Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS.
GENERAL
Texas Gas Transmission Corporation (the Company) is a wholly owned subsidiary of Transco Gas Company, which is wholly owned by Transco Energy Company (Transco). As used herein, the term Transco refers to Transco Energy Company together with its wholly owned subsidiary companies unless the context otherwise requires.
The Company is a major interstate natural gas pipeline company primarily engaged in the transportation of natural gas. The Company owns and operates an extensive pipeline system originating in major gas supply areas in the Louisiana Gulf Coast area and in East Texas and running generally north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller diameter lines extending into Illinois. The Company's system currently consists of approximately 6,050 miles of transmission lines. In conjunction with its pipeline facilities, the Company owns and operates ten underground storage reservoirs having a total capacity of 176.7 Bcf* and a working capacity of 86.5 Bcf.
The Company's direct market area encompasses eight states in the South and Midwest, and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and Indianapolis, Indiana metropolitan areas. The Company also has indirect market access to Northeast markets through interconnections with Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation (CNG) and Texas Eastern Transmission Corporation (Texas Eastern). A large portion of the gas delivered by the Company to its market area is used for space heating, resulting in substantially higher daily requirements during winter months than summer months.
TRANSPORTATION AND SALES
Traditionally, interstate pipelines, including the Company, served primarily as merchants of natural gas, purchasing gas under long-term contracts with numerous producers in the production area and reselling gas to local utilities in the market area under long-term sales agreements. Such merchant service was known as bundled service.
Regulatory policies under the Natural Gas Act of 1938 (NGA), relating to both pipeline rates and conditions of service, stressed security of gas supplies and service, and the recovery by pipelines of their prudently incurred costs of providing that service.
However, commencing in 1984, the Federal Energy Regulatory Commission (FERC) issued a series of orders which have resulted in a major restructuring of the natural gas pipeline industry and its business practices. With FERC Order 380, issued in 1984, the FERC freed pipeline customers from their contractual obligations to purchase certain minimum levels of gas from their pipeline suppliers. With implementation of "open access" transportation rules contained in FERC Orders 436 and 500, the FERC afforded pipeline customers the opportunity to purchase gas from third parties with pipelines transporting this supply to the customers' markets. These FERC rules, coupled with a nationwide excess of deliverable natural gas, have resulted in increased competition for markets and decreases in natural gas prices.
Faced with these changing conditions and declining sales, the Company altered the manner in which it had traditionally conducted its business. In September 1984, the Company began transporting gas for industrial end-users served by its direct-served local distribution customers. As excess natural gas became available and prices declined, transportation of customer-owned gas increased. In September 1988, the
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* As used in this report, the term "Mcf" means thousand cubic feet, the term "MMcf" means million cubic feet, the term "Bcf" means billion cubic feet and the term "Tcf" means trillion cubic feet. Unless otherwise stated in this report, gas volumes are stated at a pressure base of 14.73 pounds per square inch and at 60 degrees Fahrenheit.
Company accepted a certificate and became a permanent open access pipeline system under FERC Orders 436 and 500.
On April 8, 1992, the FERC issued Order 636 which brought about fundamental changes in the way natural gas pipelines conduct their businesses. The FERC's stated purpose of FERC Order 636 was to improve the competitive structure of the natural gas pipeline industry by, among other things, unbundling a pipeline's merchant role from its transportation services; ensuring "equality" of transportation services; ensuring that shippers and customers have equal access to all sources of gas; providing "no-notice" firm transportation services that are equal in quality to bundled sales service; and changing rate design methodology from Modified Fixed Variable (MFV) to Straight Fixed Variable (SFV), unless the pipeline and its customers agree to a different form.
FERC Order 636 also set forth methods for recovery by pipelines of costs associated with compliance under FERC Order 636 (transition costs), including unrecovered gas costs, gas supply realignment (GSR) costs, the cost of stranded pipeline investment and the costs of new facilities required.
On August 3, 1992, the FERC issued Order 636-A which modified the original order to include one-part volumetric rates for small customers; the option of unbundled gas sales to small customers at a cost-based rate for a one-year period after the effective date of restructuring; a capacity release program; recovery of certain transition costs through interruptible transportation (IT) rates; and its use of either SFV methodology or other ratemaking techniques to design rates which result in equitable treatment of customers with varying load factors.
On November 27, 1992, the FERC issued Order 636-B which reaffirmed several significant requirements of FERC Order 636-A. FERC Order 636-B marked the end of the restructuring rulemaking. The FERC has stated that it will not accept further rehearing petitions. FERC Orders 636, 636-A and 636-B are presently subject to court appeals.
FERC Order 636 was implemented on the Company's system on November 1, 1993. As a result of FERC Order 636, the Company's gas sales have been fundamentally restructured. Prior to implementation of FERC Order 636, the Company had maximum peak-day sales delivery obligations in excess of 1.7 Bcf per day under individually certificated bundled sales contracts with more than 90 customers. Effective November 1, 1993, all of these bundled sales services ceased and were abandoned pursuant to FERC Order 636. Also as a result of FERC Order 636, the Company entered into a limited number of new unbundled sales contracts under the blanket certificate issued to it pursuant to that order. In compliance with another FERC decision, FERC Order 497, the sales under this unbundled merchant function are separately administered by Transco Gas Marketing Company (TGMC), an affiliate of the Company. TGMC has been appointed the Company's exclusive agent for the purpose of administering all existing and future sales and purchases for the Company after implementation of FERC Order 636, except for the auction transactions discussed below. Through its agent, TGMC, the Company currently sells gas to fewer than ten customers with a total deliverability obligation of substantially less than 0.2 Bcf per day.
