Item 1. Business.
INTRODUCTION
Colorado is a Delaware corporation organized in 1927. All of Colorado's outstanding common stock is owned by Coastal Natural Gas, which is a wholly owned subsidiary of Coastal. Colorado owns and operates an interstate natural gas pipeline system and also has gas and oil exploration and production operations. At December 31, 1998, the Company had 811 employees.
Selected financial information of the Company by industry segment is set forth in Note 11 of Notes to Consolidated Financial Statements included herein.
NATURAL GAS SYSTEM
OPERATIONS
General
The Company is involved in the production, purchase, gathering, processing, transportation, storage and sale of natural gas. Colorado's gas transmission system extends from gas production areas in the Texas Panhandle, western Oklahoma and western Kansas, northwesterly through eastern Colorado to the Denver area, and from production areas in Montana, Wyoming and Utah, southeasterly to the Denver area. The Company's gas gathering and processing facilities are located throughout the production areas adjacent to its transmission system. Most of the Company's gathering facilities connect directly to its transmission system, but some gathering systems are connected to other pipelines. Colorado owns four underground gas storage fields - three located in Colorado and one in Kansas.
PSCo and Pioneer were the only customers accounting for revenue that equaled or exceeded 10% of the Company's consolidated revenues for the year 1998. PSCo was the only customer that accounted for more than 10% of the Company's consolidated revenues in 1997 and 1996. In 1998, the Company completed construction of the 53-mile Front Range Pipeline. This pipeline, which is to be owned by an entity jointly owned by affiliates of the Company and the Company's largest customer, PSCo, can transport up to 256 MMcf per day to accommodate regional market growth.
The Company's principal transmission and storage pipeline facilities, including certain facilities in the Panhandle Field of Texas ("Panhandle Field"), at December 31, 1998 consisted of 4,351 miles of pipeline and 58 compressor stations with approximately 296,300 installed horsepower. At December 31, 1998, the design peak day gas delivery capacity of the transmission system was approximately 2.2 Bcf per day. The underground gas storage facilities have a working capacity of approximately 29 Bcf and a peak day delivery capacity of approximately 775 MMcf.
Colorado's gathering facilities, excluding certain FERC regulated facilities in the Panhandle Field, consist of 2,372 miles of gathering lines and approximately 50,700 horsepower of compression. Colorado owned and operated five gas processing plants in 1998. These plants, with a total operating capacity of approximately 512 MMcf daily, recover mainly propane, butanes, natural gasoline, sulfur and other by-products, which are sold to refineries, chemical plants and other customers.
Gas Sales, Storage and Transportation
Colorado's gas sales consist primarily of Company-owned production. Effective July 1, 1998, those gas purchases and sales formerly conducted by the Company's unincorporated Merchant Division were assigned to an affiliate. Therefore, revenues and cost of gas sold associated with such activities subsequent to June 30, 1998 are not included
in the Company's consolidated financial statements. Additionally, Colorado engages in "open access" storage and transportation of gas owned by third parties.
Pursuant to an operating agreement with an affiliate, the Company operates the Young Gas Storage Field located in northeastern Colorado. The field has a working gas storage capacity of 5.3 Bcf, with a peak day delivery capacity of approximately 200 MMcf per day. Such capacity is fully subscribed under 30-year contracts.
Colorado's deliveries for the years 1998, 1997 and 1996 were as follows:
Total System Daily Average Year Deliveries System Deliveries ---- ------------ ----------------- (Bcf) (MMcf)
1998 480 1,315 1997 486 1,333 1996 475 1,298
Gas Gathering and Processing
Colorado provides gathering and processing services on an "unbundled" or stand-alone basis. The Company's processing terms are not regulated by the FERC, but Colorado is required to provide "open access" to its regulated processing facilities. The gathering that Colorado provides in the Panhandle Field continues to be regulated by the FERC, and the Company is limited to charging rates between minimum and maximum levels approved by the FERC. The gathering (and processing) that Colorado's subsidiary, CIGFS, provides is not regulated by the FERC.
The gas processing plants recovered approximately 46 million gallons of liquid hydrocarbons in 1998 compared to 55 million gallons in 1997, and 66 million gallons in 1996, as well as 300 long tons of sulfur in 1998, compared to 500 long tons in 1997 and 3,100 long tons in 1996. Additionally, Colorado processed approximately 25 million gallons of liquid hydrocarbons owned by others in 1998 compared to 24 million gallons in 1997 and 6 million gallons in 1996.
The Company operates two helium processing facilities, one located in eastern Colorado and the other in the western Oklahoma panhandle area. These helium facilities are partially owned by Company affiliates. The Company also operates two gas processing plants for affiliates.
Competition
Natural gas competes with other forms of energy available to customers, primarily on the basis of price paid by end users. These competitive forms of energy include electricity, coal, propane and fuel oils. Changes in the availability or price of natural gas or other forms of energy, as well as changes in business conditions, conservation, legislation or governmental regulations, capability to convert to alternate fuels, changes in rate structure, taxes and other factors may affect the demand for natural gas in the areas served by Colorado.
In recent years the FERC has issued orders which have resulted in more competition within the natural gas industry. This competition has intensified resulting in more rate competition among pipelines in order to increase and maintain market share and maximize capacity utilization. The Company's transportation and storage services are influenced by its customers' access to alternative service providers and the price of such services. The FERC's orders have also resulted in competition between the Company and its customers by allowing the customers to resell their unused capacity. Additionally, the Company competes with interstate and intrastate pipeline companies in the sale, transportation and storage of natural gas and with independent producers, brokers, marketers, and other pipelines in the gathering, processing and sale of gas within its service area.
GAS SYSTEM RESERVES
Reserves
The table below represents estimates of the Company's owned or controlled reserves as of December 31, 1998, 1997 and 1996, as prepared by Huddleston, Colorado's independent engineers.
The estimates of owned or controlled gas reserves include quantities economically recoverable over the productive life of existing wells and quantities estimated to be recoverable in the future, either from completions in other productive zones of existing wells or from additional wells to be drilled in proven reservoirs currently controlled by Colorado. The independent engineers' estimates of reserves are based upon new analyses or upon a review of earlier analyses updated by production and field performance. The reserve volumes reported represent those retained by Colorado as well as those assigned to a subsidiary.
At December 31, 1998, Colorado maintained under its own account 3.5 Bcf of natural gas in underground storage fields for system balancing. The Company has an additional 37.8 Bcf of base gas in its four owned storage fields. These amounts reflect actual balances at December 31, 1998, and vary slightly from the Huddleston report which includes estimates for November and December 1998.
Reserves Dedicated to a Particular Customer
Colorado is committed to sell gas to Pioneer, a customer, under a 1928 agreement, as amended, from specific owned gas reserves in the West Panhandle Field of Texas. Under an amendment which became effective January 1, 1991, a cumulative 23% of the total net production may be taken for customers other than Pioneer.
REGULATIONS AFFECTING GAS SYSTEM
General
Under the NGA, the FERC has jurisdiction over Colorado as to rates and charges for the transportation and storage of natural gas, the construction of new facilities, extension or abandonment of service and facilities, accounts and records, depreciation and amortization policies and certain other matters. In addition, the FERC has certificate authority over gas sales for resale in interstate commerce, but under Order 636, has determined that it will not regulate sales rates. Additionally, the FERC has asserted rate-regulation (but not certificate regulation) over gathering services provided by interstate pipeline companies such as Colorado.
Colorado is also subject to regulation with respect to safety requirements in the design, construction, operation and maintenance of its interstate gas transmission and storage facilities by the Department of Transportation. Additionally, the Company is subject to similar safety requirements from the Department of Labor's Occupational Safety and Health Administration related to its processing plants. Operations on United States government land are regulated by the Department of the Interior. The Company is also subject to laws and regulations associated with environmental matters as discussed on Page 6.
