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, 1994, the Company had 1,110 employees.
The revenues and operating profit of the Company by industry segment for each of the three years in the period ended December 31, 1994, and the related identifiable assets as of December 31, 1994, 1993 and 1992, are set forth in Note 12 of Notes to Consolidated Financial Statements included herein.
NATURAL GAS SYSTEM
OPERATIONS
GENERAL
The Company is involved in the production, gathering, processing, transportation, storage and sale of natural gas. Colorado purchases and produces natural gas and makes sales of such gas at the wellhead principally to local gas distribution companies for resale. Separately, Colorado contracts to gather, process, transport and store natural gas owned by third parties.
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. The Company also has certain gathering facilities located in New Mexico. Colorado owns four underground gas storage fields; three located in Colorado, and one in Kansas.
The Company's principal pipeline facilities at December 31, 1994 consisted of 6,356 miles of pipeline and 66 compressor stations with approximately 348,000 installed horsepower. At December 31, 1994, the design peak day delivery capacity of the transmission system was approximately 2.0 Bcf per day. The underground storage facilities have a working capacity of approximately 29 Bcf and a peak day delivery capacity of approximately 769 MMcf.
GAS SALES, STORAGE AND TRANSPORTATION
Beginning in October 1993, Colorado implemented Order 636 on its system and as a result, Colorado's gas sales contracts have been unbundled and such sales are now made at the producer wellhead. Colorado's gas sales contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, Colorado's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by the FERC. Colorado is also authorized to abandon all sales for resale at such time as the contracts expire and without prior FERC approval. Effective October 1, 1993, Colorado formed an unincorporated Merchant Division to conduct most of the Company's sales activity in the Order 636 environment. The gas sales volumes reported include those sales which continue to be made by Colorado together with those of its Merchant Division.
Effective October 1, 1993, Colorado assigned an undivided interest in a portion of its company-owned leases to a new subsidiary. The subsidiary contracts to sell the production to Colorado's Merchant Division, which utilizes the gas primarily for its sales to Colorado's traditional customers. The reserve volumes reported represent those interests retained by Colorado together with those assigned to the new subsidiary.
Gas sales revenues were $139 million in 1994, compared to $223 million in 1993 and $261 million in 1992. The decreases are due largely to the fact that prior to the mandated restructuring under Order 636, the costs of providing gathering, storage and transportation services for sales customers were recovered as part of the total resale rate and were classified as part of gas sales revenue. Subsequent to restructuring, these costs are now recovered under separate rates for each service.
Colorado has engaged in "open access" transportation and storage of gas owned by third parties for several years. In addition, prior to October 1, 1993, Colorado provided storage and transportation services as part of its "bundled" sales service. As a result of Order 636, the Company has "unbundled" these services from its sales services and continues to provide these services to third parties under individual contracts. Such services are at negotiated rates that are within minimum and maximum levels approved by the FERC. Also, pursuant to Order 636, the Company, on September 30, 1993, sold all of its working gas except for 3.8 Bcf which it retained for operational needs.
Colorado's deliveries for the years 1994, 1993 and 1992 are as follows:
GAS GATHERING AND PROCESSING
Colorado provides gathering and processing services on an "unbundled" or stand-alone basis. The Company contracts for these services under terms which are negotiated. With respect to gathering, the Company is limited to charging rates which are between minimum and maximum levels approved by the FERC. Processing terms are not subject to FERC approval, but Colorado is required to provide "open access" to its processing facilities.
Colorado has approximately 3,000 miles of gathering lines and approximately 110,200 horsepower of compression in its gathering operations. Colorado owns and operates six gas processing plants which recovered approximately 88 million gallons of liquid hydrocarbons in 1994, compared to 86 million gallons in 1993 and 77 million gallons in 1992, and 4,300 long tons of sulfur in 1994, compared to 4,400 long tons in 1993 and 3,600 long tons in 1992. Additionally, in 1994, Colorado processed approximately 6 million gallons of liquid hydrocarbons owned by others compared to 12 million in 1993 and 10 million in 1992. These plants, with a total operating capacity of approximately 697 MMcf daily, recover mainly propane, butanes, natural gasoline, sulfur and other by-products, which are sold to refineries, chemical plants and other customers.
COMPETITION
Colorado has historically competed with interstate and intrastate pipeline companies in the sale, transportation and storage of gas and with independent producers, brokers, marketers and other pipelines in the gathering, processing and sale of gas within its service areas. On October 1, 1993, the Company implemented Order 636 on its system and as a consequence its gas sales contracts have been unbundled at the producer wellhead. Order 636 also mandated implementation of capacity release and secondary delivery point options allowing a pipeline's firm transportation customers to compete with the pipeline for interruptible transportation. Additional information on Order 636 is included under "Regulations Affecting Gas System" included herein.
Natural gas competes with other forms of energy available to customers, primarily on the basis of price. 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.
GAS SYSTEM RESERVES
GENERAL
Colorado, through its unincorporated Merchant Division, continues to make natural gas sales to a number of customers. In 1995, Colorado has sales contract commitments of approximately 65,000 MMcf. Colorado will meet its sales commitments primarily with purchases from third parties under existing contracts and with production of Company-owned reserves. Colorado will also make monthly spot gas purchases, if needed.
RESERVES
The table below represents estimates of the Company's owned reserves as of December 31, 1994, 1993, and 1992 (Bcf), as prepared by Huddleston, Colorado's independent engineers.
The estimates of 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.
At December 31, 1994, Colorado maintained under its own account 2 Bcf of natural gas in underground working storage for system balancing. The Company has an additional 38 Bcf of base gas in its four owned storage fields.
RESERVES DEDICATED TO A PARTICULAR CUSTOMER
Colorado is committed to sell gas to Mesa Operating Company ("Mesa"), 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 Mesa. Effective October 1, 1993, an undivided interest in the West Panhandle Field leases, related to this 23% of the total net production not committed to Mesa, was assigned by Colorado to a new subsidiary. The reserve volumes reported represent those retained by Colorado as well as those assigned to the new subsidiary.
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 and 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, had determined that it will not regulate sales rates. Additionally, the FERC has asserted rate-regulation (but not certificate regulation) over
gathering. Colorado is challenging the FERC's assertion of rate jurisdiction over gathering, but has agreed in a settlement that for three years beginning October 1, 1993, Colorado will post in its tariff the minimum and maximum gathering rates which will be established and approved by the FERC. Colorado, where required, holds certificates of public convenience and necessity issued by the FERC covering its jurisdictional facilities, activities and services.
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. Operations on United States government land are regulated by the Department of the Interior.
FERC Order Nos. 500 and 528 allowed regulated pipelines, including Colorado, to recover, through a fixed charge, from 25% to 50% of the cost of payments made to producers to extinguish outstanding claims under existing gas purchase contracts or to secure reformation of existing contracts. Fixed charges are paid by pipeline sales customers without regard to volumes of gas purchased. Under this election, however, an amount equivalent to the amount included in the fixed charge must be borne by the pipeline. Colorado has incurred costs related to contract reformation and settlements of take-or-pay claims, a portion of which has been recovered under Order Nos. 500 and 528.