The only remaining sales administered by the Company are volumes purchased from a limited number of non-market-responsive gas purchase contracts which are auctioned each month to the highest bidder. The Company may file to recover the price differential, between the cost to buy the gas under these gas purchase contracts and the price realized from the resale of the gas at the auction, as a GSR cost pursuant to FERC Order 636.
The following table sets forth the Company's total system deliveries, which exclude unbundled sales, and the mix of sales and transportation volumes for the periods shown:
The Company's facilities are divided into five rate zones. Receipts and deliveries are made in four zones to serve sales and long-haul transportation markets. Receipts and deliveries in the remaining zone are made to serve sales and short-haul transportation markets in southern Louisiana.
The decline in gas sales in 1993 primarily was attributable to the Company's implementation of FERC Order 636. The increase in transportation volumes resulted primarily from the Company's implementation of additional firm service for Transcontinental Gas Pipe Line Corporation (TGPL), an affiliate of the Company, implementation of FERC Order 636 and colder weather during the winter months of 1993 than the winter months of 1992. The revenues associated with short-haul transportation volumes are not material to the Company.
The following table sets forth the names of the Company's five largest customers, along with the related sales and long-haul transportation volumes for the periods shown (expressed in Bcf).
GAS SUPPLY
During 1993, as part of the Company's restructuring under FERC Order 636, the Company has engaged in negotiations with suppliers which have resulted in the successful termination of approximately 90% of the deliverability under its non-market-responsive gas purchase contracts. Pursuant to FERC Order 636, the Company is entitled to file for recovery of up to 100% of its prudently incurred costs of terminating these contracts as GSR costs.
The Company's remaining gas purchase commitments at the end of 1993 consist of both market-responsive and non-market-responsive contracts. Pursuant to FERC Order 636, gas purchased from the Company's non-market-responsive contracts is being resold at a monthly auction. The Company continues to
pay to the supplier the actual contract price and is entitled to file for full recovery of the difference between said contract price and the amount received for sales at auction as GSR costs under FERC Order 636. The Company's market-responsive contracts are being separately managed by its marketing affiliate, TGMC. As a result of the foregoing, it is no longer material to the Company's business to have proved gas reserves committed to the Company.
REGULATION
INTERSTATE GAS PIPELINE OPERATIONS
The Company is subject to regulation by the FERC as a "natural gas company" under the NGA. The NGA grants to the FERC authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement and abandonment of such facilities. The FERC requires the filing of appropriate applications by natural gas companies showing that the extension, enlargement or abandonment of any facilities, as the case may be, is or will be required by a certificate of public convenience and necessity. The Company holds certificates of public convenience and necessity issued by the FERC authorizing it to construct and operate all pipelines, facilities and properties now in operation for which certificates are required, except for certain facilities that are not material or with respect to which the FERC has issued temporary certificates.
The NGA also grants to the FERC authority to regulate rates, charges and terms of service for natural gas transported in interstate commerce or sold by a natural gas company in interstate commerce for resale, and to regulate curtailments of sales to customers. The FERC has authorized the Company to charge natural gas sales rates that are market-based. As necessary, the Company files with the FERC changes in its transportation and storage rates and charges designed to allow it to recover fully its costs of providing service to its interstate system customers, including a reasonable rate of return. Regulation of gas curtailment priorities and the importation of gas are, under the Department of Energy Reorganization Act of 1977, vested in the Secretary of Energy.
The Company is also subject to regulation by the Department of Transportation under the Natural Gas Pipeline Safety Act of 1968 with respect to safety requirements in the design, construction, operation and maintenance of its interstate gas transmission facilities.
REGULATORY MATTERS
Pursuant to FERC Order 500, certain other pipelines, from which the Company made gas purchases (upstream pipelines), had received approval from the FERC to bill customers for their producer settlement costs. The Company had, in turn, received FERC approval to flow these costs through to its customers under the FERC Order 500 purchase deficiency-based direct bill methodology. Following the issuance of FERC Order 528, which replaced the purchase deficiency-based recovery methodology, the Company, in 1991, made a series of filings which reallocated these costs among customers pursuant to the provisions of FERC Order 528. Pursuant to these filings, the Company proposed to ultimately flow through to its customers approximately $64.3 million of costs billed from upstream pipelines. The FERC has issued orders accepting these filings subject to the ultimate outcome of the underlying filings of the upstream pipelines and future settlement by the Company. Although the total billings to the Company are unresolved and the Company may be required to refund certain amounts previously collected, the Company believes that it will be entitled to ultimately collect all amounts that are billed by the upstream pipelines.
On September 2, 1993, the Company filed to recover 75% of $3.4 million of its producer settlement costs under FERC Order 528 which have resulted from reimbursements to producers for certain royalty payments. A FERC order, accepting the filing subject to refund and certain conditions, was issued on October 1, 1993, allowing for recovery of $0.9 million through direct bill and $1.7 million through a volumetric surcharge, both to be collected over a 12-month period which began October 3, 1993.
FERC ORDER 94-A
In 1983, the FERC issued FERC Order 94-A, which permitted producers to collect certain production-related gas costs from pipelines on a retroactive basis. The FERC subsequently issued orders allowing pipelines, including the Company, to bill their customers for such production-related costs through fixed monthly charges based on a customer's historical purchases. In February 1990, the D.C. Circuit Court overturned the FERC's authorization for pipelines to bill production-related costs to customers based on gas purchased in prior periods and remanded the matter to the FERC to determine an appropriate recovery mechanism.
