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 16,300 persons as of December 31, 1994.
Annual Reports on Form 10-K for the year ended December 31, 1994, are also filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by each of the four 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, 1994, 1993 and 1992, and the related identifiable assets as of December 31, 1994, 1993 and 1992, 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 transportation, storage, gathering 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 auctions gas on the open market in producing areas to handle a residual quantity of gas purchased under certain continuing gas purchase contracts pending renegotiation or expiration of such contracts. ANR Pipeline operates two 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, an intrastate pipeline extending from Niagara Falls to Syracuse, New York, in which an affiliate of ANR Pipeline has a 45% interest.
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. ANR Pipeline's principal pipeline facilities at December 31, 1994 consisted of 12,661 miles of pipeline and 96 compressor stations with 1,069,398 installed horsepower. At December 31, 1994, 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 the production, gathering, processing, transportation, storage and sale of natural gas. Colorado purchases and produces natural gas and makes sales of such gas at the wellhead principally to local gas distribution companies for resale. Separately, Colorado contracts to gather, process, transport and store natural gas owned by third parties.
Colorado's gas transmission system extends from gas production areas in the Texas Panhandle, western Oklahoma and western Kansas, northwesterly through eastern Colorado to the Denver area, and from production areas in Montana, Wyoming and Utah, southeasterly to the Denver area. 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, 1994 consisted of 6,356 miles of pipeline and 66 compressor stations with approximately 348,000 installed horsepower. At December 31, 1994, the design peak day delivery capacity of the transmission system was approximately 2.0 Bcf per day. The underground storage facilities have a working capacity of approximately 29 Bcf and a peak day delivery capacity of approximately 769 MMcf.
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. In 1994, CGS formed Coastal Electric Services Company to market electricity and provide related physical and financial services.
COMPETITION
ANR Pipeline and Colorado have historically competed with interstate and intrastate pipeline companies in the sale, transportation and storage of gas and with independent producers, brokers, marketers and other pipelines in the gathering, processing and sale of gas within 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, Colorado's gas sales contracts have been unbundled at the producer wellhead and 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. Additional information on Order 636 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 transportation, storage 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 transportation, storage and balancing business. ANR Pipeline's gathering services, which are offered in the southeast and southwest gas producing areas of the United States, compete with other providers of such services, including gathering companies, producers and intrastate and interstate pipeline companies.
ANR PIPELINE
TRANSPORTATION SERVICES AND GAS SALES
On November 1, 1992, as part of its Interim Settlement, ANR Pipeline implemented a restructuring of its traditional sales services 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" transportation, storage and balancing service options. Additional information concerning Order 636, including transportation and storage, is set forth in "Regulations Affecting Gas Systems - General" included herein.
ANR Pipeline transports gas to markets on its system and also transports gas to other markets off its system under transportation and exchange arrangements with other companies including distributors, intrastate and interstate pipelines, producers, brokers, marketers and end-users. Transportation service revenues amounted to $555 million for 1994 compared to $533 million for 1993 and $463 million for 1992. The significant increase in transportation revenues for 1993 was largely attributable to the restructuring of ANR Pipeline's sales service under the Interim Settlement, as discussed above.
Gas sales revenues of ANR Pipeline amounted to $106 million during 1994, compared to $604 million in 1993 and $635 million in 1992. The significant decrease in 1994 is due to the elimination of ANR Pipeline's merchant function effective November 1, 1993, as discussed above. Gas sales revenues in 1994 were derived primarily from the auctioning of gas on the open market in producing areas, as previously discussed.
During 1994, ANR Pipeline's throughput was 1,371 Bcf, of which approximately 24% was transported for 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 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 cities of Racine, Kenosha, Appleton and their surrounding areas in Wisconsin. In 1994, ANR Pipeline provided approximately 70% and 35% of the total gas requirements for Wisconsin and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1994, 1993 and 1992 are as follows:
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 a residual quantity of gas under certain remaining gas purchase contracts. ANR Pipeline's Order 636 restructured tariff provides a transitional mechanism 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 the auctioning of such gas on the open market in producing areas.
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 reclassified 62.1 Bcf of working gas to recoverable base gas, which is pending approval before the FERC. ANR Pipeline also has the contract rights for 42 Bcf of storage capacity provided by Blue Lake Gas Storage Company and 30 Bcf of storage capacity provided by ANR Storage. Underground storage services of up to 180 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, 1994, 1993 and 1992 were 113.8 Bcf, 106.5 Bcf and 128.0 Bcf, respectively. The 1994 gas storage reserves are comprised of 23.4 Bcf of natural gas, maintained under ANR Pipeline's own account as working gas for system balancing and no-notice services and 90.4 Bcf of recoverable base gas reserves. Of the total recoverable base gas reserves, 28.3 Bcf represents reserves in the seven owned and eight leased storage fields and 62.1 Bcf represents working gas which ANR Pipeline has reclassified as recoverable base gas.
COLORADO
GAS SALES, STORAGE AND TRANSPORTATION
Beginning in October 1993, Colorado implemented Order 636 on its system and as a result, Colorado's gas sales contracts have been unbundled and such sales are now made at the producer wellhead. Colorado's gas sales contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, Colorado's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by the FERC. Colorado is also authorized to abandon all sales for resale at such time as the contracts expire and without prior FERC approval. Effective October 1, 1993, Colorado formed an unincorporated Merchant Division to conduct most of 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 October 1, 1993, Colorado assigned an undivided interest in a portion of its company-owned leases to a new subsidiary. The subsidiary contracts to sell the production to Colorado's Merchant Division, which utilizes the gas primarily for its sales to Colorado's traditional customers. The reserve volumes reported by Colorado represent those interests retained by Colorado together with those assigned to the new subsidiary.
Gas sales revenues were $139 million in 1994, compared to $223 million in 1993 and $261 million in 1992. The decreases are due largely to the fact that prior to the mandated restructuring under Order 636, the costs of providing gathering, storage and transportation services for sales customers were recovered as part of the total resale
rate and were classified as part of gas sales revenue. Subsequent to restructuring, these costs are now recovered under separate rates for each service.
Colorado has engaged in "open access" transportation and storage of gas owned by third parties for several years. In addition, prior to October 1, 1993, Colorado provided storage and transportation services as part of its "bundled" sales service. As a result of Order 636, Colorado has "unbundled" these services from its sales services and continues to provide these services to third parties under individual contracts. Such services are at negotiated rates that are within minimum and maximum levels approved by the FERC. Also, pursuant to Order 636, 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 1994, 1993 and 1992 are as follows:
GAS GATHERING AND PROCESSING
Colorado 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 approximately 3,000 miles of gathering lines and approximately 110,200 horsepower of compression in its gathering operations. Colorado owns and operates six gas processing plants which recovered approximately 88 million gallons of liquid hydrocarbons in 1994, compared to 86 million gallons in 1993 and 77 million gallons in 1992, and 4,300 long tons of sulfur in 1994, compared to 4,400 long tons in 1993 and 3,600 long tons in 1992. Additionally, in 1994, Colorado processed approximately 6 million gallons of liquid hydrocarbons owned by others compared to 12 million in 1993 and 10 million in 1992. These plants, with a total operating capacity of approximately 697 MMcf daily, recover mainly propane, butanes, natural gasoline, sulfur and other by-products, which are sold to refineries, chemical plants and other customers.
ANR STORAGE COMPANY
ANR Storage develops and operates gas storage reservoirs to store gas for customers. ANR Storage owns four underground storage fields and related facilities in northern Michigan, the working storage capacity of which is approximately 56 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. All of the jointly owned capacity is committed under long term contracts, including 42 Bcf contracted to ANR Pipeline.
GAS SYSTEM RESERVES
ANR PIPELINE
With the termination of its merchant service, ANR Pipeline no longer reports on gas system reserves and, therefore, this report has been replaced by a general discussion set forth in "Producing Area Deliverability", presented below.
PRODUCING AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas producing areas in the United States, the Gulf Coast and the Midcontinent. Statistics published by the Energy Information Agency, Office of Oil and Gas, U.S. Department of Energy, indicate that approximately 81% of all natural gas in the lower 48 states is produced from these two areas. Interconnecting pipelines provide shippers with access to all other major gas producing areas in the United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the Midcontinent and Gulf Coast producing areas through direct connections and interconnecting pipelines and gatherers is approximately 4,200 MMcf per day. An additional 250 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 sources of natural gas to facilitate transportation arrangements made by third-party shippers. During 1994, field development, newly connected gas wells, gas production facilities and pipeline interconnections contributed over 1,100 MMcf per day to total deliverability accessible to shippers on ANR Pipeline's pipeline system.
COLORADO
Colorado has reported in its Form 10-K for the year ended December 31, 1994 its gas system reserves based on information prepared by Huddleston, the Company's independent engineers. Additional information is set forth in "Reserves Dedicated to a Particular Customer," presented below.
RESERVES DEDICATED TO A PARTICULAR CUSTOMER
Colorado is committed to sell gas to Mesa Operating Company ("Mesa"), a customer, under a 1928 agreement as amended, from specific owned gas reserves in the West Panhandle Field of Texas. Under an amendment which became effective January 1, 1991, a cumulative 23% of the total net production may be taken for customers other than Mesa. Effective October 1, 1993, an undivided interest in the West Panhandle Field leases, related to this 23% of the total net production not committed to Mesa, was assigned by Colorado to a new subsidiary.
