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, 1993, the Company had 2,126 employees engaged in the operation of ANR Pipeline and 149 employees engaged in the operation of HIOS, UTOS and Empire.
NATURAL GAS SYSTEM
OPERATIONS
GENERAL
The Company is involved in the storage, transportation and balancing of natural gas. ANR Pipeline provides these services for various customers through its facilities located in Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Nebraska, New Jersey, Ohio, Oklahoma, Tennessee, Texas, Wisconsin, Wyoming and offshore in federal waters. Prior to November 1, 1993, 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 will auction gas on the open market as part of its gas restructuring program designed to handle the continuation of certain gas purchase contracts pending renegotiation or expiration of such contracts. The Company's gas sales for resale customers previously included 51 local distributors in Michigan, Wisconsin, Illinois, Indiana, Iowa, Kansas, Missouri, Ohio and Tennessee. The Company operates two major offshore gas pipeline systems in the Gulf of Mexico which are owned by HIOS and UTOS, general partnerships composed of ANR Pipeline subsidiaries and subsidiaries of other pipeline companies. The Company also operates Empire, a 156-mile pipeline extending from Niagara Falls to Syracuse, New York, in which an affiliate of the Company has a 45% interest.
During 1993, approximately 62% of the Company's gas supply was purchased from gas producers and marketers in Illinois, Indiana, Kansas, Louisiana, Michigan, Mississippi, Oklahoma, Texas, Wisconsin, Wyoming and the Texas and Louisiana offshore areas; approximately 32% was obtained from three Canadian suppliers; and approximately 6% was purchased from the Dakota Gasification Company in North Dakota.
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. Gas from Wyoming and Canada is obtained by the Company through transportation and exchange agreements with other companies.
The Company's principal pipeline facilities at December 31, 1993 consisted of 12,657 miles of pipeline and 97 compressor stations with 1,069,788 installed horsepower. At December 31, 1993, the design peak day delivery capacity of the transmission system, considering supply sources, storage, markets and transportation for others, was approximately 5.6 Bcf per day.
GAS SALES FOR RESALE AND TRANSPORTATION
ANR Pipeline transports gas to markets on its system and other markets under transportation and exchange arrangements with other companies, including distributors, intrastate and interstate pipelines, producers, brokers, marketers and end-users. Typically, these arrangements call for ANR Pipeline to transport such gas to points of interconnection with local distribution companies or other interstate pipelines. Transportation service revenues provided by ANR Pipeline amounted to $533 million for 1993 compared to $463 million for 1992 and $382 million for 1991.
During the period January through October of 1993, ANR Pipeline sold 228 Bcf of gas, of which approximately 71% was sold to its three largest customers: Michigan Consolidated Gas Company, Wisconsin Gas Company and Wisconsin Natural Gas Company. Michigan Consolidated Gas Company serves the City of Detroit and certain surrounding areas, the industrial cities of Grand Rapids and Muskegon, the communities of Ann Arbor and Ypsilanti and numerous other communities in Michigan. Wisconsin Gas Company serves the Milwaukee metropolitan area and numerous other communities in Wisconsin. Wisconsin Natural Gas Company serves the industrial cities of Racine, Kenosha, Appleton and their surrounding areas in Wisconsin. In 1993, ANR Pipeline provided 71% and 33% of the total gas requirements for Wisconsin and Michigan, respectively. Gas sales for resale by ANR Pipeline amounted to $604 million for 1993, compared to $635 million for 1992 and $641 million for 1991.
ANR Pipeline's deliveries for the years 1993, 1992 and 1991 are as follows:
On November 1, 1992, as part of its Interim Settlement, ANR Pipeline implemented a restructuring of its traditional sales service by replacing existing services with a combination of competitive service alternatives. This restructuring provided a number of options for pipeline customers and was designed to enhance competition in ANR Pipeline's service areas. Under this restructuring, the sales service was "unbundled" on an interim basis into firm sales, transportation, flexible storage and flexible delivery services. Prior to the restructuring, the cost of providing transportation services for sales customers was recovered as part of ANR Pipeline's total resale rate and therefore, was classified as part of gas sales revenue. Under the restructuring, these costs were recovered through a separate rate and were included in transportation revenue. Additional information concerning the restructuring is set forth in "Regulations Affecting Gas 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" storage, transportation and balancing service options. Additional information concerning Order 636, including transportation and storage, is set forth in "Regulations Affecting Gas System - General" included herein.
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 gas under a number of gas purchase contracts. The Company's Order 636 restructured tariff provides mechanisms for the purpose of recovering from or refunding to its customers any pricing differential between costs incurred to purchase this gas and the amount the Company recovers through auctioning of gas on the open market.
Of ANR Pipeline's gas purchases in 1993, approximately 62% was obtained directly from producers, including 17% from affiliates. In addition, ANR Pipeline received approximately 32% of its gas supply from Canadian suppliers and 6% from a producer of synthetic fuels. The border price of gas originating in Canada has been based on policies, established in 1984 by the NEB and the OFE, allowing exporters and importers to negotiate market-responsive prices.
Gas purchase contracts with producers generally provide for minimum purchase obligations based on estimated reserves under the well, the well's ability to produce or allowable gas takes set by state regulatory agencies. The prices paid depend upon, among other things, contractual requirements, market conditions, and the quality, condition of delivery and location of the gas. Under the NGWDA, effective July 26, 1989, all gas which would otherwise continue to be subject to price controls under the NGPA was deregulated over a three-year period and complete deregulation became effective January 1, 1993.
