ITEM 1. BUSINESS.
INTRODUCTION
Coastal, acting through its subsidiaries, is a diversified energy holding company with subsidiary operations in natural gas marketing, processing, storage and transmission; petroleum refining, marketing and distribution; gas and oil exploration and production; coal mining; chemicals; independent power production; and trucking. The Company was incorporated under the laws of Delaware in 1972 to become the successor parent, through a corporate restructuring, of a corporate enterprise founded in 1955. The Company employed approximately 16,000 persons as of December 31, 1993.
Annual Reports on Form 10-K for the year ended December 31, 1993, are also filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by each of the six limited partnership oil and gas drilling programs, of which Coastal's subsidiary, Coastal Limited Ventures, Inc., is the managing general partner. Such reports contain additional details concerning the reporting organizations.
The operating revenues and operating profit of the Company by industry segment for the years ended December 31, 1993, 1992 and 1991, and the related identifiable assets as of December 31, 1993, 1992 and 1991, are set forth in Note 10 of the Notes to Consolidated Financial Statements included herein. Information concerning inventories is set forth in Note 2 of the Notes to Consolidated Financial Statements included herein.
NATURAL GAS SYSTEMS
OPERATIONS
GENERAL
Natural gas operations involve the production, purchase, gathering, processing, transportation, balancing, storage and sale of natural gas to and for utilities, industrial customers, distributors, other pipeline companies and end-users.
ANR Pipeline is involved in the storage, transportation and balancing of natural gas. ANR Pipeline provides these services for various customers through its facilities located in Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Nebraska, New Jersey, Ohio, Oklahoma, Tennessee, Texas, Wisconsin, Wyoming and offshore in federal waters. Prior to November 1, 1993, ANR Pipeline was also engaged in the sale for resale of natural gas. With ANR Pipeline's implementation of Order 636 effective November 1, 1993, ANR Pipeline no longer provides a merchant service. However, former gas sales customers of ANR Pipeline have largely retained their firm storage and transportation service levels previously included in their "bundled" gas sales services. ANR Pipeline will auction gas on the open market as part of its gas restructuring program designed to handle the continuation of certain gas purchase contracts pending renegotiation or expiration of such contracts. ANR Pipeline's gas sales for resale customers previously included 51 local distributors in Michigan, Wisconsin, Illinois, Indiana, Iowa, Kansas, Missouri, Ohio and Tennessee. ANR Pipeline operates two major offshore gas pipeline systems in the Gulf of Mexico which are owned by HIOS and UTOS, general partnerships composed of ANR Pipeline subsidiaries and subsidiaries of other pipeline companies. ANR Pipeline also operates Empire, a 156-mile pipeline extending from Niagara Falls to Syracuse, New York, in which an affiliate of ANR Pipeline has a 45% interest.
During 1993, approximately 62% of ANR Pipeline's gas supply was purchased from gas producers and marketers in Illinois, Indiana, Kansas, Louisiana, Michigan, Mississippi, Oklahoma, Texas, Wisconsin, Wyoming and the Texas and Louisiana offshore areas; approximately 32% was obtained from three Canadian suppliers; and approximately 6% was purchased from the Dakota Gasification Company in North Dakota.
ANR Pipeline's two interconnected large-diameter multiple pipeline systems transport gas to the Midwest from (a) the Hugoton Field and other fields in the Anadarko Basin in Texas and Oklahoma and (b) the Louisiana onshore and Louisiana and Texas offshore areas. Gas from Wyoming and Canada is obtained by ANR Pipeline through transportation and exchange agreements with other companies.
ANR Pipeline's principal pipeline facilities at December 31, 1993 consisted of 12,657 miles of pipeline and 97 compressor stations with 1,069,788 installed horsepower. At December 31, 1993, the design peak day delivery capacity of the transmission system, considering supply sources, storage, markets and transportation for others, was approximately 5.6 Bcf per day.
Colorado is involved in all phases of the production, gathering, processing, transportation, storage and sale of natural gas. Colorado purchases and produces natural gas and makes sales of such gas 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. Colorado's gas gathering and processing facilities are located throughout the production areas adjacent to its transmission system. Most of Colorado's gathering facilities connect directly to its transmission system, but some gathering systems are connected to other pipelines. Colorado also has certain gathering facilities located in New Mexico. Colorado owns four underground gas storage fields; three located in Colorado, and one in Kansas.
Colorado's principal pipeline facilities at December 31, 1993 consisted of 6,347 miles of pipeline and 65 compressor stations with approximately 346,000 installed horsepower. At December 31, 1993, 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 per year and a peak day delivery capacity of approximately 769 MMcf.
The Company formed CGS as a wholly-owned subsidiary in early 1993 to consolidate its unregulated natural gas businesses. CGS and its subsidiaries operate certain of Coastal's natural gas gathering and processing, gas supply and marketing, price risk management and producer financing activities.
COMPETITION
ANR Pipeline and Colorado have historically competed with interstate and intrastate pipeline companies in the sale, storage and transportation of gas and with independent producers, brokers, marketers and other pipelines in the gathering, processing and sale of gas within their service areas. On October 1, 1993 and November 1, 1993, Colorado and ANR Pipeline, respectively, implemented Order 636 on their systems. As a consequence, ANR Pipeline is no longer a seller of natural gas to resale customers. 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, which may result in reduced interruptible transportation revenue of pipelines. Additional information on this subject is included under "Regulations Affecting Gas Systems" 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 ANR Pipeline and Colorado.
ANR Pipeline's storage, transportation and balancing services are influenced by its customers' access to alternative providers of such services. ANR Pipeline competes directly with Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Northern Natural Gas Company, Natural Gas Pipeline Company of America, Michigan
Consolidated Gas Company and CMS Energy Company in its principal market areas of Michigan and Wisconsin for its storage, transportation and balancing business.
ANR PIPELINE
GAS SALES FOR RESALE AND TRANSPORTATION
ANR Pipeline transports gas to markets on its system and other markets under transportation and exchange arrangements with other companies, including distributors, intrastate and interstate pipelines, producers, brokers, marketers and end-users. Typically, these arrangements call for ANR Pipeline to transport such gas to points of interconnection with local distribution companies or other interstate pipelines. Transportation service revenues provided by ANR Pipeline amounted to $533 million for 1993 compared to $463 million for 1992 and $382 million for 1991.
During the period January through October of 1993, ANR Pipeline sold 228 Bcf of gas, of which approximately 71% was sold to its three largest customers: Michigan Consolidated Gas Company, Wisconsin Gas Company and Wisconsin Natural Gas Company. Michigan Consolidated Gas Company serves the City of Detroit and certain surrounding areas, the industrial cities of Grand Rapids and Muskegon, the communities of Ann Arbor and Ypsilanti and numerous other communities in Michigan. Wisconsin Gas Company serves the Milwaukee metropolitan area and numerous other communities in Wisconsin. Wisconsin Natural Gas Company serves the industrial cities of Racine, Kenosha, Appleton and their surrounding areas in Wisconsin. In 1993, ANR Pipeline provided 71% and 33% of the total gas requirements for Wisconsin and Michigan, respectively. Gas sales for resale by ANR Pipeline amounted to $604 million for 1993, compared to $635 million for 1992 and $641 million for 1991.
ANR Pipeline's deliveries for the years 1993, 1992 and 1991 are as follows:
On November 1, 1992, as part of its Interim Settlement, ANR Pipeline implemented a restructuring of its traditional sales service by replacing existing services with a combination of competitive service alternatives. This restructuring provided a number of options for pipeline customers and was designed to enhance competition in ANR Pipeline's service areas. Under this restructuring, the sales service was "unbundled" on an interim basis into firm sales, transportation, flexible storage and flexible delivery services. Prior to the restructuring, the cost of providing transportation services for sales customers was recovered as part of ANR Pipeline's total resale rate and therefore, was classified as part of gas sales revenue. Under the restructuring, these costs were recovered through a separate rate and were included in transportation revenue. Additional information concerning the restructuring is set forth in "Regulations Affecting Gas Systems - Rate Matters" included herein.
Effective November 1, 1993, ANR Pipeline implemented Order 636. This Order required significant changes in the services provided by ANR Pipeline, and resulted in the elimination of ANR Pipeline's merchant service. ANR Pipeline now offers an array of "unbundled" storage, transportation and balancing service options. Additional information concerning Order 636, including transportation and storage, is set forth in "Regulations Affecting Gas Systems - General" included herein.
GAS PURCHASES
Effective November 1, 1993, as a result of the elimination of ANR Pipeline's merchant service, as mentioned above, ANR Pipeline's gas purchases decreased substantially. However, ANR Pipeline still purchases gas under a number of gas purchase contracts. ANR Pipeline's Order 636 restructured tariff provides mechanisms for the purpose of recovering from or refunding to its customers any pricing differential between costs incurred to purchase this gas and the amount ANR Pipeline recovers through auctioning of gas on the open market.
Of ANR Pipeline's gas purchases in 1993, approximately 62% was obtained directly from producers, including 17% from affiliates. In addition, ANR Pipeline received approximately 32% of its gas supply from Canadian suppliers and 6% from a producer of synthetic fuels. The border price of gas originating in Canada has been based on policies, established in 1984 by the NEB and the OFE, allowing exporters and importers to negotiate market-responsive prices.
Gas purchase contracts with producers generally provide for minimum purchase obligations based on estimated reserves under the well, the well's ability to produce or allowable gas takes set by state regulatory agencies. The prices paid depend upon, among other things, contractual requirements, market conditions, and the quality, condition of delivery and location of the gas. Under the NGWDA, effective July 26, 1989, all gas which would otherwise continue to be subject to price controls under the NGPA was deregulated over a three-year period and complete deregulation became effective January 1, 1993.
Some of ANR Pipeline's remaining gas purchase contracts with independent producers contain provisions which require taking minimum volumes and/or making prepayments for volumes not taken if purchases fall below specified levels during the contract year ("take-or-pay"). Additional information on take-or-pay matters is set forth in Note 3 of the Notes to Consolidated Financial Statements included herein.
GAS STORAGE
ANR Pipeline owns seven and leases eight underground storage facilities in Michigan. The total working storage capacity of the system is approximately 193 Bcf, with a maximum day delivery capacity of 2 Bcf as late as the end of February. However, of the 193 Bcf, ANR Pipeline has proposed to the FERC to reclassify 62.1 Bcf of working gas to recoverable base gas. ANR Pipeline also has the contract rights for 42 Bcf of storage capacity provided by Blue Lake Gas Storage Company, 30 Bcf of storage capacity provided by ANR Storage and 10 Bcf of storage capacity provided by Michigan Consolidated Gas Company. The contract with Michigan Consolidated Gas Company expires in March 1994. Underground storage services of up to 166 Bcf of gas are provided by ANR Pipeline to customers on a firm basis. ANR Pipeline also provides interruptible storage services for customers on a short-term basis.
Coastal's independent engineers, Huddleston, have estimated that ANR Pipeline's gas storage reserves as of December 31, 1993, 1992 and 1991 were 106.5 Bcf, 128 Bcf and 134 Bcf, respectively. The 1993 gas storage reserves are comprised of 19.4 Bcf of natural gas, maintained under ANR Pipeline's own account as working gas for system balancing and no-notice storage services; 25 Bcf of recoverable base gas reserves in seven owned storage fields; and 62.1 Bcf of working gas which ANR Pipeline has proposed to the FERC to reclassify as recoverable base gas. The decrease in the gas storage reserves between 1993 and 1992 reflects ANR Pipeline's elimination of its merchant service. Effective November 1, 1993, ANR Pipeline storage reserves are solely used to facilitate the overall operations of the system.
COLORADO
GAS SALES, STORAGE AND TRANSPORTATION
Beginning in October 1993, Colorado implemented Order 636 on its system and as required by the Order, Colorado's gas sales are now made at "upstream" locations (typically the 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 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 Colorado'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 on October 1, 1993, Colorado assigned an undivided interest in a portion of its company-owned leases (representing approximately 20% of Colorado's owned reserves) to a new subsidiary. The subsidiary has entered into a contract 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 $223 million in 1993, compared to $261 million in 1992. This decrease is 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 will continue to provide these services to third parties under individual contracts. Such services will be at negotiated rates that are within minimum and maximum levels established by the FERC. Also, pursuant to Order 636, Colorado, 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 1993, 1992 and 1991 are as follows:
GAS GATHERING AND PROCESSING
Prior to Order 636, Colorado gathered and processed gas incident to its "bundled" sales service (which also included storage and transportation activities). However, in compliance with the FERC mandated restructuring, Colorado now provides gathering and processing services on an "unbundled" or stand-alone basis. Colorado contracts for these services under terms which are negotiated. With respect to gathering, Colorado 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 2,994 miles of gathering lines and 110,500 horsepower of compression in its gathering operations. Colorado owns and operates six gas processing plants which recovered approximately 86 million gallons of liquid hydrocarbons in 1993, compared to 77 million gallons in 1992 and 61 million gallons in 1991, and 4,400 long tons of sulfur in 1993 and 3,600 long tons in both 1992 and 1991. Additionally, in 1993, Colorado processed approximately 12 million gallons of liquid hydrocarbons owned by others compared to 10 million in 1992 and 11 million in 1991. 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.
ANR STORAGE
ANR Storage develops and operates gas storage reservoirs to store gas for customers under firm long-term contracts. ANR Storage owns four underground storage fields and related facilities in northern Michigan, the working storage capacity of which is approximately 53 Bcf, including 30 Bcf contracted to ANR Pipeline. ANR Storage also owns a 50% equity interest in 3 joint venture storage facilities located in Michigan and New York with a total working storage capacity of approximately 60 Bcf, including 42 Bcf contracted to ANR Pipeline.
GAS SYSTEM RESERVES AND AVAILABILITY
ANR PIPELINE
With the termination of its merchant service, ANR Pipeline no longer reports on gas system reserves and availability and, therefore, this report has been replaced by a general discussion set forth in "Supply Area Deliverability", presented below.