Rate Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for Comments" ("Policy"). Under this Policy, (i) a pipeline and a customer are allowed to negotiate a contract which provides for rates and charges that exceed the pipeline's posted maximum tariff rates, provided that the customer agreeing to such negotiated rates has the ability to elect to receive service at the pipeline's posted maximum rate (known as a "recourse rate"), and (ii) a pipeline must also make subsequent tariff filings each time the pipeline negotiates a rate for service which is outside of the minimum
and maximum range for the pipeline's cost-based recourse rates. To implement this Policy, a pipeline must make an initial tariff filing with the FERC to indicate that it intends to contract for services under this Policy. Colorado has received FERC authority to enter into negotiated rate transactions. Separately, the FERC has determined that pipelines who seek to include negotiated rate transactions in the discount adjustment used to calculate their rates must file tariff sheets demonstrating that existing customers who purchase service under the pipeline's cost-of-service rates will not be harmed by negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in which the FERC has proposed a number of further significant changes to the industry, including, among other things, removal of price caps in the short-term market (less than one year), capacity auctions, changed reporting obligations, the ability to negotiate terms and conditions of all services, elimination of the requirement of a matching term cap on the renewal of existing contracts, and a review of its policies for approving capacity construction. On the same day, the FERC also issued a "Notice of Inquiry" soliciting industry input on various matters affecting the pricing of long-term service and certificate pricing in light of changing market conditions. The due date for comments on both of these matters has been rescheduled twice and is currently scheduled for April 22, 1999. The FERC has indicated that it may consider both proposals together inasmuch as they raise several common issues.
Certain regulatory issues remain unresolved among the Company, its customers, its suppliers and the FERC. The Company has made provisions which represent management's assessment of the ultimate resolution of these issues. As a result, the Company anticipates that these regulatory matters will not have a material adverse effect on its consolidated financial position or results of operations. While the Company estimates the provisions to be adequate to cover potential adverse rulings on these and other issues, it cannot estimate when each of these issues will be resolved.
GAS AND OIL EXPLORATION AND PRODUCTION
The Company has domestic gas and oil production operations. The gas is delivered primarily to Colorado's interstate gas pipeline system while the crude oil and condensate are sold at the wellhead to oil purchasing companies at prevailing market prices. The production of gas and oil is subject to regulation in states in which the Company operates.
The following table shows gas and oil, condensate and natural gas liquids production volumes of the Company, including quantities attributable to its natural gas system, for the three years ended December 31, 1998:
The following table summarizes sales price and unit cost information of the Company's exploration and production operations for the three years ended December 31, 1998:
Acreage held under gas and oil mineral leases as of December 31, 1998 is summarized as follows:
The net developed acreage is concentrated principally in Texas (84%), Oklahoma (6%), Utah (6%) and Wyoming (3%). The net undeveloped acreage is principally in Wyoming (56%) and Utah (43%).
Information on wells drilled in the three years ended December 31, 1998, is summarized as follows:
Productive wells as of December 31, 1998 are as follows:
Information on Company-owned reserves of oil and gas is included herein under "Supplemental Information on Oil and Gas Producing Activities (Unaudited)" in Item 14(a)1 included herein.
The Company competes with major integrated oil companies and independent oil and gas companies for suitable prospects for oil and gas drilling operations. The availability of a ready market for gas discovered and produced depends on numerous factors frequently beyond the Company's control. These factors include the extent of gas discovery and production by other producers, crude oil imports, the marketing of competitive fuels, and the proximity, availability and capacity of gas pipelines and other facilities for the transportation and marketing of gas. The production and sale of oil and gas is subject to a variety of federal and state regulations, including regulation of production levels.
ENVIRONMENTAL
The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction, operation, and maintenance of its pipeline and production facilities. Compliance with such laws and regulations can be costly. Additionally, governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital projects and anticipates capital expenditures of $1 to $2 million in 1999 in order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement developments, will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's consolidated financial position or results of operations.
Item 2.
Item 2. Properties.
Information on properties of Colorado is included in Item 1, "Business," included herein.
The real property owned by the Company in fee consists principally of sites for compressor and metering stations and microwave and terminal facilities. With respect to the four owned storage fields, the Company holds title to gas storage rights representing ownership of, or has long-term leases on, various subsurface strata and surface rights and also holds certain additional mineral rights. Under the NGA, the Company may acquire by the exercise of the right of eminent domain, through proceedings in U.S. District Courts or in state courts, necessary rights-of-way to construct, operate and maintain pipelines and necessary land or other property for compressor and other stations and equipment necessary to the operation of pipelines.
Item 3.
Item 3. Legal Proceedings.
In December 1992, certain of Colorado's natural gas lessors in the West Panhandle Field filed a complaint in the U.S. District Court for the Northern District of Texas, claiming underpayment of royalties, breach of fiduciary duty, fraud and negligent misrepresentation. Management believes that Colorado has numerous defenses to the lessors' claims, including (i) that the royalties were properly paid, (ii) that the majority of the claims were released by written agreement and (iii) that the majority of the claims are barred by the statute of limitations. In March of 1995, the trial court granted a partial summary judgment in favor of Colorado, holding that the four-year statute of limitations had not been tolled, that the releases are valid, and dismissing all tort claims and claims for breach of any duty of disclosure. The remaining claim for underpayment of royalties was tried to a jury which, in May 1995, made findings favorable to Colorado. On June 7, 1995, the trial court entered a judgment that the lessors recover no monetary damages from Colorado and permanently estopping the lessors from asserting any claim based on an interpretation of the contract different than that asserted by Colorado in the litigation. The lessors' motion for a new trial was denied on July 18, 1997, and both parties filed appeals. On June 7, 1996, the same plaintiffs sued Colorado in state court in Amarillo, Texas, for underpayment of royalties. Colorado removed the second lawsuit to federal court which granted a stay of the second suit pending the outcome of the first lawsuit. Oral arguments were heard before the Fifth Circuit Court of Appeals on December 4, 1998 and the parties are awaiting the Court's decision.
In 1996, Jack Grynberg filed a claim under the False Claims Act on behalf of the U.S. government in the U.S. District Court, District of Columbia, against 70 defendants, including Colorado and another subsidiary of Coastal. The suit sought damages for the alleged underpayment of royalties due to the purported improper measurement of gas. The 1996 suit was dismissed without prejudice in March 1997 and the dismissal was affirmed by the D.C. Court of Appeals in October 1998. In September 1997, Mr. Grynberg filed 77 separate, similar False Claims Act suits against natural gas transmission companies and producers, gatherers, and processors of natural gas, seeking unspecified damages. Colorado, Coastal and several other Coastal subsidiaries have been included in two of the September 1997 suits. The suits were filed in both the U.S. District Court, District of Colorado and the U.S. District Court, Eastern District of Michigan. The United States Department of Justice has notified the Company that it is reviewing these lawsuits to determine whether or not the United States will intervene.
Other lawsuits and other proceedings which have arisen in the ordinary course of business are pending or threatened against the Company or its subsidiaries.
Although no assurances can be given and no determination can be made at this time as to the outcome of any particular lawsuit or proceeding, the Company believes there are meritorious defenses to substantially all such claims and that any liability which may finally be determined should not have a material adverse effect on the Company's consolidated financial position or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
PART II
Item 5.
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.
All common stock of Colorado is owned by Coastal Natural Gas. At December 31, 1998, there were no restrictions on retained earnings as to its availability for dividends on common stock. Additional information relating to dividends is set forth under the "Statement of Consolidated Retained Earnings and Additional Paid-In Capital" included herein.
