 0000912057-99-010140.txt : 19991222 0000912057-99-010140.hdr.sgml : 19991222 ACCESSION NUMBER: 0000912057-99-010140 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991221 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-K405 SEC ACT: SEC FILE NUMBER: 001-07196 FILM NUMBER: 99778170 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-K405 1 10-K405 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, 1999 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 (206) 624-3900 Seattle, WA 98109 -------------- ------------------ (Registrant's telephone number (Address of principal executive offices) 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. X --- 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 December 14, 1999, was $182,179,824 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Title Outstanding Common Stock, Par Value $1 per Share 11,045,095 as of December 14, 1999 DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's definitive proxy statement for its 2000 Annual Meeting of Shareholders are incorporated by reference into Part III, Items 10, 11, 12, and 13. 1 CASCADE NATURAL GAS CORPORATION ANNUAL REPORT TO THE SECURITIES AND EXCHANGE COMMISSION ON FORM 10-K For the Fiscal Year Ended September 30, 1999 Table of Contents
Number Page - ------ ---- Part I Item 1 - Business 3 Item 2 - Properties 7 Item 3 - Legal Proceedings 8 Item 4 - Submission of Matters to a Vote of Security Holders 8 Executive Officers of the Registrant 8 Part II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters 9 Item 6 - Selected Financial Data 10 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 12 Item 7a- Quantitative and Qualitative Disclosures about Market Risk 18 Item 8 - Financial Statements and Supplementary Data 20 Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 41 Part III Item 10 - Directors and Executive Officers of the Registrant 41 Item 11 - Executive Compensation 41 Item 12 - Security Ownership of Certain Beneficial Owners and Management 41 Item 13 - Certain Relationships and Related Transactions 41 Part IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K 42 Signatures 43 Index to Exhibits 44
2 PART I ITEM 1. BUSINESS GENERAL Cascade Natural Gas Corporation (Cascade or the Company) was incorporated under the laws of the state of Washington on January 2, 1953. Its principal business is the distribution of natural gas to customers in the states of Washington and Oregon. Approximately 81% of its gas distribution revenues are from customers in the state of Washington. As of September 30, 1999, the Company had approximately 177,162 core customers and 189 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 18% of gas deliveries and 70% 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. 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. Effective December 1998, with respect to such gas supplies delivered to Oregon customers, 67% of the incremental change in the actual cost of gas supplies, as compared to the forecasted cost reflected in the PGA, is deferred. The remaining 33% (increase or decrease) is absorbed by the Company. This mechanism is intended to encourage the Company to seek opportunities to lower its cost of supplies and to be innovative in its management of the supply portfolio to avoid price spikes. Cascade has an earnings sharing mechanism with respect to its Oregon jurisdictional operations. See "Regulatory Matters" under Item 7 for a description of the mechanism. The Company is also subject to state regulation with respect to integrated resource planning, and its most recent update of its Integrated Resource Plan (IRP) was filed in 1999 with both the WUTC and the OPUC. The IRP shows the Company's optimum set of supply and demand side resources that minimizes costs and risk over the twenty-year planning horizon. The IRP also sets forth possible core customer growth scenarios for a twenty-year period. In addition, the IRP sets forth the Company's demand side management goals of achieving certain conservation levels in customer usage. The IRP also sets forth the Company's supply side management plans regarding transportation capacity and gas supply acquisition over a twenty-year period. The Company develops updates of the IRP every two years. These updated documents take into account input solicited from the public and the WUTC and OPUC staffs. While the filing of the IRP with both commissions gives the Company no advance assurance that its acquisitions of pipeline transportation capacity and gas supplies will be recognized in rates, management believes that the integrated resource planning process benefits the Company by giving it the opportunity to obtain input from regulators and the public concurrently with making these important 3 strategic decisions. Until the Company receives final regulatory approval of these decisions in the context of the rate making process, the Company cannot predict with certainty the extent to which the integrated resource planning process will affect its rates. NATURAL GAS SUPPLY The majority of Cascade's supply of natural gas is transported via Williams Gas Pipelines - West (Williams). Williams owns and operates a transmission system extending from points of interconnection with El Paso Natural Gas Company and Transwestern Pipeline Company near Blanco, New Mexico through the states of New Mexico, Colorado, Utah, Wyoming, Idaho, Oregon and Washington to the Canadian border near Sumas, Washington. Natural gas is transported north from the Colorado and New Mexico area, and south from British Columbia, Canada. The Company is a shipper on the Pacific Gas and Electric Gas Transmission Northwest (PG&E GT NW) system. PG&E GT NW 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. Cascade also receives natural gas directly from Westcoast Energy, Inc. at the Canadian border near Sumas, Washington. Presently, baseload requirements for Cascade's core market group are provided by six major gas supply contracts with various expiration dates from 2000 through 2008 and totaling 764,830 therms per day. Approximately 90% 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. One with Williams 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 Avista 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, also with Williams, for liquefied natural gas (LNG) storage is effective through October 31, 2014. Under this LNG agreement, Cascade is entitled to receive up to 600,000 therms per day to a maximum inventory of 5,622,000 therms. In addition to withdrawal and inventory capacity, Cascade maintains a corresponding amount of firm transportation from the storage facility to the city gate for each of these agreements. In addition to underground and LNG storage, Cascade has entered into a contract with a major industrial customer whereby the customer agrees to switch to alternate fuel allowing Cascade to reduce firm deliveries to that customer. Cascade then takes the customer's firm gas supply and pipeline capacity to serve its core markets. In return, Cascade reimburses the customer for the cost of its alternate fuel and pipeline capacity. Since the customer is also a distribution customer of Cascade, the supply is already being delivered to Cascade's system and is merely diverted to core customers, allowing for an even greater accommodation of late day demand spikes. Because the customer'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. This peak shaving agreement, which expires in 2014, entitles Cascade to call on 150,000 therms per day up to a seasonal total of 3,000,000 therms. During 1999, Cascade purchased approximately 90% of its gas supplies from firm gas supply contracts and 10% from 30-day spot market contracts. In addition, 912 million therms of customer purchased supplies were transported through Cascade facilities. 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 is purchased primarily on fixed price contracts. Management believes that this, 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. OREGON GAS COST ADJUSTMENTS Prior to December 1998, in Oregon Cascade was subject to an 80/20% sharing mechanism for changes in the commodity cost of gas supplies. If actual commodity gas prices were higher or lower than 4 predicted in the PGA filing, 80% of the incremental change was passed through to core customers in rates while Cascade kept or absorbed the remaining 20%. Coupled with the 80/20 sharing was an Earnings Review Test. Cascade's ability to adjust rates to recover higher than predicted gas costs was limited to the extent that adjusted operating results during the relevant period exceeded rate of return ceilings calculated by the staff of the OPUC. For purposes of the test, adjustments, such as one to impute normal rather than actual weather, were made to operating results. As a consequence, limitations on gas cost recovery could be imposed even when actual earnings were lower than the OPUC staff's ceiling. Effective December 1, 1998, the Company and OPUC staff agreed to drop the Earnings Review Test and modify the sharing mechanism for commodity gas cost changes to a 67/33% split. Cascade's current gas supply portfolio for Oregon core customers is comprised mostly of gas supplies that have a fixed commodity price, therefore management believes that there will be little risk or opportunity for the Company under the 67/33% sharing arrangement during the coming year. For the period beginning December 1998 through September 1999, under the new arrangement, Cascade's 33% share of savings achieved totaled $116,000. FEDERAL ENERGY REGULATORY COMMISSION (FERC) MATTERS Cascade is not subject to regulation by the FERC, however FERC actions can affect the amounts Cascade pays to interstate pipeline companies for interstate deliveries of natural gas supplies. Several issues are pending before FERC, or are on appeal before the U.S. Court of Appeals. The final outcome may affect prices Cascade pays. Since the policies of the WUTC and OPUC provide for 100% pass through of costs subject to FERC regulation, the Company expects that the final resolution of pending issues will not affect net earnings. CURTAILMENT PROCEDURES In previous heating seasons, cold weather has required Cascade to significantly curtail deliveries to its interruptible customers. Cascade has not curtailed any firm customers, except under force majeure conditions. Cascade's tariffs effective in Washington and Oregon allow for curtailment of interruptible services, which are provided at rates lower than for firm services. In the event of curtailment by Cascade of firm service due to force majeure, Cascade's tariffs provide that it will not be liable for damages to any customer for failure to deliver gas curtailed in accordance with the provisions of the tariffs. The tariffs provide for appropriate adjustment of the monthly charges to firm customers curtailed by reason of an insufficient supply of gas. TERRITORY SERVED AND FRANCHISES The population of communities served by Cascade totals approximately 780,000. 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 2000 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. 5 Agreements with Cascade's principal industrial customers are for fixed terms of not less than one year and provide for automatic extension from year to year unless terminated by either party on at least 30-days' notice. The principal industrial activities in Cascade's service area include the production of pulp, paper and converted paper products, plywood, chemical fertilizers, industrial chemicals, clay and ceramic products, refining of crude oil, producing and forming of aluminum, the processing, flash freezing and canning of many types of vegetable, fruit and fish products, processing of milk products, meat processing and the drying and curing of wood and agricultural products, and electric power generation. Electric generation customers represent a significant portion of industrial revenues. The demand for gas fired generation tends to decrease as the availability of hydroelectric generation increases. 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, 1999, 64% of operating revenues and 89% of earnings from operations were derived from the first two quarters (October 1998 through March 1999). Because of the seasonality of space heating revenues, Cascade believes financial results for interim periods are not indicative of results to be expected for an entire year. To mitigate the seasonality of space heating revenues, the Company pursues a marketing strategy of encouraging the installation of gas water heaters by customers, since they are not as influenced by weather conditions. COMPETITIVE CONDITIONS Cascade operates in a competitive market for natural gas service. Cascade competes with residual fuel oil and other alternative energy sources for industrial boiler uses, and oil, propane, and electricity for residential and commercial space heating, and electricity for water heating. Competition is primarily based on price. For residential and commercial space heating use, Cascade continues to maintain a price advantage over oil in its entire service territory and has an advantage over electricity in the vast majority of its territory. In the remaining areas of its service territory served by public electric utilities with their own hydro power supply, Cascade is almost equal in cost with respect to electricity furnished by those utilities for space heating and water heating uses. In addition, natural gas enjoys the advantage of being the preferred energy choice by builders for new home construction. Historically, the large volume industrial market was very sensitive to price fluctuations between the comparable cost of natural gas and alternate fuels, principally residual fuel oil used in boiler applications. However, the advent of open access transportation and the restructuring of gas supply and contractual provisions with these customers have improved the Company's competitive position. Cascade has not experienced any significant loss of sales to alternate fuels to these customers during the last ten years, even though there have been periods when the residual fuel oil prices were lower than natural gas. In addition to multiple alternative fuels, the Company is subject to bypass. Bypass refers to actual or prospective customers who install their own facilities and connect directly to an upstream pipeline and thereby "bypass" the distribution company's service. The Company has experienced bypass but has also experienced success in offering competitive rates to reduce economic incentives to bypass. In addition, other sellers of natural gas compete to sell the natural gas commodity over the Company's pipelines to its distribution customers. The Bonneville Power Administration (BPA) is a major supplier of hydro-electric power in the Pacific Northwest including Cascade's service area. BPA significantly influences the electric rates of all classes of customers including those applications in direct competition with natural gas marketed by Cascade. 6 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. For detailed descriptions of specific environmental issues, see "Environmental Matters" under Item 7. CAPITAL EXPENDITURES Capital expenditures are primarily used to expand the Company's distribution system to serve its expanding customer base, as well as to increase deliverability on its existing system to accommodate increased customer utilization. Capital expenditures for the five years ended September 30, 1999 totaled approximately $134.7 million, and the budget for fiscal 2000 is $23.5 million. Fiscal 1999 capital expenditures were $17.2 million, $6.6 million less than the prior year, due to improved cost controls, higher contributions by customers, the rescheduling of certain projects, and lower technology expenditures. The Company is currently forecasting that capital expenditures will total approximately $124 million over the next five years, reflecting expectations that customer growth will continue at a pace similar to recent experience but that spending on system reinforcement will be lower. Management performs quantitative and qualitative analyses to assure that the Company's goals and strategies are met. The overall objective is to invest limited capital to generate the highest possible returns within the shortest possible time, while assuming prudent risk, anticipating customer needs and complying with the requirements of regulators. NON-UTILITY SUBSIDIARIES Cascade has four non-utility subsidiaries, only two of which are actively engaged in business at present. Cascade Land Leasing is engaged in the servicing of loans that were made to Cascade's gas customers to finance their purchases of energy-efficient appliances. The subsidiary ceased making new loans in September 1997. Beginning in November 1998, CGC Resources began serving as an entity engaged in pipeline capacity management, with the objective of mitigating gas costs for Cascade. The subsidiaries, which in the aggregate account for less than 1% of the consolidated assets of the Company, do not currently have a significant impact on Cascade's financial statements. PERSONNEL At September 30, 1999, Cascade had 451 employees. Of the total employees, 207 are represented by the International Chemical Workers Union. The present contract with the union extends to April 1, 2001, and thereafter until terminated by either party on sixty days' notice. As of September 30, 1998, three Company executives including the president accepted an early retirement offer. The Company does not intend to replace these positions, but has instead restructured management to cover the vacated areas of responsibilities. ITEM 2. PROPERTIES At September 30, 1999, Cascade's utility plant investments included approximately 4,412 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 2,846 miles of service lines. The distribution and transmission mains are located under public property such as streets and highways or on private property with the permission or consent of the individual owner. Cascade owns at present twenty buildings used for operations, office space and warehousing in Washington and seven such buildings in Oregon. It leases an additional seven commercial offices and 7 warehouse buildings. Cascade considers its properties well maintained and in good operating condition, and adequate for Cascade's present and anticipated needs. All facilities are substantially utilized. ITEM 3. LEGAL PROCEEDINGS The information under "Environmental Matters" in Item 7 is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. EXECUTIVE OFFICERS OF THE REGISTRANT The executive officers of the Company, as of December 1, 1999, are as follows:
Year Became Name Office Age Officer - ---------------------------------------------------------------------------------------- W. Brian Matsuyama Chairman of the Board, President and Chief Executive Officer 53 1987 Jon T. Stoltz Senior Vice President - Planning, Regulatory & Consumer Affairs 52 1981 J. D. Wessling Senior Vice President - Finance and Chief Financial Officer 56 1995 Larry E. Anderson Vice President - Operations 51 1995 King C. Oberg Vice President - Gas Supply 58 1993 James E. Haug Controller and Chief Accounting Officer 50 1981 Larry C. Rosok Vice President - Human Resources and Corporate Secretary 43 1995
None of the above officers is related by blood, marriage or adoption to any other of the above named officers. Each of the above named officers has been employed by the Company in a management capacity for at least the past five years. None of the above officers hold directorships in other public corporations. All officers serve at the pleasure of the Board of Directors. 8 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Common Stock is traded on the New York Stock Exchange under the symbol CGC. The following table states the per share high and low sales prices of the Common Stock.
Fiscal 1999 Fiscal 1998 ----------- ----------- Quarter High Low High Low ------- ---- --- ---- --- December 31 $18-9/16 $16-1/8 $19 $16-1/2 March 31 18-1/8 14-15/16 18-9/16 15-1/2 June 30 19 14-5/8 17-3/16 15-5/16 September 30 18-11/16 16-9/16 16-1/2 14-5/8
At November 24, 1999, there were approximately 7,407 holders of the Common Stock. The following table shows for the periods indicated the dividends paid per share on the Common Stock.