SUPPLY AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas supply areas in the United States, the Gulf Coast and Midcontinent. Statistics published by the Energy Information Agency, Office of Oil and Gas, U.S. Department of Energy, indicate that approximately 82% of all natural gas in the lower 48 states is produced from these two supply areas. Interconnecting pipelines provide shippers with access to all other major gas supply areas in the United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the Midcontinent and Gulf Coast supply areas through direct connections and interconnecting pipelines and gatherers is approximately 3,800 MMcf per day. An additional 275 MMcf per day of deliverability is accessible to shippers on ANR Pipeline owned, or partially owned, pipeline segments not directly connected to an ANR Pipeline mainline.
ANR Pipeline remains active in locating and connecting new gas supply sources to facilitate transportation arrangements made by third party shippers. During 1993, field development, newly connected supply sources and pipeline interconnections contributed 515 MMcf per day to total deliverability accessible to shippers on ANR Pipeline.
COLORADO
Colorado has reported in its Form 10-K for the year ended December 31, 1993 the current and future availability of Colorado's gas system reserves based on information prepared by Huddleston, the Company's independent engineers. Colorado, even with the restructuring under Order 636, continues to dedicate certain of its reserves pursuant to contract. Additional information is set forth in "Reserves Dedicated to a Particular Customer," presented below.
RESERVES DEDICATED TO A PARTICULAR CUSTOMER
Colorado is committed to provide gas to Mesa Operating Company, formerly Mesa Operating Limited Partnership ("Mesa"), a customer, from specific owned gas reserves in the West Panhandle Field of Texas. Production from this area contributed approximately 46% of Colorado's total supply in 1993. Approximately 68% of those volumes were delivered to Mesa. Under an agreement which was effective January 1, 1991, as amended, Colorado has the right to take a cumulative 23% of the total net production from such reserves for its customers other than Mesa.
RECONCILIATION WITH FERC FORM 15 REPORT
The FERC Form 15 Annual Report of Gas Supplies is no longer required pursuant to FERC Order No. 554 issued July 13, 1993.
WYOMING INTERSTATE COMPANY, LTD.
WIC, a limited partnership owned by two wholly-owned Coastal subsidiaries, owns a 269-mile, 36-inch diameter pipeline across southern Wyoming. It has a throughput capacity of approximately 500 MMcf of gas daily. The WIC pipeline connects with an 88-mile western segment in which a Coastal subsidiary has a 10% interest and is the center section of the 800-mile Trailblazer pipeline system built by a group of companies to move gas from the Overthrust Belt and other Rocky Mountain areas to supply midwestern and eastern markets. Colorado and three other pipeline companies for which the WIC line transports gas have entered into long-term contracts having demand volumes totaling 500 MMcf daily. In 1993, the WIC line transported an average of 228 MMcf daily, compared to 261 MMcf daily in 1992. On January 1, 1992, WIC became an unrestricted open access transporter.
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Coastal and TransCanada, a non-affiliated company, each own 50% of Great Lakes which owns a 1,985-mile, 36-inch diameter gas pipeline system from the Manitoba-Minnesota border to an interconnection on the Michigan-Ontario border at St. Clair, Michigan. Great Lakes transported 854 Bcf in 1993 as compared to 789 Bcf in 1992. Great Lakes has contract commitments to transport a total of 1.3 Bcf per day for TransCanada. It also transports up to 800 MMcf per day primarily for United States markets, including 77 MMcf per day to ANR Pipeline. Great Lakes exchanges gas with ANR Pipeline by delivering gas in the upper peninsula of Michigan and receiving an equal amount of gas in the lower peninsula of Michigan. This arrangement reduces the distance that gas must be transported by Great Lakes and ANR Pipeline.
COASTAL GAS SERVICES COMPANY
The Company formed CGS, a wholly-owned subsidiary, in early 1993 to consolidate its unregulated natural gas businesses. CGS and its subsidiaries operate certain of Coastal's natural gas gathering and processing, gas supply and marketing, price risk management and producer financing activities. CGS' subsidiary, ANR Gas Supply Company, was formed to provide merchant services to former ANR Pipeline customers contracting for such service. ANR Gas Supply Company has executed 25 contracts with former ANR Pipeline customers with an aggregate service commitment of 85 MMcf per day. CGMC is the largest of CGS's subsidiaries and continues to be one of the most successful natural gas marketing companies in North America. CGMC managed the sale and delivery of 828 Bcf of natural gas in 1993 as compared to 788 Bcf in 1992. CGMC conducts business on over 60 pipelines and has over 1,000 producer and market customers in North America, including imports and exports with Canada and Mexico.
REGULATIONS AFFECTING GAS SYSTEMS
GENERAL
Under the NGA, the FERC has jurisdiction over ANR Pipeline, Colorado, WIC, ANR Storage and Great Lakes as to sales, transportation, balancing of gas, rates and charges, the construction of new facilities, extension or abandonment of service and facilities, accounts and records, depreciation and amortization policies and certain other matters. Under Order 636, the FERC has determined that it will not regulate sales rates by pipelines including these companies. Additionally 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 by FERC. ANR Pipeline, Colorado, WIC, ANR Storage and Great Lakes, where required, hold certificates of public convenience and necessity issued by the FERC covering their jurisdictional facilities, activities and services.
ANR Pipeline, Colorado, WIC, ANR Storage and Great Lakes are also subject to regulation with respect to safety requirements in the design, construction, operation and maintenance of their 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.
On November 1, 1990, the FERC issued Order No. 528 in which it sets forth guidelines for an acceptable allocation method for a fixed direct charge to collect take-or-pay settlement costs. Pursuant to Order No. 528, ANR Pipeline has filed for and received approval to recover 75% of expenditures associated with resolving producer claims and renegotiating gas purchase contracts. The approved filings provide for recovery of 25% of such expenditures via a direct bill to ANR Pipeline's former sales for resale customers and 50% via a surcharge on all transportation volumes. Contract reformation and take-or-pay costs incurred as a result of the mandated Order 636 restructuring will be recovered under the transition costs mechanisms of Order 636 as well as through negotiated agreements with ANR Pipeline's customers.
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 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 have been recovered under Order Nos. 500 and 528.
On April 8, 1992, the FERC issued Order Nos. 636, 636-A and 636-B (collectively "Order 636"), which required significant changes in the services provided by interstate natural gas pipelines. Subsidiaries of the Company and numerous other parties have sought judicial review of aspects of Order 636. Notwithstanding those appeals, ANR Pipeline, Colorado, WIC, ANR Storage and Great Lakes have successfully complied with the requirements of Order 636.
On July 2, 1993, Colorado 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 Colorado's restructured services became effective October 1, 1993. Under that settlement, Colorado has "unbundled" its gas sales from its other services. Separate gathering, transportation, storage, no notice transportation and storage and other services are available on a "stand alone" basis to any customers desiring them. Colorado's Order 636 transition costs are not expected to be material and are expected to be recovered through Colorado's rates.
ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. ANR Pipeline now offers a wide range of "unbundled" transportation, storage and balancing services. Several persons, including
ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving ANR Pipeline's restructuring filings. Order 636 also provides mechanisms for recovery of transition costs associated with compliance with that Order. These transition costs include gas supply realignment costs, the cost of stranded pipeline investment and the cost of new facilities required to implement Order 636. ANR Pipeline expects that it will incur transition costs of approximately $150 million. As a result of the recovery mechanisms provided under Order 636, ANR Pipeline anticipates that these transition costs will not have a material adverse effect on ANR Pipeline's consolidated financial position or its results of operations.
RATE MATTERS
ANR PIPELINE. All of ANR Pipeline's 1993 service options were subject to rate regulation by the FERC. Under the NGA, ANR Pipeline must file with the FERC to establish or adjust its service rates. The FERC may also initiate proceedings to determine whether ANR Pipeline rates are "just and reasonable."
On March 10, 1992, ANR Pipeline submitted to the FERC a comprehensive Interim Settlement designed to resolve all outstanding issues resulting from its 1989 rate case and its 1990 proposed service restructuring proceeding. The Interim Settlement involved, inter alia, an array of new sales, delivery, transportation and storage service alternatives and the implementation of a gas inventory charge, designed to compensate ANR Pipeline for the costs of standing ready to serve its sales customers. The Interim Settlement reflected a decrease in cost of service of approximately $45 million, which was largely attributable to a reduction in depreciation rates from 3.4% to 1.82%. Also included was a provision which allowed ANR Pipeline to direct bill its customers for its remaining unrecovered purchased gas costs. The Interim Settlement became effective November 1, 1992 and expired with ANR Pipeline's implementation of Order 636 on November 1, 1993. Specific provisions of the Interim Settlement relating to the deferral and future recovery of certain costs remain in effect.
On December 17, 1992, the FERC issued a policy statement that outlined changes on how pipelines may recover the costs of employees' postretirement benefits other than pensions. The FERC's policy will be to recognize, as a component of jurisdictional cost-based rates, allowances for FAS No. 106 costs of company employees when determined on an accrual basis, provided certain conditions are met.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC. The proposed rates reflect a $121 million increase in ANR Pipeline's cost of service from that approved in the Interim Settlement and a $218 million increase over ANR Pipeline's approved rates for its restructured services. The increase represents higher plant investment, Order 636 restructuring costs, rate of return and tax rate changes and increased costs related to the required adoption of recent accounting rule changes, i.e., FAS Nos. 106 and 112. (See Note 11 of the Notes to Consolidated Financial Statements for a discussion of FAS Nos. 106 and 112.) The FERC has permitted ANR Pipeline to place its new rates into effect on May 1, 1994, subject to refund and subject to certain required compliance changes and the outcome of an evidentiary hearing on all remaining issues.
COLORADO. Under the NGA, Colorado continues to be required to file with the FERC to establish or adjust certain of its service rates. The FERC may also initiate proceedings to determine whether Colorado's rates are "just and reasonable".
On March 31, 1993, Colorado filed at FERC 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.
WIC. WIC settled a rate case with the FERC, as principal payments and associated interest of $68.1 million were paid to WIC's shippers on October 8, 1991, exclusive of amounts which are being held until the resolution of pending bankruptcy proceedings involving its customer, Columbia Gas Transmission Corporation, which is currently pending before the U.S. Bankruptcy Court for the District of Delaware. Should such refunds be required, there would be no effect on the results of operations as accruals have been previously established.
In 1993 the FERC initiated proceedings under Section 5 of the NGA to determine if WIC's rates approved in 1991 had become excessive. Administrative hearings were held in December of 1993, but no decision has been issued. Any decrease in rates that the FERC may ultimately require will only take effect prospectively following the issuance of a final order by the FERC that is no longer subject to rehearing by the agency.
Certain regulatory issues remain unresolved among ANR Pipeline, Colorado, WIC and ANR Storage, their customers, their suppliers, and the FERC. ANR Pipeline, Colorado, WIC and ANR Storage have made provisions which represent management's assessment of the ultimate resolution of these issues. While these companies estimate the provisions to be adequate to cover potential adverse rulings on these and other issues, they cannot estimate when each of these issues will be resolved.
OTHER DEVELOPMENTS
The Empire State Pipeline Project, in which an affiliate of ANR Pipeline has a 45% interest and ANR Pipeline is the operator, was placed in service on November 1, 1993. The 156-mile pipeline system, extending from Niagara Falls to Syracuse, New York, will carry up to 570 MMcf per day to western and central New York and provide ANR Pipeline access to markets in the Northeastern United States.
In August 1993, ANR Pipeline and Arkla, Inc. ("Arkla") announced execution of a restructured agreement under which ANR Pipeline will purchase an ownership interest in 250 MMcf per day of capacity in existing natural gas transmission facilities from Arkla. The restructured agreement resolved certain conditions imposed by the FERC in its October 1, 1992 authorization of the original purchase and sale agreement. As restructured, ANR Pipeline will own capacity interests in facilities valued at approximately $90 million, subject to receipt of all required regulatory approvals. The reduction in value of the facilities from the original purchase and sale agreement is the result of negotiations between ANR Pipeline and Arkla in light of the FERC's orders.
ANR Pipeline and a subsidiary of CGS are partners in the SunShine Pipeline Project which is designed to capture a share of the growing Florida power generation market, as well as markets located in Mississippi, Alabama and the Florida Panhandle. SunShine Interstate Transmission Company ("SITCO"), the interstate pipeline segments of this project, will extend 170 miles from Pascagoula, Mississippi to Okaloosa, Florida where it will connect with Sunshine Pipeline Company, ("SunShine") the intrastate segment of this project. SunShine will be a 545-mile pipeline starting in Okaloosa and extending down Florida's west coast to the Tampa area. ANR Pipeline, through a wholly-owned subsidiary, will have a 40% interest in SITCO and a subsidiary of CGS will have a 40% interest in SunShine. Florida Power Corporation and TransCanada will both hold a 30% equity interest in each of the two projects. SITCO will have an initial capacity of 329.5 MMcf per day and SunShine will have an initial capacity of 249.5 MMcf per day. Both SITCO and SunShine have signed precedent agreements for a portion of their initial pipeline capacity. SITCO, which will be subject to FERC jurisdiction, has filed with the FERC to obtain a Certificate of Public Convenience and Necessity. FERC approval is expected in March, 1995. SunShine, which will be subject to the jurisdiction of the Florida Public Service Commission ("FPSC"), has received approval of its request for a Determination of Need from the FPSC. SunShine also expects environmental approval, in early 1995, under the procedures set forth in Florida's Natural Gas Transmission Pipeline Siting Act. Both projects are targeted to be placed into service in December 1995. The SunShine pipeline is expected to cost approximately $462 million and the SITCO pipeline is expected to cost approximately $188 million.
A subsidiary of ANR Pipeline will have a 25% equity interest in the proposed Liberty Pipeline project, a 38-mile pipeline extending from New Jersey across New York Harbor to Long Island with a potential capacity of 500 MMcf per day. The pipeline is expected to serve local distribution company participants and independent power producers. A filing to obtain a Certificate of Public Convenience and Necessity has been made and is currently pending before the FERC. Subject to receiving applicable governmental approvals, an in-service date of late 1995 is possible, at an estimated cost of $160 million.