Item 6.
Item 6. Selected Financial Data.
The following selected financial data (in thousands of dollars) is derived from the Consolidated Financial Statements included herein and Item 6 of the Company's Annual Report on Form 10-K for the year ended December 31, 1997, as adjusted for minor reclassifications. The Notes to Consolidated Financial Statements included herein contain information relating to this data.
All of the outstanding common stock of Colorado is owned by Coastal Natural Gas; therefore, earnings and cash dividends per common share have no significance and are not presented.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
The Management's Discussion and Analysis of Financial Condition and Results of Operations is presented on pages through herein.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
For the information required by this item, see discussion under Management's Discussion and Analysis of Financial Condition and Results of Operations, which is presented on page.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The Financial Statements and Supplementary Data required hereunder are included in this Annual Report as set forth in Item 14(a) herein.
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.
The directors and executive officers of Colorado as of March 10, 1999, were as follows:
Name (Age), Year First Elected Positions and Offices Director and/or Officer with the Registrant ---------------------------------- --------------------------
Jon R. Whitney (54), 1987 and 1974 President, Chief Executive Officer and Director Jeffrey A. Connelly (52), 1996 Director David A. Arledge (54), 1981 Director Harold Burrow (84), 1974 Director C. Scott Hobbs (45), 1985 Executive Vice President, Chief Operating Officer and Director Daniel F. Collins (57), 1986 Senior Vice President Donald H. Gullquist (55),1994 Senior Vice President Rebecca H. Noecker (47), 1988 Senior Vice President and General Counsel Austin M. O'Toole (63), 1984 Senior Vice President and Secretary Richard G. Smead (52), 1988 Senior Vice President Donald J. Zinko (54), 1988 Senior Vice President Thomas E. Jackson, Jr. (59), 1989 Vice President Jeffrey B. Levos (38), 1997 Vice President Ronald D. Matthews (51), 1994 Vice President and Treasurer Thomas L. Price (43), 1997 Vice President Robert O. Reid (52), 1985 Vice President William H. Sparger (56), 1992 Vice President Dan A. Homec (50), 1989 Assistant Vice President and Controller
The above named persons bear no family relationship to each other. Their respective terms of office expire coincident with Colorado's Annual Meeting of the Sole Stockholder and Annual Meeting of the Board of Directors to be held in May 1999. Each of the directors or officers named above have been directors or officers of Colorado, ANR Pipeline and/or Coastal or subsidiaries thereof for five years or more except for the following:
Mr. Gullquist was elected Senior Vice President of Colorado in October 1994. From 1988 to 1989 he served as Vice President, Finance at Enron Corporation; from 1989 to 1990 he served as president of Enron Finance Corporation.
Mr. Levos was elected Vice President of Colorado in May 1997 and Vice President and Controller of Coastal in March 1997. He has served as Vice President of Coastal States Management Corporation, a subsidiary of Coastal, since December 1995 and also served as General Auditor since July 1994. Prior thereto, he was a Certified Public Accountant with the Houston office of Deloitte & Touche LLP since January 1986.
Mr. Price was elected as Vice President of Colorado in March 1997. He joined Colorado in 1980 and has held positions in the Design and Evaluation and Planning and Evaluation departments. He has served as Assistant Vice President of Transmission and Storage since 1994.
Item 11.
Item 11. Executive Compensation.
The information called for by this item is omitted pursuant to General Instruction (I) of Form 10-K.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
The information called for by this item is omitted pursuant to General Instruction (I) of Form 10-K.
Item 13.
Item 13. Certain Relationships and Related Transactions.
The information called for by this item is omitted pursuant to General Instruction (I) of Form 10-K.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Colorado and Subsidiaries and Supplemental Information are included in response to Item 8 hereof on the attached pages as indicated:
Page ----
Independent Auditors' Report.................................... Consolidated Balance Sheet at December 31, 1998 and 1997........ Statement of Consolidated Earnings for the Years Ended December 31, 1998, 1997 and 1996.............................. Statement of Consolidated Retained Earnings and Additional Paid-In Capital for the Years Ended December 31, 1998, 1997 and 1996...................................................... Statement of Consolidated Cash Flows for the Years Ended December 31, 1998, 1997 and 1996.............................. Notes to Consolidated Financial Statements...................... Supplemental Information on Oil and Gas Producing Activities (Unaudited)........................................
2. Financial Statement Schedules.
Schedules are omitted as not applicable or not required, or the required information is shown in the Consolidated Financial Statements or Notes thereto.
3. Exhibits.
(3.1)+ Certificate of Incorporation of the Company (Exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on March 29, 1994).
(3.3)+ Certificate of Amendment of Certification of Incorporation of the Company (Exhibit 3.1 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1989).
(4) With respect to instruments defining the rights of holders of long-term debt, the Company will furnish to the Securities and Exchange Commission any such document on request.
(10)+ Agreement for Consulting Services between Colorado Interstate Gas Company and Harold Burrow dated January 1, 1996 (Exhibit 10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------
Note:
+ Indicates documents incorporated by reference from the prior filing indicated. * Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31, 1998.
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints David A. Arledge, Dan A. Homec and Austin M. O'Toole and each of them, any one of whom may act without the joinder of the others, as his attorney-in-fact to sign on his behalf and in the capacity stated below and to file all amendments to this Annual Report on Form 10-K, which amendment or amendments may make such changes and additions thereto as such attorney-in-fact may deem necessary or appropriate.
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.
COLORADO INTERSTATE GAS COMPANY (Registrant)
By: JON R. WHITNEY ----------------------------- Jon R. Whitney President and Chief Executive Officer March 26, 1999
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.
By: JEFFREY A. CONNELLY By: DAVID A. ARLEDGE ----------------------------- ----------------------------- Jeffrey A. Connelly David A. Arledge Director Principal Financial Officer March 26, 1999 and Director March 26, 1999
By: HAROLD BURROW By: DAN A. HOMEC ----------------------------- ----------------------------- Harold Burrow Dan A. Homec Director Principal Accounting Officer March 26, 1999 March 26, 1999
By: JON R. WHITNEY By: C. SCOTT HOBBS ----------------------------- ----------------------------- Jon R. Whitney C. Scott Hobbs Director Director March 26, 1999 March 26, 1999
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This report, including Management's Discussion and Analysis of Financial Condition and Results of Operations, includes certain forward-looking statements. The forward-looking statements reflect the Company's expectations, objectives and goals with respect to future events and financial performance, and are based on assumptions and estimates which the Company believes are reasonable. However, actual results could differ materially from anticipated results. Important factors which may affect the actual results include, but are not limited to, commodity prices, political developments, market and economic conditions, industry competition, the weather, changes in financial markets, changing legislation and regulations, and the impact of the Year 2000 issue. The forward-looking statements contained in this Report are intended to qualify for the safe harbor provisions of Section 21E of the Securities Exchange Act of 1934, as amended.
The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis.
Liquidity and Capital Resources
General Discussion
The Company uses the following consolidated ratios to measure liquidity and ability to meet future funding needs and debt service requirements.
The changes in the cash flow from operating activities to capital expenditures and debt service requirements ratio is due mainly to lower capital expenditures in 1997 as compared to 1998 and 1996. The decrease in the 1998 total debt to total capitalization ratio when compared to 1997 is due to increased retained earnings resulting from 1998 earnings. The 1997 increase in total debt to total capitalization over 1996 is due to the issuance of additional debt. The decrease in the times interest earned ratio for 1997 can be attributed to increased interest expense resulting from the additional debt.
