Item 1 - Business
General
Cascade Natural Gas Corporation (Cascade or the Corporation) 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 19% of its gas distribution revenues are from the state of Oregon.
At December 31, 1993, there were 110,441 residential customers, 21,781 commercial customers, 329 firm industrial customers and 30 traditional interruptible customers, all of which are classified as core customers. In addition, there were 87 non-core customers. In 1993, the core customers provided 73% of the operating margin (up from 71% in 1992) while consuming 31.0% of the total gas deliveries, down from 31.3% in 1992. The non-core customers (including transportation service) provided the remaining operating margin of 27% (down from 29% in 1992) while consuming 69.0% of the total throughput, up from 68.7% in 1992.
The Corporation is subject to regulation with respect to, among other matters, rates, systems of accounts and issuance of securities by the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC). The Corporation is not subject to direct regulation by the Federal Energy Regulatory Commission (FERC), but is significantly affected by the FERC's orders which regulate interstate pipelines serving the Corporation.
Cascade's gas supply contracts provide for annual review of gas prices for possible adjustment. To the extent that prices are changed, Cascade is able to pass the effect of such changes 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.
The Corporation is also subject to state regulation with respect to integrated resource planning and has filed its second Integrated Resource Plan (IRP) in draft form with both the WUTC and the OPUC. The IRP (previously least cost plan) shows the Corporation's plan for the best set of gas supply and demand side resources that minimizes costs and has acceptable levels of deliverability risk over the twenty-year planning horizon. The IRP also sets forth the Corporation's forecast of growth in customers and volume throughput for a twenty-year period. In addition, the IRP sets forth the Corporation's demand side management goals of achieving certain conservation levels in customer usage. Corporation investments in cost-effective demand side resources are recoverable in rates in both Washington and Oregon.
The IRP also sets forth the Corporation's supply side management plans regarding transportation capacity and gas supply acquisition over a twenty- year period. The Corporation developed the IRP over a two-year period and took into account input solicited from the public and the WUTC and OPUC staffs. While the filing of the IRP with both commissions gives the Corporation 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 Corporation by giving it the opportunity to obtain input from regulators and the public concurrently with making these important strategic decisions.
Until the Corporation receives final regulatory approval of these decisions in the context of a rate case, the Corporation cannot predict with
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certainty the extent to which the integrated resource planning process will affect its rates.
The principal industrial activities in Cascade's service area include the production of pulp, paper and converted paper products, plywood, chemical fertilizers, industrial chemicals, cement, clay and ceramic products, textiles, refining of crude oil, smelting and forming of aluminum, the processing and canning of many types of vegetable, fruit and fish products, processing of milk products, meat processing and the drying and curing of wood and agricultural products.
OPERATING STATISTICS (dollars in thousands except per therm and per customer data)
(Operating Statistics continued on next page)
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OPERATING STATISTICS (dollars in thousands except per therm and per customer data)
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Natural Gas Supply
The majority of Cascade's supply of natural gas is transported via Northwest Pipeline Corporation (Northwest). Northwest 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. The Corporation is also a shipper on the Pacific Gas Transmission Company (PGT) system. PGT owns and operates a gas transmission line that extends from the gas fields in Alberta, Canada through Washington and central Oregon into California.
On November 1, 1993, Northwest completed the process, begun in 1988, of converting its sales function to firm transportation service. Along with the sales conversion of its remaining sales service from Northwest, the Corporation accepted assignment of a pro-rata share of Northwest's remaining Canadian gas supply arrangements, an equivalent share of PGT firm pipeline transportation and a portion of Northwest's natural gas inventory at the Clay Basin Storage Facility.
Presently, baseload requirements for Cascade's core market group are provided by two major domestic and six major Canadian gas supply contracts with various expiration dates for 1995 through 2008 and totalling 503,840 therms per day. These contracts are supplemented by storage gas inventories including the assignment of Clay Basin inventory providing for 200,000 therms per day and a maximum 1994-95 inventory of 8,361,200 therms. Two additional agreements for storage gas cover periods of peak demand. One, with Northwest, extends to October 31, 2014 and provides for 165,950 therms per day and a maximum, renewable inventory of 5,973,780 therms. The second, with The Washington Water Power Company, extends to April 30, 1995 and entitles Cascade to receive up to 150,000 therms per day and a maximum, renewal inventory of 4,800,000 therms. Cascade has entered into a contract with one of its major industrial customers whereby it may reduce firm deliveries to that customer by 150,000 therms per day up to a seasonal total of 3,000,000 therms. This contract expires on September 30, 2015. Cascade also owns a propane air peak shaving plant with a daily capacity of 60,000 therms and has liquified natural gas storage available under an agreement with Northwest which extends to October 31, 2014. Under this agreement, Cascade is entitled to receive up to 600,000 therms per day and to a maximum, renewable inventory of 5,622,000 therms.
Cascade maintains a diversified portfolio of natural gas supplies. During 1993, Cascade purchased approximately 6.2% from Northwest, 41.9% from other firm gas supply contracts, 48.3% from 30-day spot market contracts and 3.5% from customer assigned gas purchase contracts. In addition, 240,448,000 therms of customer purchased supplies were transported across Cascade facilities.
Current Federal Energy Regulatory Commission (FERC) Matters:
On November 1, 1993, and pursuant to FERC Order No. 636, as supplemented by FERC Order No. 636A, 636B and 636C (Order 636), Northwest completed the conversion of its remaining sale service to firm transportation service and ceased nearly all activities as a merchant of natural gas. Also on November 1, 1993, PGT undertook the same conversion and is now primarily a transportation pipeline. With the completion of the Northwest conversion, Cascade holds 2,090,490 therms per day of firm transportation capacity. As part of the Northwest conversion, the Corporation took direct assignment of 313,350 therms per day of firm PGT transportation capacity and contracted for an additional 74,460 therms of wintertime only firm capacity on the PGT system.
