ITEM 1. BUSINESS.
INTRODUCTION
ANR Pipeline is a Delaware corporation organized in 1945. All of ANR Pipeline's outstanding common stock is owned by ANR. ANR is a direct, wholly- owned subsidiary of Coastal Natural Gas, and an indirect subsidiary of Coastal. ANR Pipeline owns and operates an interstate natural gas pipeline system. At December 31, 1994, the Company had 2,102 employees engaged in the operation of ANR Pipeline and 144 employees engaged in the operation of HIOS, UTOS and Empire.
NATURAL GAS SYSTEM
OPERATIONS
GENERAL
The Company 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, the Company was also engaged in the sale for resale of natural gas. With the Company'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. The Company 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. The Company 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. The Company also operates Empire, an intrastate pipeline extending from Niagara Falls to Syracuse, New York, in which an affiliate of the Company has a 45% interest.
The Company'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. The Company'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.
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 System - Rate Matters" included herein.
Effective November 1, 1993, the Company implemented Order 636. This Order required significant changes in the services provided by ANR Pipeline and resulted in the elimination of the Company's merchant service. The Company 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 System - 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 the Company'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 the Company'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, the Company's gas purchases decreased substantially. However, the Company still purchases a residual quantity of gas under certain remaining gas purchase contracts. The Company'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 the Company 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 6 of 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, the Company has reclassified 62.1 Bcf of working gas to recoverable base gas, which is pending approval before the FERC. The Company 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 the Company to customers on a firm basis. The Company also provides interruptible storage services for customers on a short-term basis.
Coastal's independent engineers, Huddleston & Co., Inc., have estimated that the Company'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 the Company'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 the Company has reclassified as recoverable base gas.
COMPETITION
ANR Pipeline has historically competed with interstate pipeline companies in the sale, transportation and storage of gas and with independent producers, brokers, marketers and other pipelines in the gathering and sale of gas within its service areas. On November 1, 1993, the Company implemented Order 636 on its system. As a consequence, the Company 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.
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.
ANR Pipeline's transportation, storage and balancing services are influenced by its customers' access to alternative providers of such services. The Company 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. The Company'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.
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 Company-owned, or partially-owned, pipeline segments not directly connected to a Company mainline.
The Company 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 the Company's pipeline system.
REGULATIONS AFFECTING GAS SYSTEM
GENERAL
Under the NGA, the FERC has jurisdiction over ANR Pipeline 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. ANR Pipeline, where required, holds certificates of public convenience and necessity issued by the FERC covering its jurisdictional facilities, activities and services.
ANR Pipeline is also subject to regulation with respect to safety requirements in the design, construction, operation and maintenance of its interstate gas transmission and storage facilities by the Department of Transportation. Operations on United States government land are regulated by the Department of the Interior.
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, the Company 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 the Company's former sales for resale customers and 50% via a surcharge on all transportation volumes. Contract reformation and take-or-pay costs incurred as a result of the mandated Order 636 restructuring will be recovered under the transition cost mechanisms of Order 636, as well as through negotiated agreements with the Company's customers.
On April 8, 1992, the FERC issued Order 636, which required significant changes in the services provided by interstate natural gas pipelines. The Company and numerous other parties have sought judicial review of aspects of Order 636. The case is currently in the briefing phase before the United States Court of Appeals for the D.C. Circuit. ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. As a result, the Company no longer provides a merchant service and now offers a wide range of "unbundled" transportation, storage and balancing services. However, the Company still purchases a residual quantity of gas under certain remaining gas purchase contracts. The Company'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 the Company recovers through the auctioning of such gas on the open market in producing areas. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving the Company'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, the Company is now fully in compliance with Order 636 and the requirements of the orders on ANR Pipeline's restructuring filings. The FERC issued a further order regarding certain compliance issues on July 1, 1994. In accordance with this order, the Company filed revised tariff sheets on July 18, 1994.
RATE MATTERS
All of the Company's service options are subject to rate regulation by the FERC. Under the NGA, ANR Pipeline must file with the FERC to establish or adjust its service rates. The FERC may also initiate proceedings to determine whether the Company's rates are "just and reasonable."
On March 10, 1992, the Company 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 the Company's implementation of Order 636 on November 1, 1993. Under the Interim Settlement, gas inventory demand charges were collected from the Company'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 the Company at risk for under-collections. As required by the Interim Settlement, the Company 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 the Company 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, the Company filed a general rate increase with the FERC under Docket No. 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" ("FAS No. 106") and FAS No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS No. 112"). 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 the Company's approved rates for its restructured services under Order 636. On April 29, 1994, the Company 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 the Company'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. The Company 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 the Company 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 the Company'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 the Company and Dakota and terminates the transportation contract. The Settlement Agreement is subject to final FERC approval, including an approval for the Company to recover the settlement costs from its customers. On August 3, 1994, the Company 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 the Company'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. The Company believes the ultimate resolution of the Dakota related issues will not have a material adverse impact on its consolidated financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated with compliance with that Order. The Company 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, the Company has incurred transition costs in the amount of $43 million. The Company 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, the Company 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 the Company in the future. As a result of the recovery mechanisms provided under Order 636, the Company anticipates that these transition costs will not have a material adverse effect on its consolidated financial position or results of operations.
Certain regulatory issues remain unresolved among the Company, its customers, its suppliers and the FERC. The Company has made provisions which represent management's assessment of the ultimate resolution of these issues. While the Company estimates the provisions to be adequate to cover potential adverse rulings on these and other issues, it cannot estimate when each of these issues will be resolved.
ENVIRONMENTAL
A subsidiary of the Company 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 its subsidiary's share, while not material to the Company, could exceed $100,000.
Information concerning other environmental matters is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 7 of Notes to Consolidated Financial Statements included herein.
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 the Company 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 on 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 the Company 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.
The Company 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 the Company'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 the Company has a 45% equity interest in the proposed Mayflower Pipeline project, which will be owned by a partnership consisting of the Company'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, the Company and NorAm Energy Corporation, formerly Arkla, Inc. ("NorAm") announced execution of a restructured agreement under which the Company, subject to certain conditions precedent, would 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.
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.
ITEM 2.
ITEM 2. PROPERTIES.
Information on properties of ANR Pipeline is in Item 1, "Business," included herein.
The real property owned by the Company in fee consists principally of sites for compressor and metering stations and microwave and terminal facilities. With respect to the seven-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 gas rights. Under the NGA, the Company may acquire by the exercise of the right of eminent domain, through proceedings in United States District Courts or in state courts, necessary rights-of-way to construct, operate and maintain pipelines and necessary land or other property for compressor and other stations and equipment necessary to the operation of pipelines.
All of the principal properties of the Company 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.
Numerous lawsuits and other proceedings which have arisen in the ordinary course of business are pending or threatened against the Company or its subsidiaries. Although no assurances can be given and no determination can be made at this time as to the outcome of any particular lawsuit or proceeding, the Company believes there are meritorious defenses to substantially all such claims and that any liability which may finally be determined should not have a material adverse effect on the Company's consolidated financial position or results of operations. Additional information regarding legal proceedings is set forth in Notes 6 and 7 of Notes to Consolidated Financial Statements included herein.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
All common stock of ANR Pipeline is owned by ANR.
Under the terms of the most restrictive of the Company's financing agreements, approximately $166 million was available at December 31, 1994 for payment of dividends on the Company's common stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial data (in millions of dollars) for the periods indicated 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, as adjusted for minor reclassifications. The Notes to Consolidated Financial Statements included herein contain information relating to this data.
Since all of the outstanding common stock of ANR Pipeline is owned by ANR, earnings and cash dividends per common share have no significance and are not presented.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The Management's Discussion and Analysis of Financial Condition and Results of Operations is presented on pages through herein.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Financial Statements and Supplementary Data required hereunder are included in this Annual Report as set forth in Item 14(a) herein.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The directors and executive officers of ANR Pipeline as of March 15, 1995, were as follows:
The above named persons bear no family relationship to each other. Their respective terms of office expire coincident with ANR Pipeline's Annual Meeting of the Sole Stockholder and Annual Meeting of the Board of Directors to be held in May 1995. Each of the directors and officers named above have been officers or employees of ANR Pipeline, Colorado and/or Coastal for five years or more except for the following:
Mr. Bissell was elected a Director in September 1994. He has been a Director of Coastal since 1985 and of ANR since 1979. He is currently Chairman of the Board of Directors and Chief Executive Officer of Bissell Inc., a position he has held since 1971.