On April 28, 1992, the Company filed a settlement with the FERC providing for a reallocation of the FERC Order 94-A payments previously collected from customers. The settlement provided for net refunds of $8.1 million to certain customers and direct bill recovery of $2.7 million from other customers. The remaining $5.4 million would be recovered through the PGA mechanism. On February 11, 1993, the FERC issued an order approving the settlement. Certain parties filed for rehearing of the settlement. On January 12, 1994, the FERC issued its "Order Granting Rehearing" which found that the FERC had committed a legal error in allowing the previously mentioned direct bill of FERC Order 94-A costs. The effect of this order as issued would be to require the Company to make refunds to certain customers of $13.5 million, recover $2.7 million through direct billing of other customers, recover $5.4 million as part of the direct billing of its unrecovered purchase gas costs and absorb the remaining $5.4 million. The Company believes it is entitled to full recovery of these FERC-ordered costs. The Company has filed for rehearing of this order and has received an extension staying the effectiveness of this order until 30 days after the FERC rules on rehearing. The Company believes that its reserve for regulatory and rate matters is adequate to provide for any costs which the Company may ultimately be required to absorb.
FERC ORDER 636
The Company has restructured its business to implement the provisions of FERC Order 636. On October 1, 1993, the FERC issued its "Order on Compliance Filing and Granting, In Part, and Denying, In Part, Rehearing and Clarification," which essentially approved the major aspects of the Company's FERC Order 636 compliance plan. The Company filed revised tariff sheets and other changes pursuant to the October 1, 1993 order on October 18, 1993, which permitted implementation of FERC Order 636 restructured services on November 1, 1993. On December 16, 1993, the FERC issued another order which required minor tariff modifications. The Company submitted a filing in compliance with this order on January 7, 1994. This filing was accepted by an order issued on February 10, 1994. The Company's analysis of FERC Order 636 indicates that the Company's transition costs are not currently expected to exceed $90 million, primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the auction transactions, as discussed below, and unrecovered purchased gas costs. As of December 31, 1993, the Company had recorded $38 million of GSR costs.
FERC Order 636 provides that pipelines should be allowed the opportunity to recover all prudently incurred transition costs. Therefore, the Company expects that any transition costs incurred should be recovered from its customers, subject only to the costs and other risks associated with the difference between the time such costs are incurred and the time when those costs may be recovered from customers. On January 28, 1994, the Company submitted its first filing to recover $11.5 million of GSR costs pursuant to the transition cost recovery provisions of FERC Order 636 and the Company's FERC-approved Gas Tariff. This amount represents 90% of the total GSR costs paid through November 30, 1993, which are expected to be recovered over a 12-month period by application of a demand surcharge to its firm transportation rates. The remaining 10% is expected to be recovered from interruptible transportation service. The Company plans to make quarterly filings to allow recovery of its GSR costs as such costs are paid.
As part of its implementation of FERC Order 636, the Company has been allowed to retain its storage gas, in part to meet operational balancing needs on its system, and in part to meet the requirements of the Company's "no-notice" transportation service, which allows customers to temporarily draw from the Company's storage gas to be repaid in-kind during the following summer season.
Although no assurances can be given, the Company does not believe the implementation of FERC Order 636 will have a material adverse effect on its financial position or results of operations.
For further discussion of regulatory matters, see Note C of Notes to Financial Statements contained in Item 8 hereof.
ENVIRONMENTAL MATTERS
The Company is subject to extensive federal, state and local environmental laws and regulations which affect the Company's operations related to the construction and operation of its pipeline facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. The Company's use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as "Superfund," imposes liability, without regard to fault or the legality of the original act, for release of a "hazardous substance" into the environment. Because these laws and regulations change from time to time, practices which have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. Since 1989, the Company has had studies underway to test its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. On the basis of the findings to date, the Company estimates that environmental assessment and remediation costs that will be incurred over the next five years under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $7 million to $11 million. As of December 31, 1993, the Company had a reserve of approximately $7 million for these estimated costs. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of remedial measures to be undertaken. The Company is continuing to conduct environmental assessments and is implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs.
The Company has used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, has discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. The Company continues to work closely with the Environmental Protection Agency (EPA) and state regulatory authorities regarding PCB issues and has programs to assess and remediate such conditions where they exist, the costs of which are a significant portion of the $7 million to $11 million range discussed above. Proposed civil penalties have been assessed by the EPA against another major natural gas pipeline company for the alleged improper use and disposal of PCBs. Although similar penalties have not been asserted against the Company to date, no assurance can be given that the EPA may not seek such penalties in the future.
The Company has either been named as a potentially responsible party (PRP) or received an information request regarding its potential involvement at four federal "Superfund" waste disposal sites and one state waste disposal site. Based on present volumetric estimates, the Company believes its estimated aggregate exposure for remediation of these sites is approximately $500,000. Liability under CERCLA (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus the ultimate liability could be substantially greater than the amount estimated above. The anticipated remediation costs associated with these sites have been included in the $7 million to $11 million range discussed above. Although no assurances can be given, the Company does not believe that its PRP status will have a material adverse effect on its financial position or results of operations.
The Company is currently recovering in its rates amounts approximately equal to its annual expenditures for these environmental matters. The Company considers these expenditures prudent operating and maintenance expenses incurred in the ordinary course of business and anticipates that these costs will continue to be recoverable through its rates.
The Company is also subject to the Federal Clean Air Act and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to mobile sources, air toxics, ozone non-attainment areas and acid rain. In addition, pursuant to the 1990 Amendments, the EPA has issued regulations under which states must implement new air pollution controls to achieve attainment of national ambient air quality standards in areas where they are not currently achieved. The Company has compressor stations in ozone non-attainment areas that could require additional air pollution reduction expenditures, depending on the requirements imposed. Additions to facilities for compliance with currently known Federal Clean Air Act standards and the 1990 Amendments are expected to cost in the range of $2 million to $3 million over the next five years and will be recorded as assets as the facilities are added. The Company considers costs associated with compliance with environmental laws to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.