Some of ANR Pipeline's remaining gas purchase contracts with independent producers contain provisions which require taking minimum volumes and/or making prepayments for volumes not taken if purchases fall below specified levels during the contract year ("take-or-pay"). Additional information on take-or-pay matters is set forth in Note 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 proposed to the FERC to reclassify 62.1 Bcf of working gas to recoverable base gas. The Company also has the contract rights for 42 Bcf of storage capacity provided by Blue Lake Gas Storage Company, 30 Bcf of storage capacity provided by ANR Storage and 10 Bcf of storage capacity provided by Michigan Consolidated Gas Company. The contract with Michigan Consolidated Gas Company expires in March, 1994. Underground storage services of up to 166 Bcf of gas are provided by 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, 1993, 1992 and 1991 were 106.5 Bcf, 128 Bcf and 134 Bcf, respectively. The 1993 gas storage reserves are comprised of 19.4 Bcf of natural gas, maintained under the Company's own account as working gas for system balancing and no-notice storage services; 25 Bcf of recoverable base gas reserves in seven owned storage fields; and 62.1 Bcf of working gas which the Company has proposed to the FERC to reclassify as recoverable base gas. The decrease in the gas storage reserves between 1993 and 1992 reflects the Company's elimination of its merchant service. Effective November 1, 1993, Company storage reserves are solely used to facilitate the overall operations of the system.
COMPETITION
ANR Pipeline has historically competed with interstate pipeline companies in the sale, storage and transportation 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, which may result in reduced interruptible transportation revenue of pipelines. Additional information on this subject is included under "Regulations Affecting Gas System" included herein.
Natural gas competes with other forms of energy available to customers, primarily on the basis of price. These competitive forms of energy include electricity, coal, propane and fuel oils. Changes in the availability or price of natural gas or other forms of energy, as well as changes in business conditions, conservation, legislation or
governmental regulations, capability to convert to alternate fuels, changes in rate structure, taxes and other factors may affect the demand for natural gas in the areas served by ANR Pipeline.
ANR Pipeline's storage, transportation 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 storage, transportation and balancing business.
GAS SYSTEM RESERVES AND AVAILABILITY
With the termination of its merchant service, the Company no longer reports on gas system reserves and availability and, therefore, this report has been replaced by a general discussion set forth in "Supply Area Deliverability," presented below.
RECONCILIATION WITH FERC FORM 15 REPORT
The FERC Form 15 Annual Report of Gas Supplies is no longer required pursuant to FERC Order No. 554 issued July 13, 1993.
SUPPLY AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas supply areas in the United States, the Gulf Coast and Midcontinent. Statistics published by the Energy Information Agency, Office of Oil and Gas, U. S. Department of Energy, indicate that approximately 82% of all natural gas in the lower 48 states is produced from these two supply areas. Interconnecting pipelines provide shippers with access to all other major gas supply areas in the United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the Midcontinent and Gulf Coast supply areas through direct connections and interconnecting pipelines and gatherers is approximately 3,800 MMcf per day. An additional 275 MMcf per day of deliverability is accessible to shippers on Company-owned, or partially owned, pipeline segments not directly connected to a Company mainline.
The Company remains active in locating and connecting new gas supply sources to facilitate transportation arrangements made by third party shippers. During 1993, field development, newly connected supply sources and pipeline interconnections contributed 515 MMcf per day to total deliverability accessible to shippers on ANR Pipeline.
REGULATIONS AFFECTING GAS SYSTEM
GENERAL
Under the NGA, the FERC has jurisdiction over ANR Pipeline as to sales, storage, transportation 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. The OFE regulates the price and other terms of imports of natural gas.
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. ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. The Company now offers a wide range of "unbundled" storage, transportation and balancing services. Several persons, including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving the Company's restructuring filings. Order 636 also provides mechanisms for recovery of transition costs associated with compliance with that Order. These transition costs include gas supply realignment costs, the cost of stranded pipeline investment and the cost of new facilities required to implement Order 636. The Company expects that it will incur transition costs of approximately $150 million. As a result of the recovery mechanisms provided under Order 636, the Company anticipates that these transition costs will not have a material adverse effect on its consolidated financial position or its results of operations.
RATE MATTERS
All of the Company's 1993 service options were subject to rate regulation by the FERC. Under the NGA, ANR Pipeline must file with the FERC to establish or adjust its service rates. The FERC may also initiate proceedings to determine whether 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 involved, inter alia, an array of new sales, delivery, transportation and storage service alternatives and the implementation of a GIC, designed to compensate the Company for the costs of standing ready to serve its sales customers. The Interim Settlement reflected a decrease in cost of service of approximately $45 million, which was largely attributable to a reduction in depreciation rates from 3.4% to 1.82%. Also included was a provision which allowed the Company to direct bill its customers for its remaining unrecovered purchased gas costs. The Interim Settlement became effective November 1, 1992 and expired with the Company's implementation of Order 636 on November 1, 1993. Specific provisions of the Interim Settlement relating to the deferral and future recovery of certain costs remain in effect.
On December 17, 1992, the FERC issued a policy statement that outlined changes on how pipelines may recover the costs of employees' postretirement benefits other than pensions. The FERC's policy will be to recognize, as a component of jurisdictional cost-based rates, allowances for FAS No. 106 costs of company employees when determined on an accrual basis, provided certain conditions are met.
On November 1, 1993, the Company filed a general rate increase with the FERC. The proposed rates reflect a $121 million increase in the Company's cost of service from that approved in the Interim Settlement and a $218 million increase over the Company's approved rates for its restructured services. The increase represents higher plant investment, Order 636 restructuring costs, rate of return and tax rate changes and increased costs related to the required adoption of recent accounting rule changes, i.e., FAS Nos. 106 and 112 (see Note 10 of Notes to Consolidated Financial Statements for a discussion of FAS Nos. 106 and 112). The FERC has permitted the Company to place its new rates into effect on May 1, 1994, subject to refund and subject to certain required compliance changes and the outcome of an evidentiary hearing on all remaining issues.
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
Information concerning 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
The Empire State Pipeline Project, in which an affiliate of the Company has a 45% interest and the Company is the operator, was placed in service on November 1, 1993. The 156-mile pipeline system, extending from Niagara Falls to Syracuse, New York, will carry up to 570 MMcf per day to western and central New York State and provide the Company access to markets in the Northeastern United States.
In August 1993, the Company and Arkla, Inc. ("Arkla") announced execution of a restructured agreement under which the Company will purchase an ownership interest in 250 MMcf per day of capacity in existing natural gas transmission facilities from Arkla. The restructured agreement resolved certain conditions imposed by the FERC in its October 1, 1992 authorization of the original purchase and sale agreement. Financing for this acquisition will be provided from internally generated funds. The capital expenditure of approximately $90 million is expected to be incurred in 1994, after FERC approval is received. The reduction in value of the facilities from the original purchase and sale agreement is the result of negotiations between the Company and Arkla in light of the FERC's orders.