Mr. Burrow was elected Vice Chairman of the Board of Directors in September 1994. He has served as a Director of Coastal since 1973 and as Chairman of the Board of Directors of Colorado since 1974.
Mr. Chapin was elected a Director in September 1994. He has been a Director of Coastal since 1988 and of ANR since 1973. Mr. Chapin was Chairman and Chief Executive Officer of American Motors Corporation from 1967 until his retirement in 1978.
Mr. Doss was elected a Director in September 1994. He has been a Director of ANR since 1980. He is a former partner of Coopers & Lybrand, an international accounting and consulting firm.
Ms. Hesse was elected a Director in September 1994. Ms. Hesse is currently President of Hesse Gas Company, a position she has held since 1991. Prior thereto she served as Senior Vice President of First Chicago Corporation since 1990. She was Chairman of the Federal Energy Regulatory Commission from 1986 to 1989. She has been a Director of ANR since 1990.
Mr. Mack was elected a Director in September 1994. Mr. Mack was an executive with ANR for 24 years, retiring in 1976 as Chairman and Chief Executive Officer and serving on the Board until 1982. He was re-elected to the Board of ANR in 1986.
Mr. MacNeil was elected a Director in September 1994. He has been a Director of ANR since 1993. Mr. MacNeil has been self employed in the securities and brokerage industry since 1980.
Mr. McNeal was elected a Director in September 1994. He has been a Director of ANR since 1982. Mr. McNeal served in various capacities with The Budd Company, retiring in 1989 as Chairman and Chief Executive Officer.
Mr. Matthews was elected Vice President and Treasurer in September 1994. He was elected Vice President and Treasurer of Colorado in October 1994. He has held various positions in financial management with Coastal and its affiliates since 1983, and was elected Treasurer of Coastal in September 1994.
Ms. Nichols was elected Vice President in January 1995. Most recently she served as Director - Application and Maintenance for Whirlpool Corporation, where she worked for more than four years. Prior thereto, she served in various capacities for the Pillsbury Corporation for 21 years.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
ANR Pipeline is an indirect, wholly-owned subsidiary of Coastal. Information concerning the cash compensation and certain other compensation of the directors and officers of Coastal is contained in this section.
The following table sets forth information for the fiscal years ended December 31, 1994, 1993 and 1992 as to cash compensation paid by Coastal and its subsidiaries, as well as certain other compensation paid or accrued for those years, to Coastal's Chief Executive Officer ("CEO") and its four other most highly compensated executive officers (the "Named Executive Officers").
SUMMARY COMPENSATION TABLE
________________________
/(1)/ Does not include the value of perquisites and other personal benefits because the aggregate amount of such compensation, if any, does not exceed the lesser of $50,000 or 10 percent of annual salary and bonus for any named individual.
/(2)/ Salary amounts for Messrs. Wyatt, Arledge and Cordes for 1992 and 1993 include directors' fees paid during these periods which were previously reported under "All Other Compensation." Directors' fees for members of management of Coastal were eliminated in September, 1993. There was no salary change for Mr. Wyatt during 1994; the reduced base pay level for 1994 was due to the September 1993 salary reduction (reported in the 1994 Coastal Proxy Statement) being in effect for all of 1994.
/(3)/ Due to Coastal's practice of paying bi-weekly, there is one extra pay period reflected in the 1992 salary. Normally there are 26 pay periods, but approximately once every 11 years there are 27 pay periods; 1992 was such a year.
/(4)/ Although 1993 bonus awards were not finalized by Coastal's Compensation and Executive Development Committee until after the 1994 Coastal Proxy Statement had been prepared, all awards were based solely on 1993 performance. Bonuses for 1992 were paid in equal installments over a three-year period, provided the employee was still employed on the anniversary date ofthe award. The 1994 bonuses were based on the following factors: the individual's position; the individual's responsibility and the individual's ability to impact Coastal's financial success.
/(5)/ The options do not carry any stock appreciation rights.
/(6)/ All Other Compensation for 1994 consists of: (i) Coastal contributions to the Coastal Thrift Plan (O. S. Wyatt, Jr. $12,000; David A. Arledge $12,000; James F. Cordes $12,000; James A. King $4,232 and Sam F. Willson, Jr. $12,000) and (ii) certain payments in lieu of Thrift Plan contributions (O. S. Wyatt, Jr. $55,928; David A. Arledge $32,310; James F. Cordes $35,378; James A. King $2,645 and Sam F. Willson, Jr. $14,725). These payments are made to all employees of Coastal and its subsidiaries who participate in the Thrift Plan who must discontinue their Thrift Plan participation due to federal statutory limits.
Mr. Cordes is employed pursuant to a five-year employment contract expiring in 1995, which provides that if he is terminated for a reason not permitted by the employment contract, he will be entitled to receive for the remainder of the term the salary, employee benefits, perquisites, salary increases, bonuses and other incentive compensation which he would have received had he not been terminated. Such reasons are a significant change in title, duties, authorities or reporting responsibilities, a reduction in salary or benefits or a move of the location of his office to a location not acceptable to him.
STOCK OPTIONS
No option/SAR grants were made to the Named Executive Officers during the fiscal year ended December 31, 1994.
OPTION/SAR EXERCISES AND HOLDINGS
The following table sets forth information with respect to the Named Executive Officers, concerning the exercise of options during the last fiscal year and unexercised options and SARs held as of the fiscal year ("FY") ended December 31, 1994.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES (1994)
- ------------------
/(1)/ $-based on the market price of $25.63 at December 31, 1994.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The following report has been provided by Coastal's Compensation and Executive Development Committee (the "Committee") of the Board of Directors in accordance with current Securities and Exchange Commission ("S.E.C.") proxy statement disclosure requirements. The members of the Committee include John M. Bissell (Chairman), Roy D. Chapin, Jr., and Jerome S. Katzin.
This material states Coastal's current overall compensation philosophy and program objectives. Detailed descriptions of Coastal's compensation programs are provided as well as the information on Coastal's 1994 pay levels for the CEO.
OVERALL OBJECTIVES OF THE EXECUTIVE COMPENSATION PROGRAM
Coastal's compensation philosophy and program objectives are directed by two primary guiding principles. First, the program is intended to provide fully competitive levels of compensation - at expected levels of performance - in order to attract, motivate and retain talented executives. Second, the program is intended to create an alignment of interests between Coastal's executives and shareowners such that a significant portion of each executive's compensation is directly linked to maximizing shareholder value.
In support of this philosophy, the executive compensation program is designed to reward performance that is directly relevant to Coastal's short-term and long-term success. As such, Coastal attempts to provide both short-term and long-term incentive pay that varies based on corporate and individual performance.
To accomplish these objectives, the Committee has structured the executive compensation program with three primary underlying components: base salary, annual incentives, and long-term incentives (i.e., stock options). The following sections describe Coastal's plans by element of compensation and discuss how each component relates to Coastal's overall compensation philosophy.
In reviewing this information, reference is often made to the use of competitive market data as criteria for establishing targeted compensation levels. Coastal targets the market 50th percentile for its total compensation program and actual total compensation rates are generally consistent with that target. (However, Coastal's competitive pay posture varies by pay element, as described below.) Several market data sources are used by Coastal, including energy industry norms for the publicly traded peer companies included in Coastal's shareholder return performance graphs, as reflected in these companies' proxy statements. In addition, we utilize published survey data and data obtained from independent consultants that are for general industry companies similar in size (i.e., revenues) to Coastal. The published surveys include data on over 40 companies of comparable size to Coastal, as measured by revenues. Greater emphasis is placed on the published data and data obtained from consultants than on the data for proxy peers, since the published data and consulting data are reflective of company size.
BASE SALARY PROGRAM
Coastal's base salary program is based on a philosophy of providing base pay levels that fall between the market 50th and 75th percentiles. Coastal periodically reviews its executive pay levels to assure consistency with the external market. Generally, Coastal's actual base salary levels for 1994 for executives as a group were consistent with the targeted percentiles. We believe it is crucial to provide strongly competitive salaries over time in order to attract and retain executives who are highly talented.