Quarter 1999 1998 ------- ---- ---- December 31 $ 0.24 $ 0.24 March 31 $ 0.24 $ 0.24 June 30 $ 0.24 $ 0.24 September 30 $ 0.24 $ 0.24
9 ITEM 6. SELECTED FINANCIAL DATA (dollars in thousands except per share data)
Year Ended Year Ended Year Ended Nine Months Year Ended Sep 30 Sep 30 Sep 30 Ended Sep 30 Dec 31 1999 1998 1997 1996 1995 ------------- ------------- ------------- ------------- ----------- STATEMENTS OF OPERATIONS: Operating Revenues $208,610 $189,656 $195,786 $127,665 $182,744 Less: Gas Purchases 109,263 97,382 104,342 69,679 102,858 Revenue Taxes 13,280 12,037 12,430 8,420 11,480 ------------- ------------- ------------- ------------- ----------- Operating Margin 86,067 80,237 79,014 49,566 68,406 ------------- ------------- ------------- ------------- ----------- Cost of Operations: Operating expenses 36,313 37,310 35,670 25,058 30,818 Depreciation and amortization 12,841 13,470 13,416 9,362 11,733 Property and payroll taxes 4,574 4,420 3,989 3,181 4,051 ------------- ------------- ------------- ------------- ----------- 53,728 55,200 53,075 37,601 46,602 ------------- ------------- ------------- ------------- ----------- Earnings From Operations 32,339 25,037 25,939 11,965 21,804 ------------- ------------- ------------- ------------- ----------- Nonoperating Expense (Income): Interest 10,486 10,132 9,436 7,459 9,938 Interest charged to construction (383) (550) (532) (569) (394) ------------- ------------- ------------- ------------- ----------- 10,103 9,582 8,904 6,890 9,544 Amortization of debt issuance expense 603 605 612 459 606 Other (495) (388) (467) (2) (586) ------------- ------------- ------------- ------------- ----------- 10,211 9,799 9,049 7,347 9,564 ------------- ------------- ------------- ------------- ----------- Earnings Before Income Taxes 22,128 15,238 16,890 4,618 12,240 Income Taxes 8,075 5,694 6,263 1,606 4,508 ------------- ------------- ------------- ------------- ----------- Net Earnings 14,053 9,544 10,627 3,012 7,732 Preferred Dividends 483 497 510 393 539 ------------- ------------- ------------- ------------- ----------- Net Earnings Available to Common Shareholders $ 13,570 $ 9,047 $ 10,117 $ 2,619 $ 7,193 ============= ============= ============= ============= =========== Net Earnings per Common Share (Basic and diluted) $ 1.23 $ 0.82 $ 0.93 $ 0.28 $ 0.80
10 ITEM 6. SELECTED FINANCIAL DATA (CONTINUED) (dollars in thousands except per share data)
At September 30 At Dec 31 --------------------------------------------------- --------- 1999 1998 1997 1996 1995 RETAINED EARNINGS: Beginning of the year $ 3,003 $ 4,553 $ 4,901 $ 9,297 $ 10,806 Net earnings available to common shareholders 13,570 9,047 10,117 2,619 7,193 Common dividends (10,603) (10,597) (10,465) (7,015) (8,702) ----------------------- ----------------------- --------- End of the year $ 5,970 $ 3,003 $ 4,553 $ 4,901 $ 9,297 ----------------------- ----------------------- --------- CAPITAL STRUCTURE: Common shareholders' equity $ 114,395 $ 111,428 $ 111,662 $ 109,126 $ 89,539 Redeemable preferred stocks 6,186 6,408 6,630 6,851 6,851 ----------------------- ----------------------- --------- Debt: Long-term debt 125,000 110,650 121,150 101,850 102,100 Notes Payable and Commercial Paper -- 6,929 12,900 -- 32,000 Current maturities of long-term debt -- 10,000 -- -- -- ----------------------- ----------------------- --------- 125,000 127,579 134,050 101,850 134,100 ----------------------- ----------------------- --------- Total capital $ 245,581 $ 245,415 $ 252,342 $ 217,827 $ 230,490 ======================= ======================= ========= FINANCIAL RATIOS: Return on common shareholders' equity 11.52% 7.77% 8.75% 8.09% 8.12% Common stock dividend payout ratio 78% 117% 103% 257% 120% Cash dividends declared per common share $ 0.96 $ 0.96 $ 0.96 $ 0.72 $ 0.96 Fixed charge coverage (before income tax deduction): Times interest earned 3.00 2.42 2.68 2.17 2.16 Times interest and preferred dividends earned 2.80 2.26 2.48 2.01 2.00 Book value per year-end share of common stock $ 10.33 $ 10.09 $ 10.18 $ 10.12 $ 9.79 Capitalization Ratios at End of Year Common shareholders' equity 46.6% 45.4% 44.3% 50.1% 39.6% Preferred stock 2.5% 2.6% 2.6% 3.1% 3.3% Long-term debt (incl. current) 50.9% 49.2% 48.0% 46.8% 48.4% Short-term debt 0.0% 2.8% 5.1% 0.0% 8.7% ----------------------- ----------------------- --------- 100.0% 100.0% 100.0% 100.0% 100.0% ----------------------- ----------------------- --------- UTILITY PLANT: Utility plant - end of year $ 453,278 $ 433,568 $ 416,365 $ 383,771 $ 362,924 Accumulated depreciation 177,878 167,356 160,332 147,599 138,831 ----------------------- ----------------------- --------- Net plant $ 275,400 $ 266,212 $ 256,033 $ 236,172 $ 224,093 ======================= ======================= ========= Capital expenditures, net of contributions in aid $ 17,262 $ 23,780 $ 21,626 $ 26,053 $ 37,637 ======================= ======================= ========= Total assets $ 315,569 $ 311,511 $ 307,703 $ 296,381 $ 296,898 ======================= ======================= =========
11 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is management's assessment of the Company's financial condition and a discussion of the principal factors that affect consolidated results of operations and cash flows for the fiscal years ended September 30, 1999, 1998, and 1997. EARNINGS PER SHARE Net earnings available to common shareholders were $13,570,000, or $1.23 per common share for fiscal 1999, representing a 50% improvement over the $9,047,000, or $0.82 per common share, reported for fiscal 1998. The improvement in earnings is primarily the result of higher operating margins. Reductions in operating expenses and depreciation also contributed to the improvement. OPERATING MARGIN RESIDENTIAL AND COMMERCIAL MARGIN for the fiscal years ended September 30, 1999, 1998, and 1997 are set forth in the table below: Residential and Commercial Operating Margins (dollars in thousands)
(12 months ended September 30) 1999 1998 1997 - ----------------------------------------------------------------- Degree Days 5,535 5,031 5,525 Average Number of Customers Residential 150,068 142,537 134,857 Commercial 26,360 25,409 24,682 Average Therm Usage Per Customer Residential 799 747 817 Commercial 4,058 3,931 4,348 Operating Margin Residential $ 35,072 $ 30,436 $ 29,725 Commercial $ 21,886 $ 19,648 $ 20,523
Fiscal 1999 operating margins from sales to residential and commercial customers were up $6,874,000, or 13.7%, compared to fiscal 1998. The primary factors contributing to this improvement were increased per-customer gas usage, increased number of customers, and a $1 per month increase in the monthly service charge paid by Washington customers. Approximately $2.8 million of the increase is attributable to increased consumption per customer, largely due to colder weather. Weather in fiscal 1999, as measured by heating degree-days, while approximately 2% warmer than normal, was 10% colder than fiscal 1998. Improvement of approximately $2.4 million was the result of the 5% increase in the number of customers. A $1 per month service charge increase added approximately $1.3 million in margin. The increase was offset by a corresponding decrease in the rates charged to industrial customers. This shift in rate responsibility was approved by the Washington Utilities & Transportation Commission (WUTC) effective August 1, 1996. The approval provided for a phased in shift of rate responsibility in three annual increments, on August 1, 1996, 1997, and 1998. The intended result was to produce no direct bottom line impact. 12 1998 VERSUS 1997. Fiscal 1998 operating margins from sales to residential and commercial customers were down $164,000, or 0.3% compared to fiscal 1997. Several factors contributed to this decrease but most significant was the decline in gas consumption resulting from warm weather during the 1997 - 1998 winter heating season. Weather in fiscal 1998, as measured by heating degree days, was approximately 11% warmer than normal, and 9% warmer than the prior year. The lower gas consumption depressed margins by an estimated $4 million, or $0.23 per share, compared to 1997. Also reducing margins by approximately $700,000 was a September 1, 1997 reduction in rates which passed on to Oregon customers a part of the benefit of efficiencies and lower capital costs since Cascade's last general rate case in that state. Other factors substantially mitigated these decreases. The 5.3% growth in the number of customers contributed approximately $2.4 million of margin. Monthly service charges collected from customers in Washington increased $1.00 on August 1, 1997, and again on August 1, 1998. These service charge increases contributed approximately $1.4 million of margin. Offsetting the higher service charges was a reduction in rates charged to industrial and other customers, as was described above. Also affecting the comparison were more stable wholesale prices of natural gas in fiscal 1998. During the fiscal 1997 heating season, gas supply prices spiked to abnormally high levels. Regulatory provisions in Oregon require that the Company absorb a portion of such price variances. During fiscal 1998, more stable prices prevailed, and the Company was able to earn a small profit from favorable prices. The resulting difference was an approximate $900,000 margin improvement. INDUSTRIAL AND OTHER MARGIN in fiscal 1999 decreased $840,000, or 2.8% from fiscal 1998. Approximately $1.3 million represents the rate reduction offset for the increased residential and commercial service charges. Also in 1999, margins from the sales of spot market gas declined $519,000. Partially offsetting these decreases is approximately $800,000 in margins from 70, mostly smaller, new industrial customers and $700,000 from consumption increases by existing industrial customers. 1998 VERSUS 1997. Margins from industrial and other customers in fiscal 1998 increased $1.4 million or 4.8% over fiscal 1997. This improvement was primarily due to greater deliveries to the Company's electric generation customers. The higher demand for gas-fired generation was driven in part by the diminished availability of hydroelectric generation, resulting from the previous winter's low snowfall in the northwest. The addition of several smaller industrial customers also contributed to the improvement in operating margins. Partially offsetting the margin improvements from industrial customers for both 1997 and 1998 were rate reductions equivalent to the amount derived from the higher monthly service charges to residential and commercial customers (see "Residential and Commercial Margin"). COST OF OPERATIONS Cost of operations, which consists of operating expenses, depreciation and amortization, and property and payroll taxes, was $53.7 million, $55.2 million, and $53.1 million for the fiscal years ended September 30, 1999, 1998, and 1997, respectively. OPERATING EXPENSES for fiscal 1999, which are primarily labor and benefits expenses, decreased $997,000, or 2.7% from 1998. Improved efficiencies have resulted in the reduction of 22 personnel positions since the end of 1998. The average employee count in 1999 was 468 compared to 483 in 1998, and these reductions were achieved through normal attrition and early retirements. As a result of these staffing reductions, savings in labor expense of $946,000 were realized in 1999 compared to 1998. In addition, overtime pay decreased $137,000. These reductions were offset by $1.3 million of normal wage and salary rate increases, and incentive compensation accruals for all salaried employees. Additional reductions were achieved in other expense categories, including administrative, advertising, and operations. 13 For fiscal 1998, operating expenses increased by $1.7 million, or 4.7%, over fiscal 1997. Labor expense was higher by $560,000, or 2.4%. Lower credits for labor and other expenses charged to construction resulted in higher operating expense of $504,000. Also included in operating expenses was a one-time charge of $369,000, recorded in the fourth quarter, for the cost of an early retirement opportunity that was accepted by three of the Company's executives, who retired as of September 30, 1998. DEPRECIATION AND AMORTIZATION for fiscal 1999 decreased $629,000, or 4.7% from 1998. Based on results of a depreciation study, conducted during 1998, the Company implemented lower depreciation rates effective with the fourth quarter of fiscal 1998. The annual effect of the lower rates is an approximate $2 million reduction in depreciation expense. The effect on the comparison of fiscal 1999 to 1998 is approximately $1.5 million. Incremental depreciation expense on new assets placed in service was approximately $900,000. For fiscal 1998, depreciation and amortization increased by $54,000 or 0.4% over fiscal 1997. Lower depreciation rates as of July 1, 1998 resulted in decreased expense by approximately $500,000, offsetting the effect of additions to depreciable utility plant. PROPERTY AND PAYROLL TAXES for fiscal 1999 were higher by $154,000, or 3.5% compared to fiscal 1998. Of the increase, $111,000 is related to the timing of recognition of property tax reductions in Oregon. Beginning in 1991, and resulting from a voter mandate in 1990 (Ballot Measure 5), Oregon property tax rates decreased each year for a five year period. For each of those five years, the Oregon Public Utility Commission required regulated energy utilities to measure and defer in a regulatory liability account, the effect of the resulting property tax reductions. Each year from 1994 to 1997, the Company reduced its customer rates to reflect the lower tax expense incurred, and to refund the deferred amounts to its customers. The amount refunded to customers varied each year and was set by the OPUC. Concurrent with the rate reductions, the Company recorded credits to property tax expense, which amortized the deferrals in amounts equivalent to the reduced revenue. Accordingly, there was no net effect on earnings. The amortization was completed in the first quarter of fiscal 1998. Property and payroll taxes in fiscal 1998 were higher by $430,000, or 10.8%, compared to fiscal 1997. The increase is primarily related to the timing of recognition of property tax reductions in Oregon as discussed in the preceding paragraph. NONOPERATING EXPENSE (INCOME) Interest expense for 1999 increased by $354,000 or 3.5% from fiscal 1998. The increase was due primarily to higher long-term debt, higher average short-term debt and deferred gas cost balances. Interest charged to construction decreased $167,000 because of lower construction expenditures and lower balances in construction work in progress. Other income increased $107,000, mainly because of a gain of $174,000 on the sale of non-utility property, partially offset by reductions in interest and other income of $67,000. Interest expense for 1998 increased by $696,000 or 7.4% from fiscal 1997. The increase was due primarily to additional amounts of outstanding long-term debt, partially offset by lower short-term debt and lower interest accrued on deferred gas cost balances. The comparison of other non-operating income was affected by the inclusion in 1997 of a $140,000 gain on the sale of a parcel of land. Additionally, there was less interest income in fiscal 1998 because of lower outstanding appliance loan amounts. INCOME TAXES The increase in the provision for federal and state income taxes is attributable to improvements in pre-tax earnings. The average effective income tax rate for 1999 is 36.5%, compared to 37.4% for 1998 and 37.1% for 1997. Increases in pretax income mitigate the effective rate impact of the differences between the statutory and effective tax rates. 