On April 8, 1992, the FERC issued Order 636 which required significant changes in the services provided by interstate natural gas pipelines. The Company and numerous other parties have sought judicial review of aspects of Order 636. The case is currently in the briefing phase before the United States Court of Appeals for the D.C. Circuit. Notwithstanding those appeals, the Company has successfully complied with the requirements of Order 636.
On July 2, 1993, the Company submitted to the FERC an unanimous offer of settlement which resolved all the Order 636 restructuring issues which had been raised in its restructuring proceedings. That settlement was ultimately approved (except for minor issues), and the Company's restructured services became effective October 1, 1993. As of October 1, 1993, the Company separated all of its services and separately contracts for each service on a stand-alone or "unbundled" basis. Gathering, storage and transportation services are provided at negotiated rates established between minimum and maximum levels approved by the FERC, while gas processing rates are not subject to FERC regulations.
RATE MATTERS
Colorado's gas sales for resale contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, Colorado's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by the FERC. Colorado is also authorized to abandon all sales for resale without prior FERC approval at such time as the contracts expire. Pursuant to Order 636, Colorado's gas sales have been unbundled at the producer wellhead. Effective October 1, 1993, Colorado formed an unincorporated Merchant Division to conduct most of the Company's sales activity in the Order 636 environment. The gas sales volumes reported include those sales which continue to be made by Colorado together with those of its Merchant Division.
On March 31, 1993, Colorado filed at FERC under Docket RP93-99 to increase its rates by approximately $26.5 million annually. Such rates (adjusted to reflect Colorado's Order 636 program) became effective subject to refund on October 1, 1993. On November 10, 1994, the FERC approved a settlement offer submitted by the Company which resolved all of the issues in the proceeding. The Company has implemented the rates established in the settlement for prospective application and will be required to make refunds as a result of the approval of the settlement. Such refunds will be distributed in March 1995. The Company has fully accrued for these refunds and therefore such refunds will not have an adverse effect on its consolidated financial position or results of operations.
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. 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, oil and condensate production volumes of the Company, including quantities attributable to its natural gas system, for the three years ended December 31, 1994:
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, 1994:
At December 31, 1994, the gas and oil properties of the Company included leasehold interests covering 471,047 acres (353,978 net acres), of which 385,978 acres (320,852 net acres) were producing and 85,069 acres (33,126 net acres) were undeveloped. The net producing acreage, held by production, is concentrated principally in Texas (78%), Oklahoma (8%), Wyoming (6%) and Utah (6%). The net undeveloped acreage, not held by production, is principally in Wyoming (45%), Montana (22%) and Colorado (19%).
The Company drilled 19 gross (7.68 net) gas wells, 22 gross (12.53 net) gas wells, and 39 gross (34.41 net) gas wells in 1994, 1993 and 1992, respectively.
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.
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 facilities. The Company anticipates annual capital expenditures of $1 to $2 million over the next several years aimed at maintaining compliance with such laws and regulations. Additionally, appropriate governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act, also known as "Superfund", as reauthorized, imposes liability, without regard to fault or the legality of the original act, for disposal of a "hazardous substance." The Company is not presently, and has not been in the past, a potentially responsible party
("PRP") in any "Superfund" waste disposal sites. However, the Company has received notice from a committee formed from a group of 55 companies who are named as PRPs at one site requesting the Company pay a de minimis share (approximately $36,000) of the associated clean-up costs.
There are additional areas of environmental remediation responsibilities which may fall upon the Company. The states have regulatory programs that mandate waste clean-up. The Clean Air Act Amendments of 1990 include new permitting regulations which will result in increased operating expenditures.
Future information and developments will require the Company to continually reassess the expected impact of all applicable environmental laws and regulations. Compliance with all applicable environmental protection laws and regulations is not expected to have a material adverse impact on the Company's liquidity, consolidated financial position or results of operations.
OTHER DEVELOPMENTS
In March 1994, the Company sold its interest in Natural Fuels Corporation to CIC Stock Corporation, an affiliate.
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, 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. Trial has been set for March 22, 1995.
Other lawsuits and other proceedings which have arisen in the ordinary course of business are pending or threatened against Colorado 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. Additional information regarding legal proceedings is set forth in Notes 3 and 10 of Notes to Consolidated Financial Statements included herein.
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.
Certain preferred stock resolutions restrict the payment of dividends on common stock. Under the most restrictive of these provisions, approximately $364.8 million was available for dividends on the common stock of the Company at December 31, 1994. 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, 1993. 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 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 15, 1995, were as follows:
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 1995. Each of the directors and officers named above have been officers or employees of Colorado, ANR Pipeline and/or Coastal for five years or more except for the following:
Mr. Coffin was elected a Vice President of Colorado in June 1990. Before joining the Company, he practiced law with the Denver law firms of Holland & Hart from 1986 to 1988 and Brownstein Hyatt Farber & Madden from 1988 to 1990. Prior thereto, he served as Deputy Administrative Assistant to a United States congressman.
Mr. Gillet was elected Vice President of Colorado in July 1993. Prior thereto he served as Vice President of ANR Pipeline Company from 1985 to 1991 and as a Vice President of Coastal States Management Corporation since 1983.
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. Matthews was elected Vice President and Treasurer of Colorado in October 1994. He was also elected Treasurer of Coastal and Vice President and Treasurer of ANR Pipeline in September 1994. He has served as Assistant Treasurer of Coastal since 1983 and as Vice President of Coastal States Management Corporation, a subsidiary of Coastal, since 1991.
Mr. Sparger was elected a Vice President of Colorado in June 1992. Before joining the Company, he served in various capacities with Transcontinental Gas Pipe Line Corporation since 1967.
Mr. Zuckweiler was elected a Vice President of Colorado in August 1991. He held the position of Director, Transportation and Exchange for the Company from July 1981 to September 1988, at which time he was elected Assistant Vice President.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Colorado is an indirectly wholly-owned subsidiary of Coastal. Information concerning the cash compensation and certain other compensation of directors and officers of Coastal is contained in this section.
The following table sets forth information for the fiscal years ended December 31, 1994, 1993 and 1992 as to cash compensation paid by Coastal and its subsidiaries, as well as certain other compensation paid or accrued for those years, to Coastal's Chief Executive Officer ("CEO") and its four other most highly compensated executive officers (the "Named Executive Officers").
SUMMARY COMPENSATION TABLE
________________________
(1) Does not include the value of perquisites and other personal benefits because the aggregate amount of such compensation, if any, does not exceed the lesser of $50,000 or 10 percent of annual salary and bonus for any named individual.
(2) Salary amounts for Messrs. Wyatt, Arledge and Cordes for 1992 and 1993 include directors' fees paid during these periods which were previously reported under "All Other Compensation." Directors' fees for members of management of Coastal were eliminated in September, 1993. There was no salary change for Mr. Wyatt during 1994; the reduced base pay level for 1994 was due to the September 1993 salary reduction (reported in the 1994 Coastal Proxy Statement) being in effect for all of 1994.
(3) Due to Coastal's practice of paying bi-weekly, there is one extra pay period reflected in the 1992 salary. Normally there are 26 pay periods, but approximately once every 11 years there are 27 pay periods; 1992 was such a year.