Annual salary adjustments for Coastal are based on several factors: general levels of market salary increases, individual performance, competitive base salary levels, and Coastal's overall financial results. Coastal reviews performance qualitatively considering total shareholder returns, the level of earnings, return on equity, return on total capital and individual business unit performance. These criteria are assessed qualitatively and are not weighted. All base salary increases are based on a philosophy of pay-for-performance and perceptions of an individual's long-term value to Coastal. As a result, employees with higher levels of performance sustained over time will be paid correspondingly higher salaries.
THE ANNUAL BONUS PLAN
Coastal's Annual Bonus Plan is intended to (1) reward key employees based on company/business unit and individual performance; (2) motivate key employees; and (3) provide competitive cash compensation opportunities to plan participants. Under the plan, target award opportunities vary by individual position and are expressed as a percent of base salary. The individual target award opportunities, which are slightly below market median levels, are then aggregated into a total target pool which is adjusted as described below. The amount a particular executive may earn is directly dependent on the individual's position, responsibility, and ability to impact Coastal's financial success.
The actual bonus pool is established each year by modifying the target pool based on Coastal's overall performance against measures established by the Committee. In fiscal year 1994, the key performance measure considered was earnings before interest and taxes ("EBIT") against plan. This measure was weighted 50% of the total bonus program. In 1994 Coastal's EBIT performance significantly improved over 1993 performance. This 1994 EBIT achievement was above threshold standards (minimum performance level for bonus payment) but below a very aggressive plan, resulting in the EBIT portion of the bonus paid being below target. The remaining 50% of the annual bonus opportunity in 1994 is a discretionary annual bonus pool. As a result, no formula performance measures were used in establishing the size of awards under this portion of the plan. However, in establishing the size of the discretionary bonus pool, the Committee considered Coastal's Return on Equity relative to industry peers (using the same peers included in the shareholder return graphs), Return on Total Capital compared to industry peers, the EBIT performance of each business unit, progress made toward improving Coastal's operational and financial performance, and the need to reward unique individual contributions. These measures were not formally weighted by the Committee. The size of the discretionary bonus pool element was established above threshold but below target based on the qualitative performance assessment described above. As a result, actual bonus payments for 1994 were below target and median market levels.
Individual awards from the established bonus pool are recommended by senior management, with advice and consent from the Committee. Individual awards from the pool are based on business unit and individual employee performance, future potential, and competitive considerations. All individual performance assessments are conducted in a non-formula fashion without specific goal weightings. The total bonus awards made may not exceed the amount of funds in the bonus pool.
LONG-TERM INCENTIVE PLAN
Coastal's Long-Term Incentive Plan ("LTIP") is designed to focus executive efforts on the long-term goals of Coastal and to maximize total return to Coastal's shareholders. While Coastal's LTIP allows the Committee to use a variety of long-term incentive devices, the Committee has relied solely on stock option awards to provide long-term incentive opportunities in recent years.
Stock options align the interests of employees and shareholders by providing value to the executive through stock price appreciation only. All stock options have a ten year term before expiration and are fully exercisable within 7 years of the grant date.
No stock options were granted to the Named Executive Officers in 1994 since Coastal made larger than normal grants to key executives in December 1993. However, it is anticipated that stock option awards will be made periodically at the discretion of the Committee in the future. As in past years, the number of shares actually granted
to a particular participant is also based on Coastal's financial success, its future business plans, and the individual's position and level of responsibility within Coastal. All of these factors are assessed subjectively and are not weighted.
1994 CHIEF EXECUTIVE OFFICER PAY
As previously described, the Committee considers several factors in developing an executive's compensation package. For the CEO, these include competitive market practices (consistent with the philosophy described for other executives), experience, achievement of strategic goals, and the financial success of Coastal (considering the factors described under the annual bonus plan above).
Mr. Wyatt received no salary increase in 1994. The Committee took no action regarding Mr. Wyatt's base salary, in spite of significantly improved Coastal performance during the year. This lack of any adjustment is not a reflection of performance; rather, it is based on considering strong input from the CEO, who wants to see continued improvement in shareholder returns before receiving any base salary increase.
Mr. Wyatt's bonus for 1994 performance was $200,000. This bonus award was below targeted levels (and below market median levels) since Coastal's aggregate performance on the measures described in the annual bonus section of this report was below the aggressive Coastal targets (but above 1993 levels).
The Committee granted no stock options to Mr. Wyatt in 1994 (consistent with past practices), considering the strongly expressed opinion of the CEO. Mr. Wyatt and the Committee considered Mr. Wyatt's current level of stock ownership in reaching this decision.
$1 MILLION PAY DEDUCTIBILITY CAP
Under Section 162(m) of the Internal Revenue Code, public companies are precluded from receiving a tax deduction on compensation paid to executive officers in excess of $1 million. To address the $1 million pay deductibility cap issue, Coastal's 1994 LTIP was structured so that stock option awards (which are intended to be the primary long-term incentive vehicle for the present time) qualify for an exemption from the $1 million pay deductibility limit.
Also, at the present time, the CEO is the only executive whose base salary plus target bonus exceeds $1 million. In order to preserve Coastal's tax deduction for the CEO's base salary plus bonus, Coastal has established a nonqualified deferred compensation program for Mr. Wyatt. Under this program, any annual incentive awards that bring Mr. Wyatt's cash compensation to a level over $1 million will be deferred so that payments occur after Mr. Wyatt is no longer a Named Executive Officer, thus preserving the deductibility of the pay for Coastal.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
John M. Bissell, Chairman Roy D. Chapin, Jr. Jerome S. Katzin
PENSION PLAN
The following table shows for illustration purposes the estimated annual benefits payable currently under the Pension Plan and Coastal's Replacement Pension Plan described below upon retirement at age 65 based on the compensation and years of credited service indicated.
PENSION PLAN TABLE
(A) Compensation covered under the Pension Plan for employees of Coastal and the Coastal Replacement Pension Plan generally includes only base salary and is limited to $150,000 for 1994.
(B) Federal legislation has reduced the benefit which may be earned due to future service; however, benefits previously earned may not be reduced. At December 31, 1994 each of the individuals named in the Summary Compensation Table had covered salary for future benefit accrual of $150,000 and the following years of credited service and pension payable at age 65 (or current age, if over 65): Mr. Wyatt, 39 years, $469,834; Mr. Arledge, 14 years, $54,181; Mr. Cordes, 17 years, $74,523; Mr. King, 2 years, $9,474 (not vested) and Mr. Willson, 22 years, $98,357.
(C) The normal form of retirement income is a straight life annuity. Benefits payable under the Pension Plan are subject to offset by 1.5% of applicable monthly social security benefits multiplied by the number of years of credited service (up to 33 1/3 years).
The Employee Retirement Income Security Act of 1974, as amended by subsequent legislation, limits the retirement benefits payable under the tax-qualified Pension Plan. Where this occurs, Coastal will provide to certain executives, including persons named in the Summary Compensation Table, additional nonqualified retirement benefits under a Coastal Replacement Pension Plan. These benefits, plus payments under the Pension Plan, will not exceed the maximum amount which Coastal would have been required to provide under the Pension Plan before application of the legislative limitations, and are reflected in the above table and footnote (B).
PERFORMANCE GRAPHS - SHAREHOLDER RETURN ON COMMON STOCK
FIVE-YEAR CUMULATIVE VALUES $100 INVESTED 12/31/89 DIVIDENDS REINVESTED
[GRAPH APPEARS HERE]
YEAR ENDED 12/31
(1) The Index is based on Value Line Diversified Natural Gas Group - the Performance Graphs reflect total shareholder return weighted to reflect the market capitalizations of the peer companies. The peer group is comprised of: NorAm, Burlington Res., Columbia, Consolidated Nat. Gas, Eastern Enterprises, Enron, Enserch, Equitable Res.,KN Energy, Mitchell Energy, National Fuel Gas, Panhandle Eastern, Seagull Energy, Sonat, Southwestern Energy, Tenneco, Transco, Valero and Williams Cos. (2) Coastal is excluded from the Index.