The Company's primary needs for cash are capital expenditures and debt service requirements. Capital expenditures, debt retirements and other cash needs in each of the years 1996 through 1998 and the sources of capital used to finance these expenditures are summarized in the Statement of Consolidated Cash Flows. Management believes the Company's stable financial position and earnings ability will enable it to continue to generate and obtain capital for financing needs in the foreseeable future.
Cash flow from operating activities amounted to $146.4 million in 1998, $136.5 million in 1997 and $127.6 million in 1996. The increases in 1998 and 1997 from the prior years can be attributed primarily to decreases for working capital requirements.
The Company has adopted a capital expenditure budget of approximately $87.4 million for 1999, an increase from the capital additions of $84.0 million in 1998. The anticipated increase in 1999 is the result of a $13.3 million increase for natural gas projects partially offset by a $9.9 million decrease for exploration and production projects. Alternatives to finance capital expenditures and other cash needs are primarily limited by the terms of a Coastal Natural Gas debt instrument. As of December 31, 1998, the Company and certain affiliates could incur an aggregate of approximately $3 billion of additional indebtedness.
The Company participates in a program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing borrowings from outside sources. At December 31, 1998, the Company had advanced $243 million to associated companies at a market rate of interest. Such amount is repayable on demand.
The Company is responding to the extensive changes in the natural gas industry by continuing to take steps to operate its facilities at their maximum efficient capacity, pursuing innovative marketing strategies and applying strict cost-cutting measures.
The FASB has issued FAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"), to be effective for all fiscal quarters of fiscal years beginning after June 15, 1999. FAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. The Company is currently evaluating the impact of FAS 133.
The Accounting Standards Executive Committee of the AICPA has issued Statement of Position 98-5, "Reporting of Costs of Start-Up Activities" ("SOP 98-5"), to be effective for periods beginning after December 15, 1998. SOP 98-5 provides guidance on accounting for costs incurred to open new facilities, conduct business in new territories or otherwise commence some new operation. The application of SOP 98-5 is not expected to have a material effect on the Company's consolidated financial statements.
The FASB Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts in Energy Trading and Risk Management Activities," to be effective for years beginning after December 15, 1998, states that energy trading contracts (as defined) should be marked to market with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The Company does not believe the application of Issue No. 98-10 will have a material effect on its consolidated financial statements.
Market Risk Management
The Company has issued fixed rate debt to partially finance expenditures and debt retirements. These agreements expose the Company to market risk related to changes in interest rates.
The following table presents hypothetical changes in fair values in the Company's debt obligations at December 31, 1998. The modeling technique used measures the change in fair values arising from selected changes in interest rates. Market changes reflect immediate hypothetical changes in interest rates at December 31, 1998. Fair values are calculated as the net present value of the expected cash flows of the financial instrument (millions of dollars).
The Company has notes receivable from related parties with a carrying value of $243 million and a note payable to a related party with a carrying value of $2.8 million. These notes earn interest at a variable rate tied to market rates of interest and therefore, the carrying amount is a reasonable estimate of its fair value. A 10% change in interest rates from December 31, 1998 levels would not have a material impact on earnings.
The Company's management of market risks is consistent with the prior year.
Year 2000
The Company, like most other companies, is addressing the Year 2000 issue. This issue is the result of computer programs written with two digits rather than four to define the applicable year. Computer programs that have
date-sensitive software using two digits to define the applicable year may recognize a date using "00" as the year 1900 instead of the year 2000. This could result in a system failure or miscalculations causing disruptions of operations, including, among other things, a temporary inability to process transactions, send invoices, or engage in similar normal business activities.
The Company's Year 2000 compliance project relates to both information technology and embedded systems throughout the Company and focuses on all technology hardware and software, external interfaces with customers and suppliers, operations process control, automation and instrumentation systems. Systems are being reviewed in an order of priority that includes an assessment of the potential adverse effects of noncompliance as well as an assessment of the complexity of the system. Assessment has been substantially completed for all systems. It will be necessary to modify or replace certain noncompliant software and hardware so that they will properly utilize dates beyond December 31, 1999. The Company believes that with such remediation, the Year 2000 issue can be mitigated. Necessary remediation and testing activities have begun and are planned to be completed for all material systems by mid 1999. Remaining systems modifications, replacement and testing are planned to be completed before the end of 1999.
The Company is continuing with a formal communications process with outside entities with which the Company conducts business to determine the extent to which those companies are addressing their Year 2000 compliance. In connection with this process, the Company has been sending letters and questionnaires to these parties and is evaluating the responses as received and is following up with those parties that have not responded. The Company does not expect any single noncompliant third party to have a material effect on the Company as it does not rely to a material extent on any single customer or supplier, including telecommunications providers, utilities and banks. However, the Company does not control these parties and there can be no assurance that third-party systems will be timely converted, or that any failure to convert would not have an adverse effect on the Company's systems. The Company will continue to cooperate and communicate with these parties to mitigate potential adverse effects.
The Company is currently preparing and will periodically update a Year 2000 contingency plan. The primary goals of the plan are to maintain continuity of operations, timely resume any operations that have been interrupted, preserve Company assets and protect the environment. The Company's geographical distribution and customer base diversity are expected to naturally reduce the risk of major disruptions to operations due to any Year 2000-related occurrence. Similarly, the Company's distributed information systems and wide scope of relationships with financial institutions, suppliers and vendors will most likely aid in limiting and localizing any individual Year 2000 failure to specific operations or facilities. Also, in recent years, the Company has replaced or updated a significant portion of its computer hardware and software. The plan will include possible manual intervention to operate noncompliant facilities or systems until they can be modified or replaced. Notwithstanding the foregoing, due to the nature of contingency planning, there can be no assurance that such plans will acceptably mitigate the risk of material impact to the Company's operations due to any Year 2000-related incident.
The Company has been using both external and internal resources to reprogram or replace its software and embedded systems for the Year 2000 issue. While the Company has included the Year 2000 project in its overall information systems planning process since 1996, certain systems were identified for replacement prior to the organization of the Year 2000 project. These amounts are not included in the Year 2000 project cost estimates, except where the replacement date has been accelerated in order to address Year 2000 issues. To date, the amounts incurred and expensed for developing and carrying out the plan total approximately $2 million. The total remaining cost for addressing the Year 2000 issue, which will be funded through operating cash flows, is currently estimated by management to be approximately $1 million.
It should be noted that the ultimate amount of Year 2000 costs is difficult to estimate due to possible disruptions in business arising from Year 2000 noncompliance of vendors, suppliers, customers and other third parties over whom the Company has no control. Notwithstanding the Company's efforts, disruptions could occur in its business due to Year 2000 problems and such disruptions could have an adverse effect.
Environmental
The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction, operation and
maintenance of its pipeline and production facilities. Compliance with such laws and regulations can be costly. Additionally, governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital projects and anticipates capital expenditures of $1 to $2 million in 1999 in order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement developments, will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's consolidated financial position or results of operations.
Results of Operations
Operating Revenues. The operating revenues by segment were as follows (thousands of dollars):
Earnings Before Interest, Income Taxes and Extraordinary Item. The earnings before interest, income taxes and extraordinary item by segment were as follows (thousands of dollars):
Natural Gas
The Company is subject to the regulations and accounting procedures of the FERC and historically followed the reporting and accounting requirements of FAS No. 71 "Accounting for the Effects of Certain Types of Regulation" ("FAS 71"). Effective November 1, 1996, the Company discontinued application of FAS 71. This accounting change has no direct effect on either the Company's ability to include the previously deferred items in future rate proceedings, or on its ability to collect the rates set thereby. The Company believes this accounting change results in financial reporting which better reflects the results of operations in the economic environment in which the Company now operates.