ANR Pipeline (20% equity interest) and Interprovincial Pipe Line System Inc. plan to participate in the construction of the InterCoastal Pipe Line, a project designed to serve incremental markets in southern Ontario and
potentially Quebec and the Northeastern United States. The project will involve converting approximately 130 miles of existing oil pipeline to natural gas service, originating in Sarnia, Ontario and extending to Toronto, and the construction of approximately 25 miles of new pipeline. In connection with the project, facilities in Michigan will be constructed by ANR Pipeline to deliver gas from domestic sources. The project, which will have a maximum capacity of 175 MMcf per day, is projected to cost $37.6 million. The InterCoastal Pipe Line is subject to regulatory approval in Canada, and the ANR Pipeline facilities are subject to regulatory approvals in the United States. Filings seeking necessary authorizations from the NEB were made in the second quarter of 1993, and with the FERC on July 19, 1993. The project could be in service as early as November 1, 1994.
A subsidiary of ANR Pipeline and affiliates of TransCanada and Brooklyn Union Gas Company have entered into a partnership agreement for the construction of the Mayflower Pipeline, which is expected to expand natural gas sales and storage services to markets in the Northeastern United States. ANR Pipeline will have a 45% interest in this project. The proposed 240-mile pipeline will extend east from the Iroquois Gas Transmission System at Canajoharie, New York to a location near Boston, Massachusetts and have an initial design capacity of 350 MMcf per day. The total project cost is expected to be $540 million. The pipeline is expected to be in service in late 1997. Construction of the project is subject to receipt of all federal regulatory approvals.
Colorado owns approximately 20% of Natural Fuels Corporation ("NFC") which is headquartered in Denver, Colorado. NFC's business is to develop compressed natural gas ("CNG") as an alternative vehicular fuel. Major services provided by NFC include vehicle conversions to CNG, fuel sales, CNG equipment sales, maintenance services, and training. Besides operating a full service conversion center which converts vehicles to CNG, NFC has installed 44 stations in Colorado, 26 of which are open to the public. NFC, in joint partnership with Total Petroleum, installs natural gas refueling facilities at selected Total Petroleum stores along the Colorado Front Range. This project is one of the largest public fueling station development commitments in the United States. As of January 1994, seven stations were operational and one was under construction. Also, Colorado is a co-sponsor in the testing of two Colorado Springs buses that are powered by dual-fueled engines modified to run on up to 90% natural gas.
On July 8, 1993, Young Gas Storage Company, Ltd. ("Young"), a limited partnership, filed an application with the FERC for a Certificate of Public Convenience and Necessity authorizing, in part, the development, construction and operation of an underground natural gas storage field. The $44.4 million storage field project, to be located in Morgan County, Colorado, will be capable of storing 5.3 Bcf of working gas with a withdrawal rate of 200 MMcf per day when fully developed in 1998. The total capacity is under long-term contracts. On March 3, 1994, the FERC issued an Order Granting Preliminary Determination which approved the non-environmental aspects of the project. The Company is reviewing this Order and intends to seek rehearing with respect to some aspects of this Order. CIG Gas Storage Company and Young Gas Storage Company, the two general partners in the Young Partnership, are affiliates of Coastal. The limited partner is the City of Colorado Springs, a municipal corporation of the State of Colorado.
CGS has established a producer and market services division to provide financing services to producers. This division will arrange funding for acquisitions and development of oil and gas reserves and other producer capital requirements. As a result of these activities, CGS will obtain access to long- term oil and gas supplies enhancing CGS' marketing capabilities.
Coastal States Gas Transmission Company, a subsidiary of the Company, is building a natural gas intrastate pipeline from the Bob West Field in South Texas to run initially 26 miles north to the Midcon Texas Pipeline System at a cost of approximately $8 million. This new pipeline is expected to be completed prior to June 1994 and will transport up to 200 MMcf per day of natural gas without compression and up to 350 MMcf per day with compression.
Funding for certain pending and proposed natural gas pipeline projects is anticipated to be provided through non-recourse financings in which the projects' assets and contracts will be pledged as collateral. This type of financing typically requires the participants to make equity investments totaling approximately 20% to 30% of the cost of the project, with the remainder financed on a long-term basis.
REFINING, MARKETING AND DISTRIBUTION
The Company has subsidiary operations involved in refining, marketing and distribution of petroleum products. The petroleum industry is highly competitive in the United States and throughout most of the world. This industry also competes with other industries in supplying the energy needs of various types of consumers.
REFINING
Subsidiaries of the Company operated their wholly-owned refineries at 87% of year 1993 average combined capacity compared to 82% in 1992. The aggregate sales volumes (millions of barrels) of Coastal's wholly-owned refineries for the three years ended December 31, 1993, were 134.9 (1993), 136.7 (1992) and 141.2 (1991). A joint venture, Pacific Refining Company, had sales of 19.9 million barrels in 1993, 21.3 million barrels in 1992 and 27.4 million barrels in 1991 which were excluded from Coastal's 1993, 1992 and 1991 sales. Of the total refinery sales in 1993, 30% was gasoline, 46% was middle distillates, such as jet fuel, diesel fuel and home heating oil, and 24% was heavy industrial fuels and other products.
The average daily processing capacity of crude oil at December 31, 1993, average daily throughput and storage capacity at the Company's wholly-owned operating refineries are set forth below:
The Company has curtailed refining operations at its three Kansas refinery locations as part of an overall restructuring plan for refining and marketing undertaken in 1992. Two of these locations, Wichita and El Dorado, are still operating as refined products terminals. Refinery units have been mothballed and are being evaluated for utilization either by the company or by third parties.
Pacific Refining at Hercules, California has a refining capacity of 55,000 barrels per day at December 31, 1993. Since January 1989, the China National Chemicals Import & Export Corporation has held a 50% interest in Coastal's west coast refining and marketing properties, including Pacific Refining Company. The Hercules refinery was operated during 1993 and processed 46,200 barrels per day of crude oil and other feedstocks. Present plans are to continue operation of the refinery through 1994 and most likely through 1995, consistent with resolution of regulatory issues and attainment of earnings objectives. The Company is evaluating several future options for the facility. These include expansion of asphalt facilities and installation of Clean Air Act of 1990 and California Air Resources Board regulations compliance upgrades and conversion of the Hercules site to alternative uses.
In addition, Coastal's international operations include a minority interest, through a foreign subsidiary, in a refinery located in Hamburg, Germany which has a refining capacity of 100,000 barrels per day and a storage capacity of 1,800,000 barrels for crude oil and 5,200,000 barrels for products.
The Company's refineries produce a full range of petroleum products ranging from transportation fuels to paving asphalt. The refineries are operated to produce the particular products required by customers within each refinery's geographic area. In 1993, the products emphasized included premium gasolines and products for specialty markets such as petrochemical feedstocks, aviation fuels and asphalt.
MARKETING AND DISTRIBUTION
REFINED PRODUCTS MARKETING. Sales volumes for distribution activities of Coastal subsidiaries, including products from Company refineries and purchases from other suppliers, for the three years ended December 31, 1993, are set forth below (thousands of barrels):
Subsidiaries of the Company market refined products and liquefied petroleum gas at wholesale in 36 states through 322 terminals. Coastal Refining & Marketing, Inc. serves customers in the Midwest, Mississippi Valley and the Southwest through 221 product and liquified petroleum gas terminals in 27 states. On the Gulf and East Coasts, Coastal Fuels Marketing, Inc., Coastal Oil New York, Inc. and Coastal Oil New England, Inc. serve home, industry, utility, defense and marine energy needs. In 1993, these subsidiaries' sales volumes were 132 million barrels, which accounted for approximately 45% of the total marketing and distribution sales. Effective January 1, 1994, the refined products marketing operations of these subsidiaries were consolidated into Coastal Refining & Marketing, Inc. International subsidiaries that acquire feedstocks for the refineries and products for the distribution system are located in Aruba, Bahrain, Bermuda, London, Madrid and Singapore.
In March 1993, Coastal Petroleum N.V., a subsidiary of Coastal, and The Subic Bay Metropolitan Authority signed a long-term lease for petroleum storage facilities located at the former U.S. naval base at Subic Bay in the Philippines. Coastal is leasing 304 acres of land, with 68 individual storage tanks totalling 2.4 million barrels of storage, most of which are underground, and 40 miles of pipeline connecting the terminal with other facilities within the Subic Bay Freeport Zone. Additionally, in late 1993, another subsidiary of Coastal signed a joint venture agreement with a subsidiary of the Malaysian national oil company, Petronas, for use of the entire capacity of this storage facility for independent marketing efforts throughout the region and for joint marketing in the Subic Bay Freeport Zone.
The Company, through Coastal Mart, Inc. and branded marketers, conducts retail marketing, using the C-MART(R) and/or COASTAL(R) trademarks, in 36 states through approximately 1,532 Coastal branded outlets, with 578 of those outlets operated by the Company. Fleet fueling operations include 17 outlets in Texas and 7 in Florida.
Coastal Unilube, Inc., based in West Memphis, Arkansas, blends, packages and distributes lubricants and automotive products under the UNILUBE(R), DUPLEX(R), CUI(R) and UNIPRO(R) brand names. Coastal Unilube, Inc. distributes lubricants and automotive products through 14 warehouses servicing customers in 36 states.
TRANSPORTATION. The Company's transportation facilities include petroleum liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal has approximately 3,900 miles of pipeline for gathering and transporting an average of 334,000 barrels daily of crude oil, condensate, natural gas liquids and refined products. These lines are located principally in Texas and Kansas and include 358 miles of crude oil pipelines, 784 miles of refined products pipelines and 671 miles of natural gas liquids pipelines, all 100% owned and operated by Coastal subsidiaries, and 1,997 miles of 50% owned crude oil pipelines and 80 miles of jointly-owned products pipelines with less than a 50% interest. In 1993, throughput of crude oil pipelines averaged 148,199 barrels per day, compared to 155,386 barrels per day in 1992. In 1993, throughput of refined products and natural gas liquid pipelines averaged 186,430 barrels per day, compared to 162,696 barrels per day in 1992.
Other transportation facilities for marketing operations of Coastal subsidiaries include a regional tank truck fleet which distributes refined and liquefied petroleum gas products to customers in parts of Florida, New England and
New York, and another fleet of trucks, which transport petroleum products and liquefied petroleum gas products for Coastal marketing subsidiaries serving the Texas area.
The marine transportation total fleet at December 31, 1993 consisted of 17 tug boats, 24 oil barges, 6 owned tankers used for the transportation of refined petroleum products and crude oil and 3 time-chartered tankers.
EXPLORATION AND PRODUCTION
GAS AND OIL PROPERTIES
Coastal subsidiaries are engaged in gas and oil exploration, development and production operations in the United States and Argentina. Argentine operations are discussed in Supplemental Information on Oil & Gas Producing Activities (Unaudited), as set forth in Item 14(a)1 hereof. United States operations are principally in Alabama, Arkansas, California, Colorado, Kansas, Louisiana, Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah, West Virginia, Wyoming and offshore in the Gulf of Mexico.
In 1993, the Company's domestic operations sold approximately 53% of all the gas it produced to its natural gas system affiliates and a gas brokerage affiliate. The Company's domestic operations make short-term gas sales directly to industrial users and distribution companies to increase utilization of its excess current gas production capacity. Oil is sold primarily under short-term contracts at field prices posted by the principal purchasers of oil in the areas in which the producing properties are located.
Acreage held under gas and oil mineral leases as of December 31, 1993 is summarized as follows:
The domestic net acreage held for production is concentrated principally in Texas (37%), Utah (20%), Oklahoma (10%), West Virginia (7%), Kansas (6%) and Wyoming (6%). Approximately 21%, 22% and 23% of the Company's total undeveloped net acreage is under leases that have minimum remaining primary terms expiring in 1994, 1995 and 1996, respectively.
Productive wells as of December 31, 1993 are as follows (domestic):
EXPLORATION AND DRILLING
During 1993, Coastal's domestic exploration and production units participated in drilling 158 gross wells, 75.5 net wells, to the Company's interest. Coastal's participation in wells drilled in the three years ended December 31, 1993, is summarized as follows:
Wells in progress as of December 31, 1993 are as follows (domestic):
During the course of 1992 and 1991 development drilling focused on natural gas wells which qualified under a federal tax incentive program providing for future tax credits on wells producing from tight sands gas formations. To qualify, wells must have been spudded before January 1, 1993. During 1993, development drilling focused on replacing and increasing production capacity as natural gas prices stabilized at acceptable levels.
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the general partner in six limited partnership drilling programs which have been offered to Coastal's employees and shareholders. Information pertaining thereto can be located in the Annual Report on Form 10-K filed by each limited partnership and available from the Company.
GAS AND OIL PRODUCTION
Natural gas production during 1993 averaged 334 MMcf daily, compared to 277 MMcf daily in 1992. Production from non-pipeline-owned wells averaged 207 MMcf daily in 1993, compared to 147 MMcf daily in 1992. Crude oil, condensate and natural gas liquids production averaged 13,534 barrels daily in 1993, compared to 13,002 barrels daily in 1992.
The following table shows gas, oil, condensate and natural gas liquids production volumes attributable to Coastal's domestic interest in gas and oil properties for the three years ended December 31, 1993:
Many of Coastal's domestic gas wells are situated in areas near, and are connected to, its gas systems. In other areas, gas production is sold to pipeline companies and other purchasers.
Generally, Coastal's domestic production of crude oil, condensate and natural gas liquids is purchased at the lease by its marketing and refinery affiliates. Some quantities are delivered via Coastal's gathering and transportation lines to its refineries, but most quantities are redelivered to Coastal through various exchange agreements.
The following table summarizes sales price (net of production taxes) and production cost information for domestic exploration and production operations during the three years ended December 31, 1993:
NATURAL GAS PROCESSING
ANR Production Company and Coastal Oil & Gas Corporation, domestic subsidiaries of the Company, are also engaged in the processing of natural gas for the extraction and sale of natural gas liquids. In 1993, total revenues of $36.7 million were generated from the extraction and sale of 136 million gallons of ethane, propane, iso-butane, normal butane and natural gasoline from natural gas processing plants. Sales prices of natural gas liquids fluctuate widely as a result of market conditions and changes in the prices of other fuels and chemical feedstocks.