TEN-YEAR TWO MONTHS CUMULATIVE VALUES $100 INVESTED 12/31/84 DIVIDENDS REINVESTED
[GRAPH APPEARS HERE]
YEAR ENDED 12/31
(1) The Index is based on Value Line Diversified Natural Gas Group - the Performance Graphs reflect total shareholder return weighted to reflect the market capitalizations of the peer companies. The peer group is comprised of: NorAm, Burlington Res., Columbia, Consolidated Nat. Gas, Eastern Enterprises, Enron, Enserch, Equitable Res.,KN Energy, Mitchell Energy, National Fuel Gas, Panhandle Eastern, Seagull Energy, Sonat, Southwestern Energy, Tenneco, Transco, Valero and Williams Cos. (2) Coastal is excluded from the Index.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security ownership of certain beneficial owners.
The following is information, as of March 15, 1995, on each person known or believed by ANR Pipeline to be the beneficial owner of 5% or more of any class of its voting securities:
(b) Security ownership of management.
ANR Pipeline is an indirect, wholly-owned subsidiary of Coastal. Information concerning the security ownership of certain beneficial owners and management of Coastal is contained in this section.
The total number of shares of stock of Coastal outstanding as of March 15, 1995 is 112,960,388 consisting of 63,118 shares of $1.19 Cumulative Convertible Preferred Stock, Series A (the "Series A Preferred Stock"), 83,756 shares of $1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred Stock"), 34,191 shares of $5.00 Cumulative Convertible Preferred Stock, Series C (the "Series C Preferred Stock") (the Series A Preferred Stock, the Series B Preferred Stock and the Series C Preferred Stock are referred to herein collectively as the "Preferred Stock"), 8,000,000 non-voting shares of $2.125 Cumulative Preferred Stock, Series H, 104,363,374 shares of Common Stock and 415,949 shares of Class A Common Stock.
Each voting share of Common Stock or Preferred Stock entitles the holder to one vote with respect to all matters to come before a shareholders' meeting, while each share of Class A Common Stock entitles the holder to 100 votes. However, 25% of Coastal's directors standing for election at each annual meeting will be determined solely by holders of the Common Stock and voting Preferred Stock voting as a class.
The following table sets forth information, as of March 15, 1995, with respect to each person known or believed by Coastal to be the beneficial owner, who has or shares voting and/or investment power (other than as set forth below), of more than five percent (5%) of any class of its voting securities.
__________
(1) Class includes presently exercisable stock options held by directors and executive officers.
(2) Includes 7,354 shares of Class A Common Stock owned by the spouse and a son of Mr. Wyatt, as to which shares beneficial ownership is disclaimed.
(3) The Trustee/Custodian is the record owner of these shares; and also is the record owner of 953 shares of the Series B Preferred Stock, each of which is convertible into 3.6125 shares of Common Stock and 0.1 share of Class A Common Stock. Voting instructions are requested from each participant in the Thrift Plan and ESOP and from the trustees under a Pension Trust. Absent voting instructions, the Trustee is permitted to vote Thrift Plan shares on any matter, but has no authority to vote ESOP shares or Pension Plan shares. Nor does the Trustee/Custodian have any authority to dispose of shares except pursuant to instructions of the administrator of the Thrift Plan and ESOP or pursuant to instructions from the trustees under the Pension Trust.
(4) Members of the DeZurik family acquired the Series C Preferred Stock in connection with a 1972 Agreement of Merger involving the acquisition of Colorado, a subsidiary of Coastal.
The following table sets forth information, as of March 15, 1995, regarding each of the then current directors, including Class III directors standing for election, and all directors and executive officers as a group. Each director has furnished the information with respect to age, principal occupation and ownership of shares of stock of Coastal. Messrs. Bissell, Burrow, Chapin and Katzin are Class I directors whose terms expire in 1996; Messrs. Arledge, Brundrett, Wooddy and Wyatt are Class II directors whose terms expire in 1997 and Messrs. Cordes, Gates, Johnson, Marshall and McDade are Class III directors whose terms expire in 1995.
* Less than one percent unless otherwise indicated. Class includes outstanding shares and presently exercisable stock options held by directors and executive officers. Excluding presently exercisable stock options, directors and executive officers as a group would own 186,832 shares of Class A Common Stock, which would constitute 44.9% of the shares of such class.
(1) Except for the shares referred to in Notes 2 and 3 below, and the shares represented by presently exercisable stock options, the holders are believed by Coastal to have sole voting and investment power
as to the shares indicated. Amounts include shares in Coastal ESOP and Thrift Plan, and presently exercisable stock options held by Messrs. Burrow (14,189 shares of Common Stock), Arledge (160,503 shares of Common Stock and 13,868 shares of Class A Common Stock), Cordes (103,785 shares of Common Stock) and Johnson (53,915 shares of Common Stock).
(2) Includes shares owned by the spouse and a son of Mr. Wyatt (266,295 shares of Common Stock and 7,354 shares of Class A Common Stock), by the spouse of Mr. Burrow (5,000 shares of Common Stock), by the spouse of Mr. Chapin (1,000 shares of Common Stock) and by the spouse of Mr. Katzin (928 shares of Common Stock), as to which shares beneficial ownership is disclaimed; also includes shares owned by the estate of the late Mrs. Marshall (4,362 shares of Common Stock and 100 shares of Class A Common Stock).
(3) Includes presently exercisable stock options to purchase 674,265 shares of Common Stock and 13,868 shares of Class A Common Stock; also includes 280,339 shares of Common Stock and 7,354 shares of Class A Common Stock owned by spouses and children, as to which shares beneficial ownership is disclaimed; also includes 4,362 shares of Common Stock and 100 shares of Class A Common Stock owned by the estate named in Note 2 above. In addition, one executive officer owns 8 shares of Series B Preferred Stock, each of which is convertible into 3.6125 shares of Common Stock and 0.1 share of Class A Common Stock.
No incumbent director is related by blood, marriage or adoption to another director or to any executive officer of Coastal or its subsidiaries or affiliates.
Except as hereafter indicated, the above table includes the principal occupation of each of the directors during the past five years. The listed executive officers have held various executive positions with Coastal, ANR, ANR Pipeline and/or Colorado during the five-year period.
Mr. Bissell is a member of the Boards of Directors of Old Kent Financial Corporation and Batts Inc.
Mr. Cordes is a member of the Board of Directors of Comerica Inc.
Mr. Katzin is a member of the Board of Directors of Qualcomm Incorporated.
Mr. Marshall is a member of the Boards of Directors of Missouri-Kansas-Texas Railroad Company and Presidio Oil Company.
Mr. McDade is a trial lawyer and the founding senior partner of the Houston law firm of McDade & Fogler L.L.P. Prior to forming McDade & Fogler L.L.P. he was a senior partner in the Houston law firm of Fulbright & Jaworski. He is a member of the Board of Directors of Equity Corporation International.
Messrs. Arledge, Burrow, Cordes and Wyatt are directors of Colorado and ANR Pipeline. Both of these subsidiaries of Coastal are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
(a) Transactions with management and others.
ANR Pipeline participates in a program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing borrowings from outside sources. At December 31, 1994, the Company had advanced $235.2 million to an associated company at a market rate of interest. Such amount is repayable on demand.
Additional information called for by this item is set forth under Item 11, "Executive Compensation," and Note 11 of Notes to Consolidated Financial Statements included herein.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
Not applicable.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as part of this Annual Report or incorporated herein by reference:
1. Financial Statements.
The following Consolidated Financial Statements of ANR Pipeline and Subsidiaries are included in response to Item 8 hereof on the attached pages as indicated:
2. Financial Statement Schedules.
Schedules are omitted as not applicable or not required, or the required information is shown in the Consolidated Financial Statements or Notes thereto.
3. Exhibits.
(3.1)+ Composite Certificate of Incorporation of ANR Pipeline effective as of December 31, 1987 (Filed as Module ANRCertIncorp on March 29, 1994).
(3.2)* Amended By-laws of ANR Pipeline effective as of September 21, 1994.
(4) With respect to instruments defining the rights of holders of long-term debt, the Company will furnish to the Securities and Exchange Commission any such document on request.
(4.1)+ Board Resolution dated September 22, 1975 establishing the $2.675 Series of Cumulative Preferred Stock (Filed as Module BoardRes_092275 on March 29, 1994).
(4.2)+ Board Resolution dated October 26, 1976 establishing the $2.12 Series of Cumulative Preferred Stock (Filed as Module BoardRes_102676 on March 29, 1994).