14 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 credit commitment of $40 million from three banks. This agreement expires in September 2000; however, the Company is currently finalizing terms for a new 5-year agreement. The Company uses the facility to meet short-term needs as well as to support a money market facility and a commercial paper facility of a similar amount. The annual commitment fee is 1/8 of one percent. The Company also has $30 million of uncommitted lines from three banks. A Medium-Term Note program provides longer term financing with $125 million outstanding at September 30, 1999. There is $15 million remaining 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 Cash from operating activities, less cash dividends paid, provided 100% of capital expenditures in fiscal 1999. Although net earnings for fiscal 1999 were higher by $4,509,000 than for 1998, net cash provided by operating activities was $28,178,000, compared to $38,564,000 last year. Affecting the comparison was the difference in cash flows from changes in current assets and liabilities. This change is primarily the result of timing differences related to changes in accounts receivable, accounts payable, and accrued taxes. INVESTING ACTIVITIES Cash used by investing activities in fiscal 1999 was $16.1 million, compared to $22.9 million in 1998. Capital expenditures in fiscal 1999 were lower due to several factors, including delays until the first quarter of fiscal 2000 in the completion of facilities to serve a major new customer and lower expenditures on distribution system reinforcement projects. Also, new feasibility rules applicable to the Company's Washington operations have had the desired effect of discouraging marginally feasible new customer hookups or requiring marginal customers to contribute more toward the cost of new plant. Under the new rules, customers are required to contractually commit to install appliances that will utilize enough gas to make the Company's investment in plant profitable. Budgeted capital expenditures for fiscal 2000 are approximately $23.5 million, which is expected to be financed approximately 75% from operating activities, and 25% from debt financing. FINANCING ACTIVITIES Cash used for financing activities was $14.0 million in fiscal 1999, and $16.5 million in 1998. Other than the payment of dividends, the principal financing activities in 1999 involved replacement of debt. During the first quarter the Company redeemed $10 million of medium-term notes, which matured in December. This redemption was funded with short-term debt. In March, the Company issued $15 million of new 7.098% medium-term notes with a 30-year maturity. Proceeds were used primarily to pay down short-term debt. At September 30, 1999, the Company had no short-term debt. In the first quarter of fiscal 2000, the Company redeemed the $6 million, 7.85% cumulative preferred stock. This redemption was funded with short-term debt. 15 REGULATORY MATTERS In the first quarter of fiscal 1999, the OPUC approved the agreement that had been reached between the Company and the OPUC Staff regarding an Earnings Sharing Mechanism. Under that mechanism, first effective for calendar year 1999, Cascade shares with its Oregon customers one third of earnings that exceed a return on equity (ROE) ceiling. The ROE ceiling will be adjusted over time based upon the change in the average US Treasury 5, 7, and 10-year bond rates. Based upon current bond rates, the ROE ceiling before any sharing occurs is 12.60%. The estimated effect of this sharing arrangement for the first nine months of calendar 1999 is $204,000. The approved agreement also dropped previous limitations that allowed recovery of certain gas cost increases only if earnings, adjusted for normal weather, were below set return levels. Management believes the new mechanisms are favorable, in that they should reduce the risk of losing the benefit of efficiency gains and the risk of being unable to recover actual costs of gas. ENVIRONMENTAL MATTERS In 1995, the Company received a claim from a property owner in Eugene, Oregon requesting that the Company assume responsibility for investigation and possible clean up of alleged contamination on property previously owned by a predecessor of Cascade. The predecessor company conducted a manufactured gas business on the property from approximately 1929 to 1948. Manufactured gas operations apparently were conducted on the site by several operators beginning about 1907. The site was used for other purposes beginning in 1949. The present owner has retained an environmental consultant, which is investigating possible contamination on the property. To date the consultant has reported that it believes contamination is present. The contamination is consistent with that which might originate from a manufactured gas operation. There have been no estimates as to possible clean up costs. The consultant's initial report has been furnished to the Oregon Department of Environmental Quality (DEQ). The owner has reached an intergovernmental agreement with the DEQ with respect to further investigation and possible remediation of contamination on the property under the voluntary cleanup program. Another northwest utility, which purchased the property from Cascade in 1958, has declined to participate in the site investigation, although it may, as a onetime owner of the property, bear some share of the responsibility as well. The Company has notified its insurance carriers of the claim and is keeping them advised as to the investigation. On one occasion in the past when hazardous materials on property formerly owned by a predecessor of the Company required clean up, the OPUC allowed the clean up costs to be passed on to customers. In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking for reimbursement through rates for such costs. In 1997, a property owner in Washington notified the Company that there is contamination on his property, and that he believes it comes from a former manufactured gas site, owned at one time by a predecessor company, which was merged with Cascade in 1953. The State of Washington Department of Ecology has categorized this site as a "listed site" ranked in its most hazardous category. As a former owner of the site, the Company may be strictly liable to the State of Washington for investigation and remediation of the contamination of the site, but may share that cost or allocate all the cost to others who actually caused or contributed to the contamination. The Company retained an environmental consultant who conducted a preliminary investigation of possible contamination at the site. There is evidence of contamination at the site, and there is also evidence of an oil line across the site property owned and operated by others, which may be a contributor to the contamination. There have been no estimates as to possible clean up costs. The Company has investigated title and other government records to identify other potentially liable parties. The Company has notified the other identified parties of the contamination claims, and has requested cooperation and financial contribution. 16 In the event the Company is responsible for clean up costs not covered by insurance, management anticipates asking the WUTC for reimbursement for such costs, through rates charged to customers. YEAR 2000 READINESS DISCLOSURE This Year 2000 Readiness Disclosure is based in part on information provided to the Company by outside suppliers and vendors. While the Company believes this outside information is accurate, Cascade is not the source of this information and has not independently verified the information submitted by third parties. Cascade is heavily reliant on computers for internal and external information processing. The Year 2000 issue is the result of computer systems and other equipment with embedded processors that use two digits rather than four to define a year date. Problems can occur when computer applications fail to distinguish between the year 1900 and 2000. To mitigate potential problems associated with this issue, Cascade began in 1996 to address the compliance of those computers and systems that are critical to business operations. In addressing this issue, the Company employed a five-phase process: 1) organize and inventory all peripherals, applications, software, metering equipment, communications equipment and date-related logic systems that could be impacted; 2) assess those systems that require modification or replacement; 3) upgrade or replace non-compliant equipment and systems; 4) test and validate all mission critical systems and implement test data migration plans and procedures for large applications; and 5) place compliant systems and equipment into service. The Company has also engaged in a process to assess upstream suppliers including pipeline companies, vendors and other utilities of their compliance status. To date, the Company has received communications from substantially all significant suppliers and vendors. While no company can provide assurance that suppliers will be compliant, Cascade has not received indication that any major third party will have a compliance problem adversely affecting its ability to conduct business. Cascade believes those statements it has received are accurate, however the company is not the source of this information and has not independently verified the information. The Company continues to monitor the compliance process of external systems, suppliers and vendors. RISKS Despite efforts to address all significant Year 2000 issues in advance, the company could potentially experience disruptions to some aspects of its activities or operations, including, but not limited to, delays in payments to the company from customers. Currently, Cascade has not received any indication that customers, third party suppliers or vendors will experience problems that could impact Cascade. However, there can be no guarantee that the systems of other companies with whom the Company transacts business will be timely converted. In the unlikely event that internal computer systems fail due to a year 2000 compliance problem, business processes that may be interrupted include: automated monitoring of gas flow and pressure; measurement of gas receipts from suppliers and deliveries to customers; processing customer invoices; payments to suppliers; financial measurement and reporting; internal and external communications; payroll processing; and other administrative functions. Management has not developed estimates of losses that may be incurred in the event of a failure of one or more of these systems. STATE OF READINESS Management believes that all mission critical systems have been identified. The Company has upgraded or replaced most of its third-party financial and distribution system monitoring hardware and software and has established that these systems are now Year 2000 compliant. All of the Company's personal computers, embedded building and office systems, and fleet vehicles have also been assessed, tested, and verified to be compliant. Corrections to internally developed software, including billing, cash receipts processing, and payroll are complete and have tested to be compliant. The company's new SCADA system, which monitors natural gas pressure and volume on the Company's distribution system, was fully tested and placed into service in December 1999. 17 COSTS OF YEAR 2000 COMPLIANCE The Company has used a combination of internal and external resources to make necessary modifications to existing systems. The Company does not separately track the direct costs associated with such internal personnel, which primarily consist of salary and benefits. Costs associated with using internal resources is viewed primarily as an opportunity cost, resulting in a delay of other planned system enhancements and replacements intended to enhance operating efficiencies. Such delays are not expected to have a material adverse effect on the Company or its competitive position. Fiscal Year 1999, capital expenditures to replace non-compliant vendor based systems total approximately $769,000. Project-to-date expenditures total approximately $1.3 million. Estimated total capital expenditures are expected to be $1.9 million. Though Year 2000 compliance is the primary motivating factor for these system replacements, management anticipates other significant improvements from these systems as compared to the old systems. Although the costs and completion dates discussed above are based on management's best estimates, actual results may differ from expectations. CONTINGENCY PLANNING The Company has given consideration to several worst-case Year 2000 scenarios and has developed a YEAR 2000 BUSINESS CONTINUITY AND DISTRIBUTION SYSTEM MONITORING PLAN that outlines manual monitoring and operating procedures of critical facilities. The Company's Plan will be enacted in the event there are short-term failures to purchased power, gas supplies, telecommunications, and internal computer systems. The plan addresses key operating processes and the roles of individuals in the event of such failures. Management believes the most likely worst case scenario is that necessary program code modifications of legacy computer systems may have been overlooked. The response to such an event is the dedication of available programming staff to correct the problem. The Company reviews and updates its remediation schedule and contingency plan as needed. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Cascade has evaluated its risk related to financial instruments whose values are subject to market sensitivity. The only such instruments are Company issued fixed-rate debt obligations. Cascade makes interest and principal payments on these obligations in the normal course of its business, and does not plan to redeem these obligations prior to normal maturities. Accordingly, management believes the Company is not subject to market risk as defined in Item 305 of Regulation S-K. 18 FORWARD-LOOKING STATEMENTS Statements contained in this report that are not historical in nature are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are subject to risks and uncertainties that may cause actual future results to differ materially. Such risks and uncertainties with respect to the Company include, among others, its ability to successfully implement internal performance goals, misjudgments in assessing the Company's year 2000 compliance requirements and risks, competition from alternative forms of energy, consolidation in the energy industry, performance issues with key natural gas suppliers, the capital-intensive nature of the Company's business, regulatory issues, including the need for adequate and timely rate relief to recover increased capital and operating costs resulting from customer growth and to sustain dividend levels, the weather, increasing competition brought on by deregulation initiatives at the federal and state regulatory levels, the potential loss of large volume industrial customers due to "bypass" or the shift by such customers to special competitive contracts at lower per unit margins, exposure to environmental cleanup requirements, and economic conditions, particularly in the Company's service area. 19 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEPENDENT AUDITORS' REPORT Board of Directors Cascade Natural Gas Corporation Seattle, Washington We have audited the consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the Corporation) as of September 30, 1999 and 1998, and the related consolidated statements of net earnings available to common shareholders, common shareholders' equity, and cash flows for the years ended September 30, 1999, 1998 and 1997. These financial statements are the responsibility of the Company'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, 1999 and 1998, and the results of its operations and its cash flows for the years ended September 30, 1999, 1998 and 1997, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Seattle, Washington November 5, 1999 20 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF NET EARNINGS AVAILABLE TO COMMON SHAREHOLDERS (Dollars in thousands except per share data)
Year Ended September 30, ------------------------------------------------- 1999 1998 1997 ------------- -------------- -------------- Operating Revenues $ 208,610 $ 189,656 $ 195,786 Less Gas purchases 109,263 97,382 104,342 Revenue taxes 13,280 12,037 12,430 ------------- -------------- -------------- Operating Margin 86,067 80,237 79,014 ------------- -------------- -------------- Cost of Operations Operating expenses 36,313 37,310 35,670 Depreciation and amortization 12,841 13,470 13,416 Property and payroll taxes 4,574 4,420 3,989 ------------- -------------- -------------- 53,728 55,200 53,075 ------------- -------------- -------------- Earnings from operations 32,339 25,037 25,939 ------------- -------------- -------------- Nonoperating Expense (Income) Interest 10,486 10,132 9,436 Interest charged to construction (383) (550) (532) ------------- -------------- -------------- 10,103 9,582 8,904 Amortization of debt issuance expense 603 605 612 Other (495) (388) (467) ------------- -------------- -------------- 10,211 9,799 9,049 ------------- -------------- -------------- Earnings Before Income Taxes 22,128 15,238 16,890 Income Taxes 8,075 5,694 6,263 ------------- -------------- -------------- Net Earnings 14,053 9,544 10,627 Preferred Dividends 483 497 510 ------------- -------------- -------------- Net Earnings Available to Common Shareholders $ 13,570 $ 9,047 $ 10,117 ============= ============== ============== Net Earnings Per Common Share (basic and diluted) $ 1.23 $ 0.82 $ 0.93 ============= ============== ==============
The accompanying notes are an integral part of these financial statements 21 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
September 30, ------------------------------------- 1999 1998 --------------- --------------- (Dollars in thousands) ASSETS Utility Plant $ 453,278 $ 433,568 Less accumulated depreciation 177,878 167,356 --------------- --------------- 275,400 266,212 Construction work in progress 6,891 10,394 --------------- --------------- 282,291 276,606 --------------- --------------- Other Assets Investments in non utility property 202 667 Notes receivable, less current maturities 577 1,006 --------------- --------------- 779 1,673 --------------- --------------- Current Assets Cash and cash equivalents 410 2,338 Accounts receivable, less allowance of $622 and $645 for doubtful accounts 12,468 9,271 Current maturities of notes receivable 176 329 Materials, supplies, and inventories 6,250 6,213 Prepaid expenses and other assets 5,584 5,122 --------------- --------------- 24,888 23,273 --------------- --------------- Deferred Charges 7,611 9,959 --------------- --------------- $ 315,569 $ 311,511 =============== =============== COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES Common Shareholders' Equity Common stock, par value $1 per share Authorized, 15,000,000 shares; issued and outstanding, 11,045,095 shares $ 11,045 $ 11,045 Additional paid-in capital 97,380 97,380 Retained earnings 5,970 3,003 --------------- --------------- 114,395 111,428 --------------- --------------- Redeemable Preferred Stocks, aggregate redemption Amount of $6,338 and $6,592 6,186 6,408 --------------- --------------- Long-Term Debt 125,000 110,650 --------------- --------------- Current Liabilities Notes payable and commercial paper -- 6,929 Current maturities of long-term debt -- 10,000 Accounts payable 8,933 10,206 Property, payroll, and excise taxes 3,434 4,570 Dividends and interest payable 7,614 7,407 Other current liabilities 4,527 3,681 --------------- --------------- 24,508 42,793 --------------- --------------- Deferred Credits and Other Gas cost changes 12,210 10,330 Income taxes 19,405 17,598 Investment tax credits 2,302 2,523 Other 11,563 9,781 --------------- --------------- 45,480 40,232 --------------- --------------- Commitments and Contingencies (Note 12) -- -- --------------- --------------- $ 315,569 $ 311,511 =============== ===============