The Company operates under FERC Order 636. The intent of Order 636 is to insure that interstate pipeline transportation services are equal in quality for all gas supplies, whether the buyer purchases gas from the pipeline or from any other gas supplier. The FERC requires the use of the straight fixed variable ("SFV") rate setting methodology. In general, SFV provides that all fixed costs of providing service to firm customers (including an authorized return on rate base and associated taxes) are to be received through fixed monthly reservation charges, which are not a function of volumes transported, and provides that the pipeline's variable operating costs are received through the commodity billing component. Order 636 provides mechanisms for the recovery of any transition costs incurred by pipelines within a reasonable time period.
Operating Revenues
1998 Versus 1997. Revenues from natural gas operations decreased in 1998 due to a $41 million decrease related to gas sales volumes caused primarily by the assignment of the Company's Merchant Division activity to an affiliate as discussed in Note 11 of the Notes to Consolidated Financial Statements, a $22 million decrease in average gas sales prices, a decrease of $8 million in non-recurring miscellaneous income, a $12 million decrease in extracted products revenue, and other net decreases of $2 million partially offset by a $16 million decrease in reservations.
1997 Versus 1996. Revenues from natural gas operations increased in 1997 due to a $28 million increase resulting from increased gas sales volumes, a $19 million increase related to average gas transportation rates, a $16 million increase resulting from increased gas transportation volumes and a $11 million increase related to average gas sales prices partially offset by a $30 million change in reservations and other net decreases of $7 million.
Other Income-Net
1998 Versus 1997. The increase of $3 million in 1998 primarily reflects changes in interest income resulting from loans to affiliated companies.
1997 Versus 1996. The decrease of $1 million in 1997 primarily reflects changes in interest income resulting from loans to affiliated companies.
Cost of Gas Sold
1998 Versus 1997. The decrease is due primarily to a $59 million reduction related to gas purchase volumes caused primarily by the assignment of the Company's Merchant Division activity to an affiliate, a decrease of $9 million related to lower average gas purchase rates and other net decreases of $3 million partially offset by a $22 million reduction in net system balancing requirements.
1997 Versus 1996. The increase is due primarily to higher average gas purchase rates of $32 million and increased purchase volumes of $17 million partially offset by $19 million in net system balancing requirements.
Operation and Maintenance
1998 Versus 1997. Operation and maintenance expense decreased in 1998 due primarily to a $8 million decrease in gas used in operations, a $3 million decrease in materials and supplies expenses, a $3 million decrease in salaries and benefits and other net decreases of $1 million.
1997 Versus 1996. Operation and maintenance expense increased in 1997 due primarily to a $10 million increase in gas used in operations offset by net decreases of $1 million.
Depreciation, Depletion and Amortization
1998 Versus 1997. The 1998 decrease of $4 million is primarily due to decreased depreciation rates on certain regulated assets.
1997 Versus 1996. The $3 million decrease in 1997 is primarily due to depreciation rate adjustments pursuant to the Company's settlement of FERC Docket No. RP96-190 and the revision of depreciation rates for certain regulated assets.
Exploration and Production
Operating Revenues
1998 Versus 1997. Revenues from exploration and production decreased in 1998 as a result of a $4 million decrease related to sales volumes and a $3 million decrease related to average sales prices.
1997 Versus 1996. Revenues from exploration and production increased in 1997 as a result of higher natural gas prices.
Operation and Maintenance
1998 Versus 1997. Operation and maintenance expenses increased by $1 million as a result of increased well count and the installation of additional compression facilities.
1997 Versus 1996. Operation and maintenance expenses increased by $2 million as a result of increased well count and the installation of additional compression facilities.
Depreciation, Depletion and Amortization
1998 Versus 1997. Depreciation, depletion and amortization decreased by $2 million due to lower production volumes and a lower depreciation rate.
Interest Expense
1997 Versus 1996. The increase in 1997 is a result of interest on a $50 million senior term loan entered into on August 27, 1996 and the issuance of $100 million, 6.85% senior debentures in June 1997.
Taxes on Income
Income taxes fluctuated primarily as a result of changing levels of income before taxes and changes in effective income tax rates. The effective federal income tax rate for the Company was 31% in 1998, 33% in 1997 and 32% in 1996.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder Colorado Interstate Gas Company Colorado Springs, Colorado
We have audited the accompanying consolidated balance sheets of Colorado Interstate Gas Company (an indirect, wholly owned subsidiary of The Coastal Corporation) and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of earnings, retained earnings and additional paid-in capital and cash flows for each of the three years in the period ended December 31, 1998. 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 Colorado Interstate Gas Company and subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado February 4, 1999
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Thousands of Dollars)
See Notes to Consolidated Financial Statements.
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Thousands of Dollars)
See Notes to Consolidated Financial Statements.
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES STATEMENT OF CONSOLIDATED EARNINGS (Thousands of Dollars)
STATEMENT OF CONSOLIDATED RETAINED EARNINGS AND ADDITIONAL PAID-IN CAPITAL (Thousands of Dollars)
See Notes to Consolidated Financial Statements.
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES STATEMENT OF CONSOLIDATED CASH FLOWS (Thousands of Dollars)
See Notes to Consolidated Financial Statements.
COLORADO INTERSTATE GAS COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
- - Basis of Presentation
Colorado is a subsidiary of Coastal Natural Gas, a wholly owned subsidiary of Coastal. The stock of the Company was contributed by Coastal to Coastal Natural Gas effective April 30, 1982. The financial statements presented herewith are presented on the basis of historical cost and do not reflect the basis of cost to Coastal Natural Gas. The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from the estimates and assumptions used.
The Company is regulated by, and subject to, the regulations and accounting procedures of the FERC and historically followed the reporting and accounting requirements of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation" ("FAS 71"). Effective November 1, 1996, Colorado discontinued application of FAS 71. This accounting change has no direct effect on either the Company's ability to include the previously deferred items in future rate proceedings or on its ability to collect the rates set thereby. The Company believes this accounting change results in financial reporting which better reflects the results of operations in the economic environment in which the Company operates. Further, the Company has reexamined the useful lives of its assets, and during 1997, revised the depreciation rates for certain of its assets, which had the effect of increasing net earnings by approximately $3.6 million in 1998 and $1 million in 1997.
- - Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany transactions. The equity method of accounting is used for an investment in which the Company has a 50% voting interest and exercises significant influence.
- - Statement of Cash Flows
For purposes of this Statement, cash equivalents include time deposits, certificates of deposit and all highly liquid instruments with original maturities of three months or less. The Company made cash payments for interest, net of amounts capitalized, of $24.6 million, $24.9 million and $18.6 million in 1998, 1997 and 1996, respectively. Cash payments for income taxes amounted to $21.3 million, $32.9 million and $29.1 million in 1998, 1997 and 1996, respectively.
- - Nature of Operations and Concentrations of Credit Risk
The Company is involved in the production, purchase, gathering, processing, transportation, storage and sale of natural gas primarily in the Texas Panhandle and Rocky Mountain regions of the United States. The Company operates under arrangements with other companies including distributors, intrastate and interstate pipelines, producers, brokers, marketers and end-users. As a result, the Company has a concentration of receivables due from these customers. This may affect the Company's overall credit risk in that the customers may be similarly affected by changes in economic, regulatory and other factors. Trade receivables are generally not collateralized; however, the Company analyzes customers' credit positions prior to extending credit.
- - Materials and Supplies
Materials and supplies are carried principally at average cost.