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. The FERC has approved an agreement under which Columbia Gas Transmission Corporation, one of these shippers, will pay WIC an "exit fee" and its contract will be terminated. The FERC's order remains pending on rehearing. In 1994, the WIC line transported an average of 339 MMcf daily, compared to 228 MMcf daily in 1993. 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 2,000-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 897 Bcf in 1994 as compared to 854 Bcf in 1993. Great Lakes has long term 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
CGS and its subsidiaries operate the Company's unregulated natural gas business, including certain of Coastal's natural gas gathering and processing, gas supply and marketing, price risk management and producer financing activities. In mid-1994, CGS expanded its functional areas to form Coastal Electric Services Company to market electricity and provide related physical and financial services. Additionally, in May, 1994, CGS's subsidiary, CGMC, accelerated its transition from a national marketing company to a North American operation by opening Coastal Gas Marketing Canada, in Calgary, Alberta, which focuses on Canadian markets and supplies. CGS, through its subsidiaries, managed the sale and delivery of over 1,000 Bcf of natural gas in 1994, as compared to 828 Bcf in 1993, and processed over 109 Bcf of natural gas, producing over 2.6 million barrels of natural gas liquids in 1994. Also, in 1994, CGS arranged a $250 million production payment facility to make capital available to producers, including affiliates, with long term oil and natural gas supplies. CGS and its affiliates conduct business with over 1,200 producer and market customers in Canada, Mexico and the United States.
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, storage, gathering and balancing of gas, rates and charges, 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. Additionally the FERC has asserted rate-regulation (but not certificate regulation) over gathering. Colorado is challenging the FERC's assertion of rate jurisdiction over gathering, but has agreed in a settlement that for three years beginning October 1, 1993, Colorado will post in its tariff the minimum and maximum gathering rates which will be established and approved by the FERC. 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. Certain other affiliates of the Company are subject to the jurisdiction of state regulatory commissions in states where their facilities are located.
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. Colorado has also filed for and recovered take-or-pay settlement costs through the same regulatory provisions.
Contract reformation, take-or-pay costs and other costs incurred as a result of the mandated Order 636 restructuring are recoverable either under the transition costs mechanisms of Order 636 or through negotiated agreements with the customers of ANR Pipeline and Colorado.
On April 8, 1992, the FERC issued 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. The case is currently in the briefing phase before the United States Court of Appeals for the D.C. Circuit. 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. As of October 1, 1993, Colorado separated all of its services and separately contracts for each service on a stand-alone or "unbundled" basis. Gathering, storage and transportation services are provided at negotiated rates established between minimum and maximum levels approved by the FERC, while gas processing rates are not subject to FERC regulations.
On November 1, 1993, ANR Pipeline placed its Order 636 restructured services and rates into effect. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving ANR Pipeline's restructuring filings. Those appeals have been held in abeyance by the United States Court of Appeals for the D.C. Circuit, pending further order. On March 24, 1994, the FERC issued its "Fourth Order on Compliance Filing and Third Order on Rehearing," which addressed numerous rehearing issues and confirmed that after minor required tariff modifications, ANR Pipeline is now fully in compliance with Order 636 and the requirements of the orders on its restructuring filings. The FERC issued a further order regarding certain compliance issues on July 1, 1994. In accordance with this order, ANR Pipeline filed revised tariff sheets on July 18, 1994.
RATE MATTERS
ANR PIPELINE. 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 became effective November 1, 1992 and expired with ANR Pipeline's implementation of Order 636 on November 1, 1993. Under the Interim Settlement, gas inventory demand charges were collected from ANR Pipeline's resale customers for the period November 1, 1992 through October 31, 1993. This method of gas cost recovery required refunds for any over- collections, and placed ANR Pipeline at risk for under-collections. As required by the Interim Settlement, ANR Pipeline filed with the FERC on April 29, 1994, a reconciliation report showing over-collections and, therefore, proposed refunds totaling $45.1 million. Such refund obligations were recorded at December 31, 1994 and December 31, 1993, and are included in the Consolidated Balance Sheet under "Deferred Credits and Other." Certain customers have disputed the level of those refunds. By an order issued in February 1995, the FERC has directed ANR Pipeline to make immediate refunds of $45.1 million and applicable interest, subject to further investigation of the claims which the customers have made. The matter is still pending.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC under Docket RP94-43. The increase represents the effects of 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 No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" and FAS No. 112, "Employers' Accounting for Postemployment Benefits." On March 23, 1994, the FERC issued an order granting and denying various requests for summary disposition and establishing hearing procedures for issues remaining to be investigated in this proceeding. The order required the reduction or elimination of certain costs which resulted in revised rates such that the revised rates reflect an $85.7 million increase in the cost of service from that approved in the Interim
Settlement and a $182.8 million increase over ANR Pipeline's approved rates for its restructured services under Order 636. On April 29, 1994, ANR Pipeline filed a motion with the FERC that placed the new rates into effect May 1, 1994, subject to refund. On September 21, 1994, the FERC accepted ANR Pipeline's filing in compliance with the March 23, 1994 order, subject to further modifications including an additional reduction in cost of service of approximately $5 million. ANR Pipeline submitted its compliance filing to the FERC on October 6, 1994, which compliance filing was accepted by order issued December 8, 1994, subject to a further compliance filing requirement, which ANR Pipeline submitted on January 9, 1995, and which was accepted by an order issued in February 1995. Further, on December 8, 1994, the FERC issued its order denying rehearing of the March 23, 1994 order. On January 26, 1995, ANR Pipeline sought judicial review of these orders before the United States Court of Appeals for the D.C. Circuit.
ANR Pipeline has executed a Settlement Agreement (the "Settlement Agreement") with Dakota Gasification Company ("Dakota") and the Department of Energy which resolves litigation concerning purchases of synthetic gas by ANR Pipeline from the Great Plains Coal Gasification Plant (the "Plant"). That litigation, originally filed in 1990 in the United States District Court in North Dakota, involved claims regarding ANR Pipeline's obligations under certain gas purchase and transportation contracts with the Plant. The Settlement Agreement resolves all disputes between the parties, amends the gas purchase agreement between ANR Pipeline and Dakota and terminates the transportation contract. The Settlement Agreement is subject to final FERC approval, including an approval for ANR Pipeline to recover the settlement costs from its customers. On August 3, 1994, ANR Pipeline filed a petition with the FERC requesting: (a) that the Settlement Agreement be approved; (b) an order approving ANR Pipeline's proposed tariff mechanism for the recovery of the costs incurred to implement the Settlement Agreement; and (c) an order dismissing a proceeding currently pending before the FERC, wherein certain of ANR Pipeline's customers have challenged Dakota's pricing under the original gas supply contract. On October 18, 1994, the FERC issued an order consolidating ANR Pipeline's petition with similar petitions of three other pipeline companies and setting the Settlement Agreement and other Dakota-related proceedings for limited hearing before an Administrative Law Judge who must render an initial decision by December 31, 1995. On December 20, 1994, ANR Pipeline filed its testimony, and has responded to numerous discovery requests. The hearing is scheduled to commence on June 20, 1995. ANR Pipeline believes the ultimate resolution of the Dakota related issues will not have a material adverse impact on its financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated with compliance with that Order. ANR Pipeline has estimated that its transition costs will amount to approximately $150 million, which will consist primarily of gas supply realignment costs, the cost of stranded pipeline investment and the Dakota costs described above. As of December 31, 1994, ANR Pipeline has incurred transition costs in the amount of $43 million. ANR Pipeline has filed for recovery of approximately $40.5 million of these transition costs, which have been accepted and made effective by the FERC, subject to refund and subject to further proceedings. In addition, ANR Pipeline has filed for recovery of approximately $90 million of costs associated with the Settlement Agreement, as mentioned above. Additional transition cost filings will be made by ANR Pipeline in the future. 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 financial position or results of operations.
COLORADO. Colorado's gas sales for resale contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, Colorado's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by the FERC. Colorado is also authorized to abandon all sales for resale without prior FERC approval at such time as the contracts expire. Pursuant to Order 636, Colorado's gas sales have been unbundled at the producer wellhead.
On March 31, 1993, Colorado filed at FERC under Docket RP93-99 to increase its rates by approximately $26.5 million annually. Such rates (adjusted to reflect Colorado's Order 636 program) became effective subject to refund on October 1, 1993. On November 10, 1994, the FERC approved a settlement offer submitted by Colorado which resolved all of the issues in the proceeding. Colorado has implemented the rates established in the settlement for prospective application and will be required to make refunds as a result of the approval of the settlement. Such refunds will be distributed in March 1995. Colorado has fully accrued for these refunds and therefore such refunds will not have an adverse effect on its consolidated financial position or results of operations.
WIC. In 1993, the FERC initiated proceedings under Section 5 of the NGA to review WIC's rates. Those proceedings resulted in an Administrative Law Judge decision as well as a FERC order which would have required WIC to reduce its rates prospectively. However, during the period that such proceedings were under way, WIC filed to revise its rates and on March 3, 1995, the FERC issued an order accepting an uncontested settlement between WIC, the FERC staff and the parties to the case which resolved WIC's rates for the period beginning December 1, 1994. The FERC issued an order on March 21, 1995 which terminated the 1993 rate proceedings and vacated its previously issued orders in that docket. WIC will be required to make refunds for amounts collected subsequent to December 1, 1994 which are in excess of the amounts that would have been collected under the settlement rates. WIC has fully accrued for these refunds and therefore such refunds will not have an adverse effect on its financial position or results of operations.
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.
OTHER DEVELOPMENTS
Effective September 9, 1994, Florida Power Corporation ("FPC") withdrew as an equity partner in both the SunShine Interstate Transmission Company and SunShine Pipeline Company ("SunShine") partnerships. Interests in these partnerships are now held by affiliates of ANR Pipeline and TransCanada. FPC has also terminated its agreements with the partnerships to transport gas on the proposed SunShine system effective March 2, 1995. Future development of the SunShine project is currently under management review. SunShine has obtained a delay in proceedings pending before the Florida Department of Environmental Protection until October 1995 and on February 24, 1995, requested that FERC allow ninety days for SunShine to report the results of its review.
Sponsors of the Liberty Pipeline Project ("Liberty") asked the FERC, on August 1, 1994, to postpone indefinitely its review of the project following the withdrawal in early June of one key shipper who was also a project partner and the withdrawal of another shipper. As a result, the FERC dismissed the application on August 12, 1994. As originally proposed, Liberty consisted of a 38-mile pipeline extending from New Jersey across New York Harbor to Long Island with a potential capacity of 500 MMcf per day and was estimated to cost $170 million. A subsidiary of ANR Pipeline holds a 25.9% interest in the project. The Liberty partners continue to believe that an additional delivery point onto Long Island, as proposed by Liberty, will be necessary in the future and plan to continue pursuing that goal.