The accompanying notes are an integral part of these financial statements 22 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(Dollars in thousands except per share data) Common Stock --------------------------- Paid-In Retained Shares Par Value Capital Earnings ------------- ------------ ------------ ---------- 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 Common stock issued: Employee savings plan and retirement trust (401(k)) 25,446 25 404 Dividend reinvestment plan 52,917 53 834 Cash dividends: Common stock, $.96 per share (10,597) Preferred stock, senior, $.55 per share (26) 7.85% cumulative preferred stock, $7.85 per share (471) Net earnings 9,544 ------------- ------------ ------------ ---------- Balance, September 30, 1998 11,045,095 11,045 97,380 3,003 Cash dividends: Common stock, $.96 per share (10,603) Preferred stock, senior, $.55 per share (12) 7.85% cumulative preferred stock, $7.85 per share (471) Net earnings 14,053 ------------- ------------ ------------ ---------- Balance, September 30, 1999 11,045,095 $ 11,045 $ 97,380 $ 5,970 ============= ============ ============ ==========
The accompanying notes are an integral part of these financial statements 23 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in thousands)
Year Ended September 30, -------------------------------------------- 1999 1998 1997 ------------ ----------- ----------- Operating Activities Net earnings $ 14,053 $ 9,544 $ 10,627 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation and amortization 12,841 13,470 13,416 Deferrals of gas cost changes 818 4,463 (12,815) Amortization of gas cost changes 1,062 (424) (2,473) Other deferrals and amortizations 2,359 1,802 1,860 Deferred income taxes and tax credits - net 2,373 1,568 (522) Other (174) -- -- Change in current assets and liabilities (5,154) 8,141 (10,047) ------------ ----------- ----------- Net cash provided by operating activities 28,178 38,564 46 ------------ ----------- ----------- Investing Activities Capital expenditures (19,942) (25,611) (29,166) Customer contributions in aid of construction 2,680 1,831 7,540 Other 1,155 862 460 ------------ ----------- ----------- Net cash used by investing activities (16,107) (22,918) (21,166) ------------ ----------- ----------- Financing Activities Issuance of common stock -- 754 1,747 Redemption of preferred stock (222) (222) (216) Proceeds from long-term debt, net 14,888 -- 19,850 Repayment of long-term debt (10,650) (500) (700) Changes in notes payable and commercial paper, net (6,929) (5,971) 12,900 Dividends paid (11,086) (10,531) (9,842) ------------ ----------- ----------- Net cash provided (used) by financing activities (13,999) (16,470) 23,739 ------------ ----------- ----------- Net Increase (Decrease) in Cash and Cash Equivalents (1,928) (824) 2,619 Cash and Cash Equivalents Beginning of year 2,338 3,162 543 ------------ ----------- ----------- End of year $ 410 $ 2,338 $ 3,162 ============ =========== ===========
The accompanying notes are an integral part of these financial statements 24 Notes to Consolidated Financial Statements NOTE 1 - NATURE OF BUSINESS Cascade Natural Gas Corporation (the Company) is a local distribution company (LDC) engaged in the distribution of natural gas. The Company's service territory consists of towns in Washington and Oregon, ranging from the Canadian border in northwestern Washington to the Idaho border in eastern Oregon. As of September 30, 1999, the Company had approximately 177,162 core customers and 189 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 18% of gas deliveries and 70% 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 generation of electricity, processing of forest products, production of chemicals, refining of crude oil, production of aluminum, 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. 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 cost, less salvage, are charged to accumulated depreciation. In the case of a sale of non-depreciable property or major operating units, the resulting gain or loss on the sale is included in other income or expense. Depreciation of utility plant is computed using the straight-line method. During 1998, the Company conducted a depreciation study resulting in a change in depreciation lives effective July 1, 1998. The new asset lives used for computing depreciation range from six to seventy years, and the weighted average annual depreciation rate decreased from approximately 3.5% to 3.0%. Based on depreciable assets at the time of the study, the annual effect of this change on depreciation expense is approximately $2 million. Investments in non utility property: This consists primarily of real estate, carried at the lower of cost or estimated net realizable value. 25 Notes receivable: Notes receivable includes loans made to customers for the purchase of energy efficient appliances, which are generally the security for the loan. The loans have terms ranging from one to ten years at interest rates varying from 6.5% to 12%. Materials, supplies and inventories: Materials and supplies for construction, operations, 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 that would otherwise be recognized in revenue or expense, if it is probable that future rates will result in recovery from customers or refund to customers of such amounts. 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, 1999 and 1998 include the following:
(dollars in thousands) 1999 1998 - ----------------------------------------------------------- Unamortized loss on reacquired debt $ 4,497 $ 5,027 Gas cost changes (12,210) (10,330) Deferred income taxes (4,247) (3,457) Postretirement benefits other than pensions 2,436 3,186 Other, net (316) 852 ------------ ----------- Net $ (9,840) $ (4,722) ------------ -----------
Revenue recognition: The Company accrues estimated revenues for gas delivered but not billed to residential and commercial customers from the meter reading dates to the end of the accounting period. 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 normalizes temporary differences between book income and taxable income, with the exception of depreciation differences on assets placed in service prior to 1981, consistent with the policies of the WUTC and OPUC. Deferred income taxes are determined according to the provisions of Statement of Financial Accounting Standards No. 109. Investment tax credits: Investment tax credits were deferred and are amortized over the remaining life of the property giving rise to the credit. 26 Cash and cash equivalents: For purposes of reporting cash flows, the Company accounts for all liquid investments, with a purchased maturity of three months or less, as cash equivalents. The following provides additional information with respect to the Consolidated Statement of Cash Flows:
(Dollars in thousands) 1999 1998 1997 - ------------------------------------------------------------------------------------------------- Changes in current assets and current liabilities: Accounts receivable $ (3,196) $ 2,596 $ (221) Income taxes (165) 2,261 1,183 Inventories (38) (326) 45 Prepaid expenses and other assets (259) (4) (2,858) Accounts payable and accrued expenses (1,394) 3,782 (8,115) Other (102) (168) (81) ---------- --------- ----------- Net change in current assets and current liabilities $ (5,154) $ 8,141 $ (10,047) ---------- --------- ----------- Cash payments: Interest (net of amounts capitalized) $ 9,136 $ 8,303 $ 7,938 Income taxes $ 5,863 $ 1,876 $ 5,606
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 estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the WUTC and the OPUC. Estimates are also used in the development of discount rates and trend rates related to the measurement of retirement benefit obligations and accrual amounts, and in the determination of depreciable lives of utility plant. Stock-Based Compensation: Compensation cost for stock options is measured as the excess of the market price of the Company's stock at the date of the grant over the price the employee must pay to acquire the stock. The Company accounts for its stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" rather than using the fair-value-based method prescribed under FAS No. 123, "Accounting for Stock-Based Compensation." The Company has adopted the disclosure requirements of FAS No. 123. See Note 6 for more information about the Company's stock-based compensation plan. New Accounting Standards: As of the first quarter of fiscal 1999, the Company adopted Statement of Financial Accounting Standards (FAS) Nos. 130, 131, and 132. FAS No. 130, entitled "REPORTING COMPREHENSIVE INCOME," 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 have other comprehensive income, therefore implementation of this standard has not affected the reporting of its financial information. FAS No. 131, entitled "DISCLOSURE ABOUT SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION," 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. Management views the Company as operating as a single segment, that of a local distribution company (LDC) in the Pacific Northwest. Therefore the adoption of this standard has not changed the Company's financial reporting. FAS No. 132, entitled "EMPLOYERS' DISCLOSURES ABOUT PENSIONS AND OTHER POSTRETIREMENT BENEFITS," modifies the disclosure requirements for pensions and other postretirement benefits, but does not affect the measurement of such benefits. These disclosure modifications are included in Note 10. 27 In June 1998, the Financial Accounting Standards Board issued FAS No. 133, entitled "ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES." This standard will be effective for fiscal years beginning after June 15, 2000, and will be adopted by the Company as of October 1, 2000. It requires that the fair value of all derivative financial instruments be recognized as either assets or liabilities on the Company's balance sheet. Changes during a period in the fair value of a derivative instrument would be included in earnings or other comprehensive income for the period. The Company is currently evaluating the effects of this standard on its financial reporting. This evaluation is not complete, but the Company believes that some of its natural gas supply contracts may meet the technical definition of derivative instruments, and thus may be subject to the requirements of FAS No. 133. The Company also believes that, because of rate regulation, derivative assets and liabilities would be offset by regulatory assets and regulatory liabilities, and therefore the earnings effect of application of this standard would not be material. SOP 98-1. In March 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position (SOP) 98-1, "ACCOUNTING FOR THE COSTS OF COMPUTER SOFTWARE DEVELOPED OR OBTAINED FOR INTERNAL USE". Application of this SOP is required for financial statements for fiscal years beginning after December 15, 1998, and was adopted by the Company effective October 1, 1999. The SOP establishes criteria for accounting for costs as operating expense when incurred, or as a capital expenditure. It provides that internal and external cost incurred to develop or obtain new software during the "application development stage" should be capitalized. Other costs, including preliminary project costs, training, data conversion, and upgrades and enhancements would be expensed under the provisions of SOP 98-1. The materiality of this change is dependent upon the magnitude of the costs and the nature and complexity of specific software development or acquisition projects incurred in any period. Based on projects planned for fiscal 2000, management does not expect the application of this standard to have a material effect on results of operations or financial reporting. NOTE 3 - EARNINGS PER SHARE The following table sets forth the calculation of earnings per share as prescribed in FAS No. 128.
1999 1998 1997 -------------------------------------- (in thousands except per share data) Net earnings $ 14,053 $ 9,544 $ 10,627 Less: Preferred dividends 483 497 510 -------------------------------------- Net earnings available to common shareholders $ 13,570 $ 9,047 $ 10,117 -------------------------------------- Weighted average shares outstanding 11,045 11,000 10,842 Plus: Issued on assumed exercise of stock options 1 -- -- -------------------------------------- Weighted average shares outstanding assuming dilution 11,046 11,000 10,842 -------------------------------------- Basic and diluted earnings per common share $ 1.23 $ 0.82 $ 0.93 --------------------------------------
The only dilutive securities are the stock options described in Note 5. 28 NOTE 4 - UTILITY PLANT Utility plant at September 30, 1999 and 1998 consists of the following components:
(dollars in thousands) 1999 1998 - ------------------------------------------------------------ Distribution plant $ 401,826 $ 381,524 Transmission plant 14,086 14,086 Production plant 1,053 1,053 General plant 32,104 32,863 Intangible plant 212 212 Nondepreciable plant 3,997 3,830 ------------ ------------ $ 453,278 $ 433,568 ------------ ------------
NOTE 5 - COMMON STOCK At September 30, 1999, shares of common stock are reserved for issuance as follows:
Number of shares - ------------------------------------------------------- Employee Savings Plan and Retirement Trust (401(k) plan) 119,765 Dividend Reinvestment Plan 51,338 Director Stock Award Plan 4,112 Stock Incentive Plan 150,000 -------------- 325,215 --------------
The price of shares issued to the above plans is determined by the market price of shares on the day of, or immediately preceding the issuance date. The Company's practice is to purchase shares on the open market for these plans rather than issue new shares. During the quarter ended March 31, 1999, the Company awarded officers, under the 1998 Stock Incentive Plan, grants to purchase 38,000 shares of Cascade common stock. The exercise price per share was equal to the fair market value of the stock at the date of grant. Stock options granted at 100% of fair market value are not recognized as compensation expense. A portion of the options become exercisable one year after the grant date, and the options are fully exercisable three years after the grant date. Holders of Common Stock have rights ("Rights") to purchase shares of Series Z Preferred Stock on the basis of one Right for each share of Common Stock. The Rights may not be exercised and will be attached to and trade with shares of Common Stock until the Distribution Date, which will occur on the earlier of (i) the tenth day following a public announcement that there has been a "Share Acquisition", i.e., that a person or group (other than the Company and certain other persons) has 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. 29 NOTE 6 - STOCK COMPENSATION PLAN At its annual meeting January 27, 1999, the Company adopted, and shareholders approved an incentive compensation plan, the 1998 STOCK INCENTIVE PLAN (the Plan), under which officers and other key management employees may be granted options to purchase stock. During the second fiscal quarter, the Company awarded grants to purchase 38,000 shares at an exercise price of $16.50. The grants vest 1/3 per year over three years, and expire five years after the grant date. At September 30, 1999, no options were exercisable. The weighted average fair value of options granted during the year are estimated at $2.43. The fair value was estimated at the date of the grants using a Black-Scholes option pricing model using the following assumptions: dividend yield of 4.52%, expected volatility of 21%, risk-free interest rate of 4.60%, and an expected life of 4 years. The Company accounts for stock-based compensation using APB Opinion No. 25, "Accounting for Stock Issued to Employees". Under this method, compensation cost is recognized on the excess, if any, of the market price of the stock at grant date over the exercise price of the option. The exercise price of $16.50 per share was equal to the market price at the grant date, therefore no compensation expense has been recorded in connection with the Plan. Under FAS No. 123, "Accounting for Stock-Based Compensation," compensation expense is determined based on the fair value of the award and is recognized over the vesting period. Had compensation expense been determined in accordance with FAS 123, the Company's net earnings would have been reduced from the reported amount of $14,053,000 to the pro forma amount of $14,033,000. Net earnings per common share (basic and diluted) would have been $1.23, the same as reported. NOTE 7 - REDEEMABLE PREFERRED STOCKS Redeemable preferred stock at September 30, 1999 and 1998 consists of the following:
(dollars in thousands) 1999 1998 - ------------------------------------------------------------------------------------------ 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 21,750 186 46,750 408 ----------------------- ----------------------- 81,750 $ 6,186 106,750 $ 6,408 ----------------------- -----------------------
Preferred stockholders have preference over common stockholders in dividends and liquidation rights. The 7.85% cumulative preferred stock was redeemed on November 1, 1999. The $.55 cumulative senior preferred stock is subject to minimum annual redemption requirements, with Series C being fully redeemed in fiscal 2001. The Series B shares were fully redeemed during fiscal 1999. The Series C 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 are $6,145,000 in fiscal 2000, $73,000 in fiscal 2001, and none thereafter. 30 NOTE 8 - NOTES PAYABLE AND COMMERCIAL PAPER The Company's short-term borrowing needs are met with a $40,000,000 revolving credit agreement with three of its banks. This agreement expires in September 2000. 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.