- - Plant, Property and Equipment
Property additions and betterments are capitalized at cost. Property additions include capitalized interest costs allocable to construction. Such costs amounted to $.5 million, $.2 million and $1.2 million in 1998, 1997 and 1996, respectively. As a result of the Company's discontinued application of FAS 71 effective November 1, 1996, the Company records capitalized interest based on the provisions of Statement of Financial Accounting Standards No. 34, "Capitalization of Interest Cost." Prior to November 1, 1996, and as allowed under the provisions of FAS 71, such interest costs reflected an allowance for equity and borrowed funds used during construction. All costs incurred in the acquisition, exploration and development of gas and oil properties, including unproductive wells, are capitalized under the full-cost method of accounting. Such costs include the costs of all unproved properties and internal costs directly related to acquisition and exploration activities. All other general and administrative costs, as well as production costs, are expensed as incurred.
The Company provides for depreciation of gas system facilities on a straight-line basis with rates that vary by type of property (2% to 27% during 1998). Depreciation, depletion and amortization of gas and oil properties are provided on the unit-of-production basis whereby the unit rate for depreciation, depletion and amortization is determined by dividing the total unrecovered carrying value of gas and oil properties (excluding costs related to unevaluated properties) plus estimated future development costs by the estimated proved reserves included therein. Estimated proved reserves for 1998 were prepared by Huddleston for the Natural Gas System while the Exploration and Production portions were prepared by Coastal's engineers and reviewed by Huddleston. Estimated proved reserves for 1997 were prepared by Huddleston. The average amortization rate per equivalent unit of a thousand cubic feet of gas production for oil and gas operations was $.89 for the year 1998, $.91 for the year 1997 and $.88 for the year 1996. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the estimated future net cash flows from proved gas and oil properties, net of related income tax effects, discounted at 10 percent. If the unamortized costs are greater than this ceiling, any excess will be charged to depreciation, depletion and amortization expense. No such charge was required in the periods presented.
The cost of minor property units replaced or retired, net of salvage, is credited to plant accounts and charged to accumulated depreciation, depletion and amortization. Since provisions for depreciation, depletion and amortization expense are generally made on a composite basis, no adjustments to accumulated depreciation, depletion and amortization are made in connection with retirements or other dispositions occurring in the ordinary course of business. Gain or loss on sales of major property units is credited or charged to income.
- - Accounting Standards
The Company adopted Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive Income" in 1998. The application of the new standard did not have a material effect on the Company's consolidated financial statements as the Company currently does not have any material items of other comprehensive income.
The Company adopted Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information " ("FAS 131"), in 1998 and the disclosures for prior years have been revised in accordance with this statement. See Note 11 for additional information on FAS 131.
The Company adopted Statement of Financial Accounting Standards No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" ("FAS 132"), in 1998 and the disclosures for prior years have been revised in accordance with this statement. See Note 7 for additional information on FAS 132.
The FASB has issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133"), to be effective for all fiscal quarters of fiscal years beginning after June 15, 1999. FAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting for changes in the fair value of a derivative will depend on the intended use of the derivative and the resulting designation. The Company is currently evaluating the impact of FAS 133.
The Accounting Standards Executive Committee of the AICPA issued Statement of Position 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use" ("SOP 98-1") which was adopted by the Company in 1998. The application of the new statement did not have a material effect on the Company's consolidated results of operations, financial position or cash flows.
The Accounting Standards Executive Committee of the AICPA has issued Statement of Position 98-5, "Reporting on the Costs of Start-Up Activities" ("SOP 98-5"), to be effective for periods beginning after December 15, 1998. SOP 98-5 provides guidance on accounting for costs incurred to open new facilities, conduct business in new territories or otherwise commence some new operation. The application of SOP 98-5 is not expected to have a material effect on the Company's consolidated financial statements.
The FASB Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts in Energy Trading and Risk Management Activities," to be effective for years beginning after December 15, 1998, states that energy trading contracts (as defined) should be marked to market with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The Company does not believe the application of Issue No. 98-10 will have a material effect on its consolidated financial statements.
- - Income Taxes
The Company follows the liability method of accounting for deferred federal income taxes as required by the provisions of FAS No. 109, "Accounting for Income Taxes." The Company is a member of a consolidated group which files a consolidated federal income tax return. Members of the consolidated group with taxable income are charged with the amount of income taxes as if they filed separate federal income tax returns, and members providing deductions and credits which result in income tax savings are allocated credits for such savings.
- - Revenue Recognition
The Company recognizes revenues for the sale of their products in the period of delivery. Revenue for services are recognized in the period the services are provided.
- - Reclassification of Prior Period Statements
Certain minor reclassifications of prior period statements have been made to conform with current reporting practices. The effect of the reclassifications was not material to the Company's consolidated financial position or results of operations.
2. Long-Term Debt
Balances at December 31 were as follows (thousands of dollars):
The 10% Senior Debentures, due 2005, are not redeemable prior to maturity and have no sinking fund provisions.
The 6.85% senior debentures are not redeemable prior to maturity; but each holder has the right to require the Company to redeem such debentures, in whole or in part, on June 15, 2007, at a redemption price equal to 100% of the aggregate principal amount thereof plus accrued and unpaid interest.
Alternatives to finance capital expenditures and other cash needs are primarily limited by the terms of a Coastal Natural Gas debt instrument. As of December 31, 1998, the Company and certain affiliates could incur an aggregate of approximately $3 billion of additional indebtedness.
3. Common Stock and Other Stockholders' Equity
All of the Company's common stock is owned by Coastal Natural Gas.
At December 31, 1998, there were no restrictions on retained earnings as to its availability for dividends on common stock.
4. Mandatory Redemption Preferred Stock
All of the remaining shares of the Company's mandatory Redemption Preferred Stock were redeemed on July 31, 1996 at par value.
5. Fair Value of Financial Instruments
The estimated fair value amounts of the Company's financial instruments have been determined by the Company, using appropriate market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value; thus, the estimates provided herein are not necessarily indicative of the amounts that could be realized in a current market exchange.
The carrying values of cash, notes receivable from affiliates and note payable to affiliate are reasonable estimates of their fair values. The estimated value of the Company's long-term debt is based on interest rates at December 31, 1998 and 1997, respectively, for new issues with similar remaining maturities.
6. Taxes On Income
Provisions for income taxes before extraordinary item are composed of the following (thousands of dollars):
Coastal and the Internal Revenue Service ("IRS") Appeals Office have concluded a final settlement of certain adjustments originally proposed to federal income tax returns filed for the years 1985 through 1987. The IRS has proposed additional adjustments to those returns, and Coastal is contesting certain of these adjustments before the IRS Appeals Office. Coastal's federal income tax returns filed for the years 1988 through 1990 have been examined by the IRS and Coastal has received notice of proposed adjustments to the returns for each of those years. Coastal currently is contesting certain of these adjustments with the IRS Appeals Office. Examination of Coastal's federal income tax returns for 1991, 1992, 1993 and 1994 began in 1997. It is the opinion of management that adequate provisions for federal income taxes have been reflected in the Company's consolidated financial statements.
Provisions for federal income taxes were different from the amount computed by applying the statutory U.S. federal income tax rate to earnings before tax. The reasons for these differences are (thousands of dollars):
Deferred tax liabilities (assets) which are recognized for the estimated future tax effects attributable to temporary differences are (thousands of dollars):
7. Benefit Plans
The Company participates in the non-contributory pension plan of Coastal (the "Plan") which covers substantially all employees. The Plan provides benefits based on final average monthly compensation and years of service. As of December 31, 1998, the Plan did not have an unfunded accumulated benefit obligation. The Company's funding policy is to contribute the amount necessary for the plan to maintain its qualified status under the Employee Retirement Income Security Act of 1974, as amended. Colorado made no contributions to the Plan for 1998, 1997 or 1996. Assets of the Plan are not segregated or restricted by participating subsidiaries and pension obligations for Company employees would remain the obligation of the Plan if the Company were to withdraw.