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Interstate pipelines that cease being gas sellers face the cost of buying down take-or-pay commitments contained in contracts with their own gas suppliers. Such costs were relatively small on Northwest's system, and to the extent they were passed on, state regulators allowed Cascade to include them in rates to its customers. The FERC since has determined that $37,000,000 of these past charges were allocated among Northwest's customers in an impermissible manner. Proceedings to reallocate these costs are now in progress. To the extent Cascade's final allocation differs from the original, it will seek to pass on the difference to its customers in rates.
Even though PGT is still restructuring supply contracts which were entered into between PGT and a sister company for the sole purpose of providing sales service to their parent, Pacific Gas and Electric Company in California, Cascade and other northwest shippers negotiated a settlement that capped their PGT Gas Supply Restructuring (GSR) costs at approximately 1.3% of the anticipated final approved GSR costs. Cascade's allocation was $350,000 and the Corporation opted to make a one time payment earlier this year, thereby discharging all obligations to the PGT GSR costs associated with Cascade's original PGT capacity regardless of the eventual PGT settlement total. The Corporation may have some additional exposure to a small amount of GSR costs that may be collected from all shippers through a volumetric surcharge assessed on its 1993 and 1995 PGT expansion capacity. Cascade is seeking full recovery of this payment in its rates, as was done with respect to Northwest transition costs.
Because Northwest has been working toward the transformation from sales to open access transportation of natural gas since 1988, Cascade has experienced very little operational impact or transition costs from the implementation of Order 636. The April 1, 1993 shift to straight fixed variable rates mandated by Order 636 did not, by itself, increase total pipeline transportation costs to Cascade, but did result in a greater share of such costs being attributable to low load factor customers of Cascade. Additional pipeline costs were experienced with the November 1, 1993 completion of the first of Northwest's and PGT's expansion projects. The rates presently being collected, subject to refund, reflect a rolled-in methodology currently being challenged through FERC rate case proceedings, by Cascade and several other shippers advocating an incremental rate design.
Cost of Purchased Gas
Following the implementation of Order 636, Cascade's cost of gas depends primarily on the prices negotiated with producers and brokers, coupled with the cost of interstate pipeline transportation service.
Curtailment Procedures
In previous heating seasons, cold weather has required Cascade to significantly curtail its interruptible customers. Cascade has not curtailed any firm customers, except under force majeure provisions. Cascade's tariffs effective in Washington and Oregon, allow for curtailment of interruptible services, which are provided at rates lower than for firm services. In the event of curtailment by Cascade of firm service due to force majeure, Cascade's tariffs provide that it shall not be liable for damages or otherwise to any customer for failure to deliver gas curtailed in accordance with the provisions of the tariffs. The tariffs provide for appropriate adjustment of the monthly bill of firm customers curtailed by reason of an insufficient supply of gas.
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Territory Served and Franchises
The population of communities served by Cascade totaled approximately 700,000 at the end of 1993 compared to 665,000 at the end of 1992, a 5.3% increase.
Cascade has all the franchises necessary for the distribution of natural gas in the communities it serves in Washington and Oregon with the exception of one city franchise in Washington the renewal of which is being negotiated. 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 1994 to 2065. Management has not incurred difficulties in renewing franchises when they expire and does not expect any 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.
Of its non-core customers, 15 accounted for approximately 31% of Cascade's total 1993 gas and transportation revenues. Agreements with its principal industrial customers are for fixed terms of not less than one year and provide for automatic extension from year to year unless terminated by either party on 30-days' notice. No one customer accounted for as much as 10% of gas revenues.
Seasonality
Weather is an important factor affecting gas revenues because of the large number of customers using gas for space heating. In 1993, 64.5% of operating revenues and 96.8% of earnings from operations were derived from the first and last quarters. Because of the seasonality of space heating revenues, Cascade believes financial results for interim periods are not necessarily indicative of results to be expected for the year.
Competitive Conditions
Cascade sells in a competitive market for natural gas. Cascade competes with residual fuel oil and other alternative energy sources for industrial boiler uses and oil and electricity for residential and commercial space and water heating uses.
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 a significant advantage over electricity in over 90% (by population) of its territory. In the remaining areas of its service territory served by public electric utilities with their own substantial hydro power supply, Cascade is at parity with respect to electricity furnished by those utilities for space heating and water heating uses. Cascade has increased its efforts in attaining a positive customer growth in the residential and commercial market over the last several years by aggressively meeting consumers' needs. Through its wholly-owned subsidiary, Cascade Land Leasing Co., the Corporation provides loans to customers to finance the purchase and installation of energy efficient gas appliances. - 6 -
Historically, the large volume industrial market was very sensitive to price fluctuations between the comparable cost of natural gas and alternate fuels, principally residual fuel oil used in boiler applications. However, the advent of open access transportation and the restructuring of gas supply and contractual provisions with these customers has improved the Corporation's competitive position. From December 1991 through January 1992 and again from December 1992 through February 1994, except for a brief period in June 1993, residual fuel oil prices were lower than natural gas, but Cascade did not experience any significant loss of sales to alternate fuels during those periods.
In addition to multiple alternate fuels, the Corporation competes with other sources of natural gas because of the potential for bypass of the Corporation's facilities. Bypass refers to actual or prospective customers which install their own facilities and connect directly to an upstream pipeline and thereby "bypass" the distribution company's service. The Corporation has experienced bypass but has also experienced success in offering competitive rates to reduce economic incentives to bypass.
The Bonneville Power Administration ( BPA ) is a major supplier of hydro-electric power in the Pacific Northwest including Cascade's service area. BPA significantly influences the electric rates of all classes of customers including those applications in direct competition with natural gas marketed by Cascade. BPA increased rates by approximately 14% in October, 1993.
Environmental
The Corporation is subject to federal and state environmental regulation of its operations and properties through the United States Environmental Protection Agency, the Washington Department of Ecology and the Oregon Department of Environmental Quality. Such regulation may, at times, result in the imposition of liability or responsibility for the clean-up or treatment of existing environmental problems or for the prevention of future environmental problems.