COMPANY-OWNED RESERVES
Coastal's domestic proved reserves of crude oil, condensate and natural gas liquids at December 31, 1993, as estimated by Huddleston, its independent engineers, were 28.8 million barrels, compared to 33.1 million barrels at the end of 1992. Proved gas reserves as of December 31, 1993, net to Coastal's interest, were estimated by the engineers to be 925.5 Bcf compared to 974.8 Bcf as of December 31, 1992.
For information as to Company-owned reserves of oil and gas, see "Supplemental Information On Oil and Gas Producing Activities" as set forth in Item 14(a)1 hereof.
COMPETITION
In the United States, the Company competes with major integrated oil companies and independent oil and gas companies for suitable prospects for oil and gas drilling operations. The availability of a ready market for gas discovered and produced depends on numerous factors frequently beyond the Company's control. These factors include the extent of gas discovery and production by other producers, crude oil imports, the marketing of competitive fuels, and the proximity, availability and capacity of gas pipelines and other facilities for the transportation and marketing of gas. The production and sale of oil and gas is subject to a variety of federal and state regulations, including regulation of production levels.
REGULATION
In all states in the United States in which Coastal engages in oil and gas exploration and production, its activities are subject to regulation. Such regulations may extend to requiring drilling permits, the spacing of wells, the prevention of waste and pollution, the conservation of natural gas and oil, and various other matters. Such regulations may impose restrictions on the production of natural gas and crude oil by reducing the rate of flow from individual wells below their actual capacity to produce. Likewise, oil and gas operations on all federal lands are subject to regulation by the Department of the Interior and other federal agencies.
COAL
The Company, through ANR Coal Company and its subsidiaries ("ANR Coal") in the eastern United States and through Coastal States Energy Company and its subsidiaries ("Coastal States Energy") in the west, produces and markets high quality bituminous coal from its reserves in Kentucky, Virginia, West Virginia and Utah. In addition, subsidiaries of ANR Coal lease interests in their reserves to unaffiliated producers and market third-party coal through brokerage sales operations.
At December 31, 1993, coal properties consisted of the following:
- ------------------------
(1) Based on a 65% recovery rate.
In September 1993, a subsidiary of the Company acquired Soldier Creek Coal Company and its parent, Sage Point Coal Company. This acquisition added approximately 86 million tons of new recoverable coal reserves to Coastal's reserve base. Substantially all of the acquired reserves satisfy the sulfur emissions requirements of the Clean Air Act of 1990.
At December 31, 1993, the Company controlled approximately 871 million recoverable tons of bituminous coal reserves. Production in 1993 from the Company's reserves totalled 23.6 million tons of which 18.4 million tons were produced from captive operations and 5.2 million tons were produced by lessees under royalty agreements. In its eastern captive operations, ANR Coal contracts with independent mine operators to mine and deliver coal to Company owned and operated processing and loading facilities. Captive production and processing from ANR Coal and Coastal States Energy in 1993 totalled 9.2 and 9.2 million tons, respectively.
Captive sales from ANR Coal and Coastal States Energy were 7.2 million and 8.9 million tons, respectively, in 1993. Brokerage sales in which the Company receives a commission on coal sold for third parties totalled 1.3 million tons for the same period.
In 1993, approximately 70% of sales were to domestic utilities, 12% of sales were to domestic industrial customers and 18% of sales were to export markets primarily in Asia and Canada. Of the total 1993 tonnage sold, 12.1 million tons (75%) were sold under long-term contracts. At December 31, 1993, the weighted average remaining life of these contracts was 63 months.
The Company had approximately 21.2 million tons of annual production capacity at December 31, 1993. In the eastern United States, the Company owns and operates five coal preparation plants and nine loading facilities with a combined annual capacity of 10.6 million tons. Coastal States Energy's mines in Utah employ three longwall mining systems, diesel shuttle cars and have a combined annual capacity of 10.6 million tons.
In addition to its bituminous coal operations, the Company controls overriding royalty interests in approximately 484 million tons of lignite reserves in North Dakota. Production from these reserves in 1993 totalled 16.1 million tons.
The Company, through its captive operations, leasing programs and brokerage activities, participates in all aspects of the national bituminous coal industry and is a significant competitor in international coal markets. A significant portion of its eastern reserves and all of its Utah reserves are low-sulfur, compliance coal which will allow the Company to remain a major supplier of steam coal to domestic utilities under the Clean Air Act of 1990.
The Company competes with a large number of coal producers and land holding companies across the United States. The principal factors affecting the Company's coal sales are price, quality (BTU, sulfur and ash content), royalty rates, employee productivity and rail freight rates.
CHEMICALS
Coastal Chem, Inc. ("Coastal Chem"), a Coastal subsidiary, operates a plant near Cheyenne, Wyoming, which produces anhydrous ammonia, ammonium nitrate, nitric acid, food grade liquid carbon dioxide and urea for use as agricultural fertilizers, livestock feed supplements, blasting agents and various other industrial applications. This plant has the capacity to produce 500 tons per day of anhydrous ammonia, 750 tons per day of ammonium nitrate, 275 tons per day of urea, 700 tons per day of nitric acid and 400 tons per day of food grade liquid carbon dioxide. Coastal Chem also owns a plant at Table Rock, Wyoming, which has a production capacity of 150 tons of liquid fertilizer per day. In addition, Coastal Chem operates a low density ammonium nitrate ("LoDAN/(R)/") facility in Battle Mountain, Nevada. The LoDAN/(R)/ is used primarily as a blasting agent in surface mining. This facility produces 400 tons per day of LoDAN/(R)/.
Coastal Chem completed a urea expansion project in 1992 with full production commencing in mid 1993. This expanded facility increased the previous capacity of 175 tons per day to 275 tons per day. During the last six months, the facility has operated at its designed capacity.
Coastal Chem commenced production from its integrated methyl tertiary butyl ether ("MTBE") plant in 1993. MTBE is a gasoline additive which adds oxygen and boosts octane of the blended mixture. The plant has a production capacity of 4,000 barrels per day.
Sales volumes for the three years ended December 31, 1993, are set forth below (thousands of tons):
INDEPENDENT POWER PRODUCTION
Coastal Power Production Company ("Coastal Power") and certain of its affiliates develop, operate and are equity participants in cogeneration plants which produce and sell electricity and thermal products, including steam and chilled water. Affiliates of Coastal Power currently own interests in four operating cogeneration facilities in the United States.
Capitol District Energy Center Cogeneration Associates ("CDECCA") owns a cogeneration facility with an approximate 56 megawatt capacity. An affiliate of Coastal Power owns a 50% interest in CDECCA and is the project manager and Coastal Technology, Inc. ("CTI"), a Coastal subsidiary, is the operator of the plant. Electricity from the facility is sold to the local utility under a long- term contract. Steam and chilled water produced from the plant help to serve the thermal requirements of the City of Hartford and the plant's co-owner.
An affiliate of Coastal Power is the managing partner and 50% owner of a combined cycle cogeneration plant at Coastal's Eagle Point, New Jersey refinery. The plant has a permitted nameplate rating of approximately 260 megawatts and currently operates at approximately 225 megawatts. Power from the plant is sold to a local utility and Coastal's refinery under long-term contracts. Steam from the plant is also sold to the refinery under long-term contract. Gas supply and transmission is provided to the cogeneration plant by other Coastal affiliates. CTI is the operator of the cogeneration plant.
Coastal Power and an affiliate own a gas-fired cogeneration facility in Fulton, New York with an approximate 47 megawatt capacity. Electricity from this project is sold under a long-term contract to a New York utility. Steam is sold to a neighboring plant owned by a major candy manufacturer. Approximately half of the gas supply requirements for the cogeneration plant are supplied by an affiliate of Coastal Power. CTI is the plant operator.
Coastal, through a wholly-owned subsidiary, has a 10.9% equity interest in the Midland Cogeneration Venture Limited Partnership, the largest gas-fired cogeneration plant in the United States. Coastal subsidiaries supply and transport a portion of the gas to this facility.
TRUCKING OPERATIONS
ANR Freight System, Inc. ("ANR Freight") is a regional common and contract carrier by motor vehicle, conducting operations in both interstate and intrastate commerce.
During 1993, ANR Freight transported approximately 1.4 million tons of freight, consisting of both truckload shipments (10,000 pounds or more) and less than truckload (LTL) shipments (less than 10,000 pounds) versus
1.3 million tons in 1992. LTL shipments comprised approximately 42% of total tonnage hauled by ANR Freight and generated approximately 82% of its operating revenues. As of December 31, 1993, ANR Freight operated 40 terminals and almost 4,000 trucks, tractors and trailers.
Regulatory actions by the Interstate Commerce Commission ("ICC") allowing relatively easy entry into and expansion of the motor freight business have tended to increase competition among motor carriers and also between motor carriers and other modes of transportation. ANR Freight competes primarily with other regular route motor carriers of general freight and, to a lesser extent, with irregular route motor carriers, individual truckers and private carriers (for truckload general freight) and with surface freight forwarders, railroads, airlines and air freight forwarders. The extent of competition between various modes of transportation is largely determined by their rate structures and by the service requirements of the shippers. Over-capacity in the motor carrier industry has increased competition for freight, and discounting programs, which effectively reduce the rates filed with the ICC, have been adopted by many carriers. ANR Freight continues to participate, on a limited basis, in collective rate making within the regional rate bureaus as authorized by the Interstate Commerce Act. ANR Freight also carries freight under contract and under general and individually published tariff arrangements.
ANR Freight is subject to regulation by the ICC with regard to accounting. The carriers are regulated as to rates and routes of travel by the ICC for freight transported in interstate commerce and by state regulatory agencies for freight transported in intrastate commerce. The Department of Transportation regulates certain aspects of carrier operations such as the transportation of hazardous materials, motor vehicle maintenance, motor vehicle safety devices and appliances and driver qualifications. Various states regulate the gross weight and length of vehicles which travel over the highways of such states.
COMPETITION
Coastal and its subsidiaries are subject to competition. In all the Company's business segments, competition is based primarily on price with factors such as reliability of supply, service and quality being considered.
The coal, chemicals, independent power production and trucking subsidiaries of Coastal are engaged in highly competitive businesses against competitors, some of which have significantly larger facilities and market share. See the discussion of competition under "Natural Gas Systems," "Refining, Marketing and Distribution" and "Exploration and Production" herein.
ENVIRONMENTAL
The Company's operations are subject to extensive federal, state and local environmental laws and regulations. The Company anticipates annual capital expenditures of $20 to $40 million over the next several years aimed at 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." Certain subsidiaries of the Company have been named as a potentially responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15 sites for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $350 million, the Company estimates its pro-rata exposure to be paid over a period of several years is approximately $5 million and has made appropriate provisions. At 3 other sites, the EPA is currently unable to provide the Company with an estimate of total clean-up costs and, accordingly, the Company is unable to calculate its share of those costs. Finally, at 5 other sites, the Company has
paid amounts to other PRPs as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis.
The following administrative proceedings and suits involve subsidiaries of the Company:
1. In October 1993, the Bay Area Air Quality Management District brought an administrative action against Pacific Refining Company, in which Coastal has an indirect 50% interest. In March 1994, the parties agreed upon a structured settlement amount of $300,000 regarding certain compliance issues relating to the installation of a sulfur recovery unit at Pacific Refining Company's refinery.
2. In January 1993, the State of Texas filed suit against the Corpus Christi, Texas refinery of Coastal Refining & Marketing, Inc., a subsidiary of Coastal, alleging failure to comply in 1992 with certain administrative orders relating to groundwater contamination and seeking penalties in unspecified amounts. The Company believes that this suit could result in monetary sanctions which, while not material to the Company and its subsidiaries, could exceed $100,000.
3. In February 1993, the State of Texas filed suit against Coastal Refining & Marketing, Inc., seeking civil penalties in unspecified amounts for alleged public nuisance odor violations occurring in 1991 and 1992 at the Corpus Christi refinery. In July 1993, the proceeding was amended to include a claim for excess benzene emissions and to seek civil penalties. The Company believes that this suit could result in monetary sanctions which, while not material to the Company and its subsidiaries, could exceed $100,000.
There are additional areas of environmental remediation responsibilities which may fall on the Company. Future information and developments will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's liquidity or financial position.
ITEM 2.


ITEM 2. PROPERTIES.
Information on properties of Coastal is included in Item 1, "Business" and certain encumbrances on its properties are described in Note 5 of the Notes to Consolidated Financial Statements included herein.
The real property owned by the Company with regard to its subsidiary pipelines is owned in fee and consists principally of sites for compressor and metering stations and microwave and terminal facilities. With respect to the subsidiary 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 and its pipeline subsidiaries may acquire by the exercise of the right of eminent domain, through proceedings in United States 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. All of the principal properties of ANR Pipeline are subject to the lien of its Mortgage and Deed of Trust dated as of September 1, 1948, securing its First Mortgage Pipe Line Bonds, and some of such properties are subject to "permitted liens" as defined in such Mortgage and Deed of Trust. The First Mortgage Pipe Line Bonds were retired in 1993 and ANR Pipeline is in the process of terminating the associated Mortgage and Deed of Trust.
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.
A subsidiary of Coastal has initiated a suit against TransAmerican Natural Gas Corporation ("TransAmerican") in the District Court of Webb County, Texas, for breach of two gas purchase agreements. In February 1993, TransAmerican filed a Third Party Complaint and a Counterclaim in this action against Coastal and certain subsidiaries. TransAmerican alleges breach of contract, fraud, conspiracy, duress, tortious interference and violations of the Texas Free Enterprises and Anti-trust Act arising out of the gas purchase agreements. TransAmerican seeks compensatory damages, exemplary damages and attorney fees. The trial began on March 14, 1994.
Numerous 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. Additional information regarding legal proceedings is set forth in Notes 3 and 14 of the 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.