RATES
GENERAL
The Company's rates are established primarily through the FERC ratemaking process. Key determinants in the ratemaking process are (i) volume throughput assumptions, (ii) costs of providing service and (iii) allowed rate of return. The allowed rate of return is determined by the FERC in each rate case. Rate design and the allocation of costs between the demand and commodity rates also impact profitability.
RATE ISSUES
In April 1990, the Company filed a general rate case (Docket No. RP90-104), which became effective in November 1990, subject to refund. A settlement agreement was filed on July 22, 1991, and approved by the FERC's "Order Granting Reconsideration," on October 21, 1992. Refunds, including interest, of $36.3 million were made to customers on January 19, 1993.
On April 29, 1993, the Company filed a general rate case (Docket No. RP93-106) which, pursuant to the FERC's Suspension Order issued May 28, 1993, became effective on November 1, 1993, subject to refund. The new rate case was filed to satisfy the three-year filing requirements of the FERC's regulations, to recover increased operating costs, to provide a return on increased capital investment in pipeline facilities, to implement the SFV rate design methodology and to facilitate resolution of various rate-related issues in the Company's FERC Order 636 restructuring proceeding. The Company is currently engaged in settlement proceedings regarding this case. The Company has established a reserve, which it believes to be adequate, to reflect the difference between the rates currently being charged and the rates expected to ultimately be effective upon settlement of the case.
During 1993, the Company made several filings under the provisions of its approved tariff and FERC Orders 483 and 483-A to reflect changes in its purchased gas costs. The Company also made filings to reflect changes in costs of transportation by others, pursuant to the Transport Cost Adjustment (TCA) tracker provisions of the approved tariff. Pursuant to that tariff, on December 30, 1993, the Company refunded $14.9 million of overcollected transportation costs. The Annual PGA filing for gas costs incurred through August 1992 (Docket No. TA93-1-18) was accepted by FERC Letter Order dated January 29, 1993, with no purchasing practice issues being raised.
On November 1, 1993, the Company implemented the provisions of FERC Order 636 (see discussion on FERC Order 636). Pursuant to FERC Order 636, the Company terminated its PGA clause on that date. On January 31, 1994, the Company filed a limited Section 4(e) filing pursuant to its approved FERC Gas Tariff to direct bill the balance of its unrecovered purchase gas costs at October 31, 1993, to its former sales customers. This filing is necessary to recover $3.0 million of deferred gas costs applicable to the period September 1992 through October 1993. The Company has no outstanding deferred gas cost issues pending in any other proceeding.
COMPETITION
The Company and its primary market area competitors (ANR Pipeline Company, Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Texas Eastern, Columbia, Tennessee Gas Pipeline Company and Midwestern Gas Transmission Company) implemented FERC Order 636 on their respective systems during the period May 1993 to November 1993. The Company and its major competitors all employ SFV rate design for firm transportation as mandated by FERC Order 636.
Future utilization of the Company's pipeline capacity will depend on competition from other pipelines and alternative fuels, the general level of natural gas demand and weather conditions. Although some of the Company's major competitors implemented FERC Order 636 and SFV rates prior to the Company's implementation, the impact on the Company's throughput was minimal. The Company believes that under FERC Order 636, with SFV rates, its rate structure will remain competitive and surcharges for recovery of its total transition costs will not make its rates noncompetitive in its market as competitor pipelines are believed to have transition costs also to be recovered in their rates.
The end-use markets of several of the Company's customers have the ability to switch to alternative fuels. To date, however, losses from fuel switching have not been significant.
PIPELINE PROJECTS
The Company is involved in expanding its markets through the following projects:
LIBERTY PIPELINE COMPANY
In 1992, Liberty Pipeline Company (Liberty Pipeline), a partnership of interstate pipelines and local distribution companies, filed for FERC approval to construct and operate a natural gas pipeline to provide up to 500 MMcf per day in firm transportation service to the greater New York City area. The partnership is comprised of subsidiaries of Transco, two other interstate pipelines and subsidiaries of three of Transco's customers in New York, collectively known as The New York Facilities Group.
The pipeline is expected to cost approximately $162 million and is proposed to be in service by the 1995-1996 winter heating season, subject to timely FERC approval. Liberty Operating Company, a subsidiary of Transco, will construct and operate the pipeline for the partnership.
The Company has filed two separate applications with the FERC requesting authority to expand its pipeline facilities to provide upstream transportation service in connection with the Liberty Pipeline project. One application requests authority to construct facilities at an estimated cost of $59.4 million to provide an incremental 100 MMcf per day of firm service for The New York Facilities Group and KIAC Partners, a cogeneration affiliate of The Brooklyn Union Gas Company. The Company plans, subject to FERC approval, to construct $16 million of facilities to implement 30.3 MMcf per day of this incremental firm service for the 1995-1996 winter heating season with the remaining $43.4 million of facilities being constructed during 1996 to provide the remaining 69.7 MMcf per day of incremental service for the 1996-1997 winter heating season. This volume of gas will ultimately be transported by TGPL for redelivery to Liberty Pipeline. The second application requests authority to expand the Company's facilities to provide an incremental 35 MMcf per day of firm service for The Power Authority of the State of New York at an estimated cost of $20.9 million. The Company plans, subject to FERC approval, to construct the $20.9 million of facilities during 1995 in order to implement the incremental firm transportation service for The Power Authority of New York in time for the 1995-1996 winter heating season.