ANR Pipeline has filed an application with the FERC to construct, at a cost of $15.3 million, approximately 12 miles of new pipeline in the State of Michigan (the "Link Project") which would interconnect to approximately 8 miles of new pipeline to be constructed by The Consumers' Gas Company, Ltd. ("Consumers") at the Canadian-United States border. The Link Project is an amendment to ANR Pipeline's earlier application to construct the InterCoastal Pipe Line, which was denied approval by the Canadian National Energy Board. The new facilities will have a capacity of 150 MMcf per day and will serve markets in the United States and Canada, including Consumers and Michigan Consolidated Gas Company. Consumers is expected to file for the necessary Canadian regulatory approvals by the end of March 1995, and, subject to the receipt of the necessary FERC and Canadian regulatory approvals, the project could be in service as early as November 1, 1995.
A subsidiary of ANR Pipeline has a 45% equity interest in the proposed Mayflower Pipeline project, which will be owned by a partnership consisting of ANR Pipeline's subsidiary and affiliates of TransCanada and Brooklyn Union Gas Company. The project is proposed to provide natural gas transportation and storage services to markets in the northeastern United States. 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 project could be in service by late 1999, subject to the receipt of federal regulatory approvals of its construction.
In August 1993, ANR Pipeline and NorAm Energy Corporation, formerly Arkla, Inc. ("NorAm") announced the execution of a restructured agreement under which ANR Pipeline, subject to certain conditions precedent, will purchase an ownership interest in 250 MMcf per day of capacity in existing gas transmission facilities. On March 25, 1994, the FERC issued an Order approving this acquisition, subject to certain conditions. NorAm and ANR Pipeline have filed for judicial review of this Order and FERC's Order on Rehearing issued September 20, 1994.
Construction of the new 5.3 Bcf Young Storage Field in northeastern Colorado, in which an affiliate of Colorado is a 47.5% partner, began in 1994. This new storage field is expected to be completed in the first half of 1995 and already is fully subscribed under 30-year contracts.
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 average combined capacity in 1994 and 1993. The aggregate sales volumes (millions of barrels) of Coastal's wholly-owned refineries for the three years ended December 31, 1994, were 136 (1994), 134.9 (1993) and 136.7 (1992). A joint venture, Pacific Refining Company, had sales of 18.8 million barrels in 1994, 19.9 million barrels in 1993 and 21.3 million barrels in 1992 which were excluded from Coastal's 1994, 1993 and 1992 sales. Of the total refinery sales in 1994, 28% was gasoline, 47% was middle distillates, such as jet fuel, diesel fuel and home heating oil, and 25% was heavy industrial fuels and other products.
The average daily processing capacity of crude oil at December 31, 1994, average daily throughput and storage capacity at the Company's wholly-owned operating refineries are set forth below:
* In March 1995, the Company began a program of comprehensive maintenance and inspections at its Aruba refinery. The Company is performing the maintenance now to take advantage of a period of worldwide low refining margins and to prepare for the integration of a new $100 million delayed coker unit coming on line at the refinery later this year. The delayed coker unit will provide for conversion of about 23,000 barrels per day of residual fuel oil into more valuable light-end petroleum products and petroleum coke. Process operations at the Aruba refinery have been suspended for the duration of the maintenance program.
Pacific Refining at Hercules, California has a refining capacity of 55,000 barrels per day at December 31, 1994. 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 1994 and processed 44,142 barrels per day of crude oil and other feedstocks. Present plans are to continue operation of the refinery, 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 Amendments of 1990 and California Air Resources Board regulations compliance upgrades.
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 1994, the products emphasized included premium gasolines and products for specialty markets such as petrochemical feedstocks, aviation fuels and asphalt.
In July 1994, Coastal Aruba Refining Company N.V., a subsidiary of Coastal, acquired approximately 4.5 million barrels of crude oil storage previously under a long term lease arrangement. A related ship berth capable of handling very large crude carrier tanker ships was also acquired.
In August 1994, Coastal Canada Petroleum, Inc., a subsidiary of Coastal, signed agreements under which the Company has restarted production of paraxylene at a petrochemical plant in Montreal East, Quebec, Canada. The facility has the capability of producing up to 400 million pounds per year of paraxylene, a component used in the manufacturing of polyester fibers and containers. Coastal Canada Petroleum, Inc. acquired the processing equipment and entered into a long term lease for the plant site. Other aromatic production units could be restarted as economic conditions and petrochemical markets warrant. The paraxylene unit was restarted in October. The unit has averaged 88% of capacity since start-up and now is operating at its rated capacity of 400 million pounds per year.
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, 1994, are set forth below (thousands of barrels):
Subsidiaries of the Company market refined products and liquefied petroleum gas at wholesale in 37 states through 372 terminals. Coastal Refining & Marketing, Inc. serves customers in the Midwest, Mississippi Valley and the Southwest through 263 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 1994, these subsidiaries' sales volumes were 126 million barrels, which accounted for approximately 42% 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.
A subsidiary of Coastal leases 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. Another subsidiary of Coastal is a partner in a joint venture with a subsidiary of the Malaysian national oil company, Petronas, which uses 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 37 states through approximately 1,457 Coastal branded outlets, with 574 of those outlets operated by the Company. Fleet fueling operations include 21 outlets in Texas and 8 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 35 states.
TRANSPORTATION. The Company's transportation facilities include petroleum liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal has approximately 1,700 miles of pipeline for gathering and transporting an average of 218,000 barrels daily of crude oil, condensate, natural gas liquids and refined products. These lines are located principally in Texas and include 226 miles of crude oil pipelines, 737 miles of refined products pipelines and 671 miles of natural gas liquids pipelines, all 100% owned and operated by Coastal affiliates, and 80 miles of jointly-owned products pipelines with less than a 50% interest. In 1994, throughput of crude oil pipelines averaged 18,339 barrels per day, compared to 148,199 barrels per day in 1993. In 1994, throughput of refined products and natural gas liquid pipelines averaged 200,037 barrels per day, compared to 186,430 barrels per day in 1993.
Other transportation facilities for marketing operations of Coastal subsidiaries include a regional tank truck fleet which distributes refined products and liquefied petroleum gas products to customers in parts of Florida, New England and New York, and another fleet of trucks, which transports petroleum products and liquefied petroleum gas products for Coastal marketing subsidiaries serving the Texas area.
The marine transportation total fleet at December 31, 1994 consisted of 15 tug boats, 23 oil barges, 7 owned tankers used for the transportation of refined petroleum products and crude oil and 2 time-chartered tankers.
EXPLORATION AND PRODUCTION
GAS AND OIL PROPERTIES
Coastal subsidiaries are engaged in gas and oil exploration, development and production operations 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 addition, Coastal subsidiaries are engaged in exploratory concessions in Peru and China.
In 1994, the Company's domestic operations sold approximately 60% 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, 1994 is summarized as follows:
The domestic net acreage held for production is concentrated principally in Texas (32%), Utah (22%), Oklahoma (9%), West Virginia (7%), offshore Gulf of Mexico (7%), Kansas (5%) and Wyoming (5%). Approximately 25%, 17% and 21% of the Company's total domestic undeveloped net acreage is under leases that have minimum remaining primary terms expiring in 1995, 1996 and 1997, respectively.
Productive wells as of December 31, 1994 are as follows (domestic):
EXPLORATION AND DRILLING
During 1994, Coastal's domestic exploration and production units participated in drilling 108 gross wells, 47.7 net wells, to the Company's interest. Coastal's participation in wells drilled in the three years ended December 31, 1994, is summarized as follows:
Wells in progress as of December 31, 1994 are as follows (domestic):
TYPE OF WELL GROSS NET ------------ ----- --- Exploratory........ 1 0.4 Development........ 21 7.8 --- ----- Total............. 22 8.2 === =====
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the general partner in four 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.
Coastal renewed its emphasis on the Gulf of Mexico in 1994 by acquiring over 79,000 net leasehold acres, including reserves, platforms, production facilities and exploration acreage. Coastal began to emphasize international exploration opportunities during 1994 with a subsidiary signing a contract for exploration and development rights covering a 100% interest in approximately 2.97 million acres in central Peru and another subsidiary acquiring a 40% interest in exploration and development rights to approximately 895,000 acres in the East China Sea.
GAS AND OIL PRODUCTION
Natural gas production during 1994 averaged 345 MMcf daily, compared to 334 MMcf daily in 1993. Production from non-pipeline-owned wells averaged 218 MMcf daily in 1994, compared to 207 MMcf daily in 1993. Crude oil, condensate and natural gas liquids production averaged 12,239 barrels daily in 1994, compared to 13,534 barrels daily in 1993.
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, 1994:
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, 1994:
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 1994, total revenues of $34.5 million were generated from the extraction and sale of 124 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, 1994, as estimated by Huddleston, its independent engineers, were 33.7 million barrels, compared to 28.8 million barrels at the end of 1993. Proved gas reserves as of December 31, 1994, net to Coastal's interest, were estimated by the engineers to be 958.4 Bcf compared to 925.5 Bcf as of December 31, 1993.
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 western United States, 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, 1994, coal properties consisted of the following:
________________________
(1) Based on a 65% recovery rate.
At December 31, 1994, the Company controlled approximately 839 million recoverable tons of bituminous coal reserves. Production in 1994 from the Company's reserves totalled 20.4 million tons of which 16.1 million tons were produced from captive operations and 4.3 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 1994 totalled 7.0 and 9.1 million tons, respectively.
Captive sales from ANR Coal and Coastal States Energy were 7.6 million and 8.7 million tons, respectively, in 1994. Brokerage sales in which the Company receives a commission on coal sold for third parties totalled 1.2 million tons for the same period.
In 1994, approximately 67% of sales were to domestic utilities, 18% of sales were to domestic industrial customers and 15% of sales were to export markets primarily in Asia and Canada. Of the total 1994 tonnage sold, 12.5 million tons (77%) were sold under long-term contracts. At December 31, 1994, the weighted average remaining life of these contracts was 60 months.