The Company also makes contributions to a thrift plan, which is a trusteed, voluntary and contributory plan for eligible employees of the Company. The Company's contributions, which are based on matching employee contributions, amounted to approximately $2.3 million for 1998 and 1997, respectively and $2.5 million for 1996.
The Company provides certain health care and life insurance benefits for retired employees. The estimated costs of retiree benefit payments are accrued during the years the employee provides services. Certain costs have been deferred and were fully amortized through October 31, 1996. Effective November 1, 1996, such costs are no longer being deferred as a result of the Company's discontinued application of FAS 71.
The following tables provide a reconciliation of the changes in the postretirement benefit obligation, the fair value of plan assets over each of the years ended December 31, 1998 and 1997, and a statement of the funded status as of December 31, 1998 and 1997 (millions of dollars):
The following table provides the components of net periodic postretirement benefit cost for 1998, 1997 and 1996 (millions of dollars):
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 9.0% in 1998, declining gradually to 6.0% by the year 2004. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 9.7% in 1997 and 10.4% in 1996. A one percentage point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 1998 by approximately 3.67% and the net postretirement health care cost by approximately 3.61%. A one percentage point decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 1998 by approximately 4.02% and the net postretirement health care cost by approximately 4.13%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.0% in 1998, 7.25% in 1997 and 7.5% in 1996 and the expected long-term rate of return on assets was 4.3% in 1998, 1997 and 1996.
8. Lease Commitments
The Company had rental expense of approximately $5.1 million, $5.2 million and $4.7 million in 1998, 1997 and 1996, respectively (excluding leases covering natural resources). The aggregate minimum lease payments under existing noncapitalized long-term leases are estimated to be $4.1 million, $3.8 million, $3.7 million, $2.4 million and $2.3 million for the years 1999-2003, respectively, and $3.0 million thereafter.
9. Litigation, Environmental and Regulatory Matters
- - Litigation Matters
In December 1992, certain of Colorado's natural gas lessors in the West Panhandle Field filed a complaint in the U.S. District Court for the Northern District of Texas, claiming underpayment of royalties, breach of fiduciary duty, fraud and negligent misrepresentation. Management believes that Colorado has numerous defenses to the lessors' claims, including (i) that the royalties were properly paid, (ii) that the majority of the claims were released by written agreement and (iii) that the majority of the claims are barred by the statute of limitations. In March of 1995, the trial court granted a partial summary judgment in favor of Colorado, holding that the four-year statute of limitations had not been tolled, that the releases are valid, and dismissing all tort claims and claims for breach of any duty of disclosure. The remaining claim for underpayment of royalties was tried to a jury which, in May 1995, made findings favorable to Colorado. On June 7, 1995, the trial court entered a judgment that the lessors recover no monetary damages from Colorado and permanently estopping the lessors from asserting any claim based on an interpretation of the contract different than that asserted by Colorado in the litigation. The lessors' motion for a new trial was denied on July 18, 1997, and both parties filed appeals. On June 7, 1996, the same plaintiffs sued Colorado in state court in Amarillo, Texas, for underpayment of royalties. Colorado removed the second lawsuit to federal court which granted a stay of the second suit pending the outcome of the first lawsuit. Oral arguments were heard before the Fifth Circuit Court of Appeals on December 4, 1998 and the parties are awaiting the Court's decision.
In 1996, Jack Grynberg filed a claim under the False Claims Act on behalf of the U.S. government in the U.S. District Court, District of Columbia, against 70 defendants, including Colorado and another subsidiary of Coastal. The suit sought damages for the alleged underpayment of royalties due to the purported improper measurement of gas. The 1996 suit was dismissed without prejudice in March 1997 and the dismissal was affirmed by the D.C. Court of Appeals in October 1998. In September 1997, Mr. Grynberg filed 77 separate, similar False Claims Act suits against natural gas transmission companies and producers, gatherers, and processors of natural gas, seeking unspecified damages. Colorado, Coastal and several other Coastal subsidiaries have been included in two of the September 1997 suits. The suits were filed in both the U.S. District Court, District of Colorado and the U.S. District Court, Eastern District of Michigan. The United States Department of Justice has notified the Company that it is reviewing these lawsuits to determine whether or not the United States will intervene.
Other lawsuits and other proceedings which have arisen in the ordinary course of business are pending or threatened against the Company or its subsidiaries.
Although no assurances can be given and no determination can be made at this time as to the outcome of any particular lawsuit or proceeding, the Company believes there are meritorious defenses to substantially all of the above
claims and that any liability which may finally be determined should not have a material adverse effect on the Company's consolidated financial position or results of operations.
- - Environmental Matters
The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction, operation and maintenance of its pipeline and production facilities. Compliance with such laws and regulations can be costly. Additionally, governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Company spent approximately $1 million in 1998 on environmental capital projects and anticipates capital expenditures of $1 to $2 million in 1999 in order to comply with such laws and regulations.
Future information and developments, including legislative and enforcement developments, will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's consolidated financial position or results of operations.
- - Regulatory Matters
On January 31, 1996, the FERC issued a "Statement of Policy and Request for Comments" ("Policy"). Under this Policy, (i) a pipeline and a customer are allowed to negotiate a contract which provides for rates and charges that exceed the pipeline's posted maximum tariff rates, provided that the customer agreeing to such negotiated rates has the ability to elect to receive service at the pipeline's posted maximum rate (known as a "recourse rate"), and (ii) a pipeline must also make subsequent tariff filings each time the pipeline negotiates a rate for service which is outside of the minimum and maximum range for the pipeline's cost-based recourse rates. To implement this Policy, a pipeline must make an initial tariff filing with the FERC to indicate that it intends to contract for services under this Policy. Colorado has received FERC authority to enter into negotiated rate transactions. Separately, the FERC has determined that pipelines who seek to include negotiated rate transactions in the discount adjustment used to calculate their rates must file tariff sheets demonstrating that existing customers who purchase service under the pipeline's cost-of-service rates will not be harmed by negotiated rate discounts.
On July 29, 1998, the FERC issued a "Notice of Proposed Rulemaking," in which the FERC has proposed a number of further significant changes to the industry, including, among other things, removal of price caps in the short-term market (less than one year), capacity auctions, changed reporting obligations, the ability to negotiate terms and conditions of all services, elimination of the requirement of a matching term cap on the renewal of existing contracts, and a review of its policies for approving capacity construction. On the same day, the FERC also issued a "Notice of Inquiry" soliciting industry input on various matters affecting the pricing of long-term service and certificate pricing in light of changing market conditions. The due date for comments on both of these matters has been rescheduled twice and is currently scheduled for April 22, 1999. The FERC has indicated that it may consider both proposals together inasmuch as they raise several common issues.
Certain regulatory issues remain unresolved among the Company, its customers, its suppliers and the FERC. The Company has made provisions which represent management's assessment of the ultimate resolution of these issues. As a result, the Company anticipates that these regulatory matters will not have a material adverse effect on its consolidated financial position or results of operations. While the Company estimates the provisions to be adequate to cover potential adverse rulings on these and other issues, it cannot estimate when each of these issues will be resolved.
10. Extraordinary Item
The Company is subject to the regulations and accounting procedures of the FERC and historically followed the reporting and accounting requirements of FAS 71. Effective November 1, 1996, the Company discontinued application of FAS 71. The Company believes this accounting change results in financial reporting which better reflects the results
of operations in the economic environment in which the Company now operates. The impact of this change was a charge to earnings in 1996 of $6.3 million, net of related income taxes of $(1.5) million, and is shown as an extraordinary item in the Statement of Consolidated Earnings.