The Company is a partner in the SunShine Pipeline Project which is designed to capture a share of the growing Florida power generation market, as well as markets located in Mississippi, Alabama and the Florida Panhandle. SunShine Interstate Transmission Company ("SITCO"), the interstate pipeline segments of this project, will extend 170 miles from Pascagoula, Mississippi to Okaloosa, Florida where it will connect with Sunshine Pipeline Company, ("SunShine") the intrastate segment of this project. SunShine will be a 545-mile pipeline starting in Okaloosa and extending down Florida's west coast to the Tampa area. The Company, through a wholly-owned subsidiary, will have a 40% interest in SITCO and an affiliate of the Company will have a 40% interest in SunShine. Florida Power Corporation and TransCanada will both hold a 30% equity interest in each of the two projects. SITCO will have an initial capacity of 329.5 MMcf per day and SunShine will have an initial capacity of 249.5 MMcf per day. Both SITCO and SunShine have signed precedent agreements for a portion of their initial pipeline capacity. SITCO, which will be subject to FERC jurisdiction, has filed with the FERC to obtain a Certificate of Public Convenience and Necessity. FERC approval is expected in March 1995. SunShine, which will be subject to the jurisdiction of the Florida Public Service Commission ("FPSC"), has received approval of its request for a Determination of Need from the FPSC. SunShine also expects environmental approval, in early 1995, under the procedures set forth in Florida's Natural Gas Transmission Pipeline Siting Act. Both projects are targeted to be placed into service in December 1995. The SITCO pipeline is expected to cost $188 million, with the Company's share of this cost approximating $75 million.
A subsidiary of the Company will have a 25% equity interest in the proposed Liberty Pipeline project, a 38-mile pipeline extending from New Jersey across New York Harbor to Long Island with a potential capacity of 500 MMcf per day. The pipeline is expected to serve local distribution company participants and independent power producers. A filing to obtain a Certificate of Public Convenience and Necessity has been made and is currently pending before the FERC. Subject to receiving applicable government approvals, an in-service date of late 1995 is possible, at an estimated cost of $160 million.
The Company (20% equity interest) and Interprovincial Pipe Line System Inc. plan to participate in the construction of InterCoastal Pipe Line, a project designed to serve incremental markets in southern Ontario and potentially Quebec and the Northeastern United States. The project will involve converting approximately 130 miles of existing oil pipeline to natural gas service, originating in Sarnia, Ontario and extending to Toronto, and the construction of approximately 25 miles of new pipeline. In connection with the project, facilities in Michigan will be constructed by the Company to deliver gas from domestic sources. The project, which will have a maximum capacity of 175 MMcf per day, is projected to cost $37.6 million. The InterCoastal Pipe Line is subject to regulatory approval in Canada, and the ANR Pipeline facilities are subject to regulatory approvals in the United States. Filings seeking necessary authorizations from the NEB were made in the second quarter of 1993, and with the FERC on July 19, 1993. The project could be in service as early as November 1, 1994.
A subsidiary of the Company and affiliates of TransCanada and Brooklyn Union Gas Company have entered into a partnership agreement for the construction of the Mayflower Pipeline, which is expected to expand natural gas transportation, sales and storage services to markets in the Northeastern United States. The Company will have a 45% interest in this project. The proposed 240-mile pipeline will extend east from the Iroquois Gas Transmission System at Canajoharie, New York to a location near Boston, Massachusetts and have an initial design capacity of 350 MMcf per day. The total project cost is expected to be $540 million. The pipeline is expected to be in service in late 1997. Construction of the project is subject to receipt of all federal regulatory approvals.
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 are subject to the lien of its Mortgage and Deed of Trust dated as of September 1, 1948, securing its First Mortgage Pipe Line Bonds, and some of such properties are subject to "permitted liens" as defined in such Mortgage and Deed of Trust. The First Mortgage Pipe Line Bonds were retired in 1993 and the Company is in the process of terminating the associated Mortgage and Deed of Trust.
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. 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 $454 million was available at December 31, 1993 for payment of dividends on the Company's common and preferred stock. In March 1994, the Company paid a $255 million dividend on its common stock, which leaves approximately $199 million of dividend capacity.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial data (in millions of dollars) is derived from the Consolidated Financial Statements included herein and Item 6 of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1992. The Notes to Consolidated Financial Statements included herein contain information relating to this data.
- ------------ (1) Includes unamortized investment tax credit, consistent with ratemaking treatment. (2) See Item 5 above for a discussion concerning a 1994 common stock dividend payment.
All of the outstanding common stock of ANR Pipeline is owned by ANR; therefore, earnings and cash dividends per common share have no significance and are not presented.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The Management's Discussion and Analysis of Financial Condition and Results of Operations is presented on pages through herein.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Financial Statements and Supplementary Data required hereunder are included in this Annual Report as set forth in Item 14(a) herein.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The directors and executive officers of ANR Pipeline as of March 22, 1994, 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 1994. 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. Hitchcock was elected a Senior Vice President of ANR Pipeline in March 1994. He previously served as a Vice President of Northern Indiana Public Service Company, where he had been employed since 1990. From 1984 to 1990, he was employed by Natural Gas Pipeline Company in various positions.
Ms. Prairie was elected a Senior Vice President in March 1994. She had been a Vice President of ANR Pipeline since October 1989. Prior to that time she was an Executive Director of Gas Supply for Michigan Consolidated Gas Company from October 1987 to October 1989. She was an attorney for the law firm of John, Hengerer & Esposito in Washington, D.C. from October 1986 to August 1987 and an attorney for Michigan Consolidated Gas Company from January 1985 to September 1986.
Mr. Anger was elected a Vice President of ANR Pipeline in July 1990. From October 1987 to 1989, he was an independent consultant to Coastal. Prior thereto he worked in the Federal Affairs department of Coastal.