In the early 1950's, the Corporation purchased several of the gas distribution facilities that it operates today. Among the acquired facilities, the Corporation has identified to date 12 small manufactured gas plants which had used oil or coal as feedstock to produce manufactured gas. Some of the waste byproducts of the manufacturing process contain hazardous substances which, if found in sufficient concentrations, could pose environmental problems.
Almost all of these plants were either dismantled or converted to propane air prior to 1956. In 1956, when natural gas became available, the remaining plants were dismantled. The plant sites were cleaned up when the plants were dismantled and the sites are currently being used for other purposes. Environmental agencies have monitored three of the sites and have found no hazardous substances at levels requiring remediation. Based on information received to date, management is not aware of hazardous substances present at any of the sites at levels that would require remediation.
The Corporation is in the process of remediating a site that was contaminated by underground diesel and gasoline storage tanks. See Note 9 under Notes to Consolidated Financial Statements.
Capital Expenditures
Capital expenditures for 1994 are budgeted for $35,100,000. Including the 1994 capital budget, the Corporation will have spent slightly over $103,000,000 in new plant in the three years ended in 1994, compared to - 7 -
$108,000,000 in the nine years from the end of 1982 through 1991. Included in the budget are distribution facilities to serve the fourth cogeneration plant on the Corporation's system. The contracts for service to the four cogeneration plants are expected to yield virtually level payments over the 15- to 25-year contract lives of the which should recover the capital investment in the facilities and provide a return to shareholders over their term. With level payments, projected rates of return are low in the early years and increase significantly over time as the Corporation's investment is depreciated. Therefore, the significant capital expenditures incurred in 1992, 1993 and budgeted for 1994, will likely produce a dampening effect on earnings in the short term with a longer term effect of strengthening the earnings flow.
No budgets have been prepared beyond 1994, however, the Corporation expects that capital expenditures will total approximately $110,000,000 to $140,000,000 over the following five years.
Non-Utility Subsidiaries
Cascade has six non-utility subsidiaries. These subsidiaries are engaged in the following businesses, respectively; financing Cascade customers' purchases of energy-efficient appliances; marketing a gas measurement chart scanner; ownership and licensing of the technology related to a gas measurement chart scanner; exploring for natural gas; and ownership of certain real property in Oregon. The subsidiaries, which in the aggregate account for less than 5% of the consolidated assets of the Corporation, do not currently have a significant impact on Cascade's financial condition or the results of its operation.
Personnel
At December 31, 1993, Cascade had 467 employees. Of the total employees, 209 are represented by the International Chemical Workers Union. The present contract with the union extends to April 1, 1996, and thereafter until terminated by either party on 60-days' notice.
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Item 2
Item 2 - Properties
At December 31, 1993, Cascade's utility plant investments included approximately 3,558 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 2,162 miles of service lines.
The lateral lines and distribution 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 16 buildings used for operations, office space and warehousing in Washington and five such buildings in Oregon. It occupies an additional five commercial offices and maintains 35 pay stations in communities throughout its operating territory. 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. The Corporation also owns a propane air plant in Yakima, Washington, with a capacity of 60,000 therms per day used for peak load shaving.
Item 3
Item 3 - Legal Proceedings
See last paragraph under "Business - Environmental".
Item 4
Item 4 - Submission of Matters To a Vote of Security Holders
None
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Executive Officers of the Registrant
The Executive Officers of the Corporation, as of March 1, 1994, are as follows:
None of the above officers is related by blood, marriage or adoption to any other of the above named officers. Except as discussed below, each of the above named officers has been employed by the Corporation 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.
King C. Oberg has been employed by the Corporation since January 2, 1989. From 1963 through October 1988, he held various positions in gas measurement and accounting with ENRON Corp. of Houston Texas.
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PART II
Item 5
Item 5 - Market for Registrant's Common Equity and Related Shareholder Matters
The Common Stock is traded on the New York Stock Exchange under the symbol CGC. At February 28, 1994, there were approximately 6,745 record holders of the Common Stock. The following table shows for the periods indicated the high and low sales prices of, and the per share dividends paid on, the Common Stock in each case as adjusted for stock splits.
Market and Dividend Information
The Corporation's practice has been to declare dividends on its common shares quarterly, payable on the 15th day of February, May, August, and November. The most recent quarterly dividend on the common shares was $.24 per share and was paid on February 15, 1994, to holders of record on January 15, 1994. Future dividend action will depend on the earnings and financial condition of the Corporation and other relevant factors.
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Item 6
Item 6 - Selected Financial Data
Statements of Operations (dollars in thousands except per share data)
(Selected Financial Data continued on next page)
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Item 7
Item 7 - Management's Discussion of the Results of Operations and Financial Conditions
Results of Operations 1993 vs 1992
The continuing strong customer growth coupled with reasonably normal weather (7.5% colder than normal) pushed total year earnings as well as fourth quarter earnings to new record levels. Net earnings to common shareholders for 1993 were $8,523,000 or $1.08 per share compared to $4,248,000 or $0.64 per share in 1992. Fourth quarter net earnings to common shareholders were $5,005,000 compared to $3,962,000 in the 1992 fourth quarter. Earnings per share were $0.59 in the 1993 quarter and $0.57 in the 1992 quarter.
Margin and Volume Changes Between 1993 and 1992
The successful sales of common stock in November, 1992 and June, 1993, increased the number of shares outstanding, affecting per share comparisons for both the year and the quarter. All per share numbers reflect the three for two stock split which was effective on December 20, 1993.
Acquisition of new customers continued at the healthy rate of 7.5% in 1993. Residential customers increased 8.3% in 1993 over 1992. Therm deliveries to the core market increased 20.7% while therm deliveries to the non-core market were up 22.7%. The significant increase in deliveries to the non-core market, primarily in the latter half of 1993, reflects the beginning of commercial operation for the second cogeneration plant on the Corporation's system.