WEST TENNESSEE PIPELINE EXPANSION
In January 1994, the Company received approval from the FERC to expand its Jackson-Ripley pipeline system located in northwest Tennessee to provide 4.6 MMcf per day of additional firm deliveries to three West Tennessee customers and to construct additional pipeline looping providing system security on that part of the Company's system. Construction is anticipated to commence during the first quarter of 1994. Total cost for
this system expansion is expected to be $3.2 million, which the Company anticipates it will incur during the first half of 1994.
EMPLOYEE RELATIONS
The Company had 1,155 employees as of December 31, 1993. Certain of those employees were covered by a collective bargaining agreement. A favorable relationship existed between management and labor during the period.
The International Chemical Workers Local 187 represents 199 of the Company's 494 field operating employees. The current collective bargaining agreement between the Company and Local 187 expires on April 30, 1995.
The Company has a non-contributory pension plan and various other plans which provide regular active employees with group life, hospital and medical benefits as well as disability benefits and savings benefits. Officers and directors who are full-time employees may participate in these plans.
ITEM 2.



ITEM 2. PROPERTIES.
See "Item 1. Business."
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS.
For a discussion of the Company's current legal proceedings, see Note D of Notes to Financial Statements contained in Item 8 hereof.
PART II
ITEM 5.


ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
(a) and (b) As of December 31, 1993, all of the outstanding shares of the Company's common stock are owned by Transco Gas Company, a wholly owned subsidiary of Transco. The Company's common stock is not publicly traded and there exists no market for such common stock.
ITEM 7.


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL ANALYSIS OF OPERATIONS
1993 COMPARED TO 1992
As discussed in Note C of Notes to Financial Statements contained in Item 8


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Texas Gas Transmission Corporation:
We have audited the accompanying balance sheets of Texas Gas Transmission Corporation (a Delaware corporation and an indirect wholly owned subsidiary of Transco Energy Company) as of December 31, 1993 and 1992, and the related statements of income, retained earnings and paid-in capital and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and 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, the financial statements referred to above present fairly, in all material respects, the financial position of Texas Gas Transmission Corporation as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The financial statement schedules listed in the index to Part IV, Item 14(a)2 are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These financial statement schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas February 18, 1994
MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS
The financial statements have been prepared by the management of Texas Gas Transmission Corporation (the Company) in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments of the effects of certain events and transactions based on currently available information.
The Company maintains accounting and other controls that management believes provide reasonable assurance that financial records are reliable, assets are safeguarded and that transactions are properly recorded in accordance with management's authorizations. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived.
The Company's independent auditors, Arthur Andersen & Co., are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with generally accepted auditing standards to enable them to report that the financial statements present fairly, in all material respects, the financial position, results of operations and cash flows of the Company in conformity with generally accepted accounting principles.
The Audit Committee of the Board of Directors of Transco Energy Company (Transco), composed of three directors who are not employees of Transco, meets regularly with the independent auditors and management. The independent auditors have full and free access to the Audit Committee and meet with them, with and without management being present, to discuss the results of their audits and the quality of financial reporting.
TEXAS GAS TRANSMISSION CORPORATION
BALANCE SHEETS (THOUSANDS OF DOLLARS)
ASSETS
The accompanying notes are an integral part of these financial statements.
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF INCOME (THOUSANDS OF DOLLARS)
The accompanying notes are an integral part of these financial statements.
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL (THOUSANDS OF DOLLARS)
The accompanying notes are an integral part of these financial statements.
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF CASH FLOWS (THOUSANDS OF DOLLARS)
The accompanying notes are an integral part of these financial statements.
TEXAS GAS TRANSMISSION CORPORATION
NOTES TO FINANCIAL STATEMENTS
A. CORPORATE STRUCTURE AND CONTROL AND BASIS OF PRESENTATION
Corporate Structure and Control
Texas Gas Transmission Corporation (the Company) is a wholly owned subsidiary of Transco Gas Company (TGC), which is a wholly owned subsidiary of Transco Energy Company (Transco). As used herein, the term Transco refers to Transco Energy Company and its wholly owned subsidiary companies; the term TGMC refers to Transco Gas Marketing Company, a wholly owned subsidiary of Transco, and its wholly owned subsidiary companies; and the term TGPL refers to Transcontinental Gas Pipe Line Corporation, a wholly owned subsidiary of TGC, unless the context otherwise requires.
The Company's sole subsidiary, Texam Offshore Gas Transmission, Inc. (Texam), was sold on July 20, 1992 (see Note H). The financial information presented for periods prior to the date of sale represents the Company's consolidated financial position and results of operations.
Basis of Presentation
The acquisition of the Company was accounted for using the purchase method of accounting. Accordingly, the acquisition debt and the purchase price were "pushed down" and recorded in the Company's financial statements. Retained earnings, deferred taxes and accumulated depreciation and amortization were eliminated at the date of acquisition.
Included in property, plant and equipment as of the date of Transco's acquisition of the Company in 1989 is an aggregate of $226 million related to amounts in excess of the original cost of the regulated facilities. This amount is amortized over the estimated life of the assets acquired at approximately $9 million per year. Current Federal Energy Regulatory Commission (FERC) policy does not permit the Company to recover through its rates amounts in excess of original cost.