Mr. Johnson was elected a Vice President and Controller of ANR Pipeline in August 1991. Prior thereto he was employed by Great Lakes Gas Transmission Company from 1982 until 1991. He became an Assistant Controller for Great Lakes in 1987 and served as their Controller from 1989 to 1991.
Mr. Leehr was elected a Vice President of ANR Pipeline in July 1991. Prior thereto he held various positions with ANR Pipeline.
Mr. Marantette was elected a Vice President of ANR Pipeline in May 1992. He has held various positions with other subsidiaries of ANR, including President of ANR Development Corporation since 1985.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
ANR Pipeline is an indirectly 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, 1993, 1992 and 1991 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 most highly compensated executive officers other than the CEO (the "Named Executive Officers"). The table also sets forth the cash compensation paid to James R. Paul, CEO through July 20, 1993, including Long Term Incentive Plan ("LTIP") cash compensation.
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) 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.
(3) The bonuses shown in the table represent the amount awarded for performance in the year indicated. With the exception of Mr. Burrow, bonuses for 1993 will not be finalized until after preliminary results for the 1994 first quarter are known. These bonuses will be reported in the Coastal Proxy Statement for the 1995 Annual Meeting. Mr. Burrow's bonus was paid in full in 1993. Bonuses for 1992 were paid or are payable in equal installments over a three-year period, provided the employee is still employed on the anniversary date of the award. The 1991 bonuses were payable in equal installments in 1992 and 1993.
(4) The options do not carry any stock appreciation rights.
(5) All Other Compensation for 1993 consists of: (i) directors' fees paid by Coastal, ANR and Colorado (O. S. Wyatt, Jr. $66,375; David A. Arledge $18,000; James R. Paul $51,625; James F. Cordes $66,375; Sam F. Willson, Jr. $-0-; and Harold Burrow $56,624); (ii) cash payments for relinquishing certain stock appreciation rights (O. S. Wyatt, Jr. $ -0-; David A. Arledge $5,625; James R. Paul $9,375; James F. Cordes $3,750; Sam F. Willson, Jr. $1,875; and Harold Burrow $-0-); (iii) Coastal contributions to the Coastal Thrift Plan (O. S. Wyatt, Jr. $15,000; David A. Arledge $15,000; James R. Paul $15,000; James F. Cordes $15,000; Sam F. Willson, Jr. $15,000; and Harold Burrow $15,000); and (iv) certain payments in lieu of Thrift Plan contributions (O. S. Wyatt, Jr. $56,690; David A. Arledge $21,417; James R. Paul $-0-; James F. Cordes $29,664; Sam F. Willson, Jr. $11,725; and Harold Burrow $8,409).
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
The following table sets forth information with respect to stock options granted on November 4, 1993 and December 8, 1993 for the fiscal year ended December 31, 1993 to the Named Executive Officers.
OPTION/SAR GRANTS IN LAST FISCAL YEAR (1993)
- ------------------ (1) Options expire ten years from the date of issuance and are granted at the fair market value of the Common Stock of Coastal on the date of grant. Options granted on November 4, 1993 vested in full immediately. Options granted on December 8, 1993, vest in full on the second anniversary of the date of grant.
(2) Granted November 4, 1993 as a one-time grant for relinquishment of directors fees.
(3) Granted December 8, 1993.
(4) The options do not carry any stock appreciation rights. The option information included in the table does not include grants made on March 4, 1993 for the fiscal year ended December 31, 1992 which (except for Mr. Willson) were reported in the Coastal 1993 Proxy Statement. These grants were at $26.06 per share as follows: O. S. Wyatt, Jr. -0-; David A. Arledge 35,000 shares; James R. Paul 40,000 shares; James F. Cordes 25,000 shares; Sam F. Willson, Jr. 15,000 shares; and Harold Burrow -0-.
(5) Based on the Black-Scholes option pricing model expressed as a ratio (.425 for options granted on November 4, 1993; .399 for options granted on December 8, 1993) x exercise price x number of shares. The actual value, if any, an executive may realize will depend on the excess of the stock price over the exercise price on the date the option is exercised, so that there is no assurance the value realized by an executive will be at or near the value estimated by the Black-Scholes model. The estimated values under that model are based on assumptions that include (i) a stock price volatility of .2786, calculated using monthly stock prices for the three years prior to the grant date, (ii) an interest rate of 6.10%, (iii) a dividend yield of 1.44% and (iv) an option exercise term of ten years. No adjustments were made for the non-transferability of the options or to reflect any risk of forfeiture prior to vesting. The Securities and Exchange Commission requires disclosure of the potential realizable value or present value of each grant. The Company's use of the Black-Scholes model to indicate the present value of each grant is not an endorsement of this valuation, which is based on certain assumptions, including the assumption that the option will be held for the full ten-year term prior to exercise. Studies conducted by the Company's independent consultants indicate that options are usually exercised before the end of the full ten-year term.
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, 1993.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES (1993)
- ------------------ (1) $-based on the market price of $28.00 at December 31, 1993.
PENSION PLAN
The following table shows for illustration purposes the estimated annual benefits payable 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 $235,840 for 1993.
(B) At December 31, 1993 each of the individuals named in the Summary Compensation Table had covered salary of $235,840 and the following years of credited service: Mr. Wyatt, 38 years; Mr. Arledge, 13 years; Mr. Paul, 20 years; Mr. Cordes, 16 years; Mr. Willson, 21 years; and Mr. Burrow, 19 years.
(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.
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 16, 1994, 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 indirectly, wholly-owned subsidiary of Coastal. Information concerning the security ownership of certain beneficial owners and management of Coastal is contained in this section.