The principal market on which Coastal Common Stock is traded is the New York Stock Exchange; Coastal Common Stock is also listed on The Stock Exchange in London, the Stock Exchanges of Dusseldorf, Frankfurt, Hamburg and Munich in Germany and on the Amsterdam Stock Exchange. The Class A Common Stock of Coastal is non-transferable; however, such stock is convertible share-for-share into Coastal Common Stock. As of March 16, 1994, the approximate number of holders of record of Common Stock was 12,550 and of the Class A Common Stock was 3,900.
The following table presents the high and low sales prices for Coastal common shares based on the daily composite listing of transactions for New York Stock Exchange stocks.
Coastal expects to continue paying dividends in the future. Dividends of $.09 per share were paid on the Class A Common Stock for each quarterly period in 1993 and 1992. At December 31, 1993, under the most restrictive of its financing agreements, the Company was prohibited from paying dividends and distributions on its Common Stock, Class A Common Stock and preferred stocks in excess of approximately $409.9 million.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial data (in millions of dollars except per share amounts) is derived from the Consolidated Financial Statements included herein and Item 6 of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992. The Notes to Consolidated Financial Statements included herein contain other information relating to this data.
* In addition, cash dividends of $.36, $.36, $.36 and $.18, respectively, were paid on the Company's Class A Common Stock in 1993, 1992, 1991 and 1990.
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 hereof.
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) hereof.
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 information called for by this Item with respect to the directors is set forth under "Election of Directors" and "Information Regarding Directors" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is incorporated herein by reference.
The executive officers of the Registrant as of March 16, 1994, were as follows:
The above named persons bear no family relationship to each other. Their respective terms of office expire coincident with the officer elections at the Annual Board of Directors' meeting which follows Coastal's Annual Meeting of Stockholders. Each of the officers named above have been officers of Coastal, ANR Pipeline and/or Colorado for five years or more with the following exceptions:
Mr. Arnold was elected Vice President of Coastal in August 1993. He has been a Vice President of Coastal States Management Corporation, a subsidiary of Coastal, since 1977.
Mr. Bullock was elected Senior Vice President of Coastal in August 1992. From 1987 to 1990, he was an Executive Vice President of British Petroleum's BP Exploration Company and a director and a member of the
management committee of BP Exploration USA. From 1990 to 1992, he was an independent petroleum consultant for several major exploration companies.
Mr. Corrallo was elected Senior Vice President and General Counsel of Coastal in March 1993. He has served as a Senior Vice President of Coastal States Management Corporation, a subsidiary of Coastal, since August 1991 and prior thereto as Vice President since December 1986.
Mr. Gullquist was elected Senior Vice President of Coastal in March 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. Hart was elected Vice President of Coastal in March 1994. From 1989 through 1994, he was president of Hart Associates, Inc., an energy development firm.
Mr. Iglesias was elected a Senior Vice President of Coastal in January 1992. He was president of Mobile Bay Refining Company from 1982 to 1987 and of Mo-Bel Corporation from 1987 to 1990.
Mr. King was elected Executive Vice President of Coastal in May 1992. From 1987 to 1990, he was Senior Vice President of refining, supply and transportation for Crown Central Petroleum Corporation.
Mr. Oglesby was elected a Vice President of Coastal in August 1991. He served as an Executive Vice President of Colorado and ANR Pipeline from January 1988 to May 1993. He was Senior Vice President for Marketing and Transportation of Valero Transmission Company from 1985 to 1987.
Mr. Powell was elected Vice President of Coastal and Senior Vice President of Coastal States Management Corporation in August 1993. From 1984 to 1993 he was in private law practice with the law firms of Powell, Popp & Ikard and Powell & Associates representing Coastal and other corporations. Prior thereto he was employed at Coastal since 1978.
Mr. Simpson was elected a Vice President of Coastal in April 1990 and of Colorado in May 1990. He has been a Vice President of Coastal States Management Corporation, a subsidiary of Coastal, for the past ten years.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The information called for by this item is set forth under "Executive Compensation" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information called for by this item is set forth under "Stock Ownership," "Election of Directors" and "Information Regarding Directors" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information called for by this item is set forth under "Election of Directors," "Transactions with Management and Others" and "Certain Business Relationships" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders filed pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is incorporated herein by reference.
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 Coastal and Subsidiaries and Supplemental Information are included in response to Item 8 hereof on the attached pages as indicated:
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included on the attached pages as indicated:
Schedules other than those referred to above are omitted as not applicable or not required, or the required information is shown in the Consolidated Financial Statements or Notes thereto.
3. Exhibits.
_________________________ 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, 1993.
POWERS OF ATTORNEY
Each person whose signature appears below hereby appoints David A. Arledge, Coby C. Hesse 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.
THE COASTAL CORPORATION (Registrant)
By: DAVID A ARLEDGE -------------------- David A. Arledge President March 29, 1994
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: O. S. WYATT, JR. --------------------- O. S. Wyatt, Jr. Chairman of the Board and Chief Executive Officer March 29, 1994
By: DAVID A. ARLEDGE ---------------------- David A. Arledge Principal Financial Officer and Director March 29, 1994
By: COBY C. HESSE --------------------- Coby C. Hesse Principal Accounting Officer March 29, 1994
By: JOHN M. BISSELL --------------------- John M. Bissell Director March 29, 1994
* * *
By: GEORGE L. BRUNDRETT, JR. By: KENNETH O. JOHNSON ---------------------------- --------------------------- George L. Brundrett, Jr. Kenneth O. Johnson Director Director March 29, 1994 March 29, 1994
By: ERVIN O. BUCK By: JEROME S. KATZIN ---------------------------- --------------------------- Ervin O. Buck Jerome S. Katzin Director Director March 29, 1994 March 29, 1994
By: HAROLD BURROW By: THOMAS R. McDADE ---------------------------- --------------------------- Harold Burrow Thomas R. McDade Director Director March 29, 1994 March 29, 1994
By: ROY D. CHAPIN, JR. By: J. HOWARD MARSHALL, II ---------------------------- --------------------------- Roy D. Chapin, Jr. J. Howard Marshall, II Director Director March 29, 1994 March 29, 1994
By: JAMES F. CORDES By: L. D. WOODDY, JR. ---------------------------- --------------------------- James F. Cordes L. D. Wooddy, Jr. Director Director March 29, 1994 March 29, 1994
By: ROY L. GATES ---------------------------- Roy L. Gates Director March 29, 1994
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 changes in the ratio of net return on average common stockholders' equity can be attributed primarily to changes in earnings, as earnings increased in 1993 and decreased in 1992. The 1993 increase in the cash flow from operating activities to long-term debt ratio resulted from increased cash flow from operations and reduced long-term debt, while the 1992 decrease can be attributed to decreased cash flow from operations and increased long-term debt. The total debt to total capitalization ratio improved in 1993 as debt was paid down while equity was increased through retained earnings and stock issuances. The 1992 increase was due to increased debt and reduced equity. The 1993 increase in the times interest earned ratio resulted from increased earnings and reduced interest expense; while the 1992 decrease resulted from decreased earnings and increased interest expense.
Cash flows provided from operating activities were $809.8 million in 1993 and $434.2 million in 1992. The 1993 increase can be attributed to increased earnings and a reduction in inventories and other working capital requirements.
Capital expenditures amounted to $392.7 million in 1993 and $573.5 million in 1992. The Company, which had emphasized its capital expansion program in 1992 and 1991 in order to expand its earnings base, returned to a lower level of capital spending in 1993, as it emphasized debt reduction. Prepayments for gas supply and payments for settlement of natural gas contract disputes required investments of $11.4 million and $43.8 million in 1993 and 1992, respectively.
The Company was able to reduce total debt by $471.3 million in 1993 primarily by the use of internally generated funds and $193.5 million of proceeds resulting from the issuance of preferred stock in April 1993. Dividend payments increased by $11.0 million as a result of the new preferred stock issue.
Capital expenditures for 1994, including the Company's equity investments in partnerships and joint ventures, are currently budgeted at approximately $500.0 million. These expenditures are primarily for completion of projects in process, operational necessities, environmental requirements, expansion projects and increased efficiency. Other expansion opportunities will continue to be evaluated.
Financing for budgeted expenditures and mandatory debt retirements in 1994 will be accomplished by the use of internally generated funds, existing credit lines and new financings.
Funding for certain proposed natural gas pipeline projects is anticipated to be provided through non-recourse project financings in which the projects' assets and contracts will be pledged as collateral. Equity participation by other entities will also be considered. To the extent required, cash for equity contributions to projects will be from general corporate funds.
On September 23, 1993, ANR Pipeline filed a shelf registration statement with the Securities and Exchange Commission for the public offering of up to $200 million in senior unsecured debt securities which became effective October 5, 1993. In February 1994, ANR Pipeline completed an offering of $125.0 million of 7-3/8% Debentures due in 2024. The net proceeds from the sale will be used for capital expenditures and for other general corporate purposes.
Unused lines of credit at December 31, 1993, were as follows (millions of dollars):
Credit agreements of certain subsidiaries contain covenants which limit the making of advances to affiliates and payment of dividends. Where applicable, restrictions are generally in the form of computed capacities with respect to advances and the payment of dividends. At December 31, 1993, net assets of consolidated subsidiaries amounted to approximately $5.1 billion, of which approximately $1.7 billion was restricted. These provisions have not and are not expected to have any meaningful impact on the ability of the Company to meet its cash obligations.
In 1994, the Company adopted Statement of Financial Accounting Standards ("FAS") No. 112, "Employer's Accounting for Postemployment Benefits." This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The implementation of this new standard is not expected to have a significant effect on the Company's results of operations or financial position.
In 1993, the Company adopted changes in accounting for post-retirement benefits as required by FAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions." See Note 11 in the Notes to Consolidated Financial Statements.
The Company's operations are subject to extensive federal, state and local environmental laws and regulations. The Company anticipates annual capital expenditures of $20 to $40 million over the next several years aimed at 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." Certain subsidiaries of the Company have been named as a potentially responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15 sites for which the Environmental Protection Agency ("EPA") has developed sufficient information to estimate total clean-up costs of approximately $350 million, the Company estimates its pro-rata exposure to be paid over a period of several years is approximately $5 million, and has made appropriate provisions. At three other sites, EPA is currently unable to provide the Company with an estimate of total clean-up costs and, accordingly, the Company is unable to calculate its share of those costs. Finally, at five other sites, the Company has paid amounts to other PRPs as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis.
There are additional areas of environmental remediation responsibilities which may fall on the Company. Future information and developments will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's liquidity or financial position.
RESULTS OF OPERATIONS
The Company operates principally in the following lines of business: natural gas, refining and marketing, exploration and production, and coal.
NATURAL GAS. Natural gas operations involve the production, purchase, gathering, storage, transportation and sale of natural gas, principally to utilities, industrial customers and other pipelines, and include the operations of natural gas liquids extraction plants.
In the fourth quarter of 1993, ANR Pipeline Company and Colorado Interstate Gas Company ("CIG") placed their Order 636 (See Note 14 in the Notes to Consolidated Financial Statements) service structures into effect and now offer an array of unbundled transportation, storage and balancing service options. Under Order 636, the interstate pipeline companies will no longer offer sales for resale services, with the exception of certain gas sales services provided by CIG, which are being phased out over a three-year period. Former gas sales customers of the interstate pipelines have largely retained their firm storage and transportation services levels. These services were previously contracted as part of bundled sales services. Consequently, while operating revenues will be reduced as a result of the implementation of Order 636, purchases and other related costs will be reduced by a similar amount.
1993 Versus 1992. The increase in operating revenues of $501 million can be attributed to increased sales volumes for the interstate pipelines and gas marketing companies, higher prices for the gas marketing companies, and increased storage and transportation revenues. Decreased gas sales prices for the interstate pipelines partially offset the increase. Total throughput volumes for the interstate pipelines increased by approximately 1%, while the volume for the gas marketing companies increased by 10%.
Purchases increased $529 million over 1992, primarily due to volume increases for the interstate pipelines and gas marketing companies and cost of gas increases for the gas marketing companies, resulting in a reduction in the gross profit of $28 million.
The operating profit increase of $2 million results from increased sales volumes of $7 million; higher storage and transportation revenues of $137 million; and reduced depreciation, depletion and amortization of $41 million offset by lower margins of $166 million, increased operating expenses of $11 million and other decreases of $6 million. The primary factor contributing to the increase in storage and transportation revenues and the decrease in margins is the restructuring of pipeline bundled sales services into separate service components, as required by changing regulations. The depreciation, depletion and amortization decrease of $41 million results from lower pipeline rates for ANR Pipeline due to a settlement with the FERC.
1992 Versus 1991. Operating revenues increased in 1992 as a result of increased sales volumes for the interstate pipelines and gas marketing companies, higher prices for the gas marketing companies, increased storage and transportation revenues and the benefit from resolution of outstanding rate matters and litigation. Decreased gas sales prices for the interstate pipelines partially offset the increase.
Purchases increased by $267 million in 1992, primarily due to volume increases for interstate pipelines and gas marketing companies and higher costs for the gas marketing companies, resulting in a gross profit increase of $74 million.
The operating profit increase of $1 million results from increased sales volumes of $14 million, improved storage and transportation revenues of $37 million and other increases of $21 million which were partially offset by lower margins of $32 million, increased operating expenses of $29 million and increased depreciation, depletion and amortization of $10 million. The other increases are primarily due to the settlement of outstanding rate matters and litigation. The sales volumes were up and the margins were down for both the interstate pipeline companies and gas marketing companies. The storage and transportation revenue increase results from increased transportation volumes
and improved storage revenues. The operating expense increase results from increases for compressor fuel, gas and gas liquids handling charges and rate settlement related expenses. The depreciation, depletion and amortization increase results from a non-recurring 1991 retroactive adjustment related to Wyoming Interstate Company, Ltd.
REFINING AND MARKETING. Refining and marketing operations involve the purchase, transportation and sale of refined products, crude oil, condensate and natural gas liquids; the operation of refining and chemical plants; the sale at retail of gasoline, petroleum products and convenience items; petroleum product terminaling and marketing of crude oil and refined petroleum products worldwide.