Operating expenses were up 8.7% ($2,274,000) in 1993. Payroll and fringe benefit cost increases accounted for 85% of the increase. The Corporation adopted Statement of Financial Accounting Standard (SFAS) No. 106 Employers' Accounting for Postretirement Benefits other than Pensions, which accounted for a portion of the fringe benefit cost increase. Depreciation expense increased 9.1% ($763,000) as a result of the significant additions to utility plant in 1993 and prior years. Income taxes were up 85.4% ($2,407,000) over 1992. The increase is primarily due to the improvement in earnings.
Interest expense was down 5.9% ($440,000) from the 1992 level as a result of the refinancing of higher cost debt that was accomplished in mid 1992 and early 1993. Interest charged to construction was up 48% ($105,000) as the result of the use of more short-term debt in 1993. Amortization of debt issuance expense was up 40% ($160,000) in 1993 reflecting the costs incurred to refinance the higher cost debt mentioned above. Other expense reflects termination of all interests and the writeoff of all remaining costs ($244,000) associated with the drilling activities in northwestern Washington as well as other valuation reserves.
The results for 1993 include the effect of adopting, in the first quarter of 1993, SFAS No. 109, Accounting for Income Taxes, which resulted in a one time credit to earnings of $209,000 or $0.03 per share.
Results of Operations 1992 vs 1991
A return to more normal weather in the fourth quarter of 1992 produced strong earnings for the quarter but, not sufficient to offset the impact of the record warm temperatures in the first quarter of 1992. Therm deliveries to the - 14 -
core market were up 11.7% in the 1992 quarter compared to the prior year producing a 21.4% increase in margins from the core category over the similar period in 1991. While this significant improvement over the fourth quarter of 1991 was largely attributable to the return to more normal weather, the continuing strong customer growth of 7.5% also had an impact.
Total margin for 1992 was down $898,000 (1.7%), however, margin from the core customers was down $1,764,000 (4.5%) reflecting the impact of the warmer than normal weather experienced through most of the year. The increase in margin from the non-core customers reflected the full year impact of the first cogeneration plant on the system as well as an increase in customers. Total volumes for 1992 were up 46,315,000 therms (8.3%) but deliveries to the core customers were down 6,536,000 therms (3.3%).
While earnings for all of 1992 were depressed as a result of the significant decline in degree days (6.9% fewer than 1991 and 10.6% warmer than normal), continuing customer growth contributes to improved profitability under normal weather. The Corporation continued to add new customers at a record pace and while the vast majority of the new customers in 1992 came from the residential class, the number of non-core customers increased by 7.8%.
Operating expenses increased 6.6% in 1992 over 1991 and this compares favorably to the 9.8% increase experienced in 1991 over 1990. Employee costs, including fringe benefits, accounted for 80% ($1,299,000) of the increase. Staffing increases and increased medical costs were the primary driving force behind the increases.
Depreciation expense increased 8.9% as a result of the significant growth in utility plant (up 11.6%) required to serve the additional customers. The decline in income tax expense is the result of lower earnings. Costs of $157,000 or $0.03 per share representing costs incurred in connection with natural gas exploration were charged to expenses in the fourth quarter.
Liquidity and Capital Resources
The Corporation invested $32,990,000 in new utility plant in 1993. Internal cash generation, after cash dividends, funded approximately 20%. The low level of internal cash generation for funding construction was the result of returning in excess of $8,778,000 to customers from a Northwest Pipeline Corporation refund received in 1989 as a result of the settlement of their rate case. These items coupled with the seasonal nature of the Corporation's business required the use of short and long-term debt in 1993. To provide the short-term debt requirements the Corporation has $25,000,000 of committed lines from two banks which are used to support a money market facility of a similar amount. The Corporation also has $30,000,000 of uncommitted lines from three banks. The long-term debt requirements were funded through the issuance of two $5,000,000 Medium-Term Notes which mature in 1998 and bear interest rates of 5.77% and 5.78%. The Corporation also sold $24,000,000 of 20 year Medium-Term Notes in February 1993 at interest rates ranging from 7.95% to 8.01% to refund the 9.875% Debentures Due 2013 in the amount of $21,677,000.
On June 22, 1993, the Corporation sold 575,000 shares of common stock through a public offering at $26.125 per share. The net proceeds of $14,435,000 - 15 - were used to reduce short-term indebtedness. Effective December 20, 1993, the Corporation issued a three for two common stock split.
In November 1993, an additional $50,000,000 of Medium-Term notes were registered with the Securities and Exchange Commission.
In December, 1993, changes were implemented to the existing Dividend Reinvestment Plan to allow residential customers of the Corporation residing in Oregon and Washington to purchase stock through the Plan with an initial investment of $250. While there is no way of predicting the level of customer response, it is expected that this program will provide, at a lower cost, a new stream of equity capital to the Corporation to fund utility construction expenditures.
The Corporation has a capital budget for 1994 of $35,100,000 which will be funded through internal cash generation and the short and long-term debt facilities mentioned above.
Effects of Inflation
Changing prices have had a minimal impact on the Corporation's operating margins. The effects of price changes in purchased gas costs and the cost of transporting gas to the Corporation's system are passed onto customers in accordance with regulatory policy. Inflationary increases in wages and other operating expenses are generally recognized by the regulatory agencies in their rate decisions in general rate filings. Since the Corporation's last general rate adjustment in 1989, growth in the customer base has mitigated the negative effect of inflation on income from operations.
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Item 8
Item 8 - Financial Statements and Supplementary Data
The financial statements and supplementary data listed in the following index are filed as part of this report.
Index to Financial Statements and Supplementary Data
Page No.