The total number of shares of stock of Coastal outstanding as of March 16, 1994 is 112,832,796: consisting of 64,403 shares of $1.19 Cumulative Convertible Preferred Stock, Series A (the "Series A Preferred Stock"), 87,398 shares of $1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred Stock"), 35,252 shares of $5.00 Cumulative Convertible Preferred Stock, Series C (the "Series C Preferred Stock"), and 8,000,000 non-voting shares of $2.125 Cumulative Preferred Stock, Series H (the "Series H Preferred Stock"), 104,218,335 shares of Common Stock, and 427,408 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 16, 1994, 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 969 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 16, 1994, regarding each of the then current directors, including Class II 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. As of such date, Messrs. Bissell, Burrow, Chapin, Cordes, Gates and Katzin were the Class I directors whose terms expire in 1996; Messrs. Arledge, Brundrett, Wooddy and Wyatt were the Class II directors whose terms expire in 1994; and Messrs. Buck, Johnson, Marshall and McDade were the 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 187,501 shares of Class A Common Stock, which would constitute 43.9% 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 plans, and presently exercisable stock options held by Messrs. Burrow (14,189 shares of Common Stock), Arledge (140,960 shares of Common Stock and 13,412 shares of Class A Common Stock), Cordes (89,786 shares of Common Stock), and Johnson (60,415 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 629,038 shares of Common Stock and 14,628 shares of Class A Common Stock; also includes 280,239 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 Boards of Directors of Comerica Inc. and Royal Group, 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. Prior to forming McDade & Fogler he was a senior partner in the Houston law firm of Fulbright & Jaworski.
Messrs. Arledge, Burrow, Cordes and Wyatt are directors of Colorado. Mr. Cordes is a director of ANR Pipeline. Both of these subsidiaries of Coastal are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act").
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, 1993, the Company had advanced $285.5 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.
The following schedules of ANR Pipeline and Subsidiaries are included on the attached pages as indicated:
Schedules other than those referred to above are omitted as not applicable or not required, or the required information is shown in the Consolidated Financial Statements or Notes thereto.
3. Exhibits.
- -----------
Note:
+ Indicates documents incorporated by reference from the prior 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, 1993.
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: /s/ JAMES F. CORDES ------------------------- James F. Cordes Chairman and Chief Executive Officer March 29, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
By: /s/ JAMES F. CORDES By: /s/ DANIEL F. COLLINS ------------------------- ------------------------- James F. Cordes Daniel F. Collins Chairman and Chief Director Executive Officer March 29, 1994 March 29, 1994
By: /s/ DAVID A. ARLEDGE By: /s/ JEFFREY A. CONNELLY ------------------------- ------------------------- David A. Arledge Jeffrey A. Connelly Principal Financial Officer Director March 29, 1994 March 29, 1994
By: /s/ WILLIAM L. JOHNSON By: /s/ AUSTIN M. O'TOOLE ------------------------- ------------------------- William L. Johnson Austin M. O'Toole Principal Accounting Officer Director March 29, 1994 March 29, 1994
* * *
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is pertinent to the following analysis.
LIQUIDITY AND CAPITAL RESOURCES
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. However, in 1991 the Company completed a public offering of $300 million principal amount of 9-5/8% Debentures due November 1, 2021. Approximately $238 million of the net proceeds were used to repay long-term indebtedness and current maturities on long-term indebtedness of the Company with the balance used for capital expenditures and other general corporate purposes. The repayment of long-term indebtedness included the early retirement of a $200 million note which was due to mature in 1993.
During 1993 the Company retired $78.1 million of its long-term debt obligations, of which $47.4 million represented early redemptions. Interest rates associated with the early redemptions ranged from 9-5/8% to 13-1/4%, which are significantly higher than current market rates. Of the $47.4 million of early redemptions, $37.7 million represents First Mortgage Pipe Line Bonds, with the remaining amount representing Debentures.
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 dividends.
In March 1994, the Company paid a $255 million dividend on its common stock.
The Company uses the following consolidated ratios to measure liquidity and ability to meet future funding needs and debt service requirements.
The 1993 decrease in the cash flow from operating activities to long-term debt resulted from lower rates associated with the settlement of the Company's 1989 rate case, partially offset by a decrease in long-term debt. The 1992 decrease can be attributed to higher operating expenses and costs related to the settlement of the Company's 1989 rate case. The decreases in 1993 and 1992 in long-term debt and capital leases 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 1991 through 1993 and the sources of capital used to finance these expenditures are summarized in the "Statement of Consolidated Cash Flows."
CONSTRUCTION. Construction additions were $118.9 million in 1992 and $58.2 million in 1993. Capital expenditures for 1994, including the Company's equity investments in partnerships and joint ventures, are currently
budgeted at approximately $138 million. Included in these expenditures is approximately $90 million related to the acquisition of an ownership interest in existing natural gas transmission facilities.
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. 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 1994 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."
INVESTMENT IN STORAGE GAS. In 1993, storage gas inventories decreased by $79.1 million as compared to 1992 year end levels and increased by $30.9 million in 1992 as compared to 1991 year end levels. The decrease in 1993 is attributable to the Company's implementation of Order 636 and the fact that, effective November 1, 1993, the Company no longer provides a merchant service, which previously required an ongoing investment in working storage gas. In contrast, the increase in 1992 compared to 1991 is due to an increase in the average cost of gas.
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. In 1993, "Assets related to excess gas supply" decreased by $82.6 million. The decline is attributable to the recovery of producer contract reformation costs pursuant to FERC Order No. 528 and a significant first quarter cash recovery of a prepayment for gas under a purchase contract with a producer.
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, 1993, ANR Pipeline and certain affiliates could incur in the aggregate approximately $917 million of additional indebtedness. For the Company and these affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $400 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 borrowings from outside sources. At December 31, 1993, the Company had advanced $285.5 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 federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction and maintenance of its pipeline facilities. 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 two "Superfund" waste disposal sites. At one site for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $1.8 million, the Company estimates its pro-rata exposure is less than $50,000. At the other site, the EPA is currently unable to provide the Company with an estimate of total clean-up costs and, accordingly, the Company is unable to calculate its share of those costs.
There are additional areas of environmental remediation responsibilities which may fall on the Company. Future information and developments will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently
available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's liquidity or financial position.
RESULTS OF OPERATIONS
REVENUES. 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. Revenue recovered under this separate "bundled" service amounted to $153.1 million and $29.3 million in 1993 and 1992, respectively.