11. Segment Information
Natural gas system operations and gas and oil exploration and production are the two segments of the Company's operations. Separate management of each segment is required because each line is subject to different production, marketing and technology strategies.
Natural gas system operations involve the production, purchase, gathering, storage, transportation and sale of natural gas, principally to and for public utilities, industrial customers, other pipelines, and other gas customers, as well as the operation of natural gas liquids extraction plants.
Gas and oil exploration and production operations involve primarily the development and production of natural gas, crude oil, condensate and natural gas liquids. Sales are made to affiliated companies, industrial users, interstate pipelines and distribution companies in the Rocky Mountain, Central and Southwest United States.
The Company's operating revenues from external customers and intersegment revenues; earnings before interest, income taxes and extraordinary item; depreciation, depletion and amortization; equity income (loss) from investments; and capital expenditures for the years ended December 31, 1998, 1997 and 1996 are shown as follows (thousands of dollars):
Effective July 1, 1998, those gas purchases and sales formerly conducted by the Company's unincorporated Merchant Division were assigned to an affiliate. Therefore, revenues and cost of gas sold associated with such activities subsequent to June 30, 1998 are not included in the Company's consolidated financial statements.
Intersegment revenues are accounted for on the basis of contract, current market or internally established transfer prices. The equity income (loss) from investments is included in Operating revenues.
The Company's assets and amount of investment in equity method investees by segment as of December 31, 1998, 1997 and 1996 are as follows (thousands of dollars):
Revenues from sales, storage and transportation of natural gas to individual customers amounting to 10% or more of the Company's consolidated revenues were as indicated below (thousands of dollars):
Revenues from any other single customer did not amount to 10% or more of the Company's consolidated revenues for the years ended December 31, 1998, 1997 and 1996. The Company does not have any foreign operations.
Deliveries from the Company's field system are made to markets in the Texas Panhandle region. Transportation services are provided for brokers, producers, marketers, distributors, end-users and other pipelines. As noted above, prior to July 1, 1998, gas sales were made primarily to public utilities and natural gas marketers which resold the gas to residential, commercial and industrial customers and to end-users in Colorado and southeastern Wyoming. The Company extends credit for sales, storage and transportation services provided to certain qualifying companies.
12. Transactions with Related Parties
The Statement of Consolidated Earnings includes the following major transactions with related parties (thousands of dollars):
Services provided by the Company at cost for affiliated companies were $7.7 million for 1998, $6.3 million for 1997 and $7.0 million for 1996. Services provided by affiliated companies for the Company at cost were $7.7 million for 1998, $7.5 million for 1997 and $8.2 million for 1996. The services provided by the Company to affiliates, and by affiliates to the Company, primarily reflect the allocation of costs relating to the sharing/operating of facilities and general and administrative functions. Such costs are allocated using a three factor formula consisting of revenue, property and payroll, or other methods which have been applied on a reasonable and consistent basis.
In 1989, the Company entered into two separate five-year lease agreements with ANR Western Storage Company, an affiliate, for the rental of certain pipeline facilities. The leases were terminated in 1996 and the related facilities were purchased by the Company. Rental expense of approximately $.9 million in 1996 was recorded in conjunction with the terms of the lease agreements.
The Company participates in a program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing total borrowings from outside sources. At December 31, 1998, the Company had advanced $243 million to associated companies at a market rate of interest. Such amount is repayable on demand.
At December 31, 1998, the Company's investment in an affiliate, Coastal Medical Services, Inc., was $36.7 million. The affiliate has assumed the responsibility for facilitating the management of a portion of the medical obligations of the Company and other Coastal subsidiaries.
13. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1998 and 1997 were (thousands of dollars):
Pursuant to the Company's FERC Docket No. RP96-190 Settlement, a new rate and service structure providing for seasonal contractual changes has been put into place. Under the new structure, the Company's revenues will tend to be higher in the two heating-season quarters of the year (first and fourth quarters) than in the other two quarters. No significant difference in the total annual levels of revenue and earnings is expected to result from this change.
Effective July 1, 1998, those gas purchases and sales formerly conducted by the Company's unincorporated Merchant Division were assigned to an affiliate. Therefore, revenues and cost of gas sold associated with such activities subsequent to June 30, 1998 are not included in the Company's consolidated financial statements.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition, exploration and development activities, results of operations and the standardized measure of discounted future net cash flows are presented for the exploration and production segment. Natural gas system reserves and the related standardized measure of discounted future net cash flows are presented separately for natural gas operations. All reserves are located in the United States. The reserve information for 1998 for the Natural Gas System shown below were prepared by Huddleston, Colorado's independent engineers, while the Exploration and Production portions are as prepared by Coastal's engineers and reviewed by Huddleston. The reserves as of December 31, 1997 and 1996 are as prepared by Huddleston.
Changes in proved reserves since the end of 1995 are shown in the following table:
Total proved reserves for the natural gas system exclude storage gas and liquids volumes. The natural gas system storage gas volumes are 41,213, 40,376 and 38,842 MMcf and storage liquids volumes are approximately 232,000, 209,000 and 192,000 barrels at December 31, 1998, 1997 and 1996, respectively. Volumes are based on Huddleston's report and include estimates which differ slightly from actuals.
Capitalized Costs Relating to Exploration and Production Activities (thousands of dollars)
The Company follows the full-cost method of accounting for oil and gas properties.
Costs Excluded from Amortization (thousands of dollars)
The following table summarizes the costs related to unevaluated properties which are excluded from amounts subject to amortization at December 31, 1998. The Company regularly evaluates these costs to determine whether impairment has occurred.
Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities (thousands of dollars)
Results of Operations for Exploration and Production Activities (thousands of dollars)
The average amortization rate per equivalent Mcf was $0.89 in 1998, $0.91 in 1997 and $0.88 in 1996.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserve Quantities
Future cash inflows from the sale of proved reserves and estimated production and development costs for the year ended December 31, 1998, are discounted at 10% after they are reduced by the Company's estimate for future income taxes. The calculations are based on year-end prices and costs, statutory tax rates and nonconventional fuel source tax credits that relate to existing proved oil and gas reserves in which the Company has mineral interests.
The standardized measure is not intended to represent the market value of reserves and, in view of the uncertainties involved in the reserve estimation process, including the instability of energy markets as evidenced by recent declines in both natural gas and crude oil prices, may be subject to material future revisions (thousands of dollars):
Principal sources of change in the standardized measure of discounted future net cash flows during each year are as follows (thousands of dollars):
None of the amounts include any value for storage gas and liquids volumes, which were approximately 41 Bcf and 232 thousand barrels, respectively, at the end of 1998. Volumes are based on Huddleston's report and include estimates which differ slightly from actuals.
EXHIBIT INDEX
Exhibit Number Document - -------- -----------------------------------------------------------------
(3.1)+ Certificate of Incorporation of the Company (Exhibit to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1980).
(3.2)+ By-laws of the Company (Filed as Module CIGBY-LAWS on March 29, 1994).
(3.3)+ Certificate of Amendment of Certification of Incorporation of the Company (Exhibit 3.1 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1989).
(4) With respect to instruments defining the rights of holders of long-term debt, the Company will furnish to the Securities and Exchange Commission any such document on request.
(10)+ Agreement for Consulting Services between Colorado Interstate Gas Company and Harold Burrow dated January 1, 1996 (Exhibit 10 to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1995).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
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Note: + Indicates documents incorporated by reference from prior filing indicated. * Indicates documents filed herewith.