Related Parties
As a subsidiary of Transco, the Company engages in transactions with Transco and other Transco subsidiaries characteristic of group operations. For consolidated cash management purposes, the Company makes interest-bearing advances to Transco. These advances are represented by demand notes payable to the Company. Those amounts that the Company anticipates Transco will repay in the next twelve months are classified as current assets, while the remainder are classified as noncurrent. As general corporate policy, the interest rate on intercompany demand notes is 1 1/2% below the prime rate of Citibank, N.A. Net interest income on advances to or from associated companies was $9.4 million, $9.6 million and $11.5 million for the years ended December 31, 1993, December 31, 1992 and December 31, 1991, respectively. See Note F for a discussion of Transco's credit facilities and indentures as they relate to the Company.
Transco has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. During the years ended December 31, 1993, December 31, 1992 and December 31, 1991, the Company was charged $6.7 million, $4.2 million and $4.4 million, respectively, for Transco management services. Management considers the cost of these services reasonable.
Effective November 1, 1993, the Company contracted with TGMC to become the Company's agent for the purpose of administering all existing and future gas sales and market-responsive purchase obligations, except for its auction gas transactions. Sales and purchases under this agreement do not impact the Company's results of operations. For the two months ended December 31, 1993, the Company paid TGMC agency fees of $0.7 million for these services.
Included in the Company's gas sales revenues for the year ended December 31, 1993 is $4.2 million applicable to gas sales to the Company's affiliate, TGMC. There were no intercompany gas sales for the years ended December 31, 1992 and December 31, 1991.
Included in the Company's gas transportation revenues for the years 1993, 1992 and 1991 are amounts applicable to transportation for affiliates as follows (expressed in thousands):
Included in the Company's cost of gas sold for the years ended December 31, 1993 and December 31, 1992, is $11.1 million and $4.2 million, respectively, applicable to gas purchases from the Company's affiliate, TGMC. There were no intercompany gas purchases for the year ended December 31, 1991.
B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Revenue Recognition
The Company recognizes revenues for the sale and transportation of natural gas in the period of sale and in the period service is provided, respectively. Pursuant to FERC regulations, a portion of the revenues being collected may be subject to possible refunds upon final orders in pending rate cases. The Company has established reserves, where required, for such cases (see Note C for a summary of pending rate cases before the FERC).
Costs Recoverable from/Refundable to Customers
The Company has various mechanisms whereby rates or surcharges are established and revenues are collected and recognized based on estimated costs. Costs incurred over or under approved levels are deferred and recovered or refunded through future rate or surcharge adjustments (see Note C for a discussion of the Company's rate matters).
Depreciation and Amortization
The Company's depreciation rates are principally mandated by the FERC. Depreciation rates used for regulated gas plant facilities at year end 1993, 1992 and 1991 are as follows:
Tax Policy
Transco and its wholly owned subsidiaries file a consolidated federal income tax return. It is Transco's policy to charge or credit each subsidiary with an amount equivalent to its federal income tax expense or benefit computed as if each subsidiary had a separate return, but including benefits from each subsidiary's losses and tax credits that may be utilized only on a consolidated basis.
Accounting for Income Taxes
The Company uses the liability method of accounting for deferred taxes which requires, among other things, adjustments to the existing deferred tax balances for changes in tax rates, whereby such balances will more closely approximate the actual taxes to be paid.
Liabilities to customers of $7.9 million and $15.2 million at December 31, 1993 and December 31, 1992, respectively, resulting from net tax rate reductions related to regulated operations and to be refunded to customers over the average remaining life of natural gas transmission plant, have been shown in the accompanying balance sheets as income taxes refundable to customers, the current portion of which is included in other current liabilities.
In the first quarter of 1993, the Company adopted Statement of Financial Accounting Standards (SFAS) 109, "Accounting for Income Taxes," which superseded SFAS 96, "Accounting for Income Taxes." Due to the Company's prior adoption of SFAS 96 in 1987, the adoption of SFAS 109 did not have a material effect on its financial position or results of operations.
Capitalized Interest
The allowance for funds used during construction represents the cost of funds applicable to regulated natural gas transmission plant under construction as permitted by FERC regulatory practices. The allowance for borrowed funds used during construction and capitalized interest for the years ended December 31, 1993, December 31, 1992 and December 31, 1991, was $0.2 million, $0.6 million and $0.7 million, respectively. The allowance for equity funds for the years ended December 31, 1993, December 31, 1992 and December 31, 1991, was $0.5 million, $1.2 million and $1.3 million, respectively.
Gas in Storage
As part of its implementation of FERC Order 636, the Company has been allowed to retain its storage gas, in part to meet operational balancing needs on its system, and in part to meet the requirements of the Company's "no-notice" transportation service, which allows customers to temporarily draw from the Company's storage gas to be repaid in-kind during the following summer season. As a result, the Company's gas stored underground has been reclassified from current assets to other noncurrent assets.
Gas Imbalances
In the course of providing transportation services to customers, the Company may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. These transactions result in imbalances which are repaid or recovered in cash or through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as transportation and exchange gas receivable or payable on the accompanying balance sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.
The Company's tariff includes a provision whereby imbalances generated after November 1, 1993 are settled on a monthly basis. The Company anticipates filing for a mechanism whereby imbalances pre-dating November 1, 1993 will be recovered or repaid in cash or through the future receipt or delivery of gas upon agreements for allocation and as permitted by operating conditions.
Cash Flows from Operating Activities
The Company uses the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows from operating activities. The Company includes short-term highly-liquid investments that have a maturity of three months or less in cash equivalents.
Postemployment Benefits
The Financial Accounting Standards Board has issued SFAS 112, "Employers' Accounting for Post employment Benefits," which requires the Company, effective January 1994, to accrue the estimated cost of providing postemployment benefits to former or inactive employees after employment but before retirement if the obligation is attributable to employees' services previously rendered, employees' rights to those benefits accumulate or vest, payment of the benefits is probable and the amount of the benefits can be reasonably
estimated. The Company does not expect adoption of SFAS 112 to have a material effect on its financial position or results of operations.