In the fourth quarter of 1993, the Company implemented its Order 636 restructuring (see Note 7 of Notes to Consolidated Financial Statements), and now offers an array of "unbundled" storage, transportation and balancing service options. Under Order 636, the Company no longer offers a merchant service. Former gas sales customers of the Company have largely retained their firm storage and transportation service levels previously included in their "bundled" gas sales services. Consequently, while operating revenues will be reduced as a result of the implementation of Order 636, purchases and other related costs will be reduced by a similar amount.
Gas sales revenues decreased by $31 million in 1993 as compared to 1992 primarily as a result of the sales service restructuring mentioned above and rate decreases associated with gas pricing. These decreases 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.
Gas sales revenues decreased by $6.7 million in 1992 in comparison to 1991 primarily as a result of the Company's restructuring of its sales service, as mentioned above. Offsetting this decrease was a change in the provision for rate-related contingencies associated with the settlement of the Company's 1989 rate case.
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 mentioned 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, and a change in the provision for rate-related contingencies associated with the settlement of the Company's 1989 rate case.
Storage and transportation revenues increased by 21% in 1992 as compared to 1991. The factors contributing to the additional revenue for 1992 were the addition of 25.8 Bcf of new firm storage and firm transportation services contracted for the 1992/1993 heating season, the recognition of $29.3 million of transportation revenue due to the sales service restructuring described previously and a change in the provision for rate-related contingencies associated with the settlement of the Company's 1989 rate case.
Other revenues increased in 1993 as compared to 1992 primarily because of increased revenue from investments in pipeline partnerships and an increase in interest income for 1993. Other revenues decreased in 1992 in comparison to 1991 because of a decrease in interest income for 1992 partially offset by an increase in revenues from investments in pipeline partnerships.
COST OF GAS SOLD. As a result of the implementation of Order 636, as discussed above, 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 reassigned. ANR Pipeline is continuing to negotiate the permanent release from a number of gas
purchase contract obligations which still exist. The Company believes it will recover any costs associated with the resolution of these negotiations with no significant adverse financial impact. For additional information concerning the recovery of transition costs resulting from the implementation of Order 636, see Note 7 of Notes to Consolidated Financial Statements included herein.
Cost of gas sold 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 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. The average unit cost of gas charged to operations was $2.31 per Mcf in 1993 as compared to $2.86 per Mcf in 1992 and $2.89 in 1991.
OPERATION AND MAINTENANCE. Operation and maintenance expenses for 1993 approximated those of 1992, although the following fluctuations were noted. Transmission and compression expenses 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 an adjustment in 1993 to the estimated costs recorded in 1992 related to the settlement of the Company's 1989 rate case, the Interim Settlement, and provisions for unrecoverable producer contract reformation costs.
Operation and maintenance expense increased by $83.5 million in 1992 as compared to 1991 primarily due to increased costs for transmission and compression of gas by others, higher compressor station expenses associated with compressor fuel and costs related to the settlement of the Company's 1989 rate case and the Interim Settlement previously described in Item 1, "Business, Regulations Affecting Gas System - Rate Matters."
DEPRECIATION. The decrease in depreciation expense of $44.1 million in 1993 as compared to 1992 and $5.2 million in 1992 as compared to 1991, is 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 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. Interest expense decreased by $2.9 million in 1992 when compared to 1991 primarily as a result of changes in provisions for rate refunds partially offset by higher average outstanding long-term debt at a higher effective rate of interest.
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 PRONOUNCEMENTS
In 1993, the Company adopted a change in accounting for postretirement benefits as required by FAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."
In 1994, the Company adopted FAS No. 112, "Employers' Accounting for Postemployment Benefits." This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The $3 million estimated earnings impact of adopting FAS No. 112 will be deferred, as the Company has included such costs in its November 1, 1993 general rate case application with the FERC.
See Note 10 of Notes to Consolidated Financial Statements included herein for a discussion of these items.
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders 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, 1993 and 1992, and the related consolidated statements of earnings, retained earnings and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 14(a)2. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ANR Pipeline Company and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 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
Detroit, Michigan February 3, 1994
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. Certain reclassifications of prior period statements have been made to conform with current reporting practices. The effect of the reclassifications was not material to the Company's results of operations or financial position.
The Company is regulated by and subject to the regulations and accounting procedures of the FERC. In addition, the Company meets the criteria and, accordingly, follows the accounting and reporting requirements of FAS No. 71 for regulated enterprises.
- - Principles of Consolidation
The Consolidated Financial Statements include the accounts of the Company and its subsidiaries after eliminating all significant intercompany transactions. The equity method of accounting is used for 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.
- - Gas in Underground Storage
Gas in underground storage at December 31, 1993 includes $161.5 million, pending approval by the FERC, which is to be transferred to Property, Plant and Equipment for regulatory and accounting purposes.
- - 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 1993, 1992 and 1991 were approximately 1.6%, 3.1% and 3.4%, respectively.
- - 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
The Company made cash payments for interest, net of interest capitalized, of $53.0 million, $68.3 million and $54.8 million in 1993, 1992 and 1991, respectively. Cash payments for income taxes amounted to $103.2 million, $104.1 million and $78.5 million in 1993, 1992 and 1991, 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 $1.5 million, $3.9 million and $4.5 million in 1993, 1992 and 1991, respectively.
- - 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 $454 million was available at December 31, 1993 for payment of dividends on the Company's common and preferred stock. In March 1994, the Company paid a $255 million dividend on its common stock, which leaves approximately $199 million of dividend capacity.
3. Mandatory Redemption Cumulative Preferred Stock
The following information relates to the preferred stock outstanding at December 31, 1993:
Mandatory sinking fund requirements yet to be met during the succeeding five years aggregate $7.7 million for each of the years 1994 and 1995, $5.1 million for 1996, $3.1 million for 1997 and $2.5 million for 1998.
The holders of preferred stock are not entitled to vote unless four quarterly dividend payments are in arrears.
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 swap, the Company would have no exposure to credit loss.
Gas properties were pledged as security for the above listed First Mortgage Pipe Line Bonds. Such bonds have been retired and the Company is in the process of terminating the associated Mortgage and Deed of Trust.