September 30 (dollars in thousands) 1999 1998 1997 - ------------------------------------------------------------------------------------------- Amount outstanding $ -- $ 6,929 $12,900 Average daily balance outstanding 8,122 6,201 13,666 Average interest rate, excluding commitment fee 5.44% 5.83% 5.94% Maximum month end amount outstanding 23,713 13,260 21,650
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 $25,472,000 is available for payment of dividends as of September 30, 1999. NOTE 9 - LONG-TERM DEBT Long-term debt at September 30, 1999 and 1998 consists of the following:
(dollars in thousands) 1999 1998 - --------------------------------------------------------------- 6.53% Five Year Term Note due Dec. 2000 $ -- $ 650 Medium-term notes: 7.18% due Oct. 2004 4,000 4,000 7.32% due Aug. 2004 22,000 22,000 8.38% due Jan. 2005 5,000 5,000 8.35% due Jul. 2005 5,000 5,000 8.50% due Oct. 2006 8,000 8,000 8.06% due Sep. 2012 14,000 14,000 8.10% due Oct. 2012 5,000 5,000 8.11% due Oct. 2012 3,000 3,000 7.95% due Feb. 2013 4,000 4,000 8.01% due Feb. 2013 10,000 10,000 7.95% due Feb. 2013 10,000 10,000 7.48% due Sep. 2027 20,000 20,000 7.098% due Mar. 2029 15,000 -- ------------ ------------- Total long-term debt $ 125,000 $ 110,650 ------------ ------------- Current maturities of medium-term notes: 5.77% due Dec. 1998 $ -- $ 5,000 5.78% due Dec. 1998 -- 5,000 ------------ ------------- $ -- $ 10,000 ------------ -------------
None of the long-term debt includes sinking fund requirements. The $650,000, 6.53% five year term note was paid off in February 1999. Annual obligations for redemption of long-term debt are as follows: None in fiscal years 2000 through 2003 and $22,000,000 in fiscal year 2004, and $103,000,000 thereafter. 31 NOTE 10 - 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) 1999 1998 1997 - ------------------------------------------------------------------------------------ Current tax expense $5,702 $4,126 $6,785 Deferred tax expense 2,594 1,809 (256) Amortization of deferred investment tax credits (221) (241) (266) ----------- ----------- ----------- $8,075 $5,694 $6,263 ----------- ----------- -----------
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) 1999 1998 1997 - ------------------------------------------------------------------------------------------------ Statutory federal income tax rate 35% 35% 35% Income tax calculated at statutory federal rate $ 7,745 $ 5,333 $ 5,911 Increase (decrease) resulting from: State income tax, net of federal tax benefit 177 117 122 Non-normalized depreciation differences 374 345 380 Amortization of investment tax credits (221) (241) (266) Other 0 140 116 ---------- ---------- ----------- $ 8,075 $ 5,694 $ 6,263 ---------- ---------- ----------- Effective tax rate 36.5% 37.4% 37.1%
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The tax effects of significant items comprising the Company's net deferred tax liability at September 30, 1999 and 1998 are as follows:
(dollars in thousands) 1999 1998 - ------------------------------------------------------------------------- Deferred tax liabilities: Basis differences on net fixed assets $17,484 $16,096 Debt refinancing costs 1,610 1,797 Retirement benefit obligations 1,092 1,005 ------------ ----------- 20,186 18,898 ------------ ----------- Deferred tax assets: Valuation reserves -- 470 Retirement benefit obligations 439 531 Provision for doubtful accounts 266 255 Other 76 44 ------------ ----------- 781 1,300 ------------ ----------- Net deferred tax liability $19,405 $17,598 ------------ -----------
32 NOTE 11 - 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 to fund the plan by contributing an amount equal to the actuarially determined normal cost plus ten-year amortization payments towards the unfunded actuarial liability, subject to the limits on deductible contributions. The Company also provides executive officers with supplemental retirement, death, and disability benefits. Under the plan, vesting occurs on a stepped basis, with full vesting 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 are equal to 70% of the executive's highest salary during any of the five years preceding retirement. The plan also provides a death benefit equivalent to ten years of vested benefits. The Company funds the plan by making contributions to a trust sufficient to assure assets held by the trust always exceed the accumulated benefit obligation for benefits payable by the 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's policy is to fund the plan to the extent allowable under Internal Revenue Service rules. The following tables set forth the pension and health care plan disclosures. COMPONENTS OF NET PERIODIC BENEFIT COST
Pension Benefits Other Benefits 1999 1998 1997 1999 1998 1997 ----------------------------- ----------------------------- Service cost $ 1,784 $ 1,584 $ 1,367 $ 434 $ 394 $ 369 Interest cost 2,838 2,617 2,398 1,316 1,201 1,211 Expected return on plan assets (3,346) (2,861) (2,288) (699) (691) (495) Amortization of transition obligation 106 106 106 657 657 657 Amortization of prior service cost 424 378 352 -- -- -- Recognized net actuarial loss / (gain) 41 76 34 (341) (371) (99) Special termination benefit 210 369 -- -- -- -- ----------------------------- ----------------------------- Net periodic benefit cost $ 2,057 $ 2,269 $ 1,969 $1,367 $1,190 $1,643 ----------------------------- -----------------------------
33
Pension Benefits Other Benefits (dollars in thousands) 1999 1998 1999 1998 - ------------------------------------------------------------------------------- ----------------------- CHANGE IN BENEFIT OBLIGATIONS Projected benefit obligation at beginning of year $ 39,745 $ 34,212 $ 18,084 $ 17,495 Service cost 1,784 1,584 434 394 Interest cost 2,839 2,617 1,316 1,201 Plan participants' contributions -- -- 21 17 Amendments 592 -- -- -- Termination benefits 210 369 -- -- Benefits paid (1,911) (1,256) (857) (683) Changes in assumptions (2,673) 3,028 -- -- Actuarial (gain)/loss 301 (809) (718) (340) ----------------------- ----------------------- Projected benefit obligation at end of year $ 40,887 $ 39,745 $ 18,280 $ 18,084 ----------------------- ----------------------- CHANGE IN PLAN ASSETS Fair value of plan assets at beginning of year $ 36,254 $ 34,046 $ 7,966 $ 7,741 Actual return on plan assets 4,646 24 838 (5) Employer contributions 2,865 3,440 1,173 580 Plan participants' contributions -- -- 21 17 Benefits Paid (1,911) (1,256) (484) (367) ----------------------- ----------------------- Fair value of plan assets at end of year $ 41,854 $ 36,254 $ 9,514 $ 7,966 ----------------------- ----------------------- Funded Status $ 967 $ (3,491) $ (8,766) $(10,118) Unrecognized prior service cost 2,965 2,798 -- -- Unrecognized net (gain)/loss 183 3,896 (1,798) (1,282) Unrecognized transition obligation 729 834 8,705 9,362 ----------------------- ----------------------- Net amount recognized in Consolidated Statements $ 4,844 $ 4,037 $ (1,859) $ (2,038) ----------------------- -----------------------
WEIGHTED AVERAGE ASSUMPTIONS 1999 1998 ------------------------- Discount rate 7.75% 7.25% Average compensation increase 5.00% 5.00% Expected rate of return on plan assets Pension plan 9.00% 9.00% Supplemental executive retirement plan 8.50% 8.50% Postretirement medical benefit plan 8.75% 8.75%
HEALTH CARE COST TREND The assumed health care cost trend rate used in measuring the APBO is 8.5% for 2000, trending down to 5.5% at 2005. A one percent change in the assumed health care cost trend rate would have the following effects as of September 30, 1999:
One Percentage Point ------------------------ Increase Decrease -------- -------- (thousands) Effect on service and interest cost $ 322 $ (259) Effect on postretirement benefit obligation $ 2,725 $ (2,248)
34 An amendment to the pension plan, effective April 1, 1999, increased the projected benefit obligation for union employees represented by the collective bargaining agreement of the International Chemical Workers Union. The amendment enhances benefits received by these employees. The special termination benefit for the supplemental retirement plan represents the recognition of the increase in the projected benefit obligation for three executives who elected to accept early retirement benefits effective September 30, 1998. The special termination benefit for the retirement plan represents the recognition of the increase in the projected benefit obligation for five employees that retired in December 1998 and January 1999. 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 employee's contribution up to 6% of the employee's compensation, as defined. The Company recognized costs for contributions to this plan of $810,000, $769,000, and $703,000, for 1999, 1998 and 1997, respectively. NOTE 12 - COMMITMENTS AND CONTINGENCIES Gas Service Contracts The Company has entered into various long-term contracts for natural gas supply, transportation, storage, and peaking services. These contracts assure that adequate supplies of gas will be available to provide firm service to core customers and to meet 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 up to 25 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 Fiscal Year Ending Firm Gas Pipeline and Peaking September 30 Supply Transportation Service Total - ----------------------------------------------------------------------------------- (dollars in thousands) 2000 $ 24,756 $ 25,904 $ 3,123 $53,783 2001 18,719 25,904 3,123 47,746 2002 18,595 25,767 2,735 47,097 2003 18,595 25,767 2,735 47,097 2004 18,595 25,767 2,735 47,097 Thereafter 15,265 265,233 27,352 307,850 ------------- -------------- ------------ ------------ $ 114,525 $ 394,342 $41,803 $550,670 ------------- -------------- ------------ ------------
Purchases under these contracts for fiscal 1999, 1998, and 1997, 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 - ------------------------------------------------------------------------------------------ 1999 $ 60,231 $ 30,224 $ 3,786 $ 94,241 1998 $ 47,102 $ 28,901 $ 4,830 $ 80,833 1997 $ 67,329 $ 30,547 $ 4,626 $ 102,502
35 Environmental Matters There are two claims against the Company for as yet unknown costs for clean up of alleged environmental contamination related to manufactured gas plant sites that were previously operated by companies, which were subsequently merged into Cascade. There is currently not enough information available to estimate the potential liability associated with these claims. The first claim was received in 1995, and relates to a site in Oregon. An investigation has shown that contamination does exist, but there has been no estimate of clean up costs. It is expected that other parties will participate in the clean up costs, and negotiations are ongoing as to the sharing arrangement. Through the end of the fiscal year the amounts spent, primarily on investigation and containment, has been immaterial. The second claim was received in 1997, and relates to a site in Washington. An investigation has determined there is evidence of contamination at the site, but there is also evidence of an oil line, operated by an unrelated party, crossing the property, which may have also contributed to the contamination. There is no estimate of possible clean up costs. Management intends to pursue reimbursement from its insurance carriers, and recovery from its customers through increased rates, for any remediation costs for which the Company is determined to be liable. There is precedent for such recovery through increased rates, as both the WUTC and OPUC have previously allowed regulated utilities to increase customer rates to recover similar costs. Litigation Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Company's business. In 1998 the Company was served with a lawsuit by six plaintiffs, claiming unspecified damages for personal injuries in connection with carbon monoxide exposure. The plaintiffs were residents of a house served by the Company at the time of the incident. The Company denies any responsibility for these injuries, and the parties are engaged in discovery. There is no estimate of the Company's potential liability for this claim, and its self-insured retainage with respect to such claims is $1 million. No other claim 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 some of its computer systems are not year 2000 compliant. The Company has completed its corrections to non-compliant systems, implemented these corrections, and continues testing of these systems. Primarily Company personnel performed the modifications to existing systems. The expense for these modifications is charged as incurred. 36 NOTE 13 - 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, 1999 and 1998, of financial instruments whose values are sensitive to market conditions are set forth in the following table:
1999 1998 ------------------------ ------------------------- Carrying Estimated Carrying Estimated (dollars in thousands) Amount Fair Value Amount Fair Value - --------------------------------------------------------------------------------------- Redeemable Preferred Stock $ 6,186 $ 6,270 $ 6,408 $ 6,525 Long-term Debt $ 125,000 $ 144,893 $ 120,650 $ 142,517
37 NOTE 14 - INTERIM RESULTS OF OPERATIONS (UNAUDITED)
(thousands except Quarter Ended per share data) 9/30/99 6/30/99 3/31/99 12/31/98 - --------------------------------------------------------------------------------- Operating revenues $31,706 $42,869 $71,118 $62,917 Gas costs and revenue taxes 19,288 25,577 41,923 35,755 ---------- ---------------------- ---------- Operating margin 12,418 17,292 29,195 27,162 Cost of operations 12,712 13,501 13,791 13,724 ---------- ---------------------- ---------- Earnings (loss) from operations (294) 3,791 15,404 13,438 Interest and other, net 2,528 2,477 2,584 2,622 ---------- ---------------------- ---------- Earnings (loss) before income taxes (2,822) 1,314 12,820 10,816 Income taxes (1,291) 503 4,801 4,062 ---------- ---------------------- ---------- Net earnings (loss) (1,531) 811 8,019 6,754 Preferred dividends 120 121 119 123 ---------- ---------------------- ---------- Net earnings (loss) available to Common Shareholders $(1,651) $ 690 $ 7,900 $ 6,631 ---------- ---------------------- ---------- Net earnings (loss) per common share - basic and diluted $ (0.15) $ 0.06 $ 0.72 $ 0.60 ---------- ---------------------- ----------
(thousands except Quarter Ended per share data) 9/30/98 6/30/98 3/31/98 12/31/97 - -------------------------------------------------------------------------------- Operating revenues $26,129 $36,995 $65,548 $60,984 Gas costs and revenue taxes 13,850 21,527 38,601 35,441 ----------- ------------------------------- Operating margin 12,279 15,468 26,947 25,543 Cost of operations 12,781 14,101 14,346 13,972 ----------- ------------------------------- Earnings (loss) from operations (502) 1,367 12,601 11,571 Interest and other, net 2,500 2,400 2,415 2,484 ----------- ------------------------------- Earnings (loss) before income taxes (3,002) (1,033) 10,186 9,087 Income taxes (1,158) (370) 3,817 3,405 ----------- ------------------------------- Net earnings (loss) (1,844) (663) 6,369 5,682 Preferred dividends 124 124 124 125 ----------- ------------------------------- Net earnings (loss) available to Common Shareholders $(1,968) $ (787) $ 6,245 $ 5,557 ----------- ------------------------------- Net earnings (loss) per common share - basic and diluted $ (0.18) $ (0.07) $ 0.57 $ 0.51 ----------- -------------------------------
38 INDEPENDENT AUDITORS' REPORT ON FINANCIAL STATEMENT SCHEDULE Cascade Natural Gas Corporation and subsidiaries Seattle, Washington We have audited the consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the Corporation) as of September 30, 1999 and 1998, and the related consolidated statements of net earnings available to common shareholders, common shareholders' equity, and cash flows for the years ended September 30, 1999, 1998, and 1997, and have issued our report thereon dated November 5, 1999; 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 Corporation'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 5, 1999 39 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: September 30, 1997 $ 439 507 417 $ 529 September 30, 1998 $ 529 585 469 $ 645 September 30, 1999 $ 645 686 709 $ 622 Valuation Reserve - Notes Receivable September 30, 1997 $1,537 183 $1,720 September 30, 1998 $1,720 118 $1,838 September 30, 1999 $1,838 1,838 $ 0
Note: Accounts written off, net of recoveries 40 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Reference is made to the information regarding directors under the caption "Election of Directors" on pages 1 through 3 and the caption "Section 16(a) Beneficial Ownership Reporting Compliance" on pages 4 and 5 of the Proxy Statement sent to shareholders for the 2000 Annual Meeting (the 2000 Proxy Statement), which information is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION Reference is made to the information regarding executive compensation set forth in the 2000 Proxy Statement under "Executive Compensation" on pages 7 and 8, "Retirement Plan" on page 9, "Executive Supplemental Retirement Income Plan" on pages 9 and 10, "Employment Agreements" on page 10, "Supplemental Benefit Trust" on page 10, "Director Compensation" on page 11, and under "Compensation Committee Interlocks and Insider Participation" on page 11, 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 made to the information regarding security ownership of certain beneficial owners and management under the caption "Security Ownership of Certain Beneficial Owners and Management" on page 4 of the 2000 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 made to the information regarding certain relationships and transactions under the caption "Compensation Committee Interlocks and Insider Participation" on page 11 of the 2000 Proxy Statement, which information is incorporated herein by reference. 41 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 for the Years Ended September 30, 1999, 1998, and 1997 Consolidated Balance Sheets, September 30, 1999 and 1998 Consolidated Statements of Common Shareholders' Equity for the Years Ended September 30, 1999, 1998, and 1997 Consolidated Statements of Cash Flows for the Years Ended September 30, 1999, 1998, and 1997 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. 42 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CASCADE NATURAL GAS CORPORATION December 20, 1999 By /s/ J. D. Wessling ----------------------- ------------------------------------------- Date J. D. Wessling Sr. Vice President - Finance, Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Chairman of the Board, President and Chief Executive /s/ W. Brian Matsuyama Officer and Director December 20, 1999 ------------------------ (Principal Executive Officer) ----------------- W. Brian Matsuyama Date Sr. Vice President - Finance, /s/ J. D. Wessling Chief Financial Officer December 20, 1999 ------------------------- (Principal Financial Officer) ----------------- J. D. Wessling Date Controller and Chief /s/ James E. Haug Accounting Officer December 20, 1999 ------------------------- (Principal Accounting Officer) ----------------- James E. Haug Date /s/ Melvin C. Clapp Director December 20, 1999 ------------------------- ----------------- Melvin C. Clapp Date /s/ Thomas E. Cronin Director December 20, 1999 ------------------------- ----------------- Thomas E. Cronin Date /s/ David A. Ederer Director December 20, 1999 ------------------------- ----------------- David A. Ederer Date /s/ Howard L. Hubbard Director December 20, 1999 ------------------------- ----------------- Howard L. Hubbard Date /s/ Larry L. Pinnt Director December 20, 1999 ------------------------- ----------------- Larry L. Pinnt Date /s/ Brooks G. Ragen Director December 20, 1999 ------------------------- ----------------- Brooks G. Ragen Date /s/ Mary A. Williams Director December 20, 1999 ------------------------- ----------------- Mary A. Williams Date