(4) Although 1993 bonus awards were not finalized by Coastal's Compensation and Executive Development Committee until after the 1994 Coastal Proxy Statement had been prepared, all awards were based solely on 1993 performance. Bonuses for 1992 were paid in equal installments over a three- year period, provided the employee was still employed on the anniversary date of the award. The 1994 bonuses were based on the following factors: the individual's position; the individual's responsibility and the individual's ability to impact Coastal's financial success.
(5) The options do not carry any stock appreciation rights.
(6) All Other Compensation for 1994 consists of: (i) Coastal contributions to the Coastal Thrift Plan (O. S. Wyatt, Jr. $12,000; David A. Arledge $12,000; James F. Cordes $12,000; James A. King $4,232 and Sam F. Willson, Jr. $12,000) and (ii) certain payments in lieu of Thrift Plan contributions (O. S. Wyatt, Jr. $55,928; David A. Arledge $32,310; James F. Cordes $35,378; James A. King $2,645 and Sam F. Willson, Jr. $14,725). These payments are made to all employees of Coastal and its subsidiaries who participate in the Thrift Plan who must discontinue their Thrift Plan participation due to federal statutory limits.
Mr. Cordes is employed pursuant to a five-year employment contract expiring in 1995, which provides that if he is terminated for a reason not permitted by the employment contract, he will be entitled to receive for the remainder of the term the salary, employee benefits, perquisites, salary increases, bonuses and other incentive compensation which he would have received had he not been terminated. Such reasons are a significant change in title, duties, authorities or reporting responsibilities, a reduction in salary or benefits or a move of the location of his office to a location not acceptable to him.
STOCK OPTIONS
No option/SAR grants were made to the Named Executive Officers during the fiscal year ended December 31, 1994.
OPTION/SAR EXERCISES AND HOLDINGS
The following table sets forth information with respect to the Named Executive Officers, concerning the exercise of options during the last fiscal year and unexercised options and SARs held as of the fiscal year ("FY") ended December 31, 1994.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES (1994)
- ------------------ (1) $-based on the market price of $25.63 at December 31, 1994.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The following report has been provided by Coastal's Compensation and Executive Development Committee (the "Committee") of the Board of Directors in accordance with current Securities and Exchange Commission ("S.E.C.") proxy statement disclosure requirements. The members of the Committee include John M. Bissell (Chairman), Roy D. Chapin, Jr., and Jerome S. Katzin.
This material states Coastal's current overall compensation philosophy and program objectives. Detailed descriptions of Coastal's compensation programs are provided as well as the information on Coastal's 1994 pay levels for the CEO.
OVERALL OBJECTIVES OF THE EXECUTIVE COMPENSATION PROGRAM
Coastal's compensation philosophy and program objectives are directed by two primary guiding principles. First, the program is intended to provide fully competitive levels of compensation - at expected levels of performance - in order to attract, motivate and retain talented executives. Second, the program is intended to create an alignment of interests between Coastal's executives and shareowners such that a significant portion of each executive's compensation is directly linked to maximizing shareholder value.
In support of this philosophy, the executive compensation program is designed to reward performance that is directly relevant to Coastal's short-term and long-term success. As such, Coastal attempts to provide both short-term and long-term incentive pay that varies based on corporate and individual performance.
To accomplish these objectives, the Committee has structured the executive compensation program with three primary underlying components: base salary, annual incentives, and long-term incentives (i.e., stock options). The following sections describe Coastal's plans by element of compensation and discuss how each component relates to Coastal's overall compensation philosophy.
In reviewing this information, reference is often made to the use of competitive market data as criteria for establishing targeted compensation levels. Coastal targets the market 50th percentile for its total compensation program and actual total compensation rates are generally consistent with that target. (However, Coastal's competitive pay posture varies by pay element, as described below.) Several market data sources are used by Coastal, including energy industry norms for the publicly traded peer companies included in Coastal's shareholder return performance graphs, as reflected in these companies' proxy statements. In addition, we utilize published survey data and data obtained from independent consultants that are for general industry companies similar in size (i.e., revenues) to Coastal. The published surveys include data on over 40 companies of comparable size to Coastal, as measured by revenues. Greater emphasis is placed on the published data and data obtained from consultants than on the data for proxy peers, since the published data and consulting data are reflective of company size.
BASE SALARY PROGRAM
Coastal's base salary program is based on a philosophy of providing base pay levels that fall between the market 50th and 75th percentiles. Coastal periodically reviews its executive pay levels to assure consistency with the external market. Generally, Coastal's actual base salary levels for 1994 for executives as a group were consistent with the targeted percentiles. We believe it is crucial to provide strongly competitive salaries over time in order to attract and retain executives who are highly talented.
Annual salary adjustments for Coastal are based on several factors: general levels of market salary increases, individual performance, competitive base salary levels, and Coastal's overall financial results. Coastal reviews performance qualitatively considering total shareholder returns, the level of earnings, return on equity, return on total capital and individual business unit performance. These criteria are assessed qualitatively and are not weighted. All base salary increases are based on a philosophy of pay-for-performance and perceptions of an individual's long-term value to Coastal. As a result, employees with higher levels of performance sustained over time will be paid correspondingly higher salaries.
THE ANNUAL BONUS PLAN
Coastal's Annual Bonus Plan is intended to (1) reward key employees based on company/business unit and individual performance; (2) motivate key employees; and (3) provide competitive cash compensation opportunities to plan participants. Under the plan, target award opportunities vary by individual position and are expressed as a percent of base salary. The individual target award opportunities, which are slightly below market median levels, are then aggregated into a total target pool which is adjusted as described below. The amount a particular executive may earn is directly dependent on the individual's position, responsibility, and ability to impact Coastal's financial success.
The actual bonus pool is established each year by modifying the target pool based on Coastal's overall performance against measures established by the Committee. In fiscal year 1994, the key performance measure considered was earnings before interest and taxes ("EBIT") against plan. This measure was weighted 50% of the total bonus program. In 1994 Coastal's EBIT performance significantly improved over 1993 performance. This 1994 EBIT achievement was above threshold standards (minimum performance level for bonus payment) but below a very aggressive plan, resulting in the EBIT portion of the bonus paid being below target. The remaining 50% of the annual bonus opportunity in 1994 is a discretionary annual bonus pool. As a result, no formula performance measures were used in establishing the size of awards under this portion of the plan. However, in establishing the size of the discretionary bonus pool, the Committee considered Coastal's Return on Equity relative to industry peers (using the same peers included in the shareholder return graphs), Return on Total Capital compared to industry peers, the EBIT performance of each business unit, progress made toward improving Coastal's operational and financial performance, and the need to reward unique individual contributions. These measures were not formally weighted by the Committee. The size of the discretionary bonus pool element was established above threshold but below target based on the qualitative performance assessment described above. As a result, actual bonus payments for 1994 were below target and median market levels.
Individual awards from the established bonus pool are recommended by senior management, with advice and consent from the Committee. Individual awards from the pool are based on business unit and individual employee performance, future potential, and competitive considerations. All individual performance assessments are conducted in a non-formula fashion without specific goal weightings. The total bonus awards made may not exceed the amount of funds in the bonus pool.