Maturities and sinking fund requirements of the long-term debt during the succeeding five years are as follows (millions of dollars):
In February 1994, the Company completed a public offering of $125 million of 7-3/8% Debentures due in 2024. The net proceeds from the sale were used for capital expenditures and for other general corporate purposes, including the payment of dividends.
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, 1993, ANR Pipeline and certain affiliates could incur in the aggregate approximately $917 million of additional indebtedness. For the Company and these affiliates to incur indebtedness for borrowed money in excess of this amount, approximately $400 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 an affiliate is based on the market quote at December 31, 1993 and is included under Deferred Charges and Other Assets. The note receivable from affiliate and the deferred gas cost receivable are at floating market rates of interest and therefore, the carrying amounts are reasonable estimates of their fair value. The estimated values of the Company's long-term debt and mandatory redemption preferred stock are based on interest rates at December 31, 1993 and 1992, 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, 1993 and 1992, respectively.
6. Take-or-Pay Obligations
"Assets related to excess gas supply" consists of $120.7 million and $203.3 million at December 31, 1993 and 1992, respectively, relating to prepayments for gas under gas purchase contracts with producers and settlement payment amounts relative to the restructuring of gas purchase contracts as negotiated with producers. Currently, FERC regulations allow for the billing of a portion of the costs of take-or-pay settlements and renegotiating gas purchase contracts. Prepayments are normally recoupable through future deliveries of natural gas.
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. 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, 1993, the Company estimated that unresolved asserted and unasserted producers' claims amounted to approximately $8 million. The remaining disputes will be settled where possible and litigated if settlement is not possible.
At December 31, 1993, the Company was committed to make future purchases under certain take-or-pay contracts with fixed, minimum or escalating price provisions. Based on contracts in effect at that date, and before considering reductions provided in the contracts or applicable law, such commitments are estimated to be $37 million, $29 million, $22 million, $14 million and $3 million for the years 1994-1998, respectively, and $4 million thereafter.
Such commitments have also not been adjusted for all amounts which may be assigned or released, or for the results of future litigation or negotiation with producers.
The Company has made provisions, which it believes are adequate, for payments to producers that may be required for settlement of take-or-pay claims and restructuring of future contractual commitments. In determining the net loss relating to such provisions, the Company has also made accruals for the estimated portion of such payments which would be recoverable pursuant to FERC- approved settlements with customers.
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.
- - Environmental
The Company's operations are subject to extensive federal, state and local environmental laws and regulations which may affect such operations and costs as a result of their effect on the construction and maintenance of its pipeline facilities. 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 two "Superfund" waste disposal sites. At one site for which the EPA has developed sufficient information to estimate total clean-up costs of approximately $1.8 million, the Company estimates its pro-rata exposure is less than $50,000. At the other site, the EPA is currently unable to provide the Company with an estimate of total clean-up costs and, accordingly, the Company is unable to calculate its share of those costs.
There are additional areas of environmental remediation responsibilities which may fall on the Company. Future information and developments will require the Company to continually reassess the expected impact of these environmental matters. However, the Company has evaluated its total environmental exposure based on currently available data, including its potential joint and several liability, and believes that compliance with all applicable laws and regulations will not have a material adverse impact on the Company's liquidity or financial position.
- - 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 involved, inter alia, an array of new sales, delivery, transportation and storage service alternatives and the implementation of a GIC, designed to compensate the Company for the costs of standing ready to serve its sales customers. The Interim Settlement reflected a decrease in cost of service of approximately $45 million, which was largely attributable to a reduction in depreciation rates from 3.4% to 1.82%. Also included was a provision which allowed the Company to direct bill its customers for its remaining unrecovered purchased gas costs. The Interim Settlement became effective November 1, 1992 and expired with the Company's implementation of Order 636 on November 1, 1993. Specific provisions of the Interim Settlement relating to the deferral and future recovery of certain costs remain in effect.
On 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. ANR Pipeline placed its restructured services under Order 636 into effect on November 1, 1993. The Company now offers a wide range of "unbundled" storage, transportation and balancing services. Several persons,
including ANR Pipeline, have sought judicial review of aspects of the FERC's orders approving the Company's restructuring filings. Order 636 also provides mechanisms for recovery of transition costs associated with compliance with that Order. These transition costs include gas supply realignment costs, the cost of stranded pipeline investment and the cost of new facilities required to implement Order 636. The Company expects that it will incur transition costs of approximately $150 million. As a result of the recovery mechanisms provided under Order 636, the Company anticipates that these transition costs will not have a material adverse effect on its financial position or its results of operations.
On December 17, 1992, the FERC issued a policy statement that outlined changes on how pipelines may recover the costs of employees' postretirement benefits other than pensions. The FERC's policy will be to recognize, as a component of jurisdictional cost-based rates, allowances for FAS No. 106 costs of company employees when determined on an accrual basis, provided certain conditions are met.
On November 1, 1993, the Company filed a general rate increase with the FERC. The proposed rates reflect a $121 million increase in the Company's cost of service from that approved in the Interim Settlement and a $218 million increase over the Company's approved rates for its restructured services. The increase represents higher plant investment, Order 636 restructuring costs, rate of return and tax rate changes and increased costs related to the required adoption of recent accounting rule changes, i.e., FAS Nos. 106 and 112. The FERC has permitted the Company to place its new rates into effect on May 1, 1994, subject to refund and subject to certain required compliance changes and the outcome of an evidentiary hearing on all remaining issues.
Certain regulatory issues remain unresolved among the Company, its customers, its suppliers and the FERC. The Company has made provisions which represent management's assessment of the ultimate resolution of these issues. While the Company estimates the provisions to be adequate to cover potential adverse rulings on these and other issues, it cannot estimate when each of these issues will be resolved.
Gas Costs
As part of the Company's Interim Settlement, the Company received the authorization to refund or direct bill its former gas sales customers for the outstanding amount of its deferred purchased gas costs as of October 31, 1992, up to $72 million. The Company is also authorized to direct bill its former gas sales customers for costs incurred to resolve billing disputes with its producers up to an amount not to exceed $25 million. The Company began billing for recovery of these costs in January 1993. The customers have up to five years to pay on these billings. Interest will be accrued on any unpaid amounts.