(4.3)+ Board Resolution dated May 12, 1980 establishing the $12.00 Series of Cumulative Preferred Stock (Filed as Module BoardRes_051280 on March 29, 1994).
(4.4)+ Indenture dated as of February 15, 1994 and First Supplemental Indenture dated as of February 15, 1994 for the $125 million of 7-3/8% Debentures due February 15, 2024. (Filed as Exhibit 4.4 to ANR Pipeline's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.)
(10.1)+ Form of Employment Agreement between ANR Pipeline and certain of its executive officers (Filed as a Module ANREmployAgree on March 29, 1994).
(10.2)+ Form of Employment Agreement between Coastal and certain Company executive officers (Filed as Module TCCEmployAgree on March 29, 1994).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
Note:
+ Indicates documents incorporated by reference from the prior filings indicated. * Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31, 1994.
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints Coby C. Hesse, William L. Johnson 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.
ANR PIPELINE COMPANY (Registrant)
By: JEFFREY A. CONNELLY -------------------------- Jeffrey A. Connelly President, Chief Executive Officer and Director March 29, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By: JAMES F. CORDES By: DAVID A. ARLEDGE --------------------------- --------------------------- James F. Cordes David A. Arledge Chairman Principal Financial Officer March 29, 1995 and Director March 29, 1995
By: WILLIAM L. JOHNSON By: HAROLD BURROW --------------------------- --------------------------- William L. Johnson Harold Burrow Principal Accounting Officer Vice Chairman March 29, 1995 March 29, 1995
By: RICHARD A. LIETZ By: JOHN M. BISSELL --------------------------- --------------------------- Richard A. Lietz John M. Bissell Executive Vice President, Director Chief Operating Officer and Director March 29, 1995 March 29, 1995
By: ROY D. CHAPIN, JR. By: LAWRENCE P. DOSS --------------------------- --------------------------- Roy D. Chapin, Jr. Lawrence P. Doss Director Director March 29, 1995 March 29, 1995
By: MARTHA O. HESSE By: WILBER H. MACK --------------------------- --------------------------- Martha O. Hesse Wilber H. Mack Director Director March 29, 1995 March 29, 1995
By: J. CARLETON MACNEIL, JR. By: JAMES H. MCNEAL, JR. --------------------------- --------------------------- J. Carleton MacNeil, Jr. James H. McNeal, Jr. Director Director March 29, 1995 March 29, 1995
By: O. S. WYATT, JR. --------------------------- O. S. Wyatt, Jr. Director March 29, 1995
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW. Internally generated funds have been the primary source to meet mandatory debt and preferred stock retirements and other cash requirements of the Company over the past three years.
During 1993 the Company retired $78.1 million of its long-term debt obligations, of which $37.7 million of First Mortgage Pipe Line Bonds and $9.7 million of Debentures represented early redemptions. Interest rates associated with the early redemptions ranged from 9-5/8% to 13-1/4%, which were significantly higher than market rates.
On September 23, 1993, the Company 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 on October 5, 1993. Subsequently, in February 1994, the Company completed an offering of $125 million in principal amount of 7-3/8% 30-year Debentures due in February 2024. The net proceeds from the sale of the Debentures were added to the general funds of the Company and were used for capital expenditures and for other general corporate purposes, including the payment of a $255 million dividend on its common stock in March 1994. In June 1994, the Company paid an additional $76 million dividend on its common stock which was financed from internally generated funds.
On June 16, 1994, the Company redeemed all of the outstanding shares of its Cumulative Preferred Stock. For additional information regarding this matter, see Note 3 of Notes to Consolidated Financial Statements included herein.
The Company uses the following consolidated ratios to measure liquidity and ability to meet future funding needs and debt service requirements.
The 1994 decrease in cash flows from operating activities to long-term debt and capital lease obligations resulted from an increase in long-term debt due to the issuance of $125 million of Debentures discussed above. The 1993 increase in the cash flows from operating activities to long-term debt and capital lease obligations resulted from a decrease in long-term debt due to the early redemptions in 1993 discussed above. The increase in 1994 in long-term debt and capital lease obligations to total capitalization resulted from issuance of long-term debt and a decrease in retained earnings resulting from dividends paid. The decrease in 1993 in long-term debt and capital lease obligations to total capitalization resulted from the retirement of long-term debt and an increase in retained earnings.
Management believes that the Company's stable financial position and earnings ability will enable it to continue to generate and obtain capital for financing needs in the foreseeable future.
Expenditures for each of the years 1992 through 1994 and the sources of capital used to finance these expenditures are summarized in the "Statement of Consolidated Cash Flows."
CAPITAL EXPENDITURES. Capital expenditures were $62.0 million in 1994 and $49.4 million in 1993. Capital expenditures for 1995, including the Company's equity investments in partnerships and joint ventures, are currently estimated at $86 million.
Funding for certain proposed natural gas pipeline projects is anticipated to be provided through nonrecourse 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. 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. Financing for the remaining budgeted expenditures in 1995 will be accomplished by the use of internally generated funds. Information concerning these projects is contained in Part I herein under Item 1, "Business - Other Developments."
GAS IN UNDERGROUND STORAGE. Gas in underground storage of $207.5 million was reclassified to "Property, Plant and Equipment" as of December 31, 1993. For additional information regarding this matter, see Note 1 of Notes to Consolidated Financial Statements included herein.
ASSETS RELATED TO EXCESS GAS SUPPLY. "Assets related to excess gas supply" are being recovered through the currently allowed billing mechanism under FERC Order No. 528, through gas takes against prepaid gas and through cash recoveries of gas prepayments under certain take-or-pay contracts. "Assets related to excess gas supply" decreased by $29.9 million and $82.6 million in 1994 and 1993, respectively. The decline in each year is attributable to the recovery of producer contract reformation costs pursuant to FERC Order No. 528 and, in 1993, a significant first quarter cash recovery of a prepayment for gas under a purchase contract with a producer.
CURRENCY SWAPS. The Company has outstanding bonds for 125 million Swiss francs which mature in October 1995, and are expected to be extinguished through an affiliate's repayment of a loan or through alternative financing arrangements. The Company's entire foreign currency risk associated with this debt, including principal and interest, has been hedged by entering into currency swap agreements with maturities matching those of the underlying debt. In the event of nonperformance by the counterparties to the currency swaps, the Company would have possible exposure to credit loss in the amount of $39.5 million as of December 31, 1994. However, the Company has largely mitigated the risk of such a loss occurring by limiting the counterparties of these agreements to a prominent international bank and a prominent international financial institution. For additional information regarding the outstanding Swiss franc bonds, see Note 4 of Notes to Consolidated Financial Statements included herein.
FINANCING ALTERNATIVES. Alternatives to finance additional capital and other expenditures are limited principally by the terms of certain debt instruments of the Company and certain affiliates. Under the most restrictive of such instruments, as of December 31, 1994, ANR Pipeline and certain affiliates could incur in the aggregate approximately $770 million of additional indebtedness. For the Company and these affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $350 million of indebtedness of Coastal Natural Gas would need to be retired.
The Company participates in a program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing borrowing from outside sources. At December 31, 1994, the Company had advanced $235.2 million to an associated company at a market rate of interest. Such amount is repayable upon demand.
ENVIRONMENTAL. The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction, operation and maintenance of its pipeline facilities. The Company anticipates annual capital expenditures of $2 million over the next several years aimed at maintaining compliance with such laws and regulations. Additionally, appropriate governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act, also known as "Superfund," as reauthorized, imposes liability, without regard to fault or the legality of the original act, for disposal of a "hazardous substance." The Company has been named as a potentially responsible party in four federal "Superfund" waste disposal sites and one state "Superfund" site. At the four federal sites for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $31.6 million, the Company estimates its pro-rata exposure is approximately $.8 million. At the state site, the Company has been named a de minimis potentially responsible party. However, since the agency having jurisdiction over the site is currently unable to provide an estimate of the total clean-up costs, the Company is unable to calculate its 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.
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, consolidated financial position or results of operations.
RESULTS OF OPERATIONS
On April 8, 1992 the FERC issued Order 636 which required significant changes in the services provided by interstate natural gas pipelines (see Note 7 of Notes to Consolidated Financial Statements included herein). 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, the adoption of 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. The Company now offers a wide range of "unbundled" transportation, storage, gathering and balancing services. In anticipation of the competitive environment created by Order 636, the Company entered into a number of firm, long-term storage and transportation contracts with customers. As a result, the majority of the revenue the Company receives from storage and transportation services is now derived from reservation charges associated with these contracts. Over time this will provide a stable stream of revenue and related cash flow for the Company.