Reclassifications
Certain reclassifications have been made in the 1992 and 1991 financial statements to conform to the 1993 presentation.
C. REGULATORY AND RATE MATTERS
FERC Order 636
In 1992, the FERC issued Order 636 which brought about fundamental changes in the way natural gas pipelines conduct their businesses. The FERC's stated purpose of Order 636 was to improve the competitive structure of the natural gas pipeline industry by, among other things, unbundling a pipeline's merchant role from its transportation services; ensuring "equality" of transportation services; ensuring that shippers and customers have equal access to all sources of gas; providing "no-notice" firm transportation service that is equal in quality to bundled sales service; and changing rate design methodology from Modified Fixed Variable (MFV) to Straight Fixed Variable (SFV), unless the pipeline company and its customers agree to a different form.
FERC Order 636 also set forth methods for recovery by pipelines of costs associated with compliance under FERC Order 636 (transition costs), including unrecovered gas costs, GSR costs, the cost of stranded pipeline investment and costs of new facilities required.
The Company has restructured its business to implement the provisions of FERC Order 636. On October 1, 1993, the FERC issued its "Order on Compliance Filing and Granting, In Part, and Denying, In Part, Rehearing and Clarification," which essentially approved the major aspects of the Company's FERC Order 636 compliance plan. The Company filed revised tariff sheets and other changes pursuant to the October 1, 1993 order on October 18, 1993, which permitted implementation of FERC Order 636 restructured services on November 1, 1993. On December 16, 1993, the FERC issued another order which required minor tariff modifications. The Company submitted a filing in compliance with this order on January 7, 1994. This filing was accepted by an order issued on February 10, 1994. The Company's analysis of FERC Order 636 indicates that the Company's transition costs are not currently expected to exceed $90 million, primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the auction process and unrecovered purchased gas costs. As of December 31, 1993, the Company had paid or committed to pay $38 million of GSR costs, as discussed below in "Long-term Gas Purchase Contracts." FERC Order 636 provides that pipelines should be allowed the opportunity to recover all prudently incurred transition costs. Therefore, the Company expects that any transition costs incurred should be recovered from its customers, subject only to the costs and other risks associated with the difference between the time such costs are incurred and the time when those costs may be recovered from customers.
As part of its implementation of FERC Order 636, the Company has been allowed to retain its storage gas, in part to meet operational balancing needs on its system, and in part to meet the requirements of the Company's "no-notice" transportation service, which allows customers to temporarily draw from the Company's storage gas to be repaid in-kind during the following summer season.
Although no assurances can be given, the Company does not believe the implementation of FERC Order 636 will have a material adverse effect on its financial position or results of operations.
General Rate Issues
In April 1990, the Company filed a general rate case (Docket No. RP90-104), which became effective in November 1990, subject to refund. A settlement agreement was filed on July 22, 1991, and approved by the FERC's "Order Granting Reconsideration," on October 21, 1992. The refunds, including interest, of $36.3 million were distributed to customers on January 19, 1993.
On April 29, 1993, the Company filed a general rate case (Docket No. RP93-106) which, pursuant to the FERC's Suspension Order issued May 28, 1993, became effective on November 1, 1993, subject to refund. The new rate case was filed to satisfy the three-year filing requirement of the FERC's regulations, to recover increased operating costs, to provide a return on increased capital investment in pipeline facilities, to implement the SFV rate design methodology and to facilitate resolution of various rate-related issues in the Company's FERC Order 636 restructuring proceeding. The Company is currently engaged in settlement proceedings regarding this case. The Company has established a reserve, which it believes to be adequate, to reflect the difference between the rates currently being collected and the rates expected to ultimately be effective upon settlement of the rate case.
During 1993, the Company made several filings under the provisions of its approved tariff and FERC Orders 483 and 483-A to reflect changes in its purchased gas costs. The Company also made a filing to reflect changes in costs of transportation by others, pursuant to the Transport Cost Adjustment (TCA) tracker provisions of the approved tariff. Pursuant to that tariff, on December 30, 1993, the Company refunded $14.9 million of overcollected transportation costs. The Annual PGA filing for gas costs incurred through August 1991 (Docket No. TA92-2-18) was accepted by FERC Letter Orders dated January 31, 1992 and May 22, 1992, with no purchasing practice issues being raised. The Annual PGA filing for gas costs incurred through August 1992 (Docket No. TA93-1-18) was accepted by FERC Letter Order dated January 29, 1993, with no purchasing practice issues being raised.
On November 1, 1993, the Company implemented the provisions of FERC Order 636 (see discussion on FERC Order 636). Pursuant to FERC Order 636, the Company terminated its PGA clause on that date. On January 31, 1994, the Company filed a limited Section 4(e) filing, pursuant to its FERC-approved FERC Gas Tariff, to direct bill the balance of its unrecovered purchase gas costs at October 31, 1993 to its former sales customers. This filing is necessary to recover $3.0 million of deferred gas costs applicable to the period September 1992 through October 1993. The Company has no outstanding deferred gas cost issues pending in any other proceeding.
FERC Orders 500 and 528
Pursuant to FERC Order 500, certain other pipelines, from which the Company made gas purchases (upstream pipelines), had received approval from the FERC to bill customers for their producer settlement costs. The Company had, in turn, received FERC approval to flow these costs through to its customers under the FERC Order 500 purchase deficiency-based direct bill methodology. Following the issuance of FERC Order 528, which replaced the purchase deficiency-based recovery methodology, the Company, in 1991, made a series of filings which reallocated these costs among customers. Pursuant to these filings, the Company proposed to ultimately flow through to its customers approximately $64.3 million of costs billed from upstream pipelines. The FERC has issued orders accepting these filings subject to the ultimate outcome of the underlying filings of the upstream pipelines and future settlement by the Company. Although the total billings to the Company are unresolved and the Company may be required to refund certain amounts previously collected, the Company believes that it will be entitled to ultimately collect all amounts that are billed by the upstream pipelines.