LONG-TERM INCENTIVE PLAN
Coastal's Long-Term Incentive Plan ("LTIP") is designed to focus executive efforts on the long-term goals of Coastal and to maximize total return to Coastal's shareholders. While Coastal's LTIP allows the Committee to use a variety of long-term incentive devices, the Committee has relied solely on stock option awards to provide long-term incentive opportunities in recent years.
Stock options align the interests of employees and shareholders by providing value to the executive through stock price appreciation only. All stock options have a ten year term before expiration and are fully exercisable within 7 years of the grant date.
No stock options were granted to the Named Executive Officers in 1994 since Coastal made larger than normal grants to key executives in December 1993. However, it is anticipated that stock option awards will be made periodically at the discretion of the Committee in the future. As in past years, the number of shares actually granted
to a particular participant is also based on Coastal's financial success, its future business plans, and the individual's position and level of responsibility within Coastal. All of these factors are assessed subjectively and are not weighted.
1994 CHIEF EXECUTIVE OFFICER PAY
As previously described, the Committee considers several factors in developing an executive's compensation package. For the CEO, these include competitive market practices (consistent with the philosophy described for other executives), experience, achievement of strategic goals, and the financial success of Coastal (considering the factors described under the annual bonus plan above).
Mr. Wyatt received no salary increase in 1994. The Committee took no action regarding Mr. Wyatt's base salary, in spite of significantly improved Coastal performance during the year. This lack of any adjustment is not a reflection of performance; rather, it is based on considering strong input from the CEO, who wants to see continued improvement in shareholder returns before receiving any base salary increase.
Mr. Wyatt's bonus for 1994 performance was $200,000. This bonus award was below targeted levels (and below market median levels) since Coastal's aggregate performance on the measures described in the annual bonus section of this report was below the aggressive Coastal targets (but above 1993 levels).
The Committee granted no stock options to Mr. Wyatt in 1994 (consistent with past practices), considering the strongly expressed opinion of the CEO. Mr. Wyatt and the Committee considered Mr. Wyatt's current level of stock ownership in reaching this decision.
$1 MILLION PAY DEDUCTIBILITY CAP
Under Section 162(m) of the Internal Revenue Code, public companies are precluded from receiving a tax deduction on compensation paid to executive officers in excess of $1 million. To address the $1 million pay deductibility cap issue, Coastal's 1994 LTIP was structured so that stock option awards (which are intended to be the primary long-term incentive vehicle for the present time) qualify for an exemption from the $1 million pay deductibility limit.
Also, at the present time, the CEO is the only executive whose base salary plus target bonus exceeds $1 million. In order to preserve Coastal's tax deduction for the CEO's base salary plus bonus, Coastal has established a nonqualified deferred compensation program for Mr. Wyatt. Under this program, any annual incentive awards that bring Mr. Wyatt's cash compensation to a level over $1 million will be deferred so that payments occur after Mr. Wyatt is no longer a Named Executive Officer, thus preserving the deductibility of the pay for Coastal.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
John M. Bissell, Chairman Roy D. Chapin, Jr. Jerome S. Katzin
PENSION PLAN
The following table shows for illustration purposes the estimated annual benefits payable currently under the Pension Plan and Coastal's Replacement Pension Plan described below upon retirement at age 65 based on the compensation and years of credited service indicated.
PENSION PLAN TABLE
(A) Compensation covered under the Pension Plan for employees of Coastal and the Coastal Replacement Pension Plan generally includes only base salary and is limited to $150,000 for 1994.
(B) Federal legislation has reduced the benefit which may be earned due to future service; however, benefits previously earned may not be reduced. At December 31, 1994 each of the individuals named in the Summary Compensation Table had covered salary for future benefit accrual of $150,000 and the following years of credited service and pension payable at age 65 (or current age, if over 65): Mr. Wyatt, 39 years, $469,834; Mr. Arledge, 14 years, $54,181; Mr. Cordes, 17 years, $74,523; Mr. King, 2 years, $9,474 (not vested) and Mr. Willson, 22 years, $98,357.
(C) The normal form of retirement income is a straight life annuity. Benefits payable under the Pension Plan are subject to offset by 1.5% of applicable monthly social security benefits multiplied by the number of years of credited service (up to 33 years).
The Employee Retirement Income Security Act of 1974, as amended by subsequent legislation, limits the retirement benefits payable under the tax-qualified Pension Plan. Where this occurs, Coastal will provide to certain executives, including persons named in the Summary Compensation Table, additional nonqualified retirement benefits under a Coastal Replacement Pension Plan. These benefits, plus payments under the Pension Plan, will not exceed the maximum amount which Coastal would have been required to provide under the Pension Plan before application of the legislative limitations, and are reflected in the above table and footnote (B).
PERFORMANCE GRAPHS - SHAREHOLDER RETURN ON COMMON STOCK
FIVE-YEAR CUMULATIVE VALUES $100 INVESTED 12/31/89 DIVIDENDS REINVESTED
[GRAPH APPEARS HERE]
YEAR ENDED 12/31
(1) The Index is based on Value Line Diversified Natural Gas Group - the Performance Graphs reflect total shareholder return weighted to reflect the market capitalizations of the peer companies. The peer group is comprised of: NorAm, Burlington Res., Columbia, Consolidated Nat. Gas, Eastern Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy, National Fuel Gas, Panhandle Eastern, Seagull Energy, Sonat, Southwestern Energy, Tenneco, Transco, Valero and Williams Cos. (2) Coastal is excluded from the Index.
TEN-YEAR TWO MONTHS CUMULATIVE VALUES $100 INVESTED 12/31/84 DIVIDENDS REINVESTED
[GRAPH APPEARS HERE]
YEAR ENDED 12/31
(1) The Index is based on Value Line Diversified Natural Gas Group - the Performance Graphs reflect total shareholder return weighted to reflect the market capitalizations of the peer companies. The peer group is comprised of: NorAm, Burlington Res., Columbia, Consolidated Nat. Gas, Eastern Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy, National Fuel Gas, Panhandle Eastern, Seagull Energy, Sonat, Southwestern Energy, Tenneco, Transco, Valero and Williams Cos. (2) Coastal is excluded from the Index.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security ownership of certain beneficial owners.
The following is information, as of March 15, 1995, on each person known or believed by Colorado to be the beneficial owner of 5% or more of any class of its voting securities:
(b) Security ownership of management.
Colorado is an indirectly wholly-owned subsidiary of Coastal. Information concerning the security ownership of certain beneficial owners and management of Coastal is contained in this section.
The total number of shares of stock of Coastal outstanding as of March 15, 1995 is 112,960,388: consisting of 63,118 shares of $1.19 Cumulative Convertible Preferred Stock, Series A (the "Series A Preferred Stock"), 83,756 shares of $1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred Stock"), 34,191 shares of $5.00 Cumulative Convertible Preferred Stock, Series C (the "Series C Preferred Stock"), and 8,000,000 non-voting shares of $2.125 Cumulative Preferred Stock, Series H, 104,363,374 shares of Common Stock, and 415,949 shares of Class A Common Stock.