As a result of Order 636, the Company no longer offers a merchant service. Because of this, a significant portion of the Company's gas purchase contracts have been bought out or assigned. The Company is continuing to negotiate the termination of the remaining gas purchase contract obligations and believes it will recover any costs associated with the resolution of these negotiations with no significant financial impact. In 1994, gas sales revenues reflect amounts related to the auctioning of gas in producing areas acquired under these remaining gas purchase contracts, in addition to purchased gas adjustment recoveries from customers associated with purchase periods prior to Order 636. While operating revenues 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, thereby having minimal net impact on earnings.
Prior to Order 636, for the period November 1, 1992 through October 31, 1993, the Company operated under restructured sales services as part of the Interim Settlement. Prior to the restructuring, the cost of providing transportation services for sales customers was recovered as part of the Company's total resale rate and, therefore, was classified as part of gas sales revenue. Under the Interim Settlement, these costs were recovered through a separate "bundled" storage and transportation rate and were included in storage and transportation revenue.
REVENUES. Storage and transportation revenues increased by 11% in 1994 as compared to 1993. The primary factor contributing to the increase was revenues associated with cost recovery mechanisms related to above market gas purchases and certain transportation services provided by others, which were offset by amounts included in cost of gas and operation and maintenance. Revenues have been reduced in 1994 by provisions of $37.6 million for rate related contingencies, associated with Docket No. RP94-43.
Storage and transportation revenues increased by 19% in 1993 as compared to 1992. The primary factors contributing to the increased revenue were the recognition of $123.8 million of additional transportation revenue due to the sales service restructuring discussed above, and the addition of 24.4 Bcf and 46.2 Bcf of new firm storage and firm transportation services contracted for, effective April 1, and November 1, 1993, respectively. These factors were offset by lower transportation commodity rates associated with the settlement of the Company's 1989 rate case, a decrease in open access transportation volumes of 7% which, in part, is the result of higher sales volumes transported during the period. Also affecting revenues in 1992 was a restoration to income of $53.7 million associated with the settlement of the Company's 1989 rate case.
Gas sales revenues declined significantly in 1994 as compared to 1993 as a result of the elimination of the Company's merchant service, as discussed above. Gas sales revenues decreased by $31 million in 1993 as compared to 1992 primarily as a result of the sales service restructuring discussed above and rate decreases associated with gas pricing. The decreases in 1993 were largely offset by higher sales volumes resulting from sales customers purchasing gas for storage injection during the spring and summer months. This purchase and storage of gas by sales customers was in anticipation of the Company's implementation of Order 636, and the fact that the Company would no longer provide a merchant service effective November 1, 1993.
Other revenues increased in 1993, as compared to 1992, largely due to additional revenue from investments in pipeline partnerships and an increase in interest income.
COST OF GAS. Cost of gas significantly declined during 1994, as compared to 1993, as a result of the elimination of the Company's merchant service, as discussed above. Cost of gas includes purchases required under certain remaining gas purchase contracts and the amortization of purchased gas adjustment recoveries from customers.
Cost of gas increased by $119.6 million in 1993 as compared to 1992 due to higher sales volumes. This increase was partially offset by a decrease in the average rate of the cost of gas purchased. Certain costs previously recorded as a component of cost of gas sold, which are now included in transmission and compression expense within operation and maintenance expenses as a result of the Interim Settlement, also contributed to this decrease.
OPERATION AND MAINTENANCE. Operation and maintenance expenses decreased by $17.8 million in 1994 as compared to 1993. This decrease was largely due to a reduction in transportation services provided by others and lower costs associated with maintenance of pipeline and compressor station facilities, partially offset by increased benefit costs related to the required adoption of FAS Nos. 106 and 112. Additionally, the variance includes a benefit in 1993 related to revisions of certain estimated costs.
Operation and maintenance expenses for 1993 approximated those of 1992, although the following fluctuations were noted. Transportation services provided by others increased in 1993 as described above, and storage expense increased due to the addition of 42 Bcf of storage capacity provided by Blue Lake Gas Storage Company commencing in April 1993. These increases were offset by the benefit related to certain estimated costs mentioned above, which were recorded in 1992.
DEPRECIATION. Depreciation expense increased by $3.9 million in 1994 as compared to 1993, primarily due to an increase in plant balances. The decrease in depreciation expense of $44.1 million in 1993 as compared to 1992 was caused by a decrease in depreciation rates, which became effective November 1, 1992, as a result of the Interim Settlement.
INTEREST EXPENSE. Interest expense decreased by $7.3 million in 1993 as compared to 1992 due to a lower effective interest rate and lower average outstanding long-term debt, partially offset by a reduction in 1992 interest expense associated with changes in provisions for regulatory matters.
TAXES ON INCOME. Income taxes increased by $3.3 million in 1993 as compared to 1992 primarily due to an increase in pre-tax income and an increase in the federal income tax rate from 34% to 35%, offset by certain adjustments to state income tax accruals.
RECENT ADOPTION OF FASB PRONOUNCEMENT
The Company adopted FAS No. 112, effective January 1, 1994. The effects of the changes required by FAS No. 112 are not material to the Company. For additional information regarding this matter, see Note 10 of Notes to Consolidated Financial Statements included herein.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder ANR Pipeline Company Detroit, Michigan
We have audited the accompanying consolidated balance sheets of ANR Pipeline Company (an indirect, wholly-owned subsidiary of The Coastal Corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ANR Pipeline Company and subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Note 10 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
Detroit, Michigan February 2, 1995
ANR PIPELINE COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Millions of Dollars)
See Notes to Consolidated Financial Statements.
ANR PIPELINE COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Millions of Dollars)
See Notes to Consolidated Financial Statements.
ANR PIPELINE COMPANY AND SUBSIDIARIES STATEMENT OF CONSOLIDATED EARNINGS (Millions of Dollars)
STATEMENT OF CONSOLIDATED RETAINED EARNINGS (Millions of Dollars)
See Notes to Consolidated Financial Statements.
ANR PIPELINE COMPANY AND SUBSIDIARIES STATEMENT OF CONSOLIDATED CASH FLOWS (Millions of Dollars)
See Notes to Consolidated Financial Statements.
ANR PIPELINE COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
- - Basis of Presentation
ANR Pipeline is a subsidiary of ANR, which is a direct subsidiary of Coastal Natural Gas and an indirect subsidiary of Coastal. The financial statements presented herewith are presented on the basis of historical cost and do not reflect the basis of cost to Coastal Natural Gas.
The Company is subject to the regulations and accounting procedures of the FERC. The Company meets the criteria and, accordingly, follows the accounting and reporting requirements of FAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
- - Reclassifications
Gas in underground storage of $207.5 million was reclassified to "Property, Plant and Equipment" as of December 31, 1993. The reclassification of these costs reflect the fact that, effective November 1, 1993, the Company no longer provides a merchant function and that under the Order 636 environment, these costs are now considered an investment needed solely for use in facilitating the overall operations of the Company's pipeline system. Certain other reclassifications of prior period statements have been made to conform with current reporting practices. The effect of these reclassifications was not material to the Company's consolidated financial position or results of operations.
- - Principles of Consolidation
The consolidated financial statements include the 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. The cost method of accounting is used for an investment in which the Company has less than a 20% continuing interest.
- - Depreciation of Gas Plant
The Company's annual provisions for depreciation of gas plant are computed on a straight-line basis using rates of depreciation which vary by type of property. The annual composite depreciation rates for 1994, 1993 and 1992 were approximately 1.7%, 1.6% and 3.1%, respectively. The decrease in the annual composite depreciation rate for 1993 resulted from provisions of the Interim Settlement which reduced depreciation rates effective November 1, 1992. The resulting reduction in depreciation expense of $44.1 million was offset by a corresponding decrease in revenues collected from customers. The determination of book depreciation useful lives and the resulting depreciation rates are consistent with the policies and practices normally followed under generally accepted accounting principles. A calculation of the cumulative effect on recorded depreciation resulting from the use of recovery periods for regulatory purposes different from the estimated useful lives absent regulation has not been prepared.