The Company had approximately 21.5 million tons of annual production capacity at December 31, 1994. In the eastern United States, the Company owns and operates six coal preparation plants and nine loading facilities with a combined annual capacity of 10.8 million tons. Coastal States Energy's mines in Utah employ three longwall mining systems, diesel shuttle cars and have a combined annual capacity of 10.7 million tons.
In addition to its bituminous coal operations, the Company controls overriding royalty interests in approximately 468 million tons of lignite reserves in North Dakota. Production from these reserves in 1994 totalled 16.0 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 Amendments 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, which facility produces 400 tons per day. The LoDAN/(R)/ product is used primarily as a blasting agent in surface mining.
Coastal Chem also operates an integrated methyl tertiary butyl ether ("MTBE") plant with a production capacity of 4,000 barrels per day. MTBE is a gasoline additive which adds oxygen and boosts octane of the blended mixture.
Sales volumes for the three years ended December 31, 1994, 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.
In February 1995, Coastal Power signed a letter of intent to form a joint venture to build and operate one or more power plants of up to 120 megawatts in the industrial center of Wuxi City in the People's Republic of China. Phase one of this project is estimated to have approximately 40 megawatts of capacity at a cost to Coastal Power of $15 to $18 million. The other joint venturer would be a company formed between the Wuxi New Energy Investment Company, a subsidiary of the local power bureau, and China National Aero-Engine Corporation, a subsidiary of Aviation Industries of China.
In January 1995, a subsidiary of Coastal Power initialled an acquisition agreement contemplating the purchase of the stock of Compania de Electricidad de Puerto Plata, S.A. ("CEPP"), an independent power company in the Dominican Republic with a capacity of 69.5 megawatts of which 50 megawatts are barge mounted and 19.5 megawatts are land based. A subsidiary of Coastal Power would own about 48.5% of CEPP's shares and Commonwealth Development Corporation of the United Kingdom would also own about 48.5% of CEPP's shares. The remainder of shares would be owned by Basic Energy Ltd., a Bermuda corporation.
In August 1994, construction commenced on a 91-megawatt power plant in El Salvador leased by a subsidiary of Coastal Power in association with a Salvadoran investor and to be operated by a Coastal subsidiary. Electricity from this new power plant, which is expected to be in operation in the second half of 1995, will be sold to the Salvadoran national utility under a 20 year power purchase agreement.
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 1994, ANR Freight transported approximately 1.6 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 1.4 million tons in 1993. LTL shipments comprised approximately 40% of total tonnage hauled by ANR Freight and generated approximately 81% of its operating revenues. As of December 31, 1994, ANR Freight operated 40 terminals and almost 4,000 trucks, tractors and trailers.
The expanded scope of deregulation has increased competition among motor carriers. 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, private carriers of truckload general freight, 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 have been adopted by most carriers. ANR Freight may continue to participate, on a limited basis, in collective rate making within the regional rate bureaus as still authorized under the Trucking Industry Regulatory Reform Act of 1994. ANR Freight also carries freight under contract and under general and individual tariff arrangements.
New federal legislation (the Negotiated Rates Act of 1993, the Trucking Industry Regulatory Reform Act of 1994, and the Federal Aviation Authorization Act of 1994) eliminated state regulation of rates, routes and service of all motor carriers and eliminated filing requirements for individually established tariffs and for all contract carriage arrangements at the federal level. Regulatory oversight of the motor carrier industry now focuses on safety and financial responsibility. The Interstate Commerce Commission, which also regulates accounting practices in the motor carrier industry, has been reduced in staff and scope of responsibility. 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, driver qualifications and alcohol and drug testing. 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 and evolving federal, state and local environmental laws and regulations. The Company anticipates capital expenditures of $70 million in 1995 in order to comply with such laws and regulations. The majority of the 1995 expenditures is attributable to major construction projects on the sulfur recovery units at two of the Company's refineries. The Company currently anticipates capital expenditures for environmental compliance for years 1996 through 1998 of $20 to $40 million per year. 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 seventeen sites for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $400 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, 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 four other sites, the Company has paid amounts to other PRPs or to the EPA as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis. In addition, a subsidiary of Coastal has been named as a de minimis PRP in one state "Superfund" site. However, since the agency having jurisdiction over the state site is currently unable to provide an estimate of the total clean-up costs, the Company is unable to calculate its subsidiary's share of those costs.
There are additional areas of environmental remediation responsibilities which may fall on the Company. The states have regulatory programs that mandate waste clean-up. The Clean Air Act Amendments of 1990 include new permitting regulations which will result in increased operating expenditures. Coastal is also supplying reduced-emission reformulated gasoline in all markets where it is required or optionally requested.
In October 1994, the Texas Natural Resources Conservation Commission ("TNRCC") sent a notification letter to Coastal Refining & Marketing, Inc. ("CR&M"), a subsidiary of the Company, alleging violations of the Resources Conservation and Recovery Act. The TNRCC has referred the allegations to the office of the Attorney General of the State of Texas. The Company believes that this action could result in monetary sanctions which, while not material to the Company and its subsidiaries, could exceed $100,000.
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.
A subsidiary of ANR Pipeline owns a 9.4% interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 370-mile pipeline which transports gas from Canada to the northeastern United States (the "Iroquois Pipeline"). Iroquois contracted with Iroquois Pipeline Operating Company ("IPOC") for IPOC to construct and operate the Iroquois Pipeline. Federal and state agencies (including the United States Attorney's office for the Northern District of New York) have been investigating alleged civil and criminal violations of environmental laws related to the construction and operation of the Iroquois Pipeline by IPOC. It is possible that this investigation could result in monetary sanctions, of which ANR Pipeline's subsidiary's share, while not material to the Company and its subsidiaries, could exceed $100,000.
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, financial position or results of operations.
ITEM 2.
ITEM 2. PROPERTIES.
Information on properties of Coastal is included in Item 1, "Business" 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 U.S. District Courts or in state courts, necessary rights-of-way to construct, operate and maintain pipelines and necessary land or other property for compressor and other stations and equipment necessary to the operation of pipelines.
All of the principal properties of ANR Pipeline were 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 were subject to "permitted liens" as defined in such Mortgage and Deed of Trust. The First Mortgage Pipe Line Bonds were retired in 1993 and the associated Mortgage and Deed of Trust was terminated in 1994.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
A subsidiary of the Company 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 the Company and certain subsidiaries. TransAmerican alleged 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. Final Judgment in this matter was entered April 22, 1994. The subsidiary was awarded approximately $2.0 million, including pre-judgment interest and attorney fees. All of TransAmerican's claims and causes of action were denied. The judgment has been
appealed by TransAmerican and the case is presently pending before the Court of Appeals for the Fourth Judicial District at San Antonio, Texas.
In December 1992, certain of Colorado's natural gas lessors in the West Panhandle Field filed a complaint in the U.S. District Court for the Northern District of Texas, claiming underpayment, breach of fiduciary duty, fraud and negligent misrepresentation. Management believes that Colorado has numerous defenses to the lessors' claims, including (i) that the royalties were properly paid, (ii) that the majority of the claims were released by written agreement, and (iii) that the majority of the claims are barred by the statute of limitations. Trial has been set for March 22, 1995.
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 or results of operations. 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 15, 1995, the approximate number of holders of record of Common Stock was 9,452 and of the Class A Common Stock was 3,682.
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 1994 and 1993. At December 31, 1994, 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 $583.2 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, 1993. The Notes to Consolidated Financial Statements included herein contain other information relating to this data.
* In addition, cash dividends of $.36, $.36, $.36, $.36 and $.18, were paid on the Company's Class A Common Stock in 1994, 1993, 1992, 1991 and 1990, respectively.
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 4, 1995 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 15, 1995, were as follows:
NAME (AGE), YEAR FIRST ELECTED AN OFFICER POSITIONS AND OFFICES WITH THE REGISTRANT --------------------------- -----------------------------------------
O. S. Wyatt, Jr. (70), 1955 Chairman of the Board of Directors and Chief Executive Officer
David A. Arledge (50), 1982 President, Chief Operating Officer, Chief Financial Officer and Director
Harold Burrow (80), 1974 Vice Chairman of the Board of Directors, Chairman of the Board of Directors of Colorado
James F. Cordes (54), 1985 Executive Vice President and Director
James A. King (55), 1992 Executive Vice President
Sam F. Willson, Jr. (65), 1974 Executive Vice President
Jerry D. Bullock (65), 1992 Senior Vice President
Jeffrey A. Connelly (48), 1988 Senior Vice President
Carl A. Corrallo (51), 1993 Senior Vice President and General Counsel
Donald H. Gullquist (51), 1994 Senior Vice President
Coby C. Hesse (47), 1986 Senior Vice President and Controller
Dan J. Hill (54), 1978 Senior Vice President
Kenneth O. Johnson (74), 1978 Senior Vice President and Director
Austin M. O'Toole (59), 1974 Senior Vice President and Secretary
Jack C. Pester (60), 1987 Senior Vice President
James L. Van Lanen (50), 1985 Senior Vice President
M. Truman Arnold (66), 1993 Vice President
Daniel F. Collins (53), 1989 Vice President
Robert C. Hart (50), 1994 Vice President
John J. Lipinski (44), 1995 Vice President
Edward A. More (46), 1995 Vice President
M. Frank Powell (44), 1993 Vice President
E. C. Simpson (59), 1990 Vice President
Thomas M. Wade (42), 1995 Vice President
Ronald D. Matthews (47), 1994 Treasurer
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. 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. Lipinski was elected Vice President of Coastal in March 1995. He has held various positions with subsidiaries of Coastal since 1985.
Mr. Matthews was elected Treasurer of the Company and Vice President and Treasurer of ANR Pipeline in September 1994. He was also elected Vice President and Treasurer of Colorado in October 1994. He has served as Assistant Treasurer of Coastal since 1983 and as Vice President of Coastal States Management Corporation, a subsidiary of Coastal, since 1991.