Independent Auditors' Report on the Consolidated Financial Statements 18
Consolidated Financial Statements:
Statements of Net Earnings Available to Common Shareholders for the Years ended December 31, 1993, 1992 and 1991 19
Balance Sheets as of December 31, 1993 and 1992 20
Statements of Common Shareholders' Equity for the Years ended December 31, 1993, 1992 and 1991 22
Statements of Cash Flows for the Years ended December 31, 1993, 1992 and 1991 23
Notes to Consolidated Financial Statements for the three years ended December 31, 1993 24
Independent Auditors' Report on the Financial Statement Schedules 36
Financial Statement Schedules:
Schedule V - Utility Plant 37
Schedule VI - Accumulated Depreciation of Utility Plant 38
Schedule VIII - Valuation and Qualifying Accounts 39
Schedule IX - Short-Term Borrowings 40
Schedule X - Supplementary Income Statement Information 41
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Independent Auditor's Report
Board of Directors Cascade Natural Gas Corporation Seattle, Washington
We have audited the accompanying consolidated balance sheets of Cascade Natural Gas Corporation and subsidiaries (the Corporation) as of December 31, 1993 and 1992, and the related consolidated statements of net earnings available to common shareholders, common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Cascade Natural Gas Corpora- tion and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed in Notes 6 and 7 to the financial statements, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, and SFAS No. 106, Employers' Accounting for Postretirement Benefits other than Pensions, for the year ended December 31, 1993.
Deloitte & Touche Seattle, Washington February 1, 1994
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CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Statements of Net Earnings Available to Common Shareholders Years ended December 31, 1993, 1992, and 1991
See notes to consolidated financial statements
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CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
ASSETS
See notes to consolidated financial statements
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COMMON SHAREHOLDERS' EQUITY, PREFERRED STOCKS, AND LIABILITIES
See notes to consolidated financial statements
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CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
Consolidated Statements of Common Shareholders' Equity
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CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows Years ended December 31, 1993, 1992, and 1991
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Three Years Ended December 31, 1993
Note 1 - Summary of Significant Accounting Policies
Cascade Natural Gas Corporation and its subsidiaries (the Corporation) follow the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission and is subject to the jurisdiction of the Washington Utilities and Transportation Commission (WUTC) and the Oregon Public Utility Commission (OPUC). Substantially all of the Corporation's operations relate to the distribution of natural gas to retail customers.
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.; CGC Resources, Inc.; Fibre Graphics, Inc.; and Metrology One, Inc. All intercompany transactions have been eliminated in consolidation.
Utility plant:
Utility plant is stated at the historical cost of construction. These costs include payroll-related costs such as taxes and other employee benefits, general and administrative costs, and the estimated cost of funds used during construction. Maintenance and repairs of property, and replacements and renewals of items deemed to be less than units of property, are charged to operations. Units of utility plant retired or replaced are credited to property accounts at cost. Such amounts plus removal expense, less salvage, are charged to accumulated depreciation. In the case of a sale of land or major operating units, the resulting gain or loss on the sale is included in other income or expense.
Depreciation of utility plant is computed using the straight-line method. The asset lives used for computing depreciation range from five to 40 years, with a composite rate of approximately 3.5%.
Investments:
Investments consist primarily of real estate, classified as nonutility property carried at original cost less accumulated depreciation.
Notes receivable:
Notes receivable include loans made to customers for the purchase of energy efficient appliances, which are generally the security for the loan. Loans are made for a term of five years at interest rates varying from 8.5% to 12%.
Materials, supplies, and inventories:
Materials, supplies, and inventories include patented chart - 24 -
scanners held for resale which are recorded at the lower of cost (specific identification) or market. Inventories of gas and other materials and supplies are stated at the lower of average cost or market.
Deferred charges:
Deferred charges consist primarily of debt issuance costs, intangible assets related to minimum liability accruals on pension obligations (see Note 7), and deferrals of postretirement health care expenses (see Note 7). Debt issuance costs are amortized over the lives of the related issues. Redemption costs relating to refinanced debt are amortized over the life of the new debt issuance.
Revenue recognition:
The Corporation accrues estimated revenues for gas delivered but not billed to residential and commercial customers from the meter reading dates to month end.
Overrun penalty income is recognized when the Corporation has determined that significant penalties are known and measurable and reasonably enforceable. Due to the unusual and infrequent nature of significant overrun penalty income, the Corporation has elected to report this income separately on the statement of net earnings.
Gas cost changes:
Gas cost changes consist primarily of the effect of decreases in purchased gas costs which have not yet been reflected in rates charged to customers. The effect of changes that are not tracked on a concurrent basis are deferred and amortized over a future period through a temporary rate change schedule. Amortization periods are subject to the approval of the regulatory agencies and are generally one to two years.
Federal income taxes:
The Corporation deducts depreciation computed on an accelerated basis for federal income tax purposes and, as a result, deductions exceed the amounts included in the financial statements.
In 1981 the Corporation elected to record depreciation on 1981 and subsequent utility plant additions under the Accelerated Cost Recovery System. This election required the Corporation to provide deferred income taxes on the difference between depreciation computed for financial statement and tax reporting purposes beginning in 1981 (see Note 6). This procedure has been accepted by the WUTC and the OPUC.
It is expected that any future increases in federal income taxes resulting from the reversal of accelerated depreciation on additions to utility plant in 1980 and prior will be allowed in future rate determinations.
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Investment tax credits:
Investment tax credits were deferred and are amortized over the life of the property giving rise to the credit.
Statements of cash flows:
For purposes of the statements of cash flows, the Corporation considers all investments with a purchased maturity of approximately three months or less to be cash equivalents.
Reclassifications:
Certain reclassifications have been made in the 1992 financial statements to conform to the classifications used in 1993.
Note 2 - Redeemable Preferred Stocks
The Corporation must retire annually 42,948 shares of Senior preferred stock through November 1, 1995, with further reductions as individual series are fully retired. The shares may be purchased on the open market or redeemed at $10 per share plus accrued dividends.
The 7.85% cumulative preferred stock may not be redeemed until maturity on November 1, 1999.
The aggregate preferred stock redemption requirements based upon the aforementioned redemption prices are: $284,000 in 1994, $425,000 in 1995, and $250,000 in 1996, 1997, and 1998. The Corporation may, at its option, purchase the required number of shares on the open market at less than the redemption price.
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 and all restrictive provisions of the long-term indebtedness agreements have been satisfied.
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Note 3 - Common Stock
At December 31, 1993, shares of common stock are reserved for issuance as follows:
Effective December 20, 1993, the Corporation issued 2,854,656 shares of common stock in a three for two stock split. For the calculations of earnings per share of common stock, the average number of shares outstanding has been recalculated to reflect the effect of this split.