Each voting share of Common Stock or Preferred Stock entitles the holder to one vote with respect to all matters to come before a shareholders' meeting while each share of Class A Common Stock entitles the holder to 100 votes. However, 25% of Coastal's directors standing for election at each annual meeting will be determined solely by holders of the Common Stock and voting Preferred Stock voting as a class.
The following table sets forth information, as of March 15, 1995, with respect to each person known or believed by Coastal to be the beneficial owner, who has or shares voting and/or investment power (other than as set forth below), of more than five percent (5%) of any class of its voting securities.
__________
(1) Class includes presently exercisable stock options held by directors and executive officers.
(2) Includes 7,354 shares of Class A Common Stock owned by the spouse and a son of Mr. Wyatt, as to which shares beneficial ownership is disclaimed.
(3) The Trustee/Custodian is the record owner of these shares; and also is the record owner of 953 shares of the Series B Preferred Stock, each of which is convertible into 3.6125 shares of Common Stock and 0.1 share of Class A Common Stock. Voting instructions are requested from each participant in the Thrift Plan and ESOP and from the trustees under a Pension Trust. Absent voting instructions, the Trustee is permitted to vote Thrift Plan shares on any matter, but has no authority to vote ESOP shares or Pension Plan shares. Nor does the Trustee/Custodian have any authority to dispose of shares except pursuant to instructions of the administrator of the Thrift Plan and ESOP or pursuant to instructions from the trustees under the Pension Trust.
(4) Members of the DeZurik family acquired the Series C Preferred Stock in connection with a 1972 Agreement of Merger involving the acquisition of Colorado, a subsidiary of Coastal.
The following table sets forth information, as of March 15, 1995, regarding each of the then current directors, including Class III directors standing for election, and all directors and executive officers as a group. Each director has furnished the information with respect to age, principal occupation and ownership of shares of stock of Coastal. Messrs. Bissell, Burrow, Chapin and Katzin are Class I directors whose terms expire in 1996; Messrs. Arledge, Brundrett, Wooddy and Wyatt are Class II directors whose terms expire in 1997 and Messrs. Cordes, Gates, Johnson, Marshall and McDade are Class III directors whose terms expire in 1995.
* Less than one percent unless otherwise indicated. Class includes outstanding shares and presently exercisable stock options held by directors and executive officers. Excluding presently exercisable stock options, directors and executive officers as a group would own 186,832 shares of Class A Common Stock, which would constitute 44.9% of the shares of such class.
(1) Except for the shares referred to in Notes 2 and 3 below, and the shares represented by presently exercisable stock options, the holders are believed by Coastal to have sole voting and investment power as to the shares indicated. Amounts include shares in Coastal ESOP and Thrift Plan, and presently exercisable stock options held by Messrs. Burrow (14,189 shares of Common Stock), Arledge (160,503 shares of Common Stock and 13,868 shares of Class A Common Stock), Cordes (103,785 shares of Common Stock) and Johnson (53,915 shares of Common Stock).
(2) Includes shares owned by the spouse and a son of Mr. Wyatt (266,295 shares of Common Stock and 7,354 shares of Class A Common Stock), by the spouse of Mr. Burrow (5,000 shares of Common Stock), by the spouse of Mr. Chapin (1,000 shares of Common Stock) and by the spouse of Mr. Katzin (928 shares of Common Stock), as to which shares beneficial ownership is disclaimed; also includes shares owned by the estate of the late Mrs. Marshall (4,362 shares of Common Stock and 100 shares of Class A Common Stock).
(3) Includes presently exercisable stock options to purchase 674,265 shares of Common Stock and 13,868 shares of Class A Common Stock; also includes 280,339 shares of Common Stock and 7,354 shares of Class A Common Stock owned by spouses and children, as to which shares beneficial ownership is disclaimed; also includes 4,362 shares of Common Stock and 100 shares of Class A Common Stock owned by the estate named in Note 2 above. In addition, one executive officer owns 8 shares of Series B Preferred Stock, each of which is convertible into 3.6125 shares of Common Stock and 0.1 share of Class A Common Stock.
No incumbent director is related by blood, marriage or adoption to another director or to any executive officer of Coastal or its subsidiaries or affiliates.
Except as hereafter indicated, the above table includes the principal occupation of each of the directors during the past five years. The listed executive officers have held various executive positions with Coastal, ANR, ANR Pipeline and/or Colorado during the five-year period.
Mr. Bissell is a member of the Boards of Directors of Old Kent Financial Corporation and Batts Inc.
Mr. Cordes is a member of the Board of Directors of Comerica Inc.
Mr. Katzin is a member of the Board of Directors of Qualcomm Incorporated.
Mr. Marshall is a member of the Boards of Directors of Missouri-Kansas-Texas Railroad Company and Presidio Oil Company.
Mr. McDade is a trial lawyer and the founding senior partner of the Houston law firm of McDade & Fogler L.L.P. Prior to forming McDade & Fogler L.L.P. he was a senior partner in the Houston law firm of Fulbright & Jaworski. He is a member of the Board of Directors of Equity Corporation International.
Messrs. Arledge, Burrow, Cordes and Wyatt are directors of Colorado and ANR Pipeline. Both of these subsidiaries of Coastal are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
(a) Transactions with management and others.
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, 1994 the Company had advanced $220.7 million to associated companies at a market rate of interest. Such amount is repayable on demand.
Additional information called for by this item is set forth under Item 11, "Executive Compensation" and Notes 9 and 13 of Notes to Consolidated Financial Statements included herein.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
Not applicable.
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:
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.
(21)* Subsidiaries of the Company.
(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, 1994.
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 March 29, 1995
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: HAROLD BURROW -------------------------------- Harold Burrow Chairman of the Board March 29, 1995
By: JON R. WHITNEY -------------------------------- Jon R. Whitney President, Chief Executive Officer and Director March 29, 1995
By: DAVID A. ARLEDGE -------------------------------- David A. Arledge Principal Financial Officer and Director March 29, 1995
By: DAN A. HOMEC -------------------------------- Dan A. Homec Assistant Vice President and Principal Accounting Officer March 29, 1995
By: RICHARD L. ANDERSON By: ROGER L. OGDEN ---------------------------- ---------------------------- Richard L. Anderson Roger L. Ogden Director Director March 29, 1995 March 29, 1995
By: JAMES F. CORDES By: PAUL W. POWERS ---------------------------- ---------------------------- James F. Cordes Paul W. Powers Director Director March 29, 1995 March 29, 1995
By: PETER J. KING, JR. By: WILLIAM B. TUTT ---------------------------- ---------------------------- Peter J. King, Jr. William B. Tutt Director Director March 29, 1995 March 29, 1995
By: REBECCA H. NOECKER By: O. S. WYATT, JR. ---------------------------- ---------------------------- Rebecca H. Noecker O. S. Wyatt, Jr. Director Director March 29, 1995 March 29, 1995
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis.
LIQUIDITY AND CAPITAL RESOURCES
The Company uses the following consolidated ratios to measure liquidity and ability to meet future funding needs and debt service requirements.