Mr. More was elected Vice President of Coastal in March 1995. He has held various positions with subsidiaries of Coastal since 1991. Prior thereto, he served as Executive Vice President at Harken Marketing, Inc. from 1987 to 1991.
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.
Mr. Wade was elected Vice President of Coastal in March 1995. He has held various positions with subsidiaries of Coastal since 1980.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The information called for by this item is set forth under "Executive Compensation", "Compensation and Executive Development Committee Report on Executive Compensation", "Pension Plan" and "Performance Graphs--Shareholder Return on Common Stock" in the Coastal Proxy Statement for the May 4, 1995 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 4, 1995 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 4, 1995 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.
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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.3+ 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).
10.4+ 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).
10.5+ 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).
10.6+ 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).
10.7+ 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).
10.8+ 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).
10.9+ 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).
10.10+ 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).
10.11+ The Coastal Corporation Deferred Compensation Plan (Exhibit 10.14 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1993).
10.12+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A to Coastal's Proxy Statement for the 1994 Annual Meeting of Stockholders dated March 29, 1994).
10.13+ Pension Plan for Employees of The Coastal Corporation as of January 1, 1993, includes Plan as Restated as of January 1, 1989 and First Amendment dated July 27, 1992, Second Amendment dated December 9, 1992, Third Amendment dated October 29, 1993 (Exhibit 10.16 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1993).
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit 28 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1990). _________________________ Note: + Indicates documents incorporated by reference from the prior filing indicated. * Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31, 1994.
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 28, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By: O. S. WYATT, JR. ------------------------ O. S. Wyatt, Jr. Chairman of the Board and Chief Executive Officer March 28, 1995
By: DAVID A. ARLEDGE ------------------------ David A. Arledge Principal Financial Officer and Director March 28, 1995
By: COBY C. HESSE ------------------------ Coby C. Hesse Principal Accounting Officer March 28, 1995
By: JOHN M. BISSELL ------------------------ John M. Bissell Director March 28, 1995
* * *
By: GEORGE L. BRUNDRETT, JR. By: KENNETH O. JOHNSON ----------------------------- ----------------------------- George L. Brundrett, Jr. Kenneth O. Johnson Director Director March 28, 1995 March 28, 1995
By: HAROLD BURROW By: JEROME S. KATZIN ----------------------------- ----------------------------- Harold Burrow Jerome S. Katzin Director Director March 28, 1995 March 28, 1995
By: ROY D. CHAPIN, JR. By: THOMAS R. McDADE ----------------------------- ----------------------------- Roy D. Chapin, Jr. Thomas R. McDade Director Director March 28, 1995 March 28, 1995
By: JAMES F. CORDES By: ----------------------------- ----------------------------- James F. Cordes J. Howard Marshall, II Director Director March 28, 1995 March ___, 1995
By: ROY L. GATES By: L. D. WOODDY, JR. ----------------------------- ----------------------------- Roy L. Gates L. D. Wooddy, Jr. Director Director March 28, 1995 March 28, 1995
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis.
LIQUIDITY AND CAPITAL RESOURCES
The Company uses the following consolidated ratios to measure liquidity and ability to meet future funding needs and debt service requirements.
The above ratios reflect increased earnings and decreased long-term debt in both 1994 and 1993. The 1994 decrease in cash flow from operating activities to long-term debt resulted from decreased cash flow as a result of changes in working capital offset by a reduction in long-term debt, while the 1993 increase resulted from increased cash flow from operations and reduced long-term debt.
Cash flows provided from operating activities were $669.1 million in 1994 and $809.8 million in 1993. The 1994 decrease can be attributed to increases for working capital requirements partially offset by increased earnings.
Capital expenditures amounted to $543.2 million in 1994 and $392.7 million in 1993. The increased expenditures in 1994 were due to expansion of the earnings bases in the Refining and Marketing and Exploration and Production segments. The Refining and Marketing increase is primarily due to improvements made at the refineries to produce higher value products and expansion of petrochemical operations into Canada. The Exploration and Production segment increase results from reserve additions which were more than double the 1994 production. The Company had returned to a lower level of capital spending in 1993 as it emphasized debt reduction. Proceeds from equity investments exceeded additions by $55.5 million in 1994 while the additions exceeded proceeds by $34.8 million in 1993. Prepayments for gas supply and payments for settlement of natural gas contract disputes required an investment of $11.4 million in 1993.
The Company was able to reduce total debt by $208.9 million in 1994, primarily by the use of internally generated funds and other financial transactions. Dividend payments increased by $6.3 million as a result of the new preferred stock issue in 1993. The increase in redemption of mandatory redemption preferred stock is due to ANR Pipeline redeeming all shares of its outstanding Cumulative Preferred Stock under sinking fund provisions and optional redemption provisions.
Capital expenditures for 1995, including the Company's equity investments in partnerships and joint ventures, are currently budgeted at approximately $540 million; however, future expenditures are dependent on conditions in the energy industry. 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 1995 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 Company ("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 were used for capital expenditures and for other general corporate purposes.
Unused lines of credit at December 31, 1994 were as follows (millions of dollars):
* $235 million of unused long-term credit lines is dedicated to a specific use.
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, 1994, net assets of consolidated subsidiaries amounted to approximately $5.1 billion, of which approximately $1.8 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.
The Company's operations involve managing market risks related to changes in interest rates and foreign exchange rates. Derivative financial instruments, specifically interest rate swaps and foreign currency swaps, are used to reduce and manage these risks. The Company currently does not hold or issue financial instruments for trading purposes.
The Company has entered into a number of interest rate swap agreements designated as a partial hedge of the Company's portfolio of variable rate debt. The purpose of these swaps is to fix interest rates on variable rate debt and reduce the exposure to interest rate fluctuations. At December 31, 1994, the Company had interest rate swaps with a notional amount of $550.0 million, and a portfolio of variable rate debt outstanding in the amount of $643.2 million. The Company has also entered into a number of interest rate swap agreements which have effectively converted $250.0 million of fixed rate debt into floating rate debt. The variable rate swaps have rates equal to the London Interbank Offered Rate ("LIBOR"), which is subject to change over time as LIBOR fluctuates. Terms expire at various dates through the third quarter of 1996. At December 31, 1994, the Company had no exposure to credit loss on interest rate swaps.
The Company has also entered into a number of foreign currency swaps to fully hedge to maturity the foreign currency denominated debt of the Company and its subsidiaries. At December 31, 1994, the Company had outstanding yen-denominated debt of $199.4 million and the Company and its subsidiaries had swiss franc denominated debt of $126.5 million. These swaps involve the exchange of interest payments in differing currencies at exchange rates effective at the time the agreement is entered into, and provide for the exchange of principal amounts at maturity, usually through an escrow arrangement to limit credit risk. At December 31, 1994, Coastal had exposure to credit loss of approximately $172.9 million on currency swaps.
Neither the Company nor the counterparties are required to collateralize their respective obligations under these swaps. Coastal is exposed to loss if one or more of the counterparties default. The counterparties on these transactions are prominent banking institutions and the Company is of the opinion that there is no material exposure to credit loss on these swaps. See Note 8 in the Notes to Consolidated Financial Statements for more information on these swaps. The Company does not believe that any reasonably likely change in interest rates or foreign currency indexes would have a material adverse effect on the financial position or the results of operations of the Company.
All interest rate and currency swaps are individually reviewed by the Company's Board of Directors.
The Company and its subsidiaries frequently enter into swaps, futures and other contracts to hedge the price risks associated with inventories, commitments and certain anticipated transactions. The swaps, futures and other contracts are with established exchanges, energy companies and major financial institutions. The Company believes
its credit risk is minimal on these transactions, as the counterparties are required to meet stringent credit standards. There is continuous day-to-day involvement by senior management in the hedging decisions, operating under resolutions adopted by each subsidiary's board of directors.
In 1994, the Company adopted Statement of Financial Accounting Standards No. 112, "Employers' 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 did not have a material effect on the Company's results of operations or financial position.
The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations. The Company anticipates capital expenditures of $70 million in 1995 to comply with such laws and regulations. The majority of the 1995 expenditures is attributable to major construction projects on the sulfur recovery units at two of the Company's refineries. The Company currently anticipates capital expenditures for environmental compliance for years 1996 through 1998 of $20 to $40 million per year. Additionally, appropriate governmental authorities may enforce these 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 17 sites for which the Environmental Protection Agency ("EPA") has developed sufficient information to estimate total clean-up costs of approximately $400 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, 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 four other sites, the Company has paid amounts to other PRPs or to the EPA as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis. In addition, a subsidiary of the Company has been named as a de minimis PRP at one state "Superfund" site.
There are additional areas of environmental remediation responsibilities which may fall on the Company. The states have regulatory programs that mandate waste clean-up. The Clean Air Act Amendments of 1990 include new permitting regulations which will result in increased operating expenditures. Coastal is also supplying reduced-emission reformulated gasoline in all markets where it is required or optionally requested.
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, financial position or results of operations.
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. The operations involve both regulated and unregulated companies.
On April 8, 1992 the Federal Energy Regulatory Commission ("FERC") issued Order 636 which required significant changes in the services provided by interstate natural gas pipelines (see Note 14 of the Notes to Consolidated Financial Statements). The intent of Order 636 is to insure that interstate pipeline transportation services are equal in quality for all gas supplies, whether the buyer purchases gas from the pipeline or from any other gas supplier. The FERC amended its regulations to require the use of the straight fixed variable ("SFV") rate setting
methodology. In general, SFV provides that all fixed costs of providing service to firm customers (including an authorized return on rate base and associated taxes) are to be received through fixed monthly reservation charges, which are not a function of volumes transported, while including within the commodity billing component the pipeline's variable operating costs. In addition, Order 636 has resulted in the incurrence of transition costs. However, Order 636 provides mechanisms for the recovery of such costs within a reasonable time period.
ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993, and Colorado Interstate Gas Company's ("CIG") restructured services became effective October 1, 1993. Both subsidiaries now offer a wide range of "unbundled" storage, transportation and balancing services. As a result of Order 636, ANR Pipeline no longer offers merchant services. CIG's gas sales for resale contracts, which have been unbundled at the producer wellhead per Order 636, extend through September 30, 1996, but provide for reduced customer purchases to be made each year. While operating revenues for interstate pipelines have been reduced as a result of the implementation of Order 636, purchases and other related costs have also been reduced by a similar amount.
1994 Versus 1993. The decrease in operating revenues of $172 million can be attributed to decreased sales volumes for the interstate pipelines and lower prices being partially offset by higher transportation and storage revenues for the interstate pipelines and increased sales volumes for the gas marketing companies. The primary factor contributing to the increase in storage and transportation revenues was revenues associated with cost recovery mechanisms related to above market gas purchases and certain transportation services provided by others. Also contributing to the storage and transportation revenue increase and the decrease in sales revenues for the interstate pipelines is the restructuring of pipeline bundled sales services into separate service components as required by changed regulations. Total throughput volumes for the interstate pipelines increased by approximately 4%, while the volume managed by the gas marketing companies increased by 29%.
Purchases decreased by $200 million in 1994, as volume decreases for the interstate pipelines and lower gas costs more than offset volume increases for the gas marketing companies, resulting in a gross profit increase of $28 million. The gas marketing companies accounted for $21 million of this increase.
The operating profit increase of $26 million results from improved transportation revenues of $83 million, higher storage revenues of $52 million and other increases of $6 million which were partially offset by lower sales margins of $58 million; reduced sales volumes of $51 million and increased depreciation, depletion and amortization of $6 million. The increased depreciation, depletion and amortization results from capital expansion.
The Natural Gas group continued to show improvement in 1994 even as weather patterns varied from a frigid first quarter to a balmy last quarter. The regulated operations benefitted from SFV rate methodology decisions made by the FERC, while the unregulated operations found opportunities in the marketplace as customers and end-users sought more efficient ways to obtain and manage their gas.
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.
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.
1994 Versus 1993. Operating revenues increased by $258 million as a result of increased volumes partially offset by lower prices. The volume increase results from an increase in the sales of products purchased from others and an increase in the average throughput at the three core refineries of approximately 20,000 barrels per day.
Purchases for the segment increased by $175 million as a result of increased volumes offset by lower costs, resulting in a gross profit increase of $83 million. Increased margins of $53 million, increased volumes of $22 million and other increases of $8 million make up the gross profit increase. The margin increase relates largely to improved refinery yields of higher value products, and stronger petrochemical prices.
The operating profit increase of $55 million results from the increased gross profit of $83 million being partially offset by increased operating expenses of $20 million and higher depreciation, depletion and amortization of $8 million. The increase in operating expenses results from expanded petrochemical operations and volume increases in other areas; while the higher depreciation, depletion and amortization is a result of expanded foreign and petrochemical operations.
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.
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.
1994 Versus 1993. The decrease in operating revenues of $58 million can be attributed to reduced revenues from natural gas marketing activities, reduced prices for all products and lower crude oil, condensate and plant products volumes partially offset by increased natural gas volumes. Natural gas revenue decreases of $48 million, including $43 million from gas marketing, and the crude oil, condensate and natural gas liquids decrease of $11 million were partially offset by other revenue increases of $1 million.
The operating profit decrease of $8 million results from decreased prices for all products of $16 million and reduced volumes for crude oil, condensate and plant products of $10 million offset by increased volumes for natural gas of $8 million, a $4 million increase from natural gas marketing sales, a $3 million decrease in depreciation, depletion and amortization and other of $3 million. Depreciation, depletion and amortization decreased as a result of a lower rate exceeding the change due to increased volumes.
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.
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.
1994 Versus 1993. The increase in coal revenues is a result of increased volumes sold and brokered more than offsetting reduced prices. The purchase of the Soldier Creek Mine in late 1993 added 600,000 tons/year of new capacity.
The operating profit increase of $3 million results from increased volumes of $6 million and other increases of $4 million, primarily from brokerage and royalty volumes, partially offset by decreased prices of $2 million and increased operating expenses of $5 million. Operating expenses, including coal costs, increased as a result of the volume increase.
1993 Versus 1992. The decrease in coal revenues results from decreased prices more than offsetting increased volumes sold and brokered.
The operating profit increase results from the 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.
OTHER. Other operations involve trucking, power production, real estate and other activities.
1994 Versus 1993. The $21 million increase in operating revenues results primarily from volume increases for the trucking operations, while the $22 million increase in operating profit results from the $21 million revenue increase and a $1 million decrease in operating expenses. The trucking operations operating profit increased by $14 million, real estate activities increased by $6 million and other operations increased by $2 million to make up the 1994 operating profit increase.
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.
OTHER INCOME - NET
1994 Versus 1993. Other income-net decreased by $8 million in 1994 due to the nonrecurrence of a 1993 settlement amount of $3 million and other decreases of $5 million.
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.
INTEREST AND DEBT EXPENSE
1994 Versus 1993. Interest and debt expense decreased by $35 million in 1994, primarily as a result of lower average debt levels, lower average interest rates and reduced other financial costs more than offsetting increases in interest on customers' refunds. At December 31, 1994, after giving effect to interest rate swaps, approximately 8.6% of the Company's debt was tied to money-market related rates.
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.
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 included 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 1993 extraordinary loss, net of income taxes, resulted from 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, 1994 and 1993, 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, 1994. 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 consolidated financial position of The Coastal Corporation and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. 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 LLP
Houston, Texas February 2, 1995
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% continuing 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 is accounted for as a hedge of an identifiable transaction is 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 $431.8 million, $447.2 million and $480.6 million in 1994, 1993 and 1992, respectively. Cash payments (refunds) for income taxes amounted to $73.7 million, $21.0 million and $(9.8) million for 1994, 1993 and 1992, respectively.
INVENTORIES - Inventories of refined products and crude oil are accounted 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. 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 swaps, 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. The Company also enters into interest rate and foreign currency swaps to manage interest rates and foreign currency risk. Income and expense related to interest rate swaps is accrued as interest rates change and is recognized in income over the life of the agreement. Gains or losses from foreign currency swaps are deferred and are recognized as payments are made on the related foreign currency denominated debt. Such gains or losses are essentially offset by gains or losses on the related debt.
PROPERTY, PLANT AND EQUIPMENT - Property additions include acquisition costs, administrative costs and, where appropriate, capitalized interest allocable to construction. Capitalized interest amounted to $8.3 million, $8.4 million and $10.7 million in 1994, 1993 and 1992, respectively. All costs incurred in the acquisition, exploration and development of gas and oil properties, including unproductive wells, are capitalized under the full-cost method of accounting.
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 $.96 for 1994 and $1.00 for the years 1993 and 1992. 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. The annual rates of depreciation are as follows:
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 ("ANR") and CIG, amounted to $544.5 million at December 31, 1994, 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 1994, 1993 and 1992, 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 include 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, "ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION" ("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 $31.2 million and $52.6 million at December 31, 1994 and 1993, respectively.
Natural gas in underground storage at December 31, 1993, included $207.5 million which was transferred to Property, Plant and Equipment in 1994 for regulatory and accounting purposes.
NOTE 3. TAKE-OR-PAY OBLIGATIONS
Other assets includes $96.5 million and $134.0 million at December 31, 1994 and 1993, respectively, relating to prepayments for gas under gas purchase contracts with producers and settlement payment amounts relative to the restructuring of gas purchase contracts as negotiated with producers. 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 gas sales are made at negotiated prices and are not subject to regulatory price controls. This does not affect the recoverability or the results of pending take-or-pay litigation or any take-or-pay or contractual reformation settlements that 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 costs incurred as a result of the mandated Order 636 restructuring will be recovered either under the transition cost mechanisms of Order 636 or 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, 1994, the Company estimated that unresolved asserted and unasserted producers' claims amounted to approximately $20 million. The remaining disputes will be settled where possible and litigated if settlement is not possible.
At December 31, 1994, the Company was committed to make future purchases under certain take-or-pay contracts with fixed, minimum or escalating price provisions. Based on contracts in effect at that date, and before considering reductions provided in the contracts or applicable law, such commitments are estimated to be $22 million, $18 million, $11 million, $1 million and $1 million for the years 1995-1999, respectively, and $4 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. Such provisions and accruals were not material to the Company for the years 1994, 1993 and 1992.
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; and several pipeline and other ventures. The Company's investment in these entities, including advances, amounted to $378.3 million and $424.7 million at December 31, 1994 and 1993, respectively. The Company's equity in income of the investments, included in Other Income-Net, was $75.7 million, $71.9 million and $63.8 million in 1994, 1993 and 1992, respectively, while dividends and partnership distributions received amounted to $39.1 million, $17.5 million and $47.8 million in 1994, 1993 and 1992, 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, 1994, long-term credit agreements with banks totaled $1,248.7 million, including $328.0 million available to The Coastal Corporation. Loans under these agreements bear interest at money market-related rates (weighted average 6.73% at December 31, 1994). Annual commitment fees range up to 1/2% payable on the unused portion of the applicable facility. At December 31, 1994, $554.2 million was outstanding and $235.0 million of the unused amount is dedicated to a specific use. Notes payable to banks of $350.0 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, 1994, net assets
of consolidated subsidiaries amounted to approximately $5.1 billion, of which $1.8 billion was restricted by such provisions.
In February 1994, ANR Pipeline Company ("ANR Pipeline") sold $125.0 million of 7-3/8% Debentures due in 2024. The net proceeds from the sale were used for capital expenditures and for other general corporate purposes.
SUBORDINATED LONG-TERM DEBT - Balances at December 31 were (millions of dollars):
The Company has notified the Trustee for its 11-1/8% Subordinated Notes of its intention to redeem such notes, at par, in March 1995.