1993 Versus 1992. The decrease in operating revenues of $360 million results from decreased sales prices and lower volumes. Sales volumes decreased primarily due to a reduction in the sales of products purchased from others. In addition, crude processing was suspended at the Company's three refineries in Kansas during 1993.
Purchases for the refining and marketing segment decreased by $550 million, a result of lower costs and volumes, and increased emphasis on hedging activities to minimize the impact of price volatility. This resulted in an increased gross profit of $190 million. Increased margins of $187 million, increased revenues from marine operations of $4 million and other increases of $8 million, which were partially offset by reduced volumes of $9 million, make up the gross profit increase. A portion of the margin increase can be attributed to the Company concentrating on marketing higher margin, value-added products and services. The Company eliminated almost 50 marginal third party locations from its distribution system in 1993. These steps also added to the volume decline in 1993.
The operating profit increase of $290 million results from the improved gross profit of $190 million, reduced operating expenses of $47 million and lower depreciation, depletion and amortization of $53 million. The reduction in operating expenses results from the suspension of crude oil processing at the Company's refineries in Kansas and the nonrecurrence of the related $35 million restructuring charge in 1992. Partially offsetting these decreases were increased expenses for new foreign operations. Depreciation, depletion and amortization decreased as a result of a 1992 restructuring charge of $50 million not recurring.
1992 Versus 1991. The increase in 1992 operating revenues of $264 million can be attributed to increased volumes, primarily for the terminal and marketing operations, which were partially offset by decreased prices and reduced marine revenues. The lower prices affected all areas of the segment's operations.
Purchases for the segment increased by $185 million, a result of increased volumes and lower costs, resulting in a gross profit increase of $79 million. This $79 million gross profit increase results from volume increases of $84 million and margin increases of $37 million being partially offset by lower marine revenues of $17 million, reduced gross profit from the sale, trading and exchanging of third-party products of $12 million and other decreases of $13 million.
The operating profit decrease of $93 million results from increased operating expenses of $114 million and increased depreciation, depletion and amortization of $58 million more than offsetting the increased gross profit of $79 million. The increased operating expenses are attributable to charges for restructuring and increased maintenance costs. Depreciation, depletion and amortization increased primarily from a $50 million charge for the restructuring of certain refining assets.
EXPLORATION AND PRODUCTION. Exploration and production operations involve the exploration, development and production of natural gas, crude oil, condensate and natural gas liquids. The segment also includes related intrastate natural gas marketing activities and gas plant processing operations.
1993 Versus 1992. The increase in operating revenues of $47 million can be attributed to increased sales volumes for all products and increased natural gas prices being partially offset by lower prices for oil, condensate and natural gas liquids. Natural gas revenue increases of $51 million were partially offset by decreases for oil, condensate and natural gas liquids of $3 million and other of $1 million.
The operating profit increase of $4 million results from increased volumes for all products of $48 million and natural gas price increases of $13 million being offset by reduced prices for crude oil, condensate and natural gas liquids of $13 million, increased operating expenses of $15 million, increased depreciation, depletion and amortization of $26 million and other of $3 million.
The increase in operating expenses results from additional wells in operation and higher costs associated with operating natural gas plants. Depreciation, depletion and amortization increased as a result of an increase in volumes.
1992 Versus 1991. Operating revenues decreased in 1992 as reduced revenues from gas brokerage, lower prices for crude oil, condensate and plant products and decreased other income were partially offset by increased natural gas prices and increased volumes for all products. The decrease in other income is due to the sale in 1991 of two gathering systems.
The operating profit increase for the segment resulted from increased volumes for all products of $31 million and increased natural gas prices of $5 million being partially offset by lower prices for oil, condensate and natural gas liquids of $10 million; increased depreciation, depletion and amortization of $14 million; reduced revenue from gas brokerage of $2 million and other decreases of $9 million. Included in the other decreases are non-recurring gains of $7 million from 1991 property sales. The increase in depreciation, depletion and amortization can be attributed to increased volumes.
COAL. Coal operations include mining, processing and marketing of coal from Company-owned reserves and from other sources, and the brokering of coal for others.
1993 Versus 1992. The decrease in coal revenues results from decreased prices more than offsetting increased volumes sold and brokered. The purchase of the Soldier Creek Mine in late 1993 added 600,000 tons/year of new capacity.
The operating profit increase results from increased volumes of $13 million, reduced operating expenses of $6 million and other of $1 million more than offsetting lower prices of $18 million. Operating expenses were reduced by expanding the percentage of overall production from the lower-cost Utah operations.
1992 Versus 1991. The decrease in operating revenues is a result of decreased sales volumes and lower prices. The tonnage, excluding brokerage, decreased approximately 1%. Sales prices decreased at all mines.
Operating profit increased in 1992 as decreases for coal costs and operating expenses of $20 million more than offset reduced revenues of $18 million and increased depreciation, depletion and amortization of $1 million. The decrease for coal costs and operating expenses results from lower volumes sold and more efficient operations.
OTHER. Other operations involve trucking, power production operations and other activities.
1993 Versus 1992. The $9 million reduction in operating revenues results from volume decreases for the trucking operations and lower cogeneration revenues. The $7 million decrease in operating loss results from reduced operating expenses of $16 million, primarily for the trucking operations, exceeding the revenue decline; as trucking operations increased by $11 million offset by a $4 million decrease for the other operations. The decreased operating expenses result from reduced wages and lower rent expense.
1992 Versus 1991. The $27 million increase in 1992 in operating revenues can be attributed to volume increases for the trucking operations and increased cogeneration revenues. The operating loss increase of $15 million results from a $19 million increased loss for trucking partially offset by a $4 million income increase for other operations, as increased operating expenses more than offset improved revenues. The increased operating expenses of $41 million are a result of increased freight volumes and increased cogeneration activities.
OTHER INCOME - NET
1993 Versus 1992. Other income-net increased by $53 million in 1993 due to increased equity income from unconsolidated subsidiaries of $8 million, nonrecurrence of the 1992 writedown of refining investments and other assets of $43 million and other increases of $2 million.
1992 Versus 1991. Other income-net decreased by $43 million in 1992 as a result of decreased gains from sales of investments of $13 million, the writedown of refining investments and other assets in 1992 of $43 million, reduced dividend and interest income of $6 million and other decreases of $18 million offset by increased equity income from unconsolidated subsidiaries of $37 million.
INTEREST AND DEBT EXPENSE
1993 Versus 1992. Interest and debt expense decreased by $43 million in 1993, primarily as a result of lower average debt outstanding and lower interest rates more than offsetting reduced capitalized interest and other financial costs. At December 31, 1993, after giving effect to interest rate swaps, approximately 16% of the Company's debt was tied to money market-related rates.
1992 Versus 1991. Interest and debt expense increased by $47 million in 1992, primarily as a result of higher average debt outstanding and reduced capitalized interest more than offsetting lower average interest rates and reduced interest on pipeline customer refunds.
TAXES ON INCOME
Income taxes fluctuated primarily as a result of changing levels of income before taxes and changes in the effective federal income tax rate. The 1993 taxes include a $29 million charge for the cumulative effect of adjusting the deferred federal income tax liability to reflect the change in the corporate federal income tax rate from 34% to 35%.
EXTRAORDINARY ITEM
The extraordinary loss, net of income taxes, resulted from the early retirement of debt. See Note 13 in the Notes to Consolidated Financial Statements.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders The Coastal Corporation Houston, Texas
We have audited the accompanying consolidated balance sheets of The Coastal Corporation and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of operations, common stock and other stockholders' equity and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 14(a)2. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 The Coastal Corporation and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 11 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
Houston, Texas February 3, 1994
THE COASTAL CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED OPERATIONS (Millions of Dollars Except Per Share)
See Notes to Consolidated Financial Statements
THE COASTAL CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Millions of Dollars)
See Notes to Consolidated Financial Statements
THE COASTAL CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Millions of Dollars)
See Notes to Consolidated Financial Statements
THE COASTAL CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED CASH FLOWS (Millions of Dollars)
See Notes to Consolidated Financial Statements
THE COASTAL CORPORATION AND SUBSIDIARIES STATEMENT OF CONSOLIDATED COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (Millions of Dollars and Thousands of Shares)
See Notes to Consolidated Financial Statements
THE COASTAL CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The equity method of accounting is used for investments in which the Company has a 20% to 50% continuing interest and exercises significant influence. Investments in which the Company has less than a 20% interest are accounted for by the cost method.
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. Cash flows of a hedging instrument that are accounted for as a hedge of an identifiable transaction are classified in the same category as the cash flows from the item being hedged. The Company made cash payments for interest and financing fees (net of amounts capitalized) of $447.2 million, $480.6 million and $426.6 million in 1993, 1992 and 1991, respectively. Cash payments (refunds) for income taxes amounted to $21.0 million, ($9.8) million and $81.0 million for 1993, 1992 and 1991, respectively.
INVENTORIES - Inventories of refined products and crude oil are accounted for by the first-in, first-out cost method ("FIFO") or market, if lower. Natural gas inventories are accounted for on the basis used for rate making and in reporting to the Federal Energy Regulatory Commission ("FERC"). Colorado Interstate Gas Company ("CIG") uses the last-in, first-out method, while ANR Pipeline Company uses the first-in, first-out method. Inventories of coal are accounted for at average cost, or market, if lower. Inventories of materials and supplies are accounted for at average cost.
HEDGES - The Company frequently enters into futures and other contracts to hedge the price risks associated with inventories, commitments and certain anticipated transactions. Coastal defers the impact of changes in the market value of these contracts until such time as the hedged transaction is completed.
PROPERTY, PLANT AND EQUIPMENT - Property additions include acquisition costs, administrative costs and, where appropriate, capitalized interest allocable to construction. Capitalized interest amounted to $8.4 million, $10.7 million and $22.1 million in 1993, 1992 and 1991, 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.
Depreciation, depletion and amortization of gas and oil properties are provided on the unit-of-production basis whereby the unit rate for depreciation, depletion and amortization is determined by dividing the total unrecovered carrying value of gas and oil properties plus estimated future development costs by the estimated proved reserves included therein, as estimated by an independent engineer. The average amortization rate per equivalent unit of a thousand cubic feet of gas production for oil and gas operations was $1.00 each for 1993, 1992 and 1991. Provisions for depletion of coal properties, including exploration and development costs, are based upon estimates of recoverable reserves using the unit-of-production method. Provision for depreciation of other property is primarily on a straight-line basis over the estimated useful life of the properties.
Costs of minor property units (or components thereof) retired or abandoned are charged or credited, net of salvage, to accumulated depreciation, depletion and amortization. Gain or loss on sales of major property units is credited or charged to income.
GOODWILL - Goodwill, which primarily relates to the acquisitions of American Natural Resources Company and Colorado Interstate Gas Company, amounted to $563.3 million at December 31, 1993, and is being amortized on a straight-line basis over a 40-year period. Amortization expense charged to operations was approximately $19.0
million for 1993, 1992 and 1991, respectively. As warranted by facts and circumstances, the Company periodically assesses the recoverability of the cost of goodwill from future operating income.
INCOME TAXES - The Company follows the liability method of accounting for deferred income taxes as required by the provisions of Statement of Financial Accounting Standards No. 109 - Accounting for Income Taxes.
REVENUE RECOGNITION - The Company's subsidiaries recognize revenues for the sale of their respective products in the period of delivery. Revenues for services are recognized in the period the services are provided.
CURRENCY TRANSLATION - The U.S. dollar is the functional currency for substantially all the Company's foreign operations. For those operations, all gains and losses from currency translations are included in income currently.
EARNINGS PER SHARE - Earnings (loss) per common and common equivalent share amounts are based on the average number of common and Class A common shares outstanding during each period, assuming conversion of preferred stocks which are common stock equivalents and exercise of all stock options having exercise prices less than the average market price of the common stock using the treasury stock method.
Average shares entering into the computations are:
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 71 (FAS 71) - The interstate natural gas pipeline operations and certain storage subsidiaries are subject to the regulations and accounting procedures of the FERC. These subsidiaries meet the criteria and, accordingly, follow the reporting and accounting requirements of FAS 71.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS - Certain minor reclassifications have been made to conform with current reporting practices. The effect of the reclassifications was not material to the Company's results of operations or financial position.
NOTE 2. INVENTORIES
Inventories at December 31 were (millions of dollars):
Elements included in inventory cost are material, labor and manufacturing expenses.
The excess of replacement cost over the carrying value of natural gas in underground storage carried by the last-in, first-out method was approximately $52.6 million and $47.8 million at December 31, 1993 and 1992, respectively.
Natural gas in underground storage at December 31, 1993, includes $161.5 million, pending approval by the FERC, which is to be transferred to Property, Plant and Equipment for regulatory and accounting purposes.
NOTE 3. TAKE-OR-PAY OBLIGATIONS
Other assets include $134.0 million and $225.6 million at December 31, 1993 and 1992, 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. Currently, FERC regulations allow for the billing of a portion of the costs of take-or-pay settlements and renegotiating gas purchase contracts. Prepayments are normally recoupable through future deliveries of natural gas.
As a result of the implementation of Order 636 by CIG on October 1, 1993 (See Note 14 in the Notes to Consolidated Financial Statements), CIG's future gas sales will be made at negotiated prices and will not be subject to regulatory price controls. This will not affect the recoverability or the results of pending take-or-pay litigation or any take-or-pay or contractual reformation settlements that CIG 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 by CIG pursuant to FERC's Order No. 528.
Contract reformation and take-or-pay costs incurred as a result of the mandated Order 636 restructuring will be recovered under the transition cost mechanisms of Order 636, as well as through negotiated agreements with customers. The Company believes that these mechanisms provide adequate coverage for such costs.
Several producers have instituted litigation arising out of take-or-pay claims against subsidiaries of 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 subsidiaries have resolved the majority of the exposure with their suppliers for approximately 13% of the amounts claimed. At December 31, 1993, the Company estimated that unresolved asserted and unasserted producers' claims amounted to approximately $31 million. The remaining disputes will be settled where possible and litigated if settlement is not possible.