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 1992 through 1994 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 $195.7 million in 1994 and $77.6 million in 1993. Pre-payments for gas supply and settlement of natural gas contract disputes required investments of $28 thousand in 1994 and $7.1 million in 1993. Liquidity needs were met in 1994 by internally generated funds.
The Company has adopted a capital expenditure budget of approximately $71.3 million for 1995, an increase from the capital additions of $52.3 million in 1994. The anticipated increase in 1995 is the result of a $24.6 million increase for natural gas projects partially offset by a $5.6 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, 1994, the Company and certain affiliates could incur approximately $770 million of additional indebtedness. For the Company and such affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $350 million of indebtedness under this agreement would need to be retired.
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, 1994, the Company had advanced $220.7 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, renegotiating the remaining gas purchase contracts which are above market in an effort to lower its cost of gas and reduce take-or-pay obligations, pursuing innovative marketing strategies and applying strict cost- cutting measures.
The Company adopted FAS No. 112, "Employers' Accounting for Postemployment Benefits", effective January 1, 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The effect of this new standard did not have a material effect on the Company's consolidated financial position or results of operations.
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 facilities. The Company anticipates annual capital expenditures of $1 to $2 million over the next several years aimed at maintaining compliance with such laws and regulations. Additionally, appropriate governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act, also known as "Superfund", as reauthorized, imposes liability, without regard to fault or the legality of the original act, for disposal of a "hazardous substance." The Company is not presently, and has not been in the past, a potentially responsible party ("PRP") in any "Superfund" waste disposal sites. However, the Company has received notice from a committee formed from a group of 55 companies who are named as PRPs at one site requesting the Company pay a de minimis share (approximately $36,000) of the associated clean-up costs.
There are additional areas of environmental remediation responsibilities which may fall upon the Company. The states have regulatory programs that mandate waste clean-up. The Clean Air Act Amendments of 1990 include new permitting regulations which will result in increased operating expenditures.
Future information and developments will require the Company to continually reassess the expected impact of all applicable environmental laws and regulations. Compliance with all applicable environmental protection laws and regulations is not expected to have a material adverse impact on the Company's liquidity, consolidated financial position or results of operations.
RESULTS OF OPERATIONS
OPERATING REVENUES
The following table reflects the increase (decrease) in operating revenues experienced by segment during the past two years (millions of dollars):
NATURAL GAS
On April 8, 1992, the FERC issued Order 636 which required significant changes in the services provided by interstate natural gas pipelines (see Note 10 of the Notes to Consolidated Financial Statements). The Company's restructured services became effective October 1, 1993, and the Company now offers a wide range of "unbundled" storage, transportation and balancing services. Colorado's gas sales contracts have been unbundled and such sales are now made at the producer wellhead. Gas sales contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year.
1994 Versus 1993. Revenues from natural gas operations decreased in 1994 due to lower average sales prices of $59 million, the $35 million sale of storage gas inventory in 1993 pursuant to the implementation of Order 636, an $11 million decrease resulting from reduced sales volumes, increased reservations of $17 million and reduced extracted products revenue of $4 million offset by increased transportation and gathering revenues of $55 million and increased contract storage revenue of $7 million.
1993 Versus 1992. Revenues from natural gas operations increased in 1993 due to the $35 million sale of storage gas inventory, increased transportation and gathering revenues of $34 million and increased extracted products revenue of $4 million offset by lower sales prices of $23 million and a $15 million decrease resulting from reduced sales volumes.
The daily average volumes of natural gas sold were 259 MMcf, 272 MMcf and 287 MMcf for 1994, 1993 and 1992, respectively. However, over the remaining life of Colorado's current gas sales contracts (most of which extend through September 30, 1996), it is expected that customers will reduce their contractual sales entitlement pursuant to the provisions of Order 636. At this time, however, the magnitude of those conversions cannot be estimated with reasonable certainty. Transportation volumes increased by 9% in 1994 over the 1993 level and are expected to increase slightly in 1995.
EXPLORATION AND PRODUCTION
1994 Versus 1993. Revenues from exploration and production increased in 1994 as natural gas volumes generated a $9 million increase and other increases of $2 million were partially offset by decreased natural gas sales prices of $5 million.
1993 Versus 1992. Revenues from exploration and production increased in 1993 as natural gas volumes generated a $4 million increase and natural gas prices increased by $1 million, partially offset by decreases of $1 million.
OTHER INCOME - NET
The increase in 1994 and the decrease in 1993 primarily reflect changes in interest income resulting from loans to affiliated companies.
COST OF GAS SOLD
1994 Versus 1993. The decrease is due primarily to reduced average gas purchase rates of $24 million, reduced purchase volumes of $9 million, decreased gas used costs of $19 million, decreased transportation, gathering and exchange gas costs of $15 million and storage gas costs associated with the 1993 sale of storage gas inventory pursuant to Order 636, net of injection/withdrawals in the amount of $11 million, partially offset by other increases of $3 million.
1993 Versus 1992. The increase in 1993 was due primarily to increased transportation, gathering and exchange gas costs of $17 million and storage gas costs associated with the sale of storage gas inventory pursuant to Order 636, net of injection/withdrawals in the amount of $11 million, partially offset by other decreases of $1 million.
OPERATION AND MAINTENANCE
1994 Versus 1993. Operation and maintenance expenses increased in 1994 due primarily to increased gas used in operations of $19 million partially offset by decreased gas and gas liquids handling of $3 million, decreased production taxes of $3 million and other decreases of $2 million.
1993 Versus 1992. Operation and maintenance expenses increased in 1993 due primarily to increased property and production taxes of $3 million, increased professional services of $2 million, increased gas used costs of $2 million and other increases of $1 million.
DEPRECIATION, DEPLETION AND AMORTIZATION
1994 Versus 1993. Depreciation, depletion and amortization increased $5 million in 1994 due primarily to increased production volumes in the exploration and production segment and an increase in the natural gas segment's depreciable plant.
1993 Versus 1992. Depreciation, depletion and amortization increased $8 million in 1993 due primarily to an increase in the natural gas segment's depreciable plant and increased production volumes in the exploration and production segment.
OPERATING PROFIT
The following table reflects the increase (decrease) in operating profit experienced by segment during the past two years (millions of dollars):
NATURAL GAS
1994 Versus 1993. The natural gas segment's operating profit increase in 1994 is due to decreased gas related costs of $75 million and an increase in other income of $5 million partially offset by decreased operating revenues of $64 million and increased operation and maintenance expenses of $11 million.
1993 Versus 1992. The natural gas segment's operating profit decrease in 1993 is due to increased gas related costs of $27 million, increased operation and maintenance expenses of $6 million, increased depreciation, depletion and amortization expenses of $6 million and other increases of $3 million partially offset by increased operating revenues of $35 million.
EXPLORATION AND PRODUCTION
1994 Versus 1993. The exploration and production segment's operating profit increase in 1994 is due to increased revenues of $6 million, partially offset by a $4 million increase in depreciation, depletion and amortization.
1993 Versus 1992. The exploration and production segment's operating profit was unchanged from 1992 as increased revenues of $4 million were offset by increases of $2 million for operation and maintenance expenses and $2 million for depreciation, depletion and amortization.