Note 4 - Notes Payable
At December 31, 1993, the Corporation had two committed lines of credit available, one of $20,000,000 and one of $5,000,000. These agreements expire in 1996 and 1994, respectively, and provide for a commitment fee of .2% and .15%, respectively. The committed lines are used as backup support for an uncommitted facility of $25,000,000, of which $13,502,000 was outstanding at December 31, 1993. In addition, the Corporation has uncommitted lines of credit available of $10,000,000 each from three banks.
The average daily amount outstanding under these arrangements during 1993 was approximately $11,696,000 with a maximum month end borrowing of $22,752,000. The effective weighted average interest rate (excluding commitment fees) based upon daily amounts outstanding was 3.66%.
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Note 5 - Long-term Debt
Long-term debt consists of the following:
None of the long-term debt includes current maturities or sinking fund requirements. The 9-7/8% debentures were called for redemption on March 1, 1993.
Various debt and credit agreements restrict the Corporation and its subsidiaries as to indebtedness, payment of cash dividends on common stock, and other matters. Under these restrictions, approximately $25,718,000 is available for payment of dividends as of December 31, 1993.
During 1992, the Corporation entered into an interest rate swap agreement, which expires on December 1, 1995, that effectively converts its 9.46% $5,000,000 promissory note into a variable rate obligation. Under the terms of this agreement, the Corporation makes payments at a floating rate which is based on LIBOR and receives payments at a fixed rate. The net interest paid or received is included in interest expense.
Note 6 - Income Taxes
The Corporation adopted Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, effective January 1, 1993. This Statement supersedes Accounting Principles Board (APB) Opinion No. 11 and SFAS No. 96, the latter of which was never adopted by the Corporation. The cumulative effect of adopting SFAS No. 109 on the Corporation's financial statements was to increase net earnings by $209,000 ($.03 per share) in the first quarter of 1993.
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Under the provisions of SFAS No. 109, the Corporation was required to record 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 Corporation was required to adjust 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 had no effect on net earnings.
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The provision for income tax expense consists of the following:
During the third quarter of 1993, the Revenue Reconciliation Act of 1993 was enacted. This Act increased the maximum federal income tax rate applicable to corporations from 34% to 35%. The provision for deferred income taxes includes a charge of $44,000 ($.01 per share) as a result of recalculating certain deferred tax balances at the new tax rate. A reconciliation between income taxes calculated at the statutory federal tax rate and income taxes reflected in the financial statements is as follows:
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 - 30 -
tax purposes. The tax effects of significant items comprising the Corporation's net deferred tax liability are as follows:
(dollars in thousands)
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Note 7 - Retirement Plans
The Corporation'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 Corporation's policy is generally to fund the plan to the extent allowable under Internal Revenue Service rules.
The Corporation provides executive officers with supplemental retirement, death, and disability benefits. Under the plan, vesting occurs on the first day of the year after the executive has reached age 55 and has completed five years of participation under the plan, or upon death. The plan supplements the benefit received through Social Security and the defined benefit pension plan so that the total retirement benefits equal 70% of the executive's highest salary during any of the five years preceding retirement.
To fund the plan, the Corporation has insured the lives of the executives.
The following table sets forth the funded status of the defined benefit pension and supplemental retirement plans and amounts recognized in the Corporation's financial statements:
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Net pension cost for both plans included the following components:
The actuarial present value of accumulated plan benefits for the pension plan at December 31, 1993, reflects an amendment effective April 1, 1993, which increases benefits applicable to compensation earned since January 1, 1990. The actuarial present value of accumulated plan benefits for both plans at December 31, 1993, reflect reductions in the discount rate and in the assumed rate of increase in future compensation levels. The combination of these changes increased the projected benefit obligation of the pension plan and supplemental retirement plan by $2,200,000 and $134,000, respectively, at December 31, 1993.
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The following assumptions were used to determine the projected benefit obligation and expected return on assets at December 31:
The Corporation 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 401(k) plan. Under the terms of the 401(k) plan, the Corporation will match each employee's contribution to the 401(k) plan at a rate of 50% of the employee's contribution up to 6% of the employee's compensation as defined. The Corporation recognized costs for contributions to this plan of $370,000, $217,000, and $138,000 for 1993, 1992, and 1991, respectively.
Effective January 1, 1993, the Corporation adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits other than Pensions. SFAS No. 106 requires the Corporation to accrue the estimated cost of future retiree benefit payments during the years the employee provides services. The Corporation previously recorded the cost of these benefits, which are principally health care, as benefit payments were incurred. SFAS No. 106 allows recognition of the cumulative effect of the liability in the year of the adoption, or the accrual of the obligation over a period of up to 20 years. The Corporation has elected to recognize this obligation of approximately $13,100,000 over a period of 20 years.
The accrual of postretirement benefits other than pensions (PBOP) for the year was $2,272,000. The accruals exceeded payments of these benefits during the period by $1,938,000. As allowed by the policy of the WUTC, $1,523,000 has been deferred, and included in deferred charges. Management expects that these and prospective deferral amounts will be recovered in the future through rates charged to customers. The remaining $415,000 is subject to the jurisdiction of the OPUC. In accordance with OPUC policy, $309,000 has been charged to operating expenses and $106,000 to construction. Implementation of this Standard has resulted in a charge to net earnings available to common shareholders of $202,000 ($.03 per share).
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The Corporation's health care plan provides benefits for substantially all of its retired employees hired prior to June 1, 1992, and their eligible dependents. In 1992 and 1991, the Corporation recognized $239,000 and $209,000, respectively, as an expense for postretirement health care benefits. Net postretirement health care benefit cost for 1993 consisted of the following components:
The Corporation's policy is generally to fund the plan to the extent allowable under Internal Revenue Service rules. The following table sets forth the health care plan's funded status:
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation is 11.5% for 1994, trending down to 6% at 2010. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.5%. A one percentage point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation by approximately 17% and the service and interest cost components of net postretirement health care cost by approximately 18%.