At December 31, 1993, 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 $38 million, $30 million, $23 million, $15 million and $4 million for the years 1994-1998, respectively, and $9 million thereafter. Such commitments have also 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.
NOTE 4. INVESTMENTS
The Company has interests in corporations and partnerships which are accounted for on an equity basis. These investments, included in Other Assets, are Great Lakes Gas Transmission Limited Partnership (50% interest), which operates an interstate pipeline system; Pacific Refining Company (50% interest), which operates a refinery and terminal facilities in California; Javelina Company (40% interest), which operates a gas processing plant in Corpus Christi, Texas; Eagle Point Cogeneration Partnership (50% interest), which operates a cogeneration facility in New Jersey; corporate joint ventures (50% interest), which have developed gas and oil properties in Argentina; and several pipeline and other ventures. The Company's investment in these entities, including advances, amounted to $424.7 million and $330.2 million at December 31, 1993 and 1992, respectively. The Company's equity in income of the investments was $71.9 million, $63.8 million and $26.6 million in 1993, 1992 and 1991, respectively, while dividends and partnership distributions received amounted to $17.5 million, $47.8 million and $18.9 million in 1993, 1992 and 1991, respectively. The 1992 equity in income excludes the restructuring charges as discussed in Note 10.
Summarized financial information of these entities is as follows (millions of dollars):
NOTE 5. DEBT
LONG-TERM DEBT - Balances at December 31 were (millions of dollars):
At December 31, 1993, long-term credit agreements with banks totaled $1,198.1 million, including $308.0 million available to The Coastal Corporation. Loans under these agreements bear interest at money market-related rates (weighted average 4.16% at December 31, 1993). Annual commitment fees range up to 1/2% payable on the unused portion of the applicable facility. At December 31, 1993, $653.5 million was outstanding. Notes payable to banks of $400.0 million are obligations of a wholly owned subsidiary, Coastal Natural Gas Company (CNG), for which CNG has pledged the common stock of its first-tier subsidiaries as collateral. The agreements contain restrictive covenants which, among other things, limit the payment of dividends by CNG and the amount of additional indebtedness of CNG and its subsidiaries.
The subsidiary project financing note bears interest at money market-related rates.
Various agreements contain restrictive covenants which, among other things, limit the payment of advances or dividends by certain subsidiaries and additional indebtedness of certain subsidiaries. At December 31, 1993, net assets of consolidated subsidiaries amounted to approximately $5.1 billion, of which $1.7 billion was restricted by such provisions.
In February 1994, ANR Pipeline Company sold $125.0 million of 7-3/8% Debentures due in 2024. The net proceeds from the sale will be used for capital expenditures and for other general corporate purposes.
INTEREST RATE AND CURRENCY SWAPS - The Company has entered into a number of interest rate swap agreements which have effectively fixed interest rates on $563.5 million of floating rate debt. Under these agreements, Coastal will pay the counterparties interest at a fixed rate, and the counterparties will pay Coastal interest at a variable rate based on the London Interbank Offered Rate (LIBOR). At December 31, 1993, the weighted average fixed rate payable under these agreements was 9.61%. The Company has also entered into a number of offsetting interest rate swap agreements which have effectively converted $250.0 million of fixed rate debt into floating rate debt. Terms expire at various dates through the third quarter of 1996.
The foreign currency exposure relating to certain of the Swiss franc denominated debt of the Company and one of its subsidiaries and Japanese yen denominated debt of the Company has been hedged to maturity, resulting in effective borrowing costs ranging from 8.2% to 11.1%.
Coastal and its subsidiaries have entered into these interest rate and currency swaps with major banking institutions to reduce the impact of interest rate and exchange rate fluctuations with respect to certain floating rate and foreign currency denominated debt. In certain instances, the Company has also entered into interest rate swaps to convert a portion of its fixed rate debt into floating rates. Coastal is exposed to loss if one or more of the counterparties default. Interest rate swap transactions generally involve exchanges of fixed and floating interest payment obligations without exchanges of underlying principal amounts. Similarly, currency swaps involve exchanges of interest payments in differing currencies but provide for the exchange of principal amounts at maturity, usually through an escrow arrangement to limit credit risk. Consequently, Coastal's exposure to credit loss is significantly less than the contracted amounts.
Neither the Company nor the counterparties are required to collateralize their respective obligations under these swaps. At December 31, 1993, Coastal had no exposure to credit loss on interest rate swaps and approximately $108.7 million of exposure to credit loss on currency swaps.
SUBORDINATED LONG-TERM DEBT - Balances at December 31 were (millions of dollars):
MATURITIES - The aggregate amounts of long-term debt (including subordinated) maturities for the five years following 1993 are (millions of dollars):
NOTES PAYABLE - At December 31, 1993, Coastal and its subsidiaries had $264.0 million of outstanding indebtedness to banks under short-term lines of credit, compared to $221.4 million at December 31, 1992. As of December 31, 1993, $413.0 million was available to be drawn under short-term credit lines.
RESTRICTIONS ON PAYMENT OF DIVIDENDS - Under the terms of the most restrictive of the Company's financing agreements, approximately $409.9 million was available at December 31, 1993, for payment of dividends on the Company's common and preferred stocks.
GUARANTEES - Coastal and certain subsidiaries have guaranteed specific obligations of several unconsolidated affiliates. Such affiliates are generally not required to collateralize their contingent liabilities to the Company. At December 31, 1993, the Company had guaranteed 50% of a construction financing entered into by a partially owned partnership, 45% of a construction financing of a second partnership and 100% of a construction financing entered into by a third partnership. The Company's proportionate share of the outstanding principal balances under these guarantees was $135.0 million at December 31, 1993. Other guarantees and indemnities related to obligations of unconsolidated affiliates amounted to approximately $224.9 million as of the same date. The Company anticipates that two of the guaranteed construction loans will be refinanced in 1994 and the third in early 1995, all on a non-recourse basis. The Company is of the opinion that its unconsolidated affiliates will be able to perform under their respective financings and other obligations and that no payments will be required and no losses will be incurred under such guarantees and indemnities.
Coastal and certain subsidiaries have guaranteed approximately $16.7 million of obligations of third parties under leases and borrowing arrangements. Where possible, the Company has obtained security interests and guarantees by the principals. Cash requirements and losses under these guarantees are expected to be nominal.
NOTE 6. LEASES
The Company and its subsidiaries had rental expense of approximately $98.2 million, $92.6 million and $98.1 million in 1993, 1992 and 1991, respectively, excluding leases covering natural resources. Aggregate minimum lease payments under existing noncapitalized long-term leases are estimated to be $82.8 million, $80.5 million, $77.3 million, $71.0 million, and $59.5 million for the years 1994-1998, respectively, and $720.7 million thereafter.
NOTE 7. MANDATORY REDEMPTION PREFERRED STOCK
Shares and aggregate redemption value of mandatory redemption preferred stock outstanding, excluding shares redeemable within one year, were (thousands of shares and millions of dollars):
CIG has 550,000 shares of $100 par value cumulative preferred stock authorized, of which 5,560 shares were outstanding at December 31, 1993. The stock outstanding is due in 1997 with an annual dividend rate of 5.5%. The series is to be redeemed at par value through annual sinking fund payments.
ANR Pipeline Company had 1,086,640 outstanding shares of $1.00 par value redeemable cumulative preferred stock at December 31, 1993. The stock consists of three series with dividends per share of $2.675, $2.12 and $12.00. The $2.675 and $2.12 series were issued at $25 per share and the $12.00 series was issued at $100 per share. The
current per share redemption prices are $25.268 for the $2.675 Series (decreases to issue price by 1995), $25.318 for the $2.12 Series (decreases to issue price by 1996) and $103.790 for the $12.00 Series (decreases to issue price by 1999). All series are to be redeemed through annual sinking fund payments.
The aggregate amount of share redemption requirements for the five years following 1993 are (millions of dollars):
NOTE 8. 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 the Company could realize in a current market exchange.
The estimated value of the Company's long-term debt and mandatory redemption preferred stock is based on interest rates at December 31, 1993 and 1992, respectively, for new issues with similar remaining maturities. The fair market value of the Company's interest rate and foreign currency swaps is based on the estimated termination values at December 31, 1993 and 1992, respectively.
NOTE 9. COMMON AND PREFERRED STOCK
Shares of common stock and Class A common stock reserved for future issuance as of December 31, 1993 were:
Common stock reserved for conversion is at the rate of one share for each share of Class A common stock, 3.6125 shares for each share of Series A or Series B preferred stock and 7.1121094 shares for each share of Series C preferred stock. Each share of common stock and Series A, Series B and Series C preferred stock is entitled to one vote while each share of Class A common stock is entitled to 100 votes. However, 25% of the Company's directors standing for election at each annual meeting will be determined solely by holders of the common stock and preferred stocks mentioned above, voting as a class.
In April 1993, the Company completed the public offering of 8,000,000 shares of $2.125 Cumulative Preferred Stock, Series H, at $25 per share. The net proceeds from the sale were used to retire short- and long-term debt of the Company.
Under the 1980 Stock Option Plan, no options were exercisable at December 31, 1993, and 904 common shares and 25 Class A common shares were exercisable at December 31, 1992. No additional options may be granted under the 1980 Plan.
Under the 1984 Plan, 4,113 Class A common shares and 13,442 common shares were available for granting of options, and options for 39,262 Class A common shares and 92,288 common shares were exercisable at December 31, 1993. At December 31, 1992, nine Class A common shares and 12 common shares were available for granting of options, and options for 124,448 Class A common shares and 185,080 common shares were exercisable.
Under the 1985 Plan, 69,758 common shares were available for granting of options, and options for 953,898 common shares were exercisable at December 31, 1993. At December 31, 1992, 102,773 common shares were available for granting of options, and options for 1,194,414 common shares were exercisable.
Under the 1990 Plan, 23,717 common shares were available for granting of options, and options for 181,380 common shares were exercisable at December 31, 1993. At December 31, 1992, 368,690 common shares were available for granting of options, and options for 42,002 common shares were exercisable.
Options are currently granted under the plans at 100% of market value. The following table presents a summary of stock option transactions for the three years ended December 31, 1993:
NOTE 10. SEGMENT REPORTING
The Company operates principally in the following lines of business: natural gas, refining and marketing, exploration and production, and coal. Natural gas operations involve the production, purchase, gathering, storage, transportation and sale of natural gas, principally to utilities, industrial customers and other pipelines, and include the operation of natural gas liquids extraction plants.
Refining and marketing operations involve the purchase, transportation and sale of refined products, crude oil, condensate and natural gas liquids; the operation of refineries and a chemical plant; the sale at retail of gasoline, petroleum products and convenience items; petroleum product terminaling; and marketing of crude oil and refined petroleum products worldwide.
Exploration and production operations involve the exploration, development and production of natural gas, crude oil, condensate and natural gas liquids. The segment also includes related intrastate natural gas marketing activities and gas plant processing operations.
Coal operations include the mining, processing and marketing of coal from Company-owned reserves and from other sources, and the brokering of coal for others.
Other operations include regional trucking operations involving activities as common carriers in interstate and intrastate commerce and activities in power production and other projects.
Operating revenues by segment include both sales to unaffiliated customers, as reported in the Company's Statement of Consolidated Operations, and intersegment sales, which are accounted for on the basis of contract, current market or internally established transfer prices. The intersegment sales are primarily sales from the exploration and production segment to the natural gas and refining and marketing segments and from the natural gas segment to the refining and marketing segment.
Operating profit is total revenues less interest income from affiliates and operating costs and 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. Corporate assets are those assets which are not specifically identifiable with a segment.
The Company's operating revenues, operating profit, capital expenditures, and depreciation, depletion and amortization expense for the years ended December 31, 1993, 1992 and 1991, and identifiable assets as of December 31, 1993, 1992 and 1991, by segment, are shown as follows (millions of dollars):
Refining and marketing revenues include gross profit arising from the selling, trading and exchanging of third party products. Approximate amounts from these transactions included in revenues and the impact on earnings, exclusive of interest costs, were (millions of dollars):
The number and magnitude of such transactions may vary significantly from year to year, particularly in view of conditions in world petroleum markets.
Results for 1992 reflect a primarily non-cash $125 million pretax charge for restructuring certain refining and marketing operations. The charge reflects numerous actions to reduce costs and working capital, limit risks and eliminate marginal activities, and primarily relates to reducing the carrying value of certain assets. Eighty-five million dollars of the charge relates to wholly owned assets and was made against operating profit. The remaining $40 million relates to partially owned investments and was included in Other Income-Net.
OTHER INCOME - Net for 1991 includes gains of $13.2 million from the sale of securities. Also included are equity method earnings related to the business segments as follows (millions of dollars):
Revenues from sales to any single customer during 1993, 1992 or 1991 did not amount to 10% or more of the Company's consolidated revenues for any year.
NOTE 11. BENEFIT PLANS
The Company has non-contributory pension plans covering substantially all U.S. employees. These plans provide benefits based on final average monthly compensation and years of service. The Company's funding policy is to contribute the amount necessary for the plan to maintain its qualified status under the Employee Retirement Income Security Act of 1974. The pension benefit for 1993, 1992 and 1991 is shown in the following table (millions of dollars):
The discount rate used in determining the actuarial present value of the projected benefit obligation was 7.25% in 1993 and 8.25% in 1992 and 1991. The expected increase in future compensation levels was 4% in 1993 and 6% in 1992 and 1991, and the expected long-term rate of return on assets was 11%.
The following table sets forth the funded status of the plans and the amounts recognized in the Company's Consolidated Balance Sheet (millions of dollars):
Plan assets include common stock and Class A common stock of the Company amounting to a total of 3.75 million shares at December 31, 1993 and 1992.
The Company also participates in several multi-employer pension plans for the benefit of its employees who are union members. Company contributions to these plans were $7.1 million each for 1993, 1992 and 1991. The data available from administrators of the multi-employer pension plans is not sufficient to determine the accumulated benefit obligations, nor the net assets attributable to the multi-employer plans in which Company employees participate.