43 INDEX TO EXHIBITS EXHIBIT NO. DESCRIPTION
3.1 Restated Articles of Incorporation of the Registrant as amended through March 28, 1996. Incorporated by reference to Exhibit 3.1 to the Registrant's current report on Form 8-K filed July 19, 1996. 3.2 Restated Bylaws of the Registrant. Incorporated by reference to Exhibit 3.2 to the Registrant's current report on Form 8-K filed July 19, 1996. 4.1 Indenture dated as of August 1, 1992, between the Registrant and The Bank of New York relating to Medium-Term Notes. Incorporated by reference to Exhibit 4 to the Registrant's current report on Form 8-K dated August 12, 1992. 4.2 First Supplemental Indenture dated as of October 25, 1993, between the Registrant and The Bank of New York relating to Medium-Term Notes. Incorporated by reference to Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the quarter ended June 30, 1993. 4.3 Rights Agreement dated as of March 19, 1993, between the Registrant and Harris Trust and Savings Bank. Incorporated by reference to Exhibit 2 to the Registrant's registration statement on Form 8-A dated April 21, 1993. 4.4 First Amendment to Rights Agreement dated June 15, 1993, between the Registrant and The Bank of New York. Incorporated by reference to Exhibit 4 to the Registrant's quarterly report on Form 10-Q for the quarter ended June 30, 1993. 10.1 1998 Stock Incentive Plan of the Registrant.* Incorporated by reference to Exhibit 10.1 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1998. 10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.2 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1993 (1993 Form 10-K). 10.3 Service agreement (assigned Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.3 to the Registrant's 1993 Form 10-K. 10.4 Service Agreement (Liquefaction -- Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.4 to the Registrant's 1993 Form 10-K. 10.5 Gas Purchase Agreement dated November 1, 1990, between Mobil Oil Canada and the Registrant. Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991. 10.6 Consent to Assignments, Dated June 1, 1997, which assigns from Westcoast Gas Services Inc. (WGSI), to Engage Energy Canada, L.P. (Engage) all the rights and obligations as specified in the contracts contained herein as Exhibit Nos. 10.7, and 10.22. Incorporated by reference to Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the year ended September 30, 1997 (1997 Form 10-K). 10.7 Natural Gas Sales Agreement dated November 1, 1998, between Engage Energy US L.P., and the Registrant. 10.8 Intentionally omitted. 10.9 Intentionally omitted. 44 10.11 Gas transportation agreement between Pacific Gas Transmission Company and the Registrant dated as of April 30, 1997. Incorporated by reference to Exhibit 10.11 to the Registrant's 1997 10-K. 10.12 Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(1) to the Registrant's registration statement on Form S-2, No. 33-52672 (1992 Form S-2). 10.12.1 Amendments dated August 20, 1992, November 1, 1992, October 20, 1993, and December 17, 1993, to Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.12.1 to the Registrant's 1993 Form 10-K. 10.13 Firm Transportation Service Agreement dated April 25, 1991, between Pacific Gas Transmission Company and the Registrant (1993 expansion). Incorporated by reference to Exhibit 10(m) to the 1992 Form S-2. 10.14 Firm Transportation Service Agreement dated October 27, 1993, between Pacific Gas Transmission Company and the Registrant. Incorporated by reference to Exhibit 10.14 to the Registrant's 1993 Form 10-K. 10.15 Intentionally omitted. 10.16 Intentionally omitted. 10.17 Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10(v) to the 1992 Form S-2. 10.17.1 Second amendment to the agreement for the release of Jackson Prairie Storage Capacity dated as of July 30, 1997, amending the Storage Agreement dated July 23, 1990, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10.17.1 to the Registrant's 1997 Form 10-K. 10.18 Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.18 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 1994 (1994 Form 10-K). 10.19 Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's assignment of SGS-1 from WWP) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.19 to the Registrant's 1994 Form 10-K. 10.20 Service Agreement (Firm Redelivery Transportation Agreement under rate Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.20 to the Registrant's 1994 Form 10-K. 10.21 Gas Purchase Contract dated October 1, 1994, between IGI Resources, Inc. and the Registrant. Incorporated by reference to Exhibit 10.21 to the Registrant's 1994 Form 10-K. 10.21.1 Amended Exhibit A, effective October 1, 1999, 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 the Registrant Incorporated by reference to Exhibit 10.22 to the Registrant's 1994 Form 10-K. 10.22.1 Letter amendment dated September 22, 1999, to Amended and restated Natural Gas Sales Agreement dated August 17, 1994, between Engage Energy Canada L.P. and Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT. 45 10.23 Firm Transportation Service Agreement dated November 4, 1994, between Pacific Gas Transmission and the Registrant, effective November 1, 1995. Incorporated by reference to Exhibit 10.23 to the Registrant's 1994 Form 10-K. 10.24 Firm Transportation Agreement dated August 1, 1994, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10.24 to the Registrant's 1994 Form 10-K. 10.25 Prearranged Permanent Capacity Release of Firm Natural Gas Transportation Agreements dated November 30, 1993 between Tenaska Gas Co., Tenaska Washington Partners, L.P. and the Registrant. Incorporated by reference to Exhibit 10.25 to the Registrant's 1994 Form 10-K. 10.26 Agreement for Peak Gas Supply Service dated August 1, 1992, between Tenaska Gas Co., Tenaska Washington Partners, L.P., and the Registrant. Incorporated by reference to Exhibit 10.26 to the Registrant's 1994 Form 10-K. 10.27 Agreement for Peaking Gas Supply Service dated November 22, 1991, between Longview Fibre Company and the Registrant. Incorporated by reference to Exhibit 10.27 to the Registrant's 1994 Form 10-K. 10.27.1 Amendment No. 3 to Agreement for Peaking Gas Supply Service, dated as of October 2, 1997. Incorporated by reference to Exhibit 10.27.1 to the Registrant's 1997 Form 10-K. 10.28 Intentionally omitted. 10.29 1991 Director Stock Award Plan of the Registrant.* Incorporated by reference to Exhibit 10(n) to the 1992 Form S-2. 10.30 Executive Supplemental Retirement Income Plan of the Registrant and Supplemental Benefit Trust as amended and restated as of May 1, 1989, as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by reference to Exhibit 10(o) to the 1992 Form S-2. 10.31 Form of employment agreement between the Registrant and W. Brian Matsuyama, and each other executive officer of the Registrant. * Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2. 10.32 Gas Storage Management Agreement, dated November 17, 1999, between Amoco Energy Trading Corporation, Part of BP Amoco Group, and the Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT. 10.33 Agreement for Jackson Prairie Storage Service, dated October 7, 1999, between Engage Energy Canada, L.P. and the Registrant. A PORTION OF THIS AGREEMENT IS SUBJECT TO A REQUEST FOR CONFIDENTIAL TREATMENT. 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. 46 EX-10.7 2 EX-10.7 Exhibit 10.7 FIRM OR INTERRUPTIBLE GAS SALES AGREEMENT GENERAL TERMS AND CONDITIONS between ENGAGE ENERGY US, L.P. as Seller and CASCADE NATURAL GAS CORPORATION as Buyer TABLE OF CONTENTS
ARTICLE 1. DEFINITIONS ...........................................................................................1 ARTICLE 2. CONFIRMATION ..........................................................................................2 ARTICLE 3. QUANTITY ..............................................................................................2 ARTICLE 4. PRICE OF GAS ..........................................................................................5 ARTICLE 5. TERM ..................................................................................................6 ARTICLE 6. DELIVERY POINT; TITLE; RIGHTS OF POSSESSION ...........................................................6 ARTICLE 7. MEASUREMENTS AND TESTS ................................................................................6 ARTICLE 8. QUALITY OF GAS ........................................................................................6 ARTICLE 9. DELIVERY PRESSURE .....................................................................................6 ARTICLE 10. BILLING AND PAYMENT ...................................................................................7 ARTICLE 11. REGULATION ............................................................................................8 ARTICLE 12. WARRANTIES OF TITLE ...................................................................................8 ARTICLE 13. CREDIT WORTHINESS .....................................................................................8 ARTICLE 14. ADDRESSES AND ACCOUNTS ................................................................................9 ARTICLE 15. FORCE MAJEURE ........................................................................................10 ARTICLE 16. TRANSFER AND ASSIGNMENT ..............................................................................11 ARTICLE 17. NON-WAIVER OF FUTURE DEFAULTS ........................................................................11 ARTICLE 18. ENTIRE AGREEMENT .....................................................................................11 ARTICLE 19. LIMITATION ON CLAIMS .................................................................................11 ARTICLE 20. MISCELLANEOUS ........................................................................................12 EXHIBIT A
FIRM OR INTERRUPTIBLE GAS SALES AGREEMENT GENERAL TERMS AND CONDITIONS ___________________ AS OF THIS 1st day of November, 1998, ENGAGE ENERGY US, L.P., a Delaware limited partnership ("Seller") and CASCADE NATURAL GAS CORPORATION, a corporation ("Buyer") who may hereinafter be referred to collectively as "Parties" or individually as "Party": WITNESSETH: WHEREAS, the Parties wish to enter into a Gas Sales Agreement covering the sale, delivery and purchase of gas. NOW, THEREFORE, in consideration of the premises and mutual covenants set forth herein, the Parties agree as follows: 1. DEFINITIONS 1.1 The term "Agreement" shall mean these General Terms and Conditions and the Exhibit "A" hereto in effect from time to time. 1.2 The term "gas" shall mean any mixture of hydrocarbons or of hydrocarbons and noncombustible gasses, in a gaseous state, consisting essentially of methane. 1.3 The term "Btu" shall mean one (1) British thermal unit, which is the amount of heat required to raise the temperature of one (1) pound of water one degree (1*) Fahrenheit at sixty degrees (60*) Fahrenheit. Btu shall be measured on a dry basis at 14.73 p.s.i.a. 1.4 The term "MMBtu" shall mean one million (1,000,000) British thermal units. 1.5 The term "Seller's Transporter" shall mean the pipeline delivering gas at the Delivery Point(s). 1.6 The term "Receiving Pipeline" shall mean the pipeline receiving gas at the Delivery Point(s) as such pipeline is identified in Exhibit "A", or absent such Receiving Pipeline, the pipeline delivering gas at the Delivery Point(s). 1.7 The term "Delivery Point(s)" shall mean the point(s) identified in Exhibit "A" at which title to the gas is transferred from Seller to Buyer. 1.8 The term "Contract Quantity" (i) for each Exhibit "A" applicable to a firm transaction having a Delivery Period of one month or less, shall mean a quantity equal to the sum of the Daily Contract Quantity (as such is set forth in section 3.1 below) in effect for each day of the Delivery Period of the Exhibit "A" in question and (ii) for each Exhibit "A" applicable to a firm transaction having a Delivery Period of more than one month, shall mean a quantity, determined for each month in the Delivery Period of such Exhibit "A", equal to the sum of the Daily Contract Quantity in effect for every day of each month in such Delivery Period for which there is a Daily Contract Quantity. 1.9 The term "Exhibit "A"" shall mean the confirmation of each transaction substantially in the form of Exhibit "A"/Confirmation attached to these General Terms and Conditions and made a part hereof. 1.10 The term "Delivery Period" shall, for each Exhibit "A", mean the period of time that deliveries under each such Exhibit "A" are to be made. 2. CONFIRMATION 2.1 Seller will prepare and immediately transmit by facsimile to Buyer the Exhibit "A" attributable to each transaction. 2.2 Either Party or both Parties may electronically record any oral statement made by telephone or otherwise by a representative of either Party which pertains or may pertain to formation or performance of a transaction. 3. QUANTITY 3.1 The Exhibit "A" shall set forth the service level (firm or interruptible) and the daily quantity of gas that the Parties intend to purchase and sell (the "Daily Contract Quantity") during the Delivery Period set forth in the Exhibit "A". More than one Exhibit "A" may be in effect between the Parties from time to time. Subject to the terms of this Agreement, the Parties agree to nominate, deliver and purchase such agreed upon Daily Contract Quantity. a. If the service level is specified as "interruptible" in the applicable Exhibit "A", then either party may interrupt the sale or reduce the quantities to be sold without liability to the other (except as set forth in section 3.2 below) if Seller determines that it does not desire to sell gas to Buyer or Buyer determines 2 that it does not desire to purchase gas from Seller. The Parties shall promptly notify each other in the event of changes in the quantities to be purchased or sold and shall change their nominations to reflect such changes. b. If the service level is specified as "firm" in the applicable Exhibit "A", Seller shall sell and deliver and Buyer shall purchase and receive each day the Daily Contract Quantity specified in the applicable Exhibit "A" for the Delivery Period specified in such Exhibit "A". 1. If, for any Exhibit "A" in effect for firm service, Seller fails to deliver the Contract Quantity and such failure is not otherwise excused by any provision of this Agreement, by operation of law or Buyer's failure to meet its obligations hereunder, then Seller shall compensate Buyer for all costs and expenses incurred by Buyer in acquiring a quantity of gas ("Replacement Gas"), up to but not in excess of the difference between the Contract Quantity and the quantity delivered during the Delivery Period of such Exhibit "A" (or during each month thereof if the Delivery Period of such Exhibit "A" exceeds one month), which are (on a per MMBtu basis) in excess of the price payable under such Exhibit "A" ("Buyer's Incremental Costs"). Buyer agrees to use commercially reasonable efforts to obtain Replacement Gas at the lowest price available to Buyer. Within thirty (30) days after the actual quantities delivered by Seller under the applicable Exhibit "A" (or during each month thereof if the Delivery Period of such Exhibit "A" exceeds one month) are confirmed by Receiving Pipeline, Buyer shall render to Seller a statement of Buyer's Incremental Costs detailing the difference between the Contract Quantity and the quantity delivered under such Exhibit "A" during the period of time in question, the quantity of Replacement Gas and the costs and description of costs incurred by Buyer for such Replacement Gas. Within thirty (30) DAYS of receipt of Buyer's statement, Seller shall reimburse Buyer for Buyer's Incremental Costs. Seller's reimbursement of Buyer's Incremental Costs shall constitute Buyer's sole and exclusive remedy for Seller's failure to deliver gas under the Exhibit "A" during the period of time in question and Seller shall not, under any circumstances whatsoever, be liable to Buyer for any 3 other costs, charges, expenses, losses or damages (except as provided under Section 3.2 below) of any nature or kind whatsoever whether direct or indirect, foreseeable or not foreseeable, consequential or incidental, arising from or in any way attributable to or suffered as a result of Seller's failure to deliver gas pursuant to the terms of the Exhibit "A" in question and this Agreement. If, for any Exhibit "A" in effect for firm service, Buyer fails to take the Contract Quantity and such failure is not otherwise excused by any provision of this Agreement, by operation of law or Seller's failure to meet its obligations hereunder, and Seller sells all or a portion of the difference between the Contract Quantity and the quantity taken by Buyer under the Exhibit "A" in question (or during each month thereof if the Delivery Period of such Exhibit "A" exceeds one month) to another purchaser at a price less than the applicable price payable under such Exhibit "A", Buyer shall compensate Seller for the difference between the price per MMBtu which would have been paid to Seller under such Exhibit "A" and the price per MMBtu paid to Seller by such other purchaser(s) ("Seller's Incremental Costs"). Seller agrees to use commercially reasonable efforts to sell such gas at the highest price available to Seller. Within thirty (30) days after the actual quantities delivered under the applicable Exhibit "A" during the period of time in question are confirmed by Receiving Pipeline, Seller shall render to Buyer a statement of Seller's Incremental Costs detailing the difference between the Contract Quantity for such Exhibit "A" and the quantity of gas taken by Buyer under such Exhibit "A" during the period of time in question, the quantity of gas not taken by Buyer that was sold to another purchaser and the price Seller received from such other purchaser(s) for such gas. Buyer shall reimburse Seller for Seller's Incremental Costs within thirty (30) days of Buyer's receipt of Seller's invoice for Seller's Incremental Costs. Buyer's payment of Seller's Incremental Costs shall constitute Seller's sole and exclusive remedy for Buyer's failure to take gas under the Exhibit "A" during the period of time in question and Buyer shall not, under any circumstances whatsoever, be liable to Seller for any other costs, charges, expenses, 4 losses or damages (except as provided under Section 3.2 below) of any nature or kind whatsoever whether direct or indirect, foreseeable or not foreseeable, consequential or incidental, arising from or in any way attributable to or suffered as a result of Buyer's failure to take gas pursuant to the terms of the Exhibit "A" in question and this Agreement. 