Costs of minor property units (or components thereof) retired or abandoned are charged or credited, net of salvage, to accumulated depreciation. Gain or loss on sales of major property units is credited or charged to income.
- - Income Taxes
The Company is a member of a consolidated group which files a consolidated federal income tax return. Members of the consolidated group with taxable 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.
- - Statement of Cash Flows
For purposes of these financial statements, cash equivalents include time deposits, certificates of deposit and all highly liquid instruments with original maturities of three months or less. The Company made cash payments for interest, net of interest capitalized, of $50.2 million, $53.0 million and $68.3 million in 1994, 1993 and 1992, respectively. Cash payments for income taxes amounted to $54.9 million, $103.2 million and $104.1 million in 1994, 1993 and 1992, respectively.
- - Allowance for Funds Used During Construction
In accordance with the accounting requirements of the FERC, an allowance for equity and borrowed funds used during construction is included in the cost of the Company's major additions to gas plant. These costs amounted to $1.2 million, $1.5 million and $3.9 million in 1994, 1993 and 1992, respectively.
- - Currency Swaps
The Company has entered into foreign currency swap agreements to manage its foreign exchange exposure on its outstanding bonds for 125 million Swiss francs which mature in October 1995. Costs associated with these swaps were fixed at the date of issuance and are being amortized over the life of the related debt issuance. Gains or losses from foreign currency swaps are deferred and 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.
- - Concentrations of Credit Risk
The Company's primary market areas are located in the Midwest region of the United States. The Company has a concentration of receivables due from interstate pipelines, intrastate pipelines and local distribution companies in these market areas. These concentrations of customers may affect the Company's overall credit risk in that the customers may be similarly affected by changes in economic, regulatory and other factors. Trade receivables are generally not collateralized; however, the Company analyzes customers' credit positions prior to extending credit.
2. Common Stock and Other Stockholder's Equity
All of ANR Pipeline's common stock is owned by ANR.
Under the terms of the most restrictive of the Company's financing agreements, approximately $166 million was available at December 31, 1994 for payment of dividends on the Company's common stock.
3. Mandatory Redemption Cumulative Preferred Stock
On June 16, 1994, the Company redeemed all outstanding shares of its Cumulative Preferred Stock. Of the 800,000 outstanding shares of the publicly held $2.12 Series, 200,000 shares were redeemed under sinking fund provisions at $25.00 per share, and 600,000 shares were redeemed under optional redemption provisions at $25.318 per share. Of the 200,000 outstanding shares of the publicly held $2.675 Series, all shares were redeemed under sinking fund provisions at $25.00 per share. Of the 86,640 outstanding shares of the privately held $12.00 Series, all shares were redeemed under optional redemption provisions at $103.79 per share. Redemption of these series included the payment of accrued dividends to June 16, 1994. A $328,000 premium paid in excess of par value to redeem the remaining outstanding preferred stock was charged directly to retained earnings in accordance with FERC accounting procedures.
4. Long-Term Debt
Balances at December 31 were as follows (millions of dollars):
* In October 1985, the Company issued 6% bonds for 125 million Swiss francs at a price of 100.25%. The foreign currency exposure resulting from the issue has been contractually hedged through two currency swap agreements, resulting in an effective borrowing cost of approximately 10.7%. Neither the Company nor the counterparties are required to collateralize their respective obligations under these swaps. In the event of nonperformance by the counterparties to the currency swaps, the Company would have possible exposure to credit loss in the amount of $39.5 million as of December 31, 1994. However, the Company has largely mitigated the risk of such a loss occurring by limiting the counterparties of these agreements to a prominent international bank and a prominent international financial institution.
Maturities of long-term debt during the succeeding five years are as follows (millions of dollars):
1995.................... $58.1 1996.................... - 1997.................... - 1998.................... - 1999.................... -
Alternatives to finance additional capital and other expenditures are limited principally by the terms of certain debt instruments of the Company and certain affiliates. Under the most restrictive of such instruments, as of December 31, 1994, ANR Pipeline and certain affiliates could incur in the aggregate approximately $770 million of additional indebtedness. For the Company and these affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $350 million of indebtedness of Coastal Natural Gas would need to be retired.
5. Value of Financial Instruments
The estimated fair value amounts of the Company's financial instruments have been determined by the Company, using appropriate market information and valuation methodologies. Considerable judgment is required to develop the estimates of fair value, thus, the estimates provided herein are not necessarily indicative of the amounts that could be realized in a current market exchange.
The estimated fair value of the marketable security of a related party is based on market quotes at December 31, 1994 and 1993, respectively, and is included under "Deferred Charges and Other Assets." The note receivable from a related party is at a floating market rate of interest and therefore, the carrying amount is a reasonable estimate of its fair value. The estimated values of the Company's long-term debt and mandatory redemption cumulative preferred stock are based on interest rates at December 31, 1994 and 1993, respectively, for new issues with similar remaining maturities. The fair market values of the Company's foreign currency swaps are based on the estimated termination values at December 31, 1994 and 1993, respectively.
6. Take-or-Pay Obligations
"Assets related to excess gas supply" consists of $90.8 million and $120.7 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.
Contract reformation costs incurred as a result of the mandated Order 636 restructuring will be recovered under the transition cost mechanisms of Order 636, as well as through negotiated agreements with the Company's 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 the Company. In the Company's experience, producers' claims are generally vastly overstated and do not consider all adjustments provided for in the contract or allowed by law. The Company has resolved the majority of the exposure with its suppliers for approximately 13% of the amounts claimed. At December 31, 1994, the Company estimated that unresolved asserted and unasserted producers' claims amounted to approximately $2 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 $21 million, $17 million and $10 million for each of the years 1995 through 1997, respectively, and $1 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.
7. Litigation, Environmental and Regulatory Matters
- - Litigation
Numerous lawsuits and other proceedings which have arisen in the ordinary course of business are pending or threatened against the Company or its subsidiaries. Although no assurances can be given and no determination can be made at this time as to the outcome of any particular lawsuit or proceeding, the Company believes there are meritorious defenses to substantially all such claims and that any liability which may finally be determined should not have a material adverse effect on the Company's consolidated financial position or results of operations.
- - Environmental
The Company's operations are subject to extensive and evolving federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction, operation and maintenance of its pipeline facilities. The Company anticipates annual capital expenditures of $2 million over the next several years aimed at maintaining compliance with such laws and regulations. Additionally, appropriate governmental authorities may enforce the laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act, also known as "Superfund," as reauthorized, imposes liability, without regard to fault or the legality of the original act, for disposal of a "hazardous substance." The Company has been named as a potentially responsible party in four federal "Superfund" waste disposal sites and one state "Superfund" site. At the four federal sites for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $31.6 million, the Company estimates its pro-rata exposure is approximately $.8 million. At the state site, the Company has been named a de minimis potentially responsible party. However, since the agency having jurisdiction over the site is currently unable to provide an estimate of the total clean-up costs, the Company is unable to calculate its 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.
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, consolidated financial position or results of operations.
- - Regulatory Matters
On March 10, 1992, the Company 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 the Company's implementation of Order 636 on November 1, 1993. Under the Interim Settlement, gas inventory demand charges were collected from the Company'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 the Company at risk for under-collections. As required by the Interim Settlement, the Company 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 the Company 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 April 8, 1992, the FERC issued Order 636, which required significant changes in the services provided by interstate natural gas pipelines. The Company and numerous other parties have sought judicial review of aspects of Order 636. The case is currently in the briefing phase before the United States Court of Appeals for the D.C. Circuit. ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. As a result, the Company no longer provides a merchant service and now offers a wide range of "unbundled" transportation, storage and balancing services. However, the Company still purchases a residual quantity of gas under certain remaining gas purchase contracts. The Company'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 the Company recovers through the auctioning of such gas on the open market in producing areas. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving the Company'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, the Company is now fully in compliance with Order 636 and the requirements of the orders on ANR Pipeline's restructuring filings. The FERC issued a further order regarding certain compliance issues on July 1, 1994. In accordance with this order, the Company filed revised tariff sheets on July 18, 1994.