INTEREST EXPENSE
The decrease in both 1994 and 1993 is primarily due to lower average debt outstanding partially offset by increases in other financial expenses.
TAXES ON INCOME
Income taxes fluctuated primarily as a result of changing levels of income before taxes and changes in the effective income tax rate. The effective federal income tax rate for the Company was 33% in 1994 and 32% in 1993 and 1992.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders 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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
As discussed in Note 8 to the consolidated financial statements, in 1993 the Company changed its method of accounting for postretirement benefits other than pensions to conform with Statement of Financial Accounting Standards No. 106.
DELOITTE & TOUCHE LLP
Denver, Colorado February 2, 1995
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 Company is regulated by and subject to the regulations and accounting procedures of the FERC. Colorado meets the criteria and, accordingly, follows the reporting and accounting requirements of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
- - Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany transactions.
- - 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 $17.5 million, $20.3 million and $20.7 million in 1994, 1993 and 1992, respectively. Cash payments for income taxes amounted to $41.9 million, $40.5 million and $22.5 million in 1994, 1993 and 1992, respectively.
- - Inventories
Materials and supplies inventories are carried principally at average cost. Gas stored underground is carried at last-in, first-out cost ("LIFO"). The excess of replacement cost over the carrying value of gas in underground storage carried by the LIFO method, which is classified as Plant, Property and Equipment, was $31.2 million and $52.6 million at December 31, 1994 and 1993, respectively.
- - Plant, Property and Equipment
Property additions and betterments are capitalized at cost. In accordance with accounting requirements of the FERC, an allowance for equity and borrowed funds used during construction is included in the cost of the natural gas segment's additions and betterments. This cost amounted to $1.9 million, $1.2 million and $2.4 million in 1994, 1993 and 1992, respectively. 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.
The Company generally provides for depreciation on a straight-line basis, although the unit-of-production method is used for depreciation, depletion and amortization of certain natural gas properties. The depreciation rates for production and gathering, products extraction, storage, and transmission plant are 1.55 percent, 3.85 percent, 2.90 percent, and 2.60 percent, respectively. The unit-of-production method is utilized for depreciation, depletion and amortization of oil and gas properties. The average amortization rate per equivalent unit of a thousand cubic feet of gas production for oil and gas properties was $0.96 for the year 1994 and $1.00 for the years 1993 and 1992.
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 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.
- - 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.
- - Gain or Loss on Reacquired Debt
As required by the FERC, gain or loss on reacquired debt is deferred and amortized over the remaining life of the related long-term indebtedness.
- - 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 results of operations or financial position.
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.
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, 1994, the Company and certain affiliates could incur approximately $770 million of additional indebtedness. For the Company and such affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $350 million of indebtedness under this agreement would need to be retired.
3. Take-or-Pay Obligations
The Consolidated Balance Sheet includes assets of $5.7 million and $13.2 million at December 31, 1994 and 1993, respectively, relating to prepayments for gas under gas purchase contracts with producers and settlement payment amounts relative to the restructuring of gas purchase contracts as negotiated with producers. As a result of the implementation of Order 636 by the Company on October 1, 1993 (see Note 10 of Notes to Consolidated Financial Statements), gas sales are made at negotiated prices and are not subject to regulatory price controls. This does not affect the recoverability or the results of pending take-or-pay litigation or any take-or-pay or contractual reformation settlements that the Company may achieve with respect to periods before October 1, 1993. A portion of the costs associated with take-or-pay incurred prior to October 1, 1993, may continue to be recovered pursuant to FERC's Order No. 528.
A few gas producers have instituted litigation arising out of take-or-pay claims against the Company. In the Company's experience, producers' claims are generally vastly overstated and do not consider all adjustments provided for in the contract or allowed by law. The Company has resolved the majority of the exposure with its suppliers for approximately 11% of the amounts claimed. At December 31, 1994, the Company estimated that unresolved asserted and unasserted producers' claims amounted to approximately $18.0 million. The remaining disputes will be settled where possible and litigated if settlement is not possible.
At December 31, 1994, the Company was committed to make future purchases under certain take-or-pay contracts with fixed, minimum or escalating price provisions. Based on contracts in effect at that date, and before considering reductions provided in the contracts or applicable law, such commitments are estimated to be $.8 million, $.7 million, $.7 million, $.6 million and $.6 million for the years 1995-1999, respectively, and $2.9 million thereafter. Such commitments have not been adjusted for all amounts which may be assigned or released, or for the results of future litigation or negotiation with producers.
The Company has made provisions, which it believes are adequate, for payments to producers that may be required for settlement of take-or-pay claims and restructuring of future contractual commitments. In determining the net loss relating to such provisions, the Company has also made accruals for the estimated portion of such payments which would be recoverable pursuant to FERC- approved settlements with customers. Such provisions and accruals were not material to the Company for the years 1994, 1993 and 1992.
4. Common Stock and Other Stockholders' Equity
All of the Company's common stock is owned by Coastal Natural Gas.
Certain provisions of the preferred stock resolutions restrict the payment of dividends on common stock; however, all $364.8 million of retained earnings were available for dividends on the common stock of the Company at December 31, 1994.
5. Mandatory Redemption Preferred Stock
The Company's Mandatory Redemption Preferred Stock consists of the following:
5.50% Cumulative Preferred Stock (Third Series) - Of the 150,000 shares authorized and issued, 5,560 were outstanding as of December 31, 1994. The remaining stock outstanding is due in 1997 at par value with an annual dividend rate of 5.5%.
The outstanding series of the Company's Mandatory Redemption Preferred Stock is a $100 par value, cumulative, non-convertible and non-voting issue. If at any time dividends on the Mandatory Redemption Preferred Stock shall be in arrears in an amount equal to six quarterly dividends, holders of the Mandatory Redemption Preferred Stock, voting as a class, will have the right to elect not less than one-fourth of the Company's Board of Directors until all accrued and unpaid dividends on the Mandatory Redemption Preferred Stock are paid in full. In addition, if at any time dividends shall be in arrears in an aggregate amount equal to eight full quarterly dividends, holders of these securities, voting as a class, will have the right to elect such number of Directors as shall be necessary to constitute a minimum majority of the Board of Directors until all accrued and unpaid dividends on the Mandatory Redemption Preferred Stock are paid in full.
6. 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 and the notes receivable from affiliates are reasonable estimates of their fair values. The estimated value of the Company's long-term debt and mandatory redemption preferred stock is based on interest rates at December 31, 1994 and 1993, respectively, for new issues with similar remaining maturities.
7. Taxes On Income
Provisions for income taxes are composed of the following (thousands of dollars):
Coastal and the Internal Revenue Service ("IRS") Appeals Office have settled all contested adjustments to federal income tax returns filed for the years 1982 through 1984. Coastal's federal income tax returns filed for the years 1985 through 1987 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. Examinations of Coastal's federal income tax returns for 1988, 1989 and 1990 are currently in progress. 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):
8. 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, 1994, the Plan did not have an unfunded accumulated benefit obligation. Colorado made no contributions to the Plan for 1994, 1993 or 1992. 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 $2.8 million for each of the years 1994 and 1993 and $2.6 million for 1992.