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Note 8 - Gas Service Contracts
The Corporation has entered into various transportation, supply, storage, and peaking service contracts to assure that adequate supplies of gas will be available to provide firm service to its core customers and to meet its obligations under long-term non-core customer agreements. These contracts, which have maturities ranging from one to 30 years, provide that the Corporation must pay a fixed demand charge each month.
One gas supply contract requires the Corporation to take 10,037,500 therms annually or the seller can reduce its commitment to provide that minimum amount. Two other gas supply contracts, which expire in 1995, require that the Corporation take 100% of all tendered gas volumes during the remaining life of the agreements. These requirements are for 105,605,450 therms in 1994 and 87,956,320 therms in 1995. Another contract has a 42% take requirement, equaling an obligation of 41,475,315 therms per year through 2004. Lastly, a 15-year contract for winter-only (October through March) supply has a 70% minimum take requirement, which equates to a purchase requirement of 9,868,688 therms per year.
The remaining gas supply contracts do not require the Corporation to take any gas, but the various suppliers are obligated to provide up to a maximum of 80,300,000 therms annually. The Corporation's minimum obligations under these contracts are set forth in the following table. The amounts are based on current contract prices, which are subject to change.
Purchases under these contracts for 1991, 1992, and 1993, including commodity purchases, as well as demand charges have been as follows:
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Note 9 - Contingencies
The Corporation was notified by the Department of Ecology of the State of Washington that it is a "potentially liable person" as a result of contamination in the area of the Corporation's underground storage tanks at its Sunnyside, Washington office. The Corporation has provided $455,000 to date for the estimated costs of the cleanup. The Corporation believes that the remaining reserves of $181,000 are adequate to complete the remediation.
Various lawsuits, claims, and contingent liabilities may arise from time to time from the conduct of the Corporation's business. None of those now pending, in the opinion of management, is expected to have a material effect on the Corporation's financial position or results of operations.
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Note 10 - Fair Value of Financial Instruments
The following estimated fair value amounts have been determined by the Corporation, using available market information and appropriate valuation methodologies. However, considerable judgment is necessarily required in interpreting market data to develop the estimates of fair value. Accordingly, these estimates are not necessarily indicative of the amounts that the Corporation could realize in a current market exchange. Thus, the use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
The estimated fair value amounts of financial instruments at December 31, 1993, are as follows:
Cash and cash equivalents, accounts receivable, and notes payable: The carrying amounts of these items are a reasonable estimate of their fair value.
Notes receivable, redeemable preferred stock, and long-term debt: Interest rates that are currently available to the Corporation for issuance of instruments with similar terms and remaining maturities are used to estimate fair value.
Temporary investments: Fair values are based on quoted market prices.
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Note 11 - Interim Results of Operations (unaudited)
Earnings (loss) per share have been restated for the effect of the three for two stock split in December 1993.
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INDEPENDENT AUDITOR'S REPORT
Cascade Natural Gas Corporation and Subsidiaries
We have audited the consolidated financial statements of Cascade Natural Gas Corporation and subsidiaries as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993, and have issued our report thereon dated February 1, 1994; such consolidated financial statements and report are included in Part II of this Annual Report on Form 10-K. Our audits also included the financial statement schedules of Cascade Natural Gas Corporation, listed in Item 14(a)2. These financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information shown therein.
DELOITTE & TOUCHE Seattle, Washington February 1, 1994
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SCHEDULE V
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
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SCHEDULE VI
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
NOTE: Additions charged to other accounts as follows:
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SCHEDULE VIII
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
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SCHEDULE IX
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
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SCHEDULE X
CASCADE NATURAL GAS CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INCOME STATEMENT INFORMATION (Thousands of Dollars)
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Item 9
Item 9 - Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
PART III
Item 10
Item 10 - Directors and Executive Officers of the Registrant
See the information regarding directors under the caption "Election of Directors" on pages 1 through 3 of the Proxy Statement issued to Shareholders for the 1994 Annual Meeting (the 1994 Proxy Statement), which information is incorporated herein by reference. Certain information concerning the executive officers of the Company is set forth in Part I under the caption "Executive Officers of the Registrant."
Item 11
Item 11 - Executive Compensation
See the information regarding excutive compensation set forth in the 1994 Proxy Statement, under the caption "Report of Nominating and Compensation Committee to the Shareholders" on page 5, under "Executive Compensation "on pages 7 and 8 and under "Compensation Committee Interlocks and Insider Participation" on page 9, which information is incorporated herein by reference.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
See the information on security ownership of certain beneficial owners and management under the caption "Security Ownership of Certain Beneficial Owners and Management" on page 4 of the 1994 Proxy Statement, which information is incorporated herein by reference.
Item 13
Item 13 - Certain Relationships and Related Transactions
See the information on certain relationships and transactions under the caption "Compensation Committee Interlocks and Insider Participation" on page 9 of the Proxy Statement, which information is incorporated herein by reference.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. and 2. For a list of the financial statements and financial statement schedules filed herewith, see the index to financial statements and supplementary data in Item 8 of this report.
(a) 3. For a list of the exhibits filed herewith, see the index to exhibits following the signature pages 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.
No reports on Form 8-K were filed for the quarter ended December 31, 1993.
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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
March 25, 1994 By /s/ Donald E. Bennett
Date Donald E. Bennett Executive Vice President, Chief Financial Officer, Secretary and Director
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.
Signature Title Date
Chairman of the Board, Chief Executive Officer /s/ Melvin C. Clapp and Director March 25, 1994 Melvin C. Clapp
/s/ W. Brian Matsuyama President and Director March 25, 1994 W. Brian Matsuyama
Executive Vice President, Chief Financial Officer, /s/ Donald E. Bennett Secretary and Director March 25, 1994 Donald E. Bennett
Treasurer and Chief /s/ James E. Haug Accounting Officer March 25, 1994 James E. Haug
/s/ Carl Burnham, Jr. Director March 25, 1994 Carl Burnham, Jr.