On November 1, 1993, the Company filed a general rate increase with the FERC under Docket No. 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" ("FAS No. 106") and FAS No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS No. 112"). 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 the Company's approved rates for its restructured services under Order 636. On April 29, 1994, the Company 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 the Company'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. The Company 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 the Company 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 the Company'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 the Company and Dakota and terminates the transportation contract. The Settlement Agreement is subject to final FERC approval, including an approval for the Company to recover the settlement costs from its customers. On August 3, 1994, the Company 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 the Company'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. The
Company believes the ultimate resolution of the Dakota related issues will not have a material adverse impact on its consolidated financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated with compliance with that Order. The Company 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, the Company has incurred transition costs in the amount of $43 million. The Company 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, the Company 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 the Company in the future. As a result of the recovery mechanisms provided under Order 636, the Company anticipates that these transition costs will not have a material adverse effect on its consolidated financial position or results of operations.
Certain regulatory issues remain unresolved among the Company, its customers, its suppliers and the FERC. The Company has made provisions which represent management's assessment of the ultimate resolution of these issues. While the Company estimates the provisions to be adequate to cover potential adverse rulings on these and other issues, it cannot estimate when each of these issues will be resolved.
8. Lease Commitments
The Company is the lessee of eight storage fields under capital leases. The storage field leases were to expire on May 1, 1998. However, the Company has the option to extend each of the leases for up to three successive five-year periods. On April 27, 1993, the Company exercised the first of these three successive and separate options, extending the current storage field leases to May 1, 2003. The net present value of the future minimum lease payments is included as part of "Property, Plant and Equipment" in the Company's Consolidated Balance Sheet as follows (millions of dollars):
The annual provision for depreciation included as a part of depreciation expense was $3.0 million for 1994 and 1993, and $4.7 million for 1992.
Future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 1994 are as follows (millions of dollars):
Operating lease rentals included in operating expenses totaled $13.7 million for 1994, $16.2 million for 1993 and $16.4 million for 1992. Aggregate minimum lease payments under existing noncapitalized, long-term leases are approximately $14.0 million for each of the years 1995 through 1999, and $117.6 million thereafter.
9. Taxes On Income
Provisions for income taxes are composed of the following (millions of dollars):
Provisions for income taxes were different from the amount computed by applying the statutory U.S. federal income tax rate to earnings before tax. The reasons for these differences are (millions of dollars):
Deferred tax liabilities (assets) which are recognized for the estimated future tax effects attributable to temporary differences are (millions of dollars):
The Coastal consolidated federal income tax returns for the years 1985 through 1987 have been examined by the Internal Revenue Service. The examination did not result in any significant adjustments to the Company's portion of these returns. Examination of such consolidated federal income tax returns for 1988, 1989 and 1990 is currently in progress. It is the opinion of management that adequate provisions for federal income taxes have been reflected in the Company's consolidated financial statements.
10. Benefit Plans
The Company participates with its affiliates in the non-contributory pension plan of Coastal (the "Plan") which covers substantially all employees. The Plan provides benefits based on final average monthly compensation and years of service. As of December 31, 1994, the Plan did not have an unfunded accumulated benefit obligation. ANR Pipeline made no contributions to the Plan for 1994, 1993 or 1992. Assets of the Plan are not segregated or restricted by its participating subsidiaries and pension obligations for Company employees would remain the obligation of the Plan if the Company were to withdraw.
ANR Pipeline 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 $6.3 million, $5.9 million and $5.7 million for 1994, 1993 and 1992, respectively.
The Company provides certain health care and life insurance benefits for substantially all of its retired employees. Effective January 1, 1993, the Company adopted FAS No. 106, which requires the Company to accrue the estimated cost of retiree benefit payments during the years the employee provides services. The Company previously expensed the cost of these benefits, which are principally health care, as claims were incurred. FAS No. 106 allows recognition of the cumulative effect of the liability in the year of the adoption or the amortization of the obligation over a period of up to 20 years. The Company has elected to recognize the initial postretirement benefit obligation of approximately $62.7 million over a period of 20 years. In accordance with a FERC policy statement issued on December 17, 1992 (the "Policy Statement"), pipeline companies are allowed to defer the difference between the costs of postretirement benefits determined in accordance with FAS No. 106 and those costs currently recovered through their rates. The Company deferred such costs for the period January 1993 through April 1994 and began recovering them over a three-year period effective May 1, 1994, subject to FERC approval, pursuant to provisions of its November 1, 1993 general rate case filing. As of December 31, 1994, the unamortized balance of these deferred costs is $5.7 million. In addition, pursuant to the Policy Statement, the Company has funded approximately $13.7 million of FAS No. 106 costs through December 31, 1994.
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% in 1994, declining gradually to 6% by the year 2005. The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 16% in 1993. A one percentage point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 and the net postretirement health care cost by approximately 6%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 8.75%.
The Company adopted FAS No. 112, effective January 1, 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. As a result of adopting the provisions of FAS No. 112, the Company recognized an additional liability of $6.4 million, which has been deferred. Of these deferred costs, $3 million is currently being recovered over a three-year period pursuant to the Company's general rate case filing, effective May 1, 1994, subject to FERC approval. The Company will seek to recover the remaining deferred costs in future rate filings, as applicable.
11. Transactions with Major Customers and Related Parties
- - Major Customers:
The Statement of Consolidated Earnings includes revenues from major customers as follows (millions of dollars):
- - Related Parties:
"Operation and Maintenance" expenses within the Statement of Consolidated Earnings includes affiliate and other related party transactions as follows (millions of dollars):
Services provided by the Company at cost for affiliated companies were $9.9 million for 1994, $10.1 million for 1993 and $10.4 million for 1992. The services provided by the Company to affiliates, and by affiliates to the Company, primarily reflect the allocation of costs relating to the sharing of facilities and general and administrative functions, characteristic of group operations. Such costs are allocated using a three-factor formula consisting of revenues, property and payroll, which is reasonable and has been applied on a consistent basis.
The Company has lease agreements with Coastal and its affiliates for the rental of office space and certain pipeline facilities. One such lease with Coastal, for pipeline facilities, was terminated during 1994 in conjunction with the terms of the lease.
ANR Pipeline participates in a program which matches short-term cash excesses and requirements of participating affiliates, thus minimizing borrowings from outside sources. At December 31, 1994, the Company had advanced $235.2 million to an associated company at a market rate of interest. Such amount is repayable on demand.
12. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1994 and 1993 were (millions of dollars):
* The quarter ended September 30, 1994, has been restated to exclude transportation imbalance activity in the amount of $33.1 million from both "Revenues" and "Cost of gas." Such activity is now accounted for on a net basis.
EXHIBIT INDEX
Exhibit Number Document - ------ -------- (3.1)+ Composite Certificate of Incorporation of ANR Pipeline effective as of December 31, 1987 (Filed as Module ANRCertIncorp on March 29, 1994).
(3.2)* Amended By-laws of ANR Pipeline effective as of September 21, 1994.
(4) With respect to instruments defining the rights of holders of long-term debt, the Company will furnish to the Securities and Exchange Commission any such document on request.
(4.1)+ Board Resolution dated September 22, 1975 establishing the $2.675 Series of Cumulative Preferred Stock (Filed as Module BoardRes_092275 on March 29, 1994).
(4.2)+ Board Resolution dated October 26, 1976 establishing the $2.12 Series of Cumulative Preferred Stock (Filed as Module BoardRes_102676 on March 29, 1994).
(4.3)+ Board Resolution dated May 12, 1980 establishing the $12.00 Series of Cumulative Preferred Stock (Filed as Module BoardRes_051280 on March 29, 1994).
(4.4)+ Indenture dated as of February 15, 1994 and First Supplemental Indenture dated as of February 15, 1994 for the $125 million of 7-3/8% Debentures due February 15, 2024. (Filed as Exhibit 4.4 to ANR Pipeline's Annual Report on Form 10-K for the fiscal year ended December 31, 1993.)
(10.1)+ Form of Employment Agreement between ANR Pipeline and certain of its executive officers (Filed as a Module ANREmployAgree on March 29, 1994).
(10.2)+ Form of Employment Agreement between Coastal and certain Company executive officers (Filed as Module TCCEmployAgree on March 29, 1994).
(21)* Subsidiaries of the Company.
(23)* Consent of Deloitte & Touche LLP.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
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Note:
+ Indicates documents incorporated by reference from the prior filings indicated. * Indicates documents filed herewith.