The Company provides certain health care and life insurance benefits for retired employees. Effective January 1, 1993, the Company adopted FAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("FAS No. 106"). FAS No. 106 requires the Company to accrue the estimated cost of retiree benefit payments during the years the employee provides services. The Company previously expensed the cost of these benefits, which are principally health care, as claims were incurred. FAS No. 106 allows recognition of the cumulative effect of the liability in the year of the adoption or the amortization of the obligation over a period of up to twenty years. The Company elected to recognize the initial postretirement benefit obligation of approximately $18.2 million over a period of twenty years. Recognition of FAS No. 106 cost is determined by currently effective rates as filed with the FERC. The difference between actuarially determined FAS No. 106 costs and the level of costs collected in rates is reflected as a deferred regulatory amount.
The following tables set forth the accumulated postretirement benefit asset recognized in the Company's Consolidated Balance Sheet and the benefit cost for the years ended December 31, 1994 and 1993 (millions of dollars):
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 12.0% in 1994, declining gradually to 6.0% by the year 2005. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 16.0% in 1993. 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, 1994 and the net postretirement health care cost by approximately 4.01%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 8.75%.
The Company adopted FAS No. 112, "Employers' Accounting for Postemployment Benefits" effective January 1, 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The implementation of the new standard did not have a material effect on the Company's consolidated financial position or results of operations.
9. Commitments
The Company and its subsidiaries had rental expense of approximately $7.3 million, $9.0 million and $9.7 million in 1994, 1993 and 1992, respectively (excluding leases covering natural resources). The aggregate minimum lease payments under existing noncapitalized long-term leases are estimated to be $4.5 million, $3.6 million, $1.7 million, $1.6 million, and $.9 million for the years 1995-1999, respectively, and $1.1 million thereafter.
The Company has executed a service agreement with WIC, an affiliate, providing for the availability of pipeline transportation capacity through January 1, 2004. Under the service agreement, the Company is required to make minimum payments on a monthly basis. The estimated amounts of minimum annual payments are as follows (thousands of dollars):
The Company expensed approximately $4.6 million related to the minimum payments under this agreement in 1994.
10. Litigation and Regulatory Matters
- - Litigation
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, 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. Trial has been set for March 22, 1995.
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.
- - Rate Matters
Colorado's gas sales for resale contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, Colorado's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by the FERC. Colorado is also authorized to abandon all sales for resale without prior FERC approval at such time as the contracts expire. Pursuant to Order 636, Colorado's gas sales have been unbundled at the producer wellhead. Effective October 1, 1993, Colorado formed an unincorporated Merchant Division to conduct most of the Company's sales activity in the Order 636 environment. The gas sales volumes reported include those sales which continue to be made by Colorado together with those of its Merchant Division.
On March 31, 1993, Colorado filed at FERC under Docket RP93-99 to increase its rates by approximately $26.5 million annually. Such rates (adjusted to reflect Colorado's Order 636 program) became effective subject to refund on October 1, 1993. On November 10, 1994, the FERC approved a settlement offer submitted by the Company which resolved all of the issues in the proceeding. The Company has implemented the rates established in the settlement for prospective application and will be required to make refunds as a result of the approval of the settlement. Such refunds will be distributed in March 1995. The Company has fully accrued for these refunds and therefore such refunds will not have an adverse effect on its consolidated financial position or results of operations.
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. 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.
11. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1994 and 1993 were (thousands of dollars):
12. Segment Reporting
Natural gas system operations and gas and oil exploration and production are the two segments of the Company's operations.
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.
Operating revenues by segment include both sales to unaffiliated customers, as reported in the Company's statement of consolidated earnings, and intersegment sales, which are accounted for on the basis of contract, current market, or internally established transfer prices. The intersegment sales are from the exploration and production segment to the natural gas segment.
Operating profit is total revenues less interest income from affiliates and operating expenses. Operating expenses exclude income taxes, corporate general and administrative expenses and interest.
Identifiable assets by segment are those assets that are used in the Company's operations in each segment.
The Company's operating revenues and operating profit for the years ended December 31, 1994, 1993 and 1992, and identifiable assets as of December 31, 1994, 1993 and 1992, by segment, are shown below (thousands of dollars):
Capital expenditures and depreciation, depletion and amortization expense by segment for the years ended December 31, 1994, 1993 and 1992, were (thousands of dollars):
Revenues from sales 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 sales and transportation of natural gas to any other single customer did not amount to 10% or more of the Company's consolidated revenues for the years ended December 31, 1994, 1993 and 1992, respectively. The Company does not have any foreign operations.
Gas sales are made primarily to public utilities which resell the gas to residential, commercial and industrial customers and to end-users in Colorado and southeastern Wyoming. 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. The Company extends credit for sales and transportation services provided to certain qualifying companies.
13. Transactions with Affiliates
The Statement of Consolidated Earnings includes the following major transactions with affiliates (thousands of dollars):
/1/ The 1994 amounts were immaterial. /2/ The 1992 amounts were immaterial. /3/ The 1993 and 1992 amounts were immaterial.
Services provided by the Company at cost for affiliated companies were $8.3 million for 1994, $7.9 million for 1993 and $8.1 million for 1992. Services provided by affiliated companies for the Company at cost were $7.7 million for 1994, $8.1 million for 1993 and $7.9 million for 1992. 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. Rental expense of approximately $1.4 million for 1994, $1.5 million in 1993 and $1.6 million in 1992 was recorded in conjunction with the terms of the lease agreements.
In 1992, the Company entered into a five-year lease agreement with ANR Production Company, an affiliate, for the rental of certain pipeline facilities. Annual rental expense of approximately $.2 million was recorded in 1994, 1993 and 1992 in conjunction with the terms of the lease agreement.
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, 1994, the Company had advanced $220.7 million to associated companies at a market rate of interest. Such amount is repayable on demand.
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 systems 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. Most of the Company-owned gas reserves are dedicated to Colorado's system.
ESTIMATED QUANTITIES OF PROVED RESERVES
Changes in proved reserves since the end of 1991 are shown in the following table:
Total proved reserves for natural gas systems exclude storage gas and liquids volumes. The natural gas systems storage gas volumes are 39,984, 41,012 and 55,284 MMcf and storage liquids volumes are approximately 172,000, 150,000 and 159,000 barrels at December 31, 1994, 1993 and 1992, respectively.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES (thousands of dollars)
As described in Note 1 of Notes to Consolidated Financial Statements, the Company follows the full-cost method of accounting for oil and gas properties.
COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (thousands of dollars)
Property acquisition costs consist principally of amounts paid for proved reserves.
RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES (thousands of dollars)
The average amortization rate per equivalent Mcf was $0.96 in 1994 and $1.00 for both 1993 and 1992.
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, as calculated by the Company's independent engineers, 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, may be subject to 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 which were approximately 40 Bcf and 172 thousand barrels, respectively, at the end of 1994.
EXHIBIT INDEX
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Note: + Indicates documents incorporated by reference from prior filing indicated. * Indicates documents filed herewith.