MATURITIES - The aggregate amounts of long-term debt (including subordinated) maturities for the five years following 1994 are (millions of dollars):
NOTES PAYABLE - At December 31, 1994, Coastal and its subsidiaries had $57.2 million of outstanding indebtedness to banks under short-term lines of credit, compared to $264.0 million at December 31, 1993. The weighted average interest rates were 6.17% and 3.93% at December 31, 1994 and 1993, respectively. As of December 31, 1994, $753.1 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 $583.2 million was available at December 31, 1994 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, 1994, the Company had guaranteed 45% of a construction financing of a partially owned partnership. The Company's proportionate share of the outstanding principal balance under this guarantee was $66.6 million at December 31, 1994. Other guarantees and indemnities related to obligations of unconsolidated affiliates amounted to approximately $259.7 million as of the same date. The Company anticipates that the guaranteed construction loan will be refinanced within the next 12 months, 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 $16.4 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 AND COMMITMENTS
The Company leases property, plant and equipment under various operating leases, certain of which contain renewal and purchase options and residual value guarantees. Such residual value guarantees amount to approximately $177.7 million.
Rental expense amounted to approximately $72.1 million, $98.2 million and $92.6 million in 1994, 1993 and 1992, respectively, excluding leases covering natural resources. Aggregate minimum lease payments under existing noncapitalized long-term leases are estimated to be $87.7 million, $86.2 million, $83.5 million, $73.7 million, and $72.1 million for the years 1995- 1999, respectively, and $786.8 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, 1994. 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.
On June 16, 1994, ANR Pipeline Company redeemed all shares of its outstanding Cumulative Preferred Stock under sinking fund provisions and optional redemption provisions. Such redemption included the payment of accrued dividends to June 16, 1994.
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's operations involve managing market risks related to changes in interest rates, foreign exchange rates and commodity prices. Derivative financial instruments, specifically swaps and other contracts, are used to reduce and manage those risks. The Company does not currently hold or issue financial instruments for trading purposes.
INTEREST RATE AND CURRENCY SWAPS - The Company has entered into a number of interest rate swap agreements designated as a partial hedge of the Company's portfolio of variable rate debt. The purpose of these swaps is to fix interest rates on variable rate debt and reduce the Company's exposure to interest rate fluctuations. At December 31, 1994, the Company had interest rate swaps with a notional amount of $550.0 million, and a portfolio of variable rate debt outstanding in the amount of $643.2 million. Under these agreements, Coastal will pay the counterparties interest at a weighted average fixed rate of 9.34%, and the counterparties will pay Coastal interest at a variable rate equal to the London Interbank Offered Rate (LIBOR). The weighted average LIBOR rate applicable to these agreements was 5.76% at December 31, 1994. The notional amounts do not represent amounts exchanged by the parties, and thus are not a measure of exposure of the Company. The amounts exchanged are normally based on the notional amounts and other terms of the swaps.
The Company has also entered into a number of interest rate swap agreements which have effectively converted $250.0 million of fixed rate debt into floating rate debt. Under these agreements, Coastal will pay the counterparties a variable rate equal to LIBOR, and the Company will receive from the counterparties a weighted average fixed rate of 4.52%. The weighted average LIBOR rate applicable to these transactions was 5.74% at December 31, 1994.
The weighted average variable rates are subject to change over time as LIBOR fluctuates. Terms expire at various dates through the third quarter of 1996.
The Company has also entered into a number of foreign currency swaps to fully hedge to maturity the foreign currency denominated debt of the Company and its subsidiaries. At December 31, 1994, the Company had outstanding yen-denominated debt of $199.4 million, and the Company and its subsidiaries had swiss franc denominated debt in the amount of $126.5 million. These swaps involve the exchange of interest payments in differing currencies at exchange rates effective at the time the agreement is entered into, and provide for the exchange of principal amounts at maturity, usually through an escrow arrangement to limit credit risk. The weighted average exchange rate for the yen swaps is 146.47 yen/dollar, and the weighted average exchange rate for the swiss franc swaps is 2.00 swiss francs/dollar. The Company has also entered into an interest rate swap with a notional amount of 19.7 million swiss francs under which the Company pays a fixed rate of 4.72% and receives a floating rate established in the interbank market. At December 31, 1994, the floating rate was 4.44%. These swaps have resulted in effective borrowing costs ranging from 10.0% to 11.1%.
Neither the Company nor the counterparties are required to collateralize their respective obligations under these swaps. Coastal is exposed to loss if one or more of the counterparties default. At December 31, 1994, Coastal had no exposure to credit loss on interest rate swaps and approximately $172.9 million of exposure to credit loss on currency swaps. However, the counterparties on these transactions are prominent banking institutions and the Company is of the opinion that there is no material exposure to credit loss on these swaps. The Company does not believe that any reasonably likely change in interest rates or foreign currency indexes would have a material adverse effect on the financial position or the results of operations of the Company. All interest rate and currency swaps are reviewed by the Company's Board of Directors.
OTHER DERIVATIVES - The Company and its subsidiaries also frequently enter into swaps and other contracts to hedge the price risks associated with inventories, commitments and certain anticipated transactions. The swaps and other contracts are with established energy companies and major financial institutions. The Company believes its credit risk is minimal on these transactions, as the counterparties are required to meet stringent credit standards. There is continuous day-to-day involvement by senior management in the hedging decisions, operating under resolutions adopted by each subsidiary's board of directors.
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, 1994 and 1993, respectively, for new issues with similar remaining maturities. The fair value of the derivatives relating to commodity swaps reflects the estimated amount to terminate the contracts at December 31, 1994 and 1993, taking into account unrealized gains or losses. Dealer quotes are available for these derivatives. The fair market value of the Company's interest rate and foreign currency swaps is based on the estimated termination values at December 31, 1994 and 1993, respectively.
NOTE 9. COMMON AND PREFERRED STOCK
Shares of common stock and Class A common stock reserved for future issuance as of December 31, 1994 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.
Under the 1984 Plan, options for 21,679 Class A common shares and 51,801 common shares were exercisable at December 31, 1994. No additional options may be granted under the 1984 plan. At December 31, 1993, 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.
Under the 1985 Plan, 3,958 common shares were available for granting of options, and options for 835,168 common shares were exercisable at December 31, 1994. At December 31, 1993, 69,758 common shares were available for granting of options, and options for 953,898 common shares were exercisable.
Under the 1990 Plan, 32,321 common shares were available for granting of options, and options for 241,073 common shares were exercisable at December 31, 1994. At December 31, 1993, 23,717 common shares were available for granting of options, and options for 181,380 common shares were exercisable.
Under the 1994 Plan, 1,891,100 common shares were available for granting of options. No options for common shares were exercisable at December 31, 1994.
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, 1994:
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, 1994, 1993 and 1992, and identifiable assets as of December 31, 1994, 1993 and 1992, 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 includes equity method earnings related to the business segments as follows (millions of dollars):
Revenues from sales to any single customer during 1994, 1993 or 1992 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 generally 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 Employment Retirement Income Security Act of 1974. The pension benefit for 1994, 1993 and 1992 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 8.75% in 1994, 7.25% in 1993 and 8.25% in 1992. The expected increase in future compensation levels was 5% in 1994,
4% in 1993 and 6% in 1992, and the expected long-term rate of return on assets was 10% in 1994 and 11% in both 1993 and 1992.
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, 1994 and 1993.
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 $7.6 million for 1994 and $7.1 million each for 1993 and 1992. 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 are based on matching employee contributions, amounted to $17.5 million, $17.7 million and $16.6 million in 1994, 1993 and 1992, 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"), which requires the Company to accrue the estimated cost of retiree benefit payments during the years the employee provides services. Previously, the Company expensed the costs of these benefits as claims were incurred. The Company's cash flows were not affected by the implementation of FAS 106 and the incremental impact on the Company's results of operations before income taxes was approximately $10.9 million in 1994 and $13.6 million, of which $8.3 million was deferred by the Company's rate regulated subsidiaries, in 1993. The Company's rate regulated subsidiaries have deferred certain costs consistent with their rates.
The following tables set forth the accumulated postretirement benefit obligation recognized in the Company's Consolidated Balance Sheet and the benefit cost for the years ended December 31, 1994 and 1993 (millions of dollars):
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 12.0% in 1994, declining gradually to 6.0% by the year 2005. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 16.0% in 1993. A one percentage point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately 4.9% and the net postretirement health care cost by approximately 4.4%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 8.75%.
The Company adopted Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" effective January 1, 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The effect of the new standard did 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 settled all contested adjustments to federal income tax returns filed for the years 1982 through 1984. 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.
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 carryforwards 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, REGULATORY AND ENVIRONMENTAL MATTERS
LITIGATION - A subsidiary of Coastal 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 alleged 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. Final judgment in this matter was entered April 22, 1994. The subsidiary was awarded approximately $2.0 million,
including pre-judgment interest and attorney fees. All of TransAmerican's claims and causes of action were denied. The judgment has been appealed by TransAmerican and the case is presently pending before the Court of Appeals for the Fourth Judicial District at San Antonio, Texas.
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. The matter has been set for trial in March 1995.
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 or results of operations.
REGULATORY MATTERS - 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. The case is currently in the briefing phase before the United States Court of Appeals for the D.C. Circuit.
On November 1, 1993, ANR Pipeline placed its Order 636 restructured services and rates into effect. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving ANR Pipeline's restructuring filings. Those appeals have been held in abeyance by the United States Court of Appeals for the D.C. Circuit, pending further order. On March 24, 1994, the FERC issued its "Fourth Order on Compliance Filing and Third Order on Rehearing," which addressed numerous rehearing issues and confirmed that after minor required tariff modifications, ANR Pipeline is now fully in compliance with Order 636 and the requirements of the orders on its restructuring filings. The FERC issued a further order regarding certain compliance issues on July 1, 1994. In accordance with this order, ANR Pipeline filed revised tariff sheets on July 18, 1994.