Also, as part of the Company's Interim Settlement, a new demand-commodity form of gas pricing replaced the purchased gas adjustment provision of the Company's tariff. This new form of gas pricing included a cost-based GIC that firm sales customers were obligated to pay for the right to purchase gas, and a gas commodity charge which was capped by reference to a spot price index for gas purchased. This method of gas cost recovery requires refund of over-collections, and placed the Company at risk for under-collection, and expired under the terms of the Interim Settlement on November 1, 1993. As required by the Interim Settlement, the Company will file with the FERC in 1994 for approval of the amount to be refunded.
Effective with the implementation of Order 636 on November 1, 1993, the Company no longer provides a merchant service. However, the Company still purchases gas under a number of gas purchase contracts. The Company's Order 636 restructured tariff provides mechanisms for the purpose of recovering from or refunding to its customers any pricing differential between costs incurred to purchase this gas and the amount the Company recovers through auctioning of gas on the open market.
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, $4.7 million and $4.9 million for 1993, 1992 and 1991, respectively.
Future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of December 31, 1993 are as follows (millions of dollars):
Operating lease rentals included in operating expenses totaled $16.2 million for 1993, $16.4 million for 1992 and $18.3 million for 1991. Aggregate minimum lease payments under existing noncapitalized long-term leases are estimated to be $12.8 million, $11.7 million, $11.7 million, $11.7 million and $11.6 million for the years 1994-1998, respectively, and $121.2 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 and carryforwards are (millions of dollars):
The Omnibus Budget Reconciliation Act of 1993 enacted in August 1993 included, among other things, an increase in the corporate federal income tax rate from 34% to 35% retroactive to January 1, 1993. The cumulative impact of the tax rate increase, which amounted to $1.1 million, has been reflected in the 1993 federal income tax provisions above. In addition, the Company has included in its November 1, 1993 general rate case application with the FERC a provision to reduce, by $4 million, its obligation to ratepayers for the "Unamortized rate reductions for excess deferred federal income taxes" as a result of this tax rate increase.
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, 1993, the Plan did not have an unfunded accumulated benefit obligation. ANR Pipeline made no contributions to the Plan for 1993, 1992 or 1991. 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 match the contributions made by employees, amounted to $5.9, $5.7 and $5.4 million for 1993, 1992 and 1991, 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, "Employers' Accounting for Postretirement Benefits Other Than Pensions" ("FAS 106"). FAS 106 requires the Company to accrue the estimated cost of retiree benefit payments during the years the employee provides services. The Company previously expensed the cost of these benefits, which are principally health care, as claims were incurred. FAS 106 allows recognition of the cumulative effect of the liability in the year of the adoption or the amortization of the obligation over a period of up to 20 years. The Company has elected to recognize the initial postretirement benefit obligation of approximately $62.7 million over a period of 20 years. The Company's cash flows were not affected by the implementation of FAS 106 and the incremental impact of $6.5 million on the Company's 1993 year-to-date results of operations has been deferred, as the Company has included such costs in its November 1, 1993 general rate case application with the FERC.
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation was 16.0% in 1993, declining gradually to 7.0% by the year 2004. A one percentage point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 and the net postretirement health care cost by approximately 7.2%. The assumed discount rate used in determining the accumulated postretirement benefit obligation was 7.25%.
The FASB has issued FAS No. 112, "Employers' Accounting for Postemployment Benefits" ("FAS 112"), to be effective in 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The $3 million estimated earnings impact of adopting FAS 112 will be deferred, as the Company has included such costs in its November 1, 1993 general rate case application with the FERC. The Company implemented FAS 112 effective January 1, 1994.
11. Transactions with Affiliates and Major Customers
The Statement of Consolidated Earnings includes Gas Sales and Storage and Transportation revenues from major customers; the cost of Gas Purchases and Transmission, Compression and Storage of gas by others from affiliates and related parties as follows (millions of dollars):
The Consolidated Balance Sheet includes $6.2 million at December 31, 1993 and $17.5 million at December 31, 1992 due from affiliates reflected in accounts receivable and $17.7 million at December 31, 1993 and $39.6 million at December 31, 1992 due to affiliates reflected in accounts payable.
Services provided by the Company at cost for affiliated companies were $10.1 million for 1993, $10.4 million for 1992 and $9.8 million for 1991. Services provided by affiliated companies for the Company at cost were $31.6 million for 1993, $31.5 million for 1992 and $27.4 million for 1991. 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. Such costs are allocated to the Company using a three factor formula consisting of revenues, property and payroll, which has been applied on a reasonable and consistent basis.
The Company has a lease agreement with ANR Ren Cen, Inc., a subsidiary of ANR, for the rental of office space in Detroit. Rental payments for the years 1993, 1992 and 1991 amounted to $4.9 million, $4.8 million and $4.6 million, respectively.
The Company has lease agreements with Coastal and one of its affiliates for the rental of certain facilities. Rental expenses of $4.1 million, $5.8 million and $4.2 million were recorded in 1993, 1992 and 1991, respectively, in conjunction with the terms of the lease agreements.
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, 1993, the Company had advanced $285.5 million to an associated company at a market rate of interest. Such amount is repayable on demand.
12. Quarterly Financial Data (Unaudited)
The results of operations by quarter for the years ended December 31, 1993 and 1992 were (millions of dollars):
ANR PIPELINE COMPANY AND SUBSIDIARIES SCHEDULE II - AMOUNTS RECEIVABLE FROM RELATED PARTIES AND UNDERWRITERS, PROMOTERS AND EMPLOYEES OTHER THAN RELATED PARTIES (Millions of Dollars)
- ------------------------------------- 1 The note receivable is a promissory note due from an affiliate on demand and bears a market rate of interest.
S-1
ANR PIPELINE COMPANY AND SUBSIDIARIES SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Millions of Dollars)
S-2
ANR PIPELINE COMPANY AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION (Millions of Dollars)
S-3
ANR PIPELINE COMPANY AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION (Millions of Dollars)
S-4
EXHIBIT INDEX
- -------------- Note:
+ Indicates documents incorporated by reference from the prior filings indicated.
* Indicates documents filed herewith.