3.2 The Parties agree to fully cooperate to eliminate imbalances between nominations and deliveries of gas on Seller's Transporter and Receiving Pipeline. If any scheduling or imbalance penalties or charges (including, but not limited to, cash-outs) are imposed upon a Party hereto by Seller's Transporter or Receiving Pipeline in accordance with the provisions of its tariff in effect from time to time, as a result of a Party's failure to deliver or purchase an agreed upon nominated quantity of gas or as a result of the other Party's failure to perform any of its obligations hereunder, then the failing Party shall reimburse the non-failing Party the dollar amount of such penalties (or the failing Party's portion thereof) within thirty (30) days following receipt of an invoice therefor. 4. PRICE OF GAS 4.1 Exhibit(s) "A" in effect from time to time shall state the price per MMBtu for the gas that is sold by Seller to, Buyer ("Price"). a. Seller shall pay or cause to be paid all taxes imposed on or with respect to the gas prior to its delivery at the Delivery Point(s). Buyer shall pay, or cause to be paid, all taxes on or with respect to the gas at and after its delivery at the Delivery Point(s) including, without limitation, any and all federal, state or local sales, use, gross receipts, consumption, franchise fee or other similar fees, taxes or charges that may arise from or be levied upon a sale under this Agreement. If Seller is required to remit or pay such fees, taxes or charges, Buyer shall promptly reimburse Seller for same. b. If Buyer is entitled to purchase gas free from any such taxes or charges, Buyer shall furnish Seller the necessary exemption or resale certificate covering the gas delivered hereunder at the Delivery Point(s). Buyer agrees to indemnify and hold harmless Seller from any and all costs, charges and expenses of any nature incurred by Seller as a result of Seller's reliance on Buyer's representation of exemption. 5 5. TERM 5.1 This Agreement shall be effective as of the date first written above, and, subject to the other provisions hereof, shall remain in effect until terminated by either Party upon at least ten (10) days prior written notice given to the other Party with such termination to be effective as of the first day of the month following expiration of such ten (10) day notice period, provided, however, that if an Exhibit "A" is in effect, termination shall not be effective as to any Exhibit "A" then in effect until expiration of the Delivery Period of each such Exhibit "A". 6. DELIVERY POINT(S); TITLE; RIGHTS OF POSSESSION 6.1 Title and right of possession to all gas delivered and sold hereunder shall pass to Buyer at the Delivery Point(s). Seller shall be deemed to be in exclusive control and possession of the gas and shall be fully responsible for and shall defend and indemnify Buyer, its successors and assigns, against any damage, loss or injury caused by the gas prior to the Delivery Point(s). Buyer shall be deemed to be in exclusive control and possession of the gas and shall be fully responsible for and shall defend and indemnify Seller, its successors and assigns, against any damage, loss or injury caused by the gas at and after the Delivery Point(s). 7. MEASUREMENTS AND TESTS 7.1 The measurement and testing of the gas sold hereunder shall be in accordance with the established procedures in use by Seller's Transporter and applicable to gas delivered at the Delivery Point(s). 8. QUALITY OF GAS 8.1 All gas delivered under the terms of this Agreement shall at all times conform to the quality specifications of Seller's Transporter at the Delivery Point(s), as such specifications are contained in Seller's Transporter tariff(s) in effect from time to time (or in Seller's Transporter standard transportation service agreement if no tariff is applicable). 9. DELIVERY PRESSURE 9.1 Seller shall deliver the gas at the pressure prevailing in Seller's Transporter's facilities at the Delivery Point specified in Exhibit "A". 6 10. BILLING AND PAYMENT 10.1 On or before the twelfth (12th) day of each month during the term of this Agreement, Seller shall render a statement to Buyer for the total quantity of gas delivered to Buyer during the preceding month and for any other amount due Seller under this Agreement for which an invoice is not otherwise provided. Buyer shall pay to Seller, on or before the twentieth (20th) day of each month, the amount due based on Seller's statement. All such payments shall be made to Seller by wire transfer, in immediately available funds, directed to Seller's account set forth in Article 14 below. a. To the extent that the actual quantity is not available to Seller by the twelfth (12th) day of each month, Seller may bill Buyer based on nominated quantities, subject to reduction for any known periods when nominated quantities were not delivered and subject to later correction based on actual data. If a statement is rendered based on nominated quantities rather than actual quantities, Seller shall render a corrected statement as soon as possible after actual quantities are known. 10.2 If presentation of a statement by Seller is delayed after the twelfth (12th) day of a month, then the time for payment shall be extended correspondingly, unless Buyer is responsible for such delay. 10.3 Buyer and Seller shall have the right during normal business hours, and upon reasonable prior notice, to examine the books, records and charts of the other Party to the extent necessary to verify any statement, charge or computation made pursuant to this Agreement. 10.4 If Buyer fails to pay when due the amount of any statement rendered by Seller, Seller may immediately suspend deliveries of gas hereunder and interest on the unpaid amount shall accrue from the due date until the date of payment, at the lesser of (i) the then current prime rate of interest charged by Citibank, N.A. to its best commercial and industrial borrowers plus two percent (2%) or (ii) the maximum lawful rate. This Section 10.4 shall not bar either Party from asserting any other remedy it may have at law or in equity. 10.5 If Buyer finds, within the later of (i) twenty-four (24) months after the date of any statement rendered by Seller or (ii) twenty-four (24) months after the date of any quantity adjustment by Seller's Transporter, that it has been overcharged and if Buyer has paid same and makes a claim for refund within such twenty-four (24) months, 7 the overcharge, if verified by Seller, shall be refunded within thirty (30) days, without interest. If Seller finds, within the later of (i) twenty-four (24) months after the date of any statement rendered by Seller or (ii) twenty-four (24) months after the date of any quantity adjustment by Seller's Transporter, that there has been an undercharge in the amount billed in such statement, Seller may within such twenty-four (24) month period submit a statement for such undercharge to Buyer and Buyer upon verifying the same, shall pay the undercharge to Seller within thirty (30) days, without interest. No adjustments shall be made unless the other Party is notified of a claim prior to the expiration of the applicable twenty-four (24) month period. 11. REGULATION 11.1 This Agreement shall be subject to all valid applicable and effective laws, orders, rules, regulations and directives of all duly constituted Federal, State and local governmental authorities having jurisdiction. 12. WARRANTIES OF TITLE 12.1 Seller warrants that it has the right to sell all gas delivered and that such gas is free and clear of all liens, encumbrances and adverse claims. Seller shall indemnify Buyer and save it harmless from suits, actions, debts, accounts, damages, costs, losses and expenses arising from or out of this warranty. 12.2 OTHER THAN THOSE EXPRESSLY STATED IN THIS AGREEMENT, THERE ARE NO GUARANTEES OR WARRANTIES, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS, OR SUITABILITY OF THE PRODUCT FOR A PARTICULAR PURPOSE NOTWITHSTANDING ANY COURSE OF PERFORMANCE, COURSE OF DEALING OR USAGE OF TRADE OR LACK THEREOF INCONSISTENT WITH THIS PARAGRAPH. 13. CREDIT WORTHINESS 13.1 Prior to the commencement of deliveries and sales of gas under this Agreement, and at any time and from time to time thereafter, Buyer shall furnish Seller with credit information as may be reasonably required to determine Buyer's credit worthiness. If requested by Seller, Buyer shall provide Seller with a satisfactory letter of credit, guarantee or other good and sufficient security of a continuing nature and in a satisfactory amount, as determined by Seller in its sole discretion. At any time Seller may immediately suspend deliveries and sales of gas to Buyer if Seller, in its sole judgment, determines that 8 Buyer's ability to pay for gas has become impaired for any reason. However, Seller may resume deliveries and sales of gas to Buyer at such time as Buyer has satisfied Seller of its ability to pay. 14. ADDRESSES AND ACCOUNTS 14.1 Notices and invoices to Buyer under this Agreement shall be made as follows: NOTICES: Cascade Natural Gas Corporation P.O. Box 24464 Seattle, WA 98124 Attention: Mickey Patton Fax No.: 206-624-7215 INVOICES: Cascade Natural Gas Corporation P.O. Box 24464 Seattle, WA 98124 Attention: Mickey Patton Fax No.: 206-624-7215 Notices and payments to Seller shall be made as follows: NOTICES: Engage Energy US, L.P. Five Greenway Plaza, Suite 1200 Houston, Texas 77046-0502 Attn: Contract Administration Fax No.: (713) 877-3583 PAYMENTS: Engage Energy US, L.P. Account #: 4071-9415 Citibank, N.A., N.Y., N.Y. ABA #: 0210-00089 Either Party may change its address or account as set forth in this Article by written notice to the other Party. Unless otherwise 9 provided, all notices given by one Party to the other shall be sent by certified mail (return receipt requested), by courier delivery, by hand delivery or by telegraph or by facsimile and shall be effective upon receipt. However, routine communications, including monthly statements, shall be considered as delivered when mailed, properly addressed, by ordinary mail. Provided further, a communication by facsimile shall be deemed received on the next business day at the point of receipt if received at such point after four o'clock (4:00) p.m. or on a Saturday, Sunday or holiday recognized by the Party receiving the facsimile communication. 15. FORCE MAJEURE 15.1 If either Buyer or Seller is rendered unable wholly or in part, by force majeure or any other cause of any kind not reasonably within such Party's control to perform or comply with any obligation or condition of this Agreement, upon giving notice and reasonably full particulars to the other Party within a reasonable time after the event of force majeure, such obligation or condition shall be suspended during the continuance of the inability so caused and such Party shall be relieved of liability and shall suffer no prejudice for failure to perform the same during such period; provided, obligations to make payments shall not be suspended and the cause of suspension (other than strikes or lockouts) shall be remedied so far as possible with reasonable dispatch. Settlement of strikes and lockouts shall be wholly within the discretion of the Party having the difficulty. The term "force majeure" shall include, without limitation by the following enumeration, acts of God and the public enemy; failure or curtailment of transportation of gas by either Seller's Transporter or Receiving Pipeline; the elements; fire; accidents; breakdowns; shutdowns for purposes of necessary repairs or maintenance; relocation or construction of facilities; freezing, breakage, accidents or operational failures to wells, machinery or lines of pipe; inability to obtain materials, supplies, permits or labor to perform or comply with any obligation or condition of this Agreement; strikes and any other industrial, civil or public disturbances; and restraints of any government or governmental body or authority, civil or military. 15.2 Notwithstanding the preceding paragraph, if the service level is specified as firm in the applicable Exhibit "A", interruption or curtailment of interruptible transportation by either Receiving Pipeline or Seller's Transporter shall not be considered an event of force majeure unless firm transportation by such pipeline(s) is also being interrupted or curtailed. 10 16. TRANSFER AND ASSIGNMENT 16.1 Any entity that shall succeed by purchase merger, or consolidation to the properties, substantially or in their entirety, of either Party shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement. No other assignment of this Agreement or of any rights or obligations hereunder shall be made by either Party without the written consent of the other Party, which consent shall not be unreasonably withheld. This Article 16 shall not prevent either Party from assigning; pledging or mortgaging its rights hereunder as security for its indebtedness. This Agreement shall be binding upon and inure to the benefit of the respective successors and permitted assigns of the Parties. 17. NON-WAIVER OF FUTURE DEFAULTS 17.1 No waiver by either Party of any one or more defaults by the other Party in the performance of this Agreement shall operate or be construed as a waiver of any future default or defaults, whether of a like or of a different character. 18. ENTIRE AGREEMENT 18.1 This Agreement constitutes the entire agreement between the Parties for the sale, delivery and purchase of gas as contemplated herein. This Agreement supersedes all prior negotiations, representations, contracts or agreements, either written or oral, regarding the subject matter hereof. No modification, alteration, or amendment of this Agreement and/or any Exhibit "A" in effect shall be binding upon either Party unless executed in writing by the Party to be bound. 19. LIMITATION ON CLAIMS 19.1 Neither Party shall be liable for any damages for any breach of this Agreement, unless a claim is presented in writing within two (2) years after the alleged damages occurred. The claim shall set forth in full the nature, character, cause, and amount of the damage. 19.2 NEITHER PARTY HERETO SHALL BE LIABLE TO THE OTHER PARTY FOR ANY CONSEQUENTIAL, INCIDENTAL OR PUNITIVE DAMAGES ARISING OUT OF, OR RELATED TO, A BREACH OF THIS AGREEMENT. 11 20. MISCELLANEOUS 20.1 THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, NOTWITHSTANDING ANY CONFLICT OF LAWS PRINCIPLES OF SAID JURISDICTION THAT MIGHT REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION. 20.2 There is no third party beneficiary to this Agreement, and the provisions of this Agreement shall not impart rights enforceable by any person, firm or organization not a Party or not a successor or assignee of a Party to this Agreement. 20.3 This Agreement was prepared jointly by the Parties hereto and shall not be construed more stringently against either Party hereto than the other. 20.4 Each Party hereby certifies that its taxpayer identification number provided below is correct and each shall, upon request by the other, execute such forms as are necessary to verify same. 20.5 The Parties represent and warrant that they have full and complete authority to enter into and to perform this Agreement. Each person who executes this Agreement on behalf of a Party represents and warrants that he or she has full and complete authority to do so and that their Party will be bound hereby. 20.6 Descriptive headings used herein, if any, are neither part of this Agreement nor an aid to interpreting it. 12 IN WITNESS WHEREOF, the Parties have caused these presents to be executed in duplicate originals by their proper officers duly authorized in that behalf, as of the date first above written. ENGAGE ENERGY US, L.P. Name By: Name: Kevin Manuel Title: Vice President Taxpayer I.D. #76-052-7677 "Seller" CASCADE NATURAL GAS CORPORATION By: Name: King Oberg Title: Vice President Taxpayer I.D. #91-059-9090 "Buyer" Signature page to Gas Sales Agreement between Engage Energy US, L.P. and Cascade Natural Gas Corporation dated November 1, 1998. 13 EX-10.21-1 3 EX-10.21-1 EXHIBIT 10.21.1 IGI IGI RESOURCES, INC. September 24, 1999 Via Facsimile Ms. Patricia Gable Cascade Natural Gas Corporation 222 Fairview Avenue Seattle, WA 98109 RE: Supply Confirmation Dear Patty: This is to confirm our arrangement for the term supply and price IGI will sell to CNG. Term: October 1, 1999 through and including March 31, 2000 Point: Kingsgate, into PG&E Gas Transmission-Northwest Volume: 7,446 Dth/Day Price: $ < * > US per Dth 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 variables and fuel-in-kind. Other: A new Exhibit "A" will be forthcoming. Sincerely, Diane M. Clark Manager - Transportation Services < * > = Redacted AMENDED EXHIBIT "A" 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, 1999 ENDING DATE OF THIS EXHIBIT "A": MARCH 31, 2000 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. The Delivery Point Selling Price shall be equal to < * > ($ < * > U.S. dry) per MMBTU at AECO-C Rub 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: VICE-PRESIDENT GAS SUPPLY "SELLER" IGI RESOURCES BY: Randy Schultz Executive Vice President Chief Operating Officer < * > = Redacted EX-10.22-1 4 EX-10.22-1 EXHIBIT 10.22.1 GAS TRANSACTION CONFIRMATION 1. BUYER: SELLER: GAS TRANS. AG. DATE FORM EFF. DATE: DELIVERED: Cascade Natural Gas Corp. Engage Energy Canada, ILP. October 1, 1995 Sep. 17, 1999 #2350
2. DETAILS OF TRANSACTIONS: Trans.N Start End Quantity/day Price Qual. of Del. Point Del. Rec. 0. Date/Time Date/Time (MMBtu) (Cdn$) Service pipe pipe (See 3. below) (Int, Firm or EFP) See Sec 3 See Sec 3 27037 MMBtu See Sec 3 Firm KINGSGATE WEI WEI