/s/ David A. Ederer Director March 25, 1994 David A. Ederer
/s/ Howard L. Hubbard Director March 25, 1994 Howard L. Hubbard
/s/ Brooks G. Ragen Director March 25, 1994 Brooks G. Ragen
/s/ Andrew V. Smith Director March 25, 1994 Andrew V. Smith
/s/ Mary A. Williams Director March 25, 1994 Mary A. Williams - 47 -
INDEX TO EXHIBITS
Exhibit No. Description
3.1 Restated Articles of Incorporation of the Registrant as amended on January 5, 1993, and May 10, 1993. Incorporated by reference to Exhibit 4 to the Registrant's current report on Form 8-K dated June 2, 1993.
3.2 Restated Bylaws of the Registrant. Incorporated by reference to Exhibit 3-(2) to the Registrant's annual report on Form 10-K for the year ended December 31, 1990.
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(c) 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 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 Distribution Agreement dated December 6, 1993, among the Registrant and Smith Barney Shearson Inc. and Merrill Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated. Incorporated by reference to Exhibit 1 to the Registrant's registration statement Form S-3, No. 33-71286.
10.2 Service Agreement (Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant.
10.3 Service agreement (assigned Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant.
10.4 Service Agreement (Liquefaction -- Storage Gas Service under Rate Schedule SGS-1) dated January 12, 1994, between Northwest Pipeline Corporation and the Registrant.
10.5 Gas Purchase Agreement dated November 1, 1990, between Mobil Oil Canada and the Registrant. Incorporated by reference to Exhibit 10-6 to the 1991 Form 10-K.
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10.6 Amendment to Gas Purchase Agreement dated August 30, 1991, between Mobil Oil Canada and the Registrant. Incorporated by reference to Exhibit 10(h)(2) to the 1992 Form S-2, No. 33-52672 (the 1992 Form S- 2).
10.7 Amendment to Natural Gas Purchase Agreement dated September 1, 1993, between Canadian Hydrocarbons Marketing Inc., and the Registrant. Incorporated by reference to Exhibit 10.1 to amendment no. 1 to the Registrant's quarterly report on Form 10-Q/A for the quarter ended September 30, 1993.
10.8 Natural Gas Sales Agreement dated November 1, 1990, as supplemented by letter dated August 27, 1992, between Canadian Hydrocarbons Marketing Inc. and the Registrant. Incorporated by reference to Exhibit 10(k) to the 1992 Form S-2.
10.9 Long Term Gas Sales Agreement dated August 26, 1993, between Canadian Hydrocarbons Marketing Inc., and the Registrant. Incorporated by reference to Exhibit 10.2 to amendment no. 1 to the Registrant's quarterly report on Form 10-Q/A for the quarter ended September 30, 1993.
10.10 Gas Sale Agreement dated November 1, 1993, between Mobil Natural Gas Inc. and the Registrant.
10.11 Agreement for Sale and Purchase of Gas dated November 1, 1993, as amended by Letter Amendment dated December 8, 1993, between Mobil Natural Gas, Inc., and the Registrant.
10.12 Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(1) to the 1992 Form S-2.
10.12.1 Amendments dated August 20, 1992, November 1, 1992, October 20, 1993, and December 17, 1993, to Replacement Firm Transportation Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant.
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.
10.15 Amendment to Transportation Agreement dated August 20, 1992, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(w) to the 1992 Form S-2.
10.16 Assignment and Amendment of Gas Purchase Contract dated September 30, 1991 (effective November 1, 1992) among Northwest Pipeline Corporation, West Coast Energy Inc., West Coast Energy Marketing Ltd., Canadian Hydrocarbons Marketing Inc., and the Registrant, amending Kingsgate Gas Sales Agreement ("Kingsgate Gas Sales Agreement") dated September 23, 1960, as amended by Letter Agreement dated August 15, 1989, between
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Northwest Pipeline Corporation and West Coast Energy Inc. Incorporated by reference to Exhibit 10(s) to the 1992 Form S-2.
10.16.1 Interim Pricing Arrangement dated November 4, 1993 between Canadian Hydrocarbons Marketing, Inc. and the Registrant relating to the Kingsgate Gas Sales Agreement.
10.17 Clay Basin Inventory Sales Agreement dated July 31, 1991, between Northwest Pipeline Corporation and the Registrant. Incorporated by reference to Exhibit 10(t) to the 1992 Form S-2.
10.18 Storage Agreement dated July 23, 1991, between Washington Water Power Company and the Registrant. Incorporated by reference to Exhibit 10(v) to the 1992 Form S-2.
10.19 Service Agreement (Firm Redelivery Transportation Agreement under Rate Schedule TF-2 for Cascade's SGS-1) dated January 12, 1994, between Northwest Pipeline Company and the Registrant.
10.20 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 Company and the Registrant.
10.21 Service Agreement (Firm Redelivery Transportation Agreement under rate Schedule TF-2 for Cascade's LS-1) dated January 12, 1994, between Northwest Pipeline Company and the Registrant.
10.22 1991 Director Stock Award Plan of the Registrant.* Incorporated by reference to Exhibit 10(n) to the 1992 Form S-2.
10.23 Executive Supplemental Income Retirement Plan of the Registrant and Supplemental Benefit Trust as amended and restated as of May 1, 1989, as amended by Amendment No. 1 dated July 1, 1991.* Incorporated by reference to Exhibit 10(o) to the 1992 Form S-2.
10.24 Employment agreement between the Registrant and W. Brian Matsuyama.* Incorporated by reference to Exhibit 10(p) to the 1992 Form S-2.
10.25 Employment agreement between the Registrant and Jon T. Stoltz.* Incorporated by reference to Exhibit 10(q) to the 1992 Form S-2.
10.26 Employment agreement between the Registrant and Ralph E. Boyd.* Incorporated by reference to Exhibit 10(r) to the 1992 Form S-2.
12. Computation of Ratio of Earnings to Fixed Charges.
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 to the incorporation of their report in the Registrant's registration statements.
* Management contract or compensatory plan or arrangement.
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