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 became effective November 1, 1992 and expired with ANR Pipeline's implementation of Order 636 on November 1, 1993. Under the Interim Settlement, gas inventory demand charges were collected from ANR Pipeline's resale customers for the period November 1, 1992 through October 31, 1993. This method of gas cost recovery required refunds for any over-collections, and placed ANR Pipeline at risk for under-collections. As required by the Interim Settlement, ANR Pipeline filed with the FERC on April 29, 1994, a reconciliation report showing over-collections and, therefore, proposed refunds totaling $45.1 million. Such refund obligations were recorded at December 31, 1994 and December 31, 1993, and are included in the Consolidated Balance Sheet under "Deferred Credits and Other." Certain customers have disputed the level of those refunds. By an order issued in February 1995, the FERC has directed ANR Pipeline to make immediate refunds of $45.1 million and applicable interest, subject to further investigation of the claims which the customers have made. The matter is still pending.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC under Docket RP94-43. The increase represents the effects of 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., Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" and Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits." On March 23, 1994, the FERC issued an order granting and denying various requests for summary disposition and establishing hearing procedures for issues remaining to be investigated in this proceeding. The order required the reduction or elimination of certain costs which resulted in revised rates such that the revised rates reflect an $85.7
million increase in the cost of service from that approved in the Interim Settlement and a $182.8 million increase over ANR Pipeline's approved rates for its restructured services under Order 636. On April 29, 1994, ANR Pipeline filed a motion with the FERC that placed the new rates into effect May 1, 1994, subject to refund. On September 21, 1994, the FERC accepted ANR Pipeline's filing in compliance with the March 23, 1994 order, subject to further modifications including an additional reduction in cost of service of approximately $5 million. ANR Pipeline submitted its compliance filing to the FERC on October 6, 1994, which compliance filing was accepted by order issued December 8, 1994, subject to a further compliance filing requirement, which ANR Pipeline submitted on January 9, 1995, and which was accepted by an order issued in February 1995. Further, on December 8, 1994, the FERC issued its order denying rehearing of the March 23, 1994 order. On January 26, 1995, ANR Pipeline sought judicial review of these orders before the U.S. Court of Appeals for the D.C. Circuit.
ANR Pipeline has executed a Settlement Agreement (the "Settlement Agreement") with Dakota Gasification Company ("Dakota") and the Department of Energy which resolves litigation concerning purchases of synthetic gas by ANR Pipeline from the Great Plains Coal Gasification Plant (the "Plant"). That litigation, originally filed in 1990 in the United States District Court in North Dakota, involved claims regarding ANR Pipeline's obligations under certain gas purchase and transportation contracts with the Plant. The Settlement Agreement resolves all disputes between the parties, amends the gas purchase agreement between ANR Pipeline and Dakota and terminates the transportation contract. The Settlement Agreement is subject to final FERC approval, including an approval for ANR Pipeline to recover the settlement costs from its customers. On August 3, 1994, ANR Pipeline filed a petition with the FERC requesting: (a) that the Settlement Agreement be approved; (b) an order approving ANR Pipeline's proposed tariff mechanism for the recovery of the costs incurred to implement the Settlement Agreement; and (c) an order dismissing a proceeding currently pending before the FERC, wherein certain of ANR Pipeline's customers have challenged Dakota's pricing under the original gas supply contract. On October 18, 1994, the FERC issued an order consolidating ANR Pipeline's petition with similar petitions of three other pipeline companies and setting the Settlement Agreement and other Dakota-related proceedings for limited hearing before an Administrative Law Judge who must render an initial decision by December 31, 1995. On December 20, 1994, ANR Pipeline filed its testimony, and has responded to numerous discovery requests. The hearing is scheduled to commence on June 20, 1995. ANR Pipeline believes the ultimate resolution of the Dakota related issues will not have a material adverse impact on its financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated with compliance with that Order. ANR Pipeline has estimated that its transition costs will amount to approximately $150 million, which will consist primarily of gas supply realignment costs, the cost of stranded pipeline investment and the Dakota costs described above. As of December 31, 1994, ANR Pipeline has incurred transition costs in the amount of $43 million. ANR Pipeline has filed for recovery of approximately $40.5 million of these transition costs, which have been accepted and made effective by the FERC, subject to refund and subject to further proceedings. In addition, ANR Pipeline has filed for recovery of approximately $90 million of costs associated with the Settlement Agreement, as mentioned above. Additional transition costs filings will be made by ANR Pipeline in the future. 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 its financial position or results of operations.
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. As of October 1, 1993, CIG separated all of its services and separately contracts for each service on a stand-alone or "unbundled" basis. Gathering, storage and transportation services are provided at negotiated rates established between minimum and maximum levels approved by the FERC, while gas processing rates are not subject to FERC regulations.
CIG's gas sales for resale contracts extend through September 30, 1996, but provide for reduced customer purchases to be made each year. Under Order 636, CIG's certificate to sell gas for resale allows sales to be made at negotiated prices and not at prices established by FERC. CIG is also authorized to abandon all sales for resale without prior FERC approval at such time as the contracts expire. Pursuant to Order 636, CIG's gas sales have been unbundled at the producer wellhead.
On March 31, 1993, CIG filed at FERC under Docket RP93-99 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. On November 10, 1994, the FERC approved a settlement offer submitted by CIG which resolved all of the issues in the proceeding. CIG has implemented the rates established in the settlement for prospective application and will be required to make refunds as a result of the approval of the settlement. Such refunds will be distributed in March 1995. CIG has fully accrued for these refunds and therefore such refunds will not have an adverse effect on its consolidated financial position or results of operations.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company, Ltd., subsidiaries of the Company, 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 and evolving federal, state and local environmental laws and regulations. The Company anticipates capital expenditures of $70 million in 1995 to comply with such laws and regulations. The majority of the 1995 expenditures is attributable to construction projects on the sulfur recovery units at two of the Company's refineries. The Company currently anticipates capital expenditures for environmental compliance for the years 1996 through 1998 of $20 to $40 million per year. 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 17 sites for which the Environmental Protection Agency ("EPA") has developed sufficient information to estimate total clean-up costs of approximately $400 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, 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 four other sites, the Company has paid amounts to other PRPs or to the EPA as its proportional share of associated clean-up costs. As to these latter sites, the Company believes that its activities were de minimis. In addition, a subsidiary of the Company has been named as a de minimis PRP at one state "Superfund" site.
There are additional areas of environmental remediation responsibilities which may fall on the Company. The states have regulatory programs that mandate waste clean-up. The Clean Air Act Amendments of 1990 include new permitting regulations which will result in increased operating expenditures. Coastal is also supplying reduced-emission reformulated gasoline in all markets where it is required or optionally requested.
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, financial position or results of operations.
NOTE 15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 1994 and 1993 were (millions of dollars except per share):
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves, capitalized costs, costs incurred in oil and gas acquisition, exploration and development activities, results of operations and the standardized measure of discounted future net cash flows are presented for the exploration and production segment. Natural gas systems reserves and the related standardized measure of discounted future net cash flows are separately presented for natural gas operations. Substantially all of the Company's properties are located in the United States.
Total proved reserves for natural gas systems exclude storage gas and liquids volumes. The natural gas systems storage gas volumes are 153,781, 147,549 and 183,741 million cubic feet and storage liquids volumes are approximately 172,000, 150,000 and 159,000 barrels at December 31, 1994, 1993 and 1992, respectively. Total proved reserves for natural gas includes approximately 27,000 MMcf associated with volumetric production payments sold by the Company.
All of the Company's proved reserves are located in the United States. International activities are connected with the evaluation of various concessions. Therefore, the tables setting forth statistical data on reserves and cash flows are for properties located in the United States while the tables on costs and results of operations contain certain capitalized and expense transactions attributable to start-up activities connected with international operations. These capitalized and expensed international transactions are not material in nature.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES (Millions of dollars)
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)
The average amortization rate per equivalent Mcf was $0.96 in 1994 and $1.00 for the years 1993 and 1992.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVE QUANTITIES. Future cash inflows from the sale of proved reserves and estimated production and development costs as calculated by the Company's independent engineers are discounted 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):
Future cash inflows for 1994 include $39 million related to volumes dedicated to volumetric production payments sold by the Company.
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 40 Bcf for CIG, 114 Bcf for ANR Pipeline and 172,000 barrels of liquids for CIG at the end of 1994.
SUPPLEMENTAL STATISTICS FOR COAL MINING OPERATIONS (UNAUDITED)
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 I - 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 I - 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 I - 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 I - 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 I - 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 $340.6 million, $357.1 million and $375.6 million in 1994, 1993 and 1992, respectively. Cash payments (refunds - primarily from subsidiaries) for income taxes amounted to $(62.2) million, $(49.8) million and $(63.9) million for 1994, 1993 and 1992, respectively.
Federal Income Taxes -- The Company follows the liability method of accounting for income taxes as required by the provisions of FAS No. 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.
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 $62.4 million outstanding at December 31, 1994, 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, joint ventures and partnerships in which the Company or certain subsidiaries have equity interests. Information on the guarantees and swaps is disclosed in Notes 5 and 8, respectively, 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 1994 are (millions of dollars):
NOTE 4. DIVIDENDS RECEIVED
Cash dividends received from consolidated subsidiaries were as follows: 1994 - $67.9 million, 1993 - $66.6 million and 1992 - $142.8 million.
S-5
THE COASTAL CORPORATION AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Millions of Dollars)
(A) Accounts charged off net of recoveries.
S-6
EXHIBIT INDEX
Exhibit Number Document ------ --------
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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.3+ 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).
10.4+ 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).
10.5+ 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).
10.6+ 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).
10.7+ 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).
10.8+ 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).
10.9+ 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).
10.10+ 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).
10.11+ The Coastal Corporation Deferred Compensation Plan (Exhibit 10.14 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1993).
10.12+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A to Coastal's Proxy Statement for the 1994 Annual Meeting of Stockholders dated March 29, 1994).
10.13+ Pension Plan for Employees of The Coastal Corporation as of January 1, 1993, includes Plan as Restated as of January 1, 1989 and First Amendment dated July 27, 1992, Second Amendment dated December 9, 1992, Third Amendment dated October 29, 1993 (Exhibit 10.16 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1993).
EXHIBIT INDEX
Exhibit Number Document ------ --------
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit 28 to Coastal's Annual Report on Form 10-K for the fiscal year ended December 31, 1990).
_________________________ Note: + Indicates documents incorporated by reference from the prior filing indicated. * Indicates documents filed herewith.