3. SPECIAL PROVISIONS INCLUDING PRICE DETAILS (if any): 1. Commodity Price of Original August 17, 1994 Contract. Price for Nov. 1/99 - Oct. 31/00 (as per Amending Agreement dated August 31, 1999) as follows- a. The Gas Commodity Price to be paid for gas delivered each month during the period commencing on November 1, 1999 and expiring on October 31, 2000 shall be calculated as a percentage price determined under Subsection c below, based upon a weighted average of the following published prices (the Index Price): (i) the 'Rocky Mountain' designated supply source into the Northwest pipeline system, as that price is provided in the publication entitled, Inside F E R C's Gas Market Report in the table entitled, "Prices of Spot Gas Delivered to Pipelines....(per MMBtu dry)", under the "Northwest Pipeline Corp." entry multiplied by 26%; and (ii) the "Canadian Border" designated supply source into the Northwest pipeline system, as that price is provided in the publication entitled, Inside F E R C's Gas Market Report in the table entitled, Prices of Spot Gas Delivered to Pipelines......(per MMBtu dry) under the "Northwest Pipeline Corp" entry multiplied by 35%; and (iii) the AECO "C" & N.I.T. One-Month Spot price as published by the 'Canadian Gas Price Reporter' in the table entitled, Canadian Natural Gas Supply Prices under the column entitled Avg in U.S$/MMBtu multiplied by 39%. 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. c. The percentage of the Index Price shall be 86.5%. 2. PRICE CONVERSION: i) Nov. 1/99 - Mar. 31/00 Price conversion transacted on August 30, 1999 for 25,000 MMBtu/Day (Firm/Fixed Obligation) Price = US $ < * > per MMBtu Volume greater than 25,001 MMBtu/Day up to 27,037 MMBtu/Day is firm delivery based on original pricing as per Section 1 above. ii) Apr. 1/00 - Oct. 31/00 Price Conversion transacted on August 30, 1999 for volumes 15,000 MMBtu/Day (Firm/Fixed Obligation) Price = US $ < * > per MMBtu. Volume greater than 15,001 MMBtu/Day up to 27,037 MMBtu/Day is firm delivery based on original pricing as per Section 1 above. 3. LOAD FACTOR COMMITMENT i) All price conversion volumes dictate a 100% minimum load factor. Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W., Calgary, Alberta, Canada T2P 4K9 Phone: (403) 297-0333 Fax: (403) 269-5909 < * > = Redacted 4. ADDRESSES, OPERATIONS AND BILLINGS AND PAYMENT INFORMATION: Engage Energy Canada, L.P. Cascade Natural Gas Corp. ("Customer") 1100, 421 - 7th Avenue S.W. 222 Fairview Avenue North Calgary, Alberta Seattle WA 98109 Canada T2P 4K9 U.S.A. Marketing Representative Name: Marketing Representative: Jeff Thompson King Oberg Phone: (403) 297-1838 Phone: (206) 624-3900 Fax: (403) 269-6909 Fax: (206) 624-7215 Accounting Contact: Accounting Contact: David Spetz Phone: (403) 297-0386 Phone: (403) Fax: (403) 269-5909 Fax: (403) Operations Contact: Operations Contact: Shelley Nord Phone: (403) 297-0381 Phone: (403) Fax: (403) 2694909 Fax: (403) Wire Transfer Acct. Wire Transfer Acct. 5. (a) The above are the essential binding terms of the transaction in question. If a formal master physical agreement is in effect between the parties, then the above confirmation terms are subject to that agreement. In the event of any conflict between this transaction and the terms of the formal agreement the terms above prevail. If no formal agreement exists, then the parties will finalize and sign one, failing which this transaction remains binding on the parties. Upon finalizing that agreement, the above transaction will form a part of, and be subject to, that formal agreement. ENGAGE ENERGY CANADA, L.P. ("Engage") CASCADE NATURAL GAS CORP. ("the Customer") Per Jeff A. Thompson Per King Oberg Vice President Supply and Marketing Vice President BC/PNW Region Dated: Sep. 22, 1999 Dated: Oct. 10, 1999 September 22, 1999 Fax No. (206) 624-7215 Cascade Natural Gas Corporation 222 Fairview Avenue North Seattle, Washington 98109 Attention: Mr. King Oberg Dear Sir: Re: Gas Transaction Agreement dated October 1, 1995 and Amended and Restated Natural Gas Sales Agreement Dated August 17, 1994 Attached in duplicate is a letter of agreement confirming the extension of the current Kingsgate Agreement pricing methodology for the contract year November 1, 1999 - October 31, 2000. Also attached in duplicate for your execution is a Gas Transaction Confirmation form reflecting Cascade's conversion of a portion of the Kingsgate Agreement Maximum Daily Quantity from a floating price to a fixed price. Upon execution, we would appreciate receiving a copy of each for our files. If you have any questions please call me at (403) 297-1838. Yours truly, ENGAGE ENERGY CANADA, LP. Jeff Thompson Vice President, Supply and Marketing British Columbia and Pacific Northwest Region JATAW Aft. Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W., Calgary, Alberta, Canada T2P 4K9 Phone: (403) 297-0333 Fax: (403) 269-5909 August 31, 1999 Fax No. (206) 624-7215 Cascade Natural Gas Corporation 222 Fairview Avenue North Seattle, Washington 98109 Attention: Mr. King Oberg Dear Sir: Re: Amended and Restated Natural Gas Sales Agreement dated August 17, 1994 between Engage Energy Canada, L.P. ("Engage") ("Seller") and Cascade Natural Gas Corporation ("Cascade") ("Buyer") (The "Kingsgate Agreement") Further to recent discussions, this letter shall confirm the agreement between Engage and Cascade to extend the current provisions of Section 7.8 of the above-referenced agreement for the period November 1, 1999 through October 31, 2000. For further clarification the terms are 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, 1999 and expiring on October 31, 2000 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 26%; 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 35%; 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 39%. Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W., Calgary, Alberta, Canada T2P 4K9 Phone: (403) 297-0333 Fax: (403) 269-5909 Cascade Natural Gas Corporation August 31, 1999 Page 2 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. c. The percentage of the Index Price shall be determined in accordance with the following table: "INDEX PRICE" PERCENTAGE TABLE Period Quantity of Gas Purchased Applicable During Period Percentage of "Index Price" Nov. 1, 1999 to All quantities purchased 86.5% Oct. 31, 2000 during period Engage and Cascade agree to add the following Subsection 4.3 c, C. Notwithstanding any other provision of this Section 4.3, Buyer shall purchase from Seller at the Delivery Point, or if not purchased and taken, shall nevertheless pay for at the Gas Commodity Price specified in Section 7.10 as in effect on the last day of the period, a minimum daily quantity of gas which shall equal to 15,000 MMBtu. Terms or phrases defined or used in the Gas Sales Agreement shall have the 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 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. Kathy Puls Accepted and Agreed to this 10th day of October, 1999. CASCADE NATURAL GAS CORPORATION King Oberg Vice President EX-10.32 5 EX-10.32 EXHIBIT 10.32 BPAmoco AMOCO ENERGY TRADING CORPORATION A subsidiary of We BP Amoco Group 501 WestLake Park Boulevard Houston, Texas 77079 November 17, 1999 Cascade Natural Gas Corporation 222 Fairview Avenue Seattle, Washington 98109 Attention: Ms. Pattie Grable STORAGE MANAGEMENT AGREEMENT Dear Ms. Grable: This letter documents the storage management agreement between Cascade Natural Gas Corporation (Cascade) and Amoco Energy Trading Corporation (AETC), Part of BP Amoco Group, relating to a portion of Cascade's storage capacity in the Jackson Prairie storage field operated by NWPL. Contract Term: November 1, 1999 through October 31, 2000, extendible by mutual agreement. Storage Capacity: 604,351 MMbtu's Contracted Withdrawal Capacity: 16,789 MMbtu/D Bonus Payment: US $ < * > payable by AETC to Cascade on or before November 24, 1999. The Bonus Payment is the consideration for Cascade allowing AETC to manage and use its storage rights as provided in this agreement. Optimization Profit Sharing: In the event AETC recovers 100% of the Bonus Payment, as optimization profits generated by its storage and cycling activities during the Contract Term, any additional such optimization profits shall be shared between AETC (< * > %) and Cascade (< * > %), payable within thirty (30) days after the end of the Contract term. < * > = Redacted CASCADE'S STORAGE MANAGEMENT AGREEMENT NOVEMBER 17, 1999 PAGE 2 OF 4 Winter Priority: Cascade shall retain the right to call on up to 604,351 MMbtu's of storage gas between November 1, 1999 through March 31, 2000. As such, AETCs right to cycle storage during this winter period shall be subordinated to Cascade's right to withdraw up to 604,351 MMbtu's during this period. Any AETC winter cycling activity shall be designed not to infringe upon Cascade's contract withdrawal rights as stated above. Summer Refill: It is the intent of the parties that AETC during the contract term will manage the refill of Cascade's storage capacity, in compliance with tariff inventory capacity targets, redelivering to Cascade 604,351 MMbtu's in the storage account at the end of the Contract Term. AETC will cause refill gas to be injected more or less ratably during the summer injection season. Cascade's ratable daily refill will be determined by dividing the cumulative volume withdrawn by Cascade through 3/31/00 by 183 days (i.e., up to 604,351 MMbtu's divided by 183 days equals 3,302 Mmbtud). In addition, with notice to AETC at least 5 business days prior to the beginning of the month, Cascade may request that AETC refill at a daily quantity of up to 125% of the ratable daily refill quantity for such month. For the 604,351 MMbtu's of supply, Cascade shall pay AETC the pertinent I.F.E.R.C. NWPL first of month index price plus applicable transportation and storage costs incurred by AETC. Cascade may elect, from time to time, to convert such first of month index price to either a) a fixed price for one or more future months, or b) a daily price tied to Gas Daily index prices. If Cascade wants a quote for either such price, it shall notify AETC at least 5 business days prior to the beginning of the applicable month. AETC shall provide Cascade a quote as soon as possible for the requested pricing alterative(s) (a fixed price or the Gas Daily average price for the upcoming month) adjusted to reflect market conditions. At that time, Cascade shall be available to verbally respond immediately to the quote provided by AETC and to elect whether to accept the alternative pricing. A verbal acceptance by Cascade shall be binding upon the parties, and AETC shall promptly confirm by facsimile Cascade's acceptance of the alternative pricing quote. If Cascade does not accept the CASCADE'S STORAGE MANAGEMENT AGREEMENT NOVEMBER 17, 1999 PAGE 3 OF 4 alternative pricing, then the aforesaid I.F.E.R.C. based price shall be the price for that month. Upon request, AETC will apprise Cascade of inventory volumes and WACOG. Operations: Cascade shall make its nominations to and from the Jackson Prairie storage account directly to AETC. Cascade shall designate AETC as its Agent for nominations to Williams Pipeline - West regarding Cascade's storage account applicable to this agreement. Cascade and AETC shall coordinate actual activities associated with the Jackson Prairie storage facility, including operating practices ensuring Cascade's nominations to AETC in a timely manner for AETC to be compliant with all Gas Industry Standards Board requirements. However, Cascade will not have the right or ability to dictate the manner in which AETC uses or cycles the Jackson Prairie storage account unless the activities of AETC can be demonstrated to adversely impact Cascade's right to call on winter gas as stated in Winter Priority, above. Cascade and AETC will cooperate to minimize the number and severity of renominations. Storage and Transport Costs: Cascade shall continue to bear all fixed transportation and storage charges related to the storage capacity, and all variable transportation and storage charges (including commodity and fuel charges) relating to the withdrawal and refill of up to 604,351 MMbtu's. AETC shall pay all other variable costs (including commodity and fuel charges) it incurs in the conduct of its storage cycling activities. Value of Storage Cycling: The value of storage management to AETC (and to Cascade once AETC recovers the Bonus Payment through optimization) arises from taking advantage of cycling opportunities whenever market conditions permit. CASCADE'S STORAGE MANAGEMENT AGREEMENT NOVEMBER 17, 1999 PAGE 4 OF 4 Availability of TF-2 Transport: November 1, 1999 through September 30, 2000 (and possibly during October 2000 but only with Cascade's prior consent). During the period November 1, 1999 through March 31, 2000, AETC's right to use TF-2 transport as agent for Cascade pursuant to this agreement will be subordinated to Cascade's right to transport up to 16,739 MMbtud. Cascade and AETC can mutually agree to allow AETC such use of TF-2 capacity. Use of such capacity by AETC will preclude any responsibility on AETC's part to reimburse Cascade for TF-2 transport costs other than applicable volumetric charges. This letter constitutes the agreement between the parties for storage management services as specified above. Sincerely, AMOCO ENERGY TRADING CORPORATION By V James A. Taylor Regional Vice President - West Agreed to and accepted this 25th day of November, 1999 CASCADE NATURAL GAS COMPANY By Name: KING OBERG Title: VICE PRESIDENT, GAS SUPPLY EX-10.33 6 EX-10.33 EXHIBIT 10.33 ENGAGE October 7, 1999 Via Telecopy Cascade Natural Gas Corporation 222 Fairview Avenue North Seattle, Washington 98109-5312 Attn: Mr. King Oberg Vice-President, Gas Supply Dear King: Re: Jackson Prairie Storage Service This letter outlines the terms and conditions under which Engage Energy Canada, L.P. ("Engage") would be prepared to purchase storage services from Cascade Natural Gas ("Cascade") for the upcoming contract year. Term: November 1, 1999, through October 31, 2000 Volume: Inventory: 480,000 MMBtu Withdrawal: Firm 15,000 MMBtutday Best efforts 5,533 MMBtu/day Price: Unconditional, up-front payment of $ < * > (est. < * > % of total demand and capacity demand charges). Revenue Sharing: < * > % over the term of the agreement. The Revenue Sharing plan will be based solely upon Secondary Call volumes and replacements, and not applicable to the 15 days maximum of Engage Firm Call volumes and replacements. All withdrawals and replacements made by Engage shall be recorded separately from all other Engage business and will be subject to audit by Cascade upon request. Firm Call: Engage shall have the first right to call on a maximum of 10,000 MMBtu/day from Cascade, not more that 5 days per month, or more than 15 days over the Firm Call Period (November 1, 1999, through March 31, 2000). For volumes specified as Firm Call Cascade shall be obligated to deliver one hundred (100%) percent of the requested quantity. Similarly, Engage shall be obligated to take all volumes specified as Firm Call volumes. Further, on the days in which Engage nominates Firm Call volumes, Engage will not request best efforts volumes. Engage Energy Canada, L.P. 1100, 421 7th Ave. S.W, Calgary, Alberta, Canada T2P 4K9 Phone: (403) 297-0333 Fax: (403) 269-5909 < * > = Redacted Cascade Natural Gas October 7, 1999 Page 2 Secondary Call: Engage shall have the ability to call on a maximum of 15,000 MMBtu/day (firm withdrawal quantity) and up to 5,533 MMBtu/day (best efforts quantity) from Cascade over the period. Engage recognizes that Cascade has the first right to call on these volumes, and provides the Secondary Call to Engage on a best-efforts basis only. Transportation: For all Firm Call volumes, Engage will have the first right to request delivery of Jackson Prairie withdrawal volumes under Cascade's TF-2 transportation. Engage will reimburse Cascade for all TF-2 commodity charges incurred during the periods in which Engage utilizes, such transportation. Engage may also elect to transport Firm Call volumes under its TF-1 service. For all Secondary Call volumes, Engage may request on a best efforts basis delivery of Jackson Prairie withdrawal volumes under Cascade's TF-2 transportation. Engage will be reimbursed by Cascade for all TF-2 commodity charges incurred during the periods in which Engage utilizes such transportation. Engage may also elect to transport Secondary Call volumes under its TF-1 service. Engage recognizes that Cascade's TF-2 transportation is limited in volume to the equivalent of 1 withdrawal cycle (480,000 MM8tu total), and once utilized is no longer available until the next storage period (November 1, 2000, through October 31, 2001). Replacements: Engage will replace all volumes withdrawn prior to September 30, 2000. All costs associated with the volume replacement will be Engage's responsibility. We hope this proposal will meet with your approval. This offer is open for acceptance until the close of business on October 8, 1999. Following this date, the proposals contained herein will be deemed to be expired. If you have any questions, please contact me at (503) 471-1333. Yours truly, ENGAGE ENERGY CANADA, L.P. Fred M. Scott, P.Eng. Director, Business Development Agreed to and accepted to this 7th day of October 1999. EX-12 7 EX-12 EXHIBIT 12 CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED DIVIDEND REQUIREMENTS
Twelve Months Ended ---------------------------------------------------------------------- 30-Sep-99 30-Sep-98 30-Sep-97 30-Sep-96 31-Dec-95 -------------- ------------- ------------- ------------ ------------ (dollars in thousands) Fixed charges, as defined: Interest expense $ 10,486 $ 10,132 $ 9,436 $ 10,101 $ 9,938 Amortization of debt issuance expense 603 605 612 612 606 -------------- ------------- ------------- ------------ ------------ Total fixed charges $ 11,089 $ 10,737 $ 10,048 $ 10,713 $ 10,544 -------------- ------------- ------------- ------------ ------------ Earnings, as defined: Net earnings $ 14,053 $ 9,544 $ 10,627 $ 8,211 $ 7,732 Add (deduct): Income taxes 8,075 5,694 6,263 4,272 4,508 Fixed charges 11,089 10,737 10,048 10,713 10,544 -------------- ------------- ------------- ------------ ------------ Total earnings $ 33,217 $ 25,975 $ 26,938 $ 23,196 $ 22,784 -------------- ------------- ------------- ------------ ------------ Ratio of earnings to fixed charges 3.00 2.42 2.68 2.17 2.16 ============== ============= ============= ============ ============ Fixed charges and preferred dividend requirements: Fixed charges $ 11,089 $ 10,737 $ 10,048 $ 10,713 $ 10,544 Preferred dividend requirements 756 778 811 819 853 -------------- ------------- ------------- ------------ ------------ Total $ 11,845 $ 11,515 $ 10,859 $ 11,532 $ 11,397 -------------- ------------- ------------- ------------ ------------ Ratio of earnings to fixed charges and preferred dividend requirements 2.80 2.26 2.48 2.01 2.00 ============== ============= ============= ============ ============
EX-23 8 EX-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, No. 33-39873 and No. 333-88419 on Form S-8 of Cascade Natural Gas Corporation, of our reports dated November 5, 1999, appearing in this Annual Report on Form 10-K of Cascade Natural Gas Corporation for the year ended September 30, 1999. DELOITTE & TOUCHE LLP Seattle, Washington December 20, 1999 EX-27 9 EX-27
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 YEAR ENDED SEPTEMBER 30, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR SEP-30-1999 OCT-01-1998 SEP-30-1999 PER-BOOK 282,291 779 24,888 7,611 0 315,569 11,045 97,380 5,970 114,395 6,186 0 125,000 0 0 0 0 0 0 0 69,988 315,569 208,610 8,075 176,271 176,271 32,339 495 24,759 10,706 14,053 483 13,570 10,603 0 28,178 1.23 1.23
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