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 match the contributions made by employees, amounted to $17.7 million, $16.6 million and $15.4 million in 1993, 1992 and 1991, respectively.
The Company provides certain health care and life insurance benefits for retired employees. Substantially all U.S. employees are provided these benefits. Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("FAS 106"). FAS 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 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 20 years. The Company has elected to recognize the initial postretirement benefit obligation of approximately $133.1 million over a period of 20 years. The Company's cash flows were not affected by implementation of FAS 106 and the incremental impact on the Company's 1993 results of operations before income taxes is approximately $13.6 million, of which $8.3 million is being deferred by the Company's rate regulated subsidiaries. The subsidiaries have filed to include such deferred costs in their rates.
[CAPTION]
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 16.0% in 1993, declining gradually to 7.0% by the year 2004. 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, 1993, and net postretirement health care cost by approximately 4.7%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.25%.
The Company adopted Statement of Financial Accounting Standards No. 112, "Employer's Accounting for Postemployment Benefits" ("FAS 112") 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 the new standard will not have a material effect on the Company's results of operations or financial position.
NOTE 12. TAXES ON INCOME
Pretax earnings (loss) before extraordinary item are composed of the following (millions of dollars):
Provisions for income taxes (benefits) before extraordinary item are composed of the following (millions of dollars):
The Company and the Internal Revenue Service ("IRS") Appeals Office have concluded a tentative settlement of all contested adjustments to federal income tax returns filed for the years 1982 through 1984. The settlement is in the process of being finalized. The Company's federal income tax returns filed for the years 1985 through 1987 have been examined by the IRS, and the Company has received notice of proposed adjustments to the returns for each of those years. The Company currently is contesting certain of these adjustments with the IRS Appeals Office. Examinations of the Company'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 consolidated financial statements.
The Company increased its deferred tax liability as a result of legislation enacted in 1993 increasing the Corporate federal income tax rate from 34% to 35% commencing in 1993.
Provisions for income taxes were different than the amount computed by applying the statutory U.S. federal income tax rate to earnings before tax. The reasons for these differences are (millions of dollars):
Deferred tax liabilities (assets) which are recognized for the estimated future tax effects attributable to temporary differences and carryforward are (millions of dollars):
NOTE 13. EXTRAORDINARY ITEM
In June 1993, the Company retired $500.0 million of 11 1/4% Senior Notes due in 1996. The transaction resulted in an extraordinary loss of $2.5 million ($.02 per share), net of income taxes of $1.3 million.
NOTE 14. LITIGATION AND REGULATORY MATTERS
LITIGATION - In December 1992, certain of CIG'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 CIG 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.
A subsidiary of Coastal has initiated a suit against TransAmerican Natural Gas Corporation in the District Court of Webb County, Texas for breach of two gas purchase agreements. In February 1993 TransAmerican Natural Gas Corporation filed a Third Party Complaint and a Counterclaim in this action against Coastal and certain subsidiaries. TransAmerican alleges breach of contract, fraud, conspiracy, duress, tortious interference and violations of the Texas Free Enterprises and Anti-trust Act arising out of the gas purchase agreements. TransAmerican seeks compensatory damages, exemplary damages and attorney fees. The matter is set for trial on March 14, 1994.
Numerous 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.
RATE REGULATION - On April 8, 1992, the FERC issued Order No. 636 ("Order 636"), which required significant changes in the services provided by interstate natural gas pipelines. Subsidiaries of the Company and numerous other parties have sought judicial review of aspects of Order 636.
ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. ANR Pipeline now offers a wide range of unbundled transportation, storage and balancing services. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving ANR Pipeline's restructuring filings.
Order 636 also provides mechanisms for recovery of transition costs associated with compliance with that Order. These transition costs include gas supply realignment costs, the cost of stranded pipeline investment and the cost of new facilities required to implement Order 636. ANR Pipeline expects that it will incur transition costs of
approximately $150 million. As a result of the recovery mechanisms provided under Order 636, the Company anticipates that these transition costs will not have a material adverse effect on the Company's consolidated financial position or its results of operations.
On December 17, 1992, the FERC issued a policy statement that outlined changes on how pipelines may recover the costs of employees' post-retirement benefits other than pensions. The FERC's policy will be to recognize, as a component of jurisdictional cost-based rates, allowances for FAS 106 costs of company employees when determined on an accrual basis, provided certain conditions are met.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC. The proposed rates reflect a $121 million increase in ANR Pipeline's cost of service from that approved in the settlement of ANR Pipeline's last rate case and a $218 million increase over ANR Pipeline's approved rates for its restructured services. The increase represents higher plant investment, Order 636 restructuring costs, rate of return and tax rate changes and increased costs related to the required adoption of recent accounting rule changes, i.e., FAS 106 and FAS 112. The FERC has permitted ANR Pipeline to place its new rates into effect on May 1, 1994, subject to refund, and subject to further orders.
On July 2, 1993, CIG 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 CIG's restructured services became effective October 1, 1993.
CIG has "unbundled" its gas sales from its other services. Separate gathering, transportation, storage and other services are available on a "stand- alone" basis to any customers desiring them. CIG's Order 636 transition costs are not expected to be material.
On March 31, 1993, CIG filed at FERC to increase its rates by approximately $26.5 million annually. Such rates (adjusted to reflect CIG's Order 636 program) became effective subject to refund on October 1, 1993.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company, Ltd., subsidiaries, are regulated by the FERC. Certain regulatory issues remain unresolved among these companies, their customers, their 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.
ENVIRONMENTAL REGULATION - The Company's operations are subject to extensive federal, state and local environmental laws and regulations. The Company anticipates annual capital expenditures of $20 to $40 million over the next several years aimed at 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." Certain subsidiaries of the Company have been named as a potentially responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15 sites for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $350 million, the Company estimates it pro-rata exposure to be paid over a period of several years is approximately $5 million and has made appropriate provisions. At three other sites, the EPA is currently unable to provide the Company with an estimate of total clean-up costs and, accordingly, the Company is unable to calculate its share of those costs. Finally, at five other sites, the Company has paid amounts to other PRPs as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis.
There are additional areas of environmental remediation responsibilities which may fall on the Company. Future information and developments will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's liquidity or financial position.
NOTE 15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 1993 and 1992 were (millions of dollars except per share):
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
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 separately presented for natural gas operations. Substantially all of the Company's properties are located in the United States. In 1992, the Company acquired an equity method investment with operations in Argentina.
The 1991 revisions of previous estimates of Natural Gas Systems reserves of natural gas are related to the Company's independent engineer's interpretation of an agreement, effective January 1, 1991, between the Company's subsidiary, CIG, and Mesa Operating Limited Partnership. Such revisions are not due to change in gross reserve estimates for the affected properties.
ESTIMATED QUANTITIES OF PROVED RESERVES
Changes in proved reserves since the end of 1990 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 147,549, 183,741 and 191,351 million cubic feet and storage liquids volumes are approximately 150,000, 159,000 and 207,000 barrels at December 31, 1993, 1992 and 1991, respectively.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES
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 (Millions of dollars)
RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES (Millions of dollars)
The average amortization rate per equivalent Mcf was $1.00 for the years 1993, 1992 and 1991.
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 by 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 material future revisions (millions of dollars):
Principal sources of change in the standardized measure of discounted future net cash flows during each year are (millions of dollars):
None of the amounts include any value for natural gas systems storage gas, which was approximately 41 Bcf of gas for CIG, 107 Bcf for ANR Pipeline and 150,000 barrels of liquids for CIG at the end of 1993.
Share of Equity Method Investment - At December 31, 1993, the net investment in Argentine properties amounted to $58.5 million, representing net proved reserves of 144.5 Bcf of gas and 6.51 million barrels of oil, condensate and natural gas liquids. The standardized measure of discounted future net cash flows related to these reserves is $78.6 million at December 31, 1993. The Company's share of earnings for 1993 was approximately $5 million.
SUPPLEMENTAL STATISTICS FOR COAL MINING OPERATIONS
The following table contains Coastal's estimated recoverable coal reserves for operating properties. Reserves estimates are prepared by independent mining consultants and by internal sources (Coastal geologists and engineers). The reliability of the estimates is a function of the amount and quality of the geological data generated to date on each property and varies considerably from property to property. The reserve amounts are subject to change depending on additional geological data generated and/or actual mining operations.
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION BALANCE SHEET (Millions of Dollars)
See Notes to Condensed Financial Statements.
S-1
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION BALANCE SHEET (Millions of Dollars)
See Notes to Condensed Financial Statements.
S-2
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION STATEMENT OF OPERATIONS (Millions of Dollars)
See Notes to Condensed Financial Statements.
S-3
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION STATEMENT OF CASH FLOWS (Millions of Dollars)
See Notes to Condensed Financial Statements.
S-4
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The financial statements of the Company reflect the investment in wholly-owned subsidiaries using the equity method.
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 and financing fees of $357.1 million, $375.6 million and $313.6 million in 1993, 1992 and 1991, respectively. Cash payments (refunds - primarily from subsidiaries) for income taxes amounted to $(49.8) million, $(63.9) million and $(6.9) million for 1993, 1992 and 1991, respectively.
Federal Income Taxes -- The Company follows the liability method of accounting for income taxes as required by the provisions of FAS 109, "Accounting for Income Taxes."
The Company files a consolidated federal income tax return with its wholly- owned subsidiaries. Members of the consolidated group with taxable incomes 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.
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 results of operations or financial position.
NOTE 2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related Notes of Coastal and Subsidiaries for additional information.
NOTE 3. DEBT AND GUARANTEES
Information on the debt of the Company is disclosed in Note 5 of the Notes to Consolidated Financial Statements included herein. The Company has guaranteed certain long-term debt of its subsidiaries (approximately $82.4 million outstanding at December 31, 1993, including current maturities) and certain other obligations arising in the ordinary course of business. The Company and certain of its subsidiaries have entered into interest rate and currency swaps with major banking institutions. The Company is exposed to loss if one or more counterparties default. In addition, the Company or certain of its subsidiaries are guarantors on certain bank loans of corporations and partnerships in which the Company or certain subsidiaries have equity interests. Information on the swaps and guarantees is disclosed in Note 5 of the Notes to Consolidated Financial Statements.
The aggregate amounts of long-term debt (including subordinated debt) maturities of Coastal for the five years following 1993 are (millions of dollars):
NOTE 4. DIVIDENDS RECEIVED
Cash dividends received from consolidated subsidiaries were as follows: 1993 - - $66.6 million, 1992 - $142.8 million and 1991 - $68.1 million.
S-5
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Millions of Dollars)
- -------------------- (A) Reclassifications and other miscellaneous adjustments. (B) Intercompany transfer. (C) Amortization of exploration cost charged to income. (D) Writedown of property, plant and equipment. (E) Reclass -- Investment in partially-owned company. S-6
Depreciation, depletion and amortization of gas and oil properties costs are provided on the unit-of-production basis whereby the unit rate for depreciation, depletion and amortization is determined by dividing the total unrecovered carrying value of all gas and oil properties plus estimated future development costs by the estimated proved reserves included therein, as estimated by an independent engineer. Provisions for depletion of coal properties are based upon estimates of recoverable reserves using the unit-of-production method. Provision for depreciation of other property is made primarily on a straight-line basis over the estimated useful lives of the property.
The annual rates of depreciation are as follows:
S-7
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
(Millions of Dollars)
- --------------- (A) Reclassifications and other miscellaneous adjustments. (B) Intercompany transfer.
S-8
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
- ----------------- (A) Accounts charged off net of recoveries.
S-9
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS
(Millions of Dollars)
The average amount of borrowings were computed by averaging the daily outstanding balances. Where interest expense was affected by commitment and/or facility fees, the weighted average interest rates were computed by averaging the daily interest rates, including such fees. If there were no such fees, the weighted average interest rates were computed by dividing the total interest for the year by the average aggregate borrowings outstanding.
S-10
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(Millions of Dollars)
- ----------- (1) Amounts are charged to operating costs and expenses with the exception of an insignificant amount which, together with other expenses, are redistributed to operating, construction and other accounts.
(2) Production taxes are charged against operating revenues.
S-11
EXHIBIT INDEX
Exhibit Number Document - ------ -------- [C] [S] 3.1+ Restated Certificate of Incorporation of Coastal, as restated on March 22, 1994. (Filed as Module TCC-Artl-Incorp on March 28, 1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit 3.4 to Coastal'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 Registrant will furnish to the Commission, on request, any such documents).
10.1+ The Coastal Corporation Stock Option Plan (Exhibit 10.1 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1980).
10.2+ Employment Agreement between Coastal States Gas Corporation and Sam F. Willson, Jr., dated December 1, 1979 (Exhibit 10.41 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1980).
10.3+ First Amendment of The Coastal Corporation Stock Option Plan, dated September 3, 1981 (Exhibit 10.11 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1982).
10.4+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.5+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.6+ The Coastal Corporation Performance Unit Plan effective as of January 1, 1987 (Exhibit 10.5 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1987).
10.7+ The Coastal Corporation Replacement Pension Plan effective as of November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1987).
10.8+ Description of Coastal's Key Employees Bonus Plan (Exhibit 10.7 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1987).
10.9+ The Coastal Corporation Stock Purchase Plan, as restated on January 1, 1994 (Appendix B to Coastal's Proxy Statement for the 1994 Annual Meeting of Stockholders dated March 29, 1994).
10.10+ The Coastal Corporation Stock Grant Plan, effective December 1, 1988 (Exhibit 10.12 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1988).
10.11+ The Coastal Corporation Deferred Compensation Plan for Directors (Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1988).
10.12+ The Coastal Corporation 1990 Stock Option Plan (Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1989).
10.13+ Employment Agreement between The Coastal Corporation and James F. Cordes dated April 12, 1990 (Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1990).
EXHIBIT INDEX
_________________________ Note: + Indicates documents incorporated by reference from the prior filing indicated. * Indicates documents filed herewith.