On September 2, 1993, the Company filed to recover 75% of $3.4 million of its producer settlement costs under FERC Order 528 which have resulted from reimbursements to producers for certain royalty payments. A FERC order, accepting the filing subject to refund and certain conditions, was issued on October 1, 1993, allowing for recovery of $0.9 million through direct bill and $1.7 million through a volumetric surcharge, both to be collected over a 12-month period which began October 3, 1993.
FERC Order 94-A
In 1983, the FERC issued FERC Order 94-A, which permitted producers to collect certain production-related gas costs from pipelines on a retroactive basis. The FERC subsequently issued orders allowing pipelines, including the Company, to direct bill their customers for such production-related costs through fixed monthly charges based on a customer's historical purchases. In February 1990, the D. C. Circuit Court
overturned the FERC's authorization for pipelines to bill production-related costs to customers based on gas purchased in prior periods and remanded the matter to the FERC to determine an appropriate recovery mechanism.
On April 28, 1992, the Company filed a settlement with the FERC providing for a reallocation of the FERC Order 94-A payments previously collected from customers. The settlement provided for net refunds of $8.1 million to certain customers and direct bill recovery of $2.7 million from other customers. The remaining $5.4 million would be recovered through the PGA mechanism. On February 11, 1993, the FERC issued an order approving the settlement. Certain parties filed for rehearing of the settlement. On January 12, 1994, the FERC issued its "Order Granting Rehearing" which found that the FERC had committed a legal error in allowing the previously mentioned direct bill of FERC Order 94-A costs. The effect of this order as issued would be to require the Company to make refunds to certain customers of $13.5 million, recover $2.7 million through direct billing of other customers, recover $5.4 million as part of the direct billing of its unrecovered purchase gas costs and absorb the remaining $5.4 million. The Company believes it is entitled to full recovery of these FERC-ordered costs. The Company has filed for rehearing of this order and has received an extension staying the effectiveness of this order until 30 days after the FERC rules on rehearing. The Company believes that its reserve for regulatory and rate matters is adequate to provide for any costs which the Company may ultimately be required to absorb.
Reserve for Regulatory and Rate Matters
The Company has established reserves for its outstanding regulatory and rate matters which it believes are adequate to provide for any costs incurred or refunds to be made in regard to the resolution of its regulatory and rate issues, including general rate matters and the royalty claims discussed in Note D. Although no assurances can be given, the Company believes that the resolution of these matters will not have a material adverse effect on its financial position or results of operations.
Long-term Gas Purchase Contracts
During 1993, as part of the Company's restructuring under FERC Order 636, the Company engaged in negotiations which have resulted in the successful termination of approximately 90% of the Company's deliverability under its non-market responsive gas purchase contracts. Gas purchased under its remaining non-market responsive contracts is being resold at a monthly auction pursuant to FERC Order 636. The Company continues to pay to the supplier the actual contract price and is entitled to file for full recovery of the difference between said contract price and the amount received for sales at auction as GSR costs under FERC Order 636.
Through December 31, 1993, the Company had paid or committed to pay a total of $38.2 million for GSR costs, primarily as a result of the contract terminations. As of December 31, 1993, the Company had paid $13.4 million of such costs; the remaining $24.8 million is recorded as a current liability in the accompanying balance sheet. Pursuant to FERC Order 636, the Company may file to recover 100% of these costs as GSR costs.
On January 28, 1994, the Company submitted its first filing to recover $11.5 million of GSR costs pursuant to the transition costs recovery provisions of FERC Order 636 and the Company's approved FERC Gas Tariff.
This amount represents 90% of the total GSR costs paid through November 30, 1993, which are expected to be recovered over a 12-month period by application of a surcharge to its firm transportation demand rates. The remaining 10% is expected to be recovered from interruptible transportation service. The Company plans to make quarterly filings to allow recovery of its GSR costs as such costs are paid.
The Company's market-responsive gas purchase contracts are being separately managed by its marketing affiliate, TGMC.
Environmental Matters
The Company is subject to extensive federal, state and local environmental laws and regulations which affect the Company's operations related to the construction and operation of its pipeline facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. The Company's use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as "Superfund," imposes liability, without regard to fault or the legality of the original act, for release of a "hazardous substance" into the environment. Because these laws and regulations change from time to time, practices which have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required. Since 1989, the Company has had studies underway to test its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. On the basis of the findings to date, the Company estimates that environmental assessment and remediation costs that will be incurred over the next five years under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $7 million to $11 million. As of December 31, 1993, the Company had a reserve of approximately $7 million for these estimated costs. This estimate depends upon a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of remedial measures to be undertaken. The Company is continuing to conduct environmental assessments and is implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs.
The Company is currently recovering in its rates amounts approximately equal to its annual expenditures for these environmental matters. The Company considers these expenditures prudent operating and maintenance expenses incurred in the ordinary course of business and anticipates that these costs will continue to be recoverable through its rates.
The Company has used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970's, has discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. The Company continues to work closely with the Environmental Protection Agency (EPA) and state regulatory authorities regarding PCB issues and has programs to assess and remediate such conditions where they exist, the costs of which are a significant portion of the $7 million to $11 million range discussed above. Proposed civil penalties have been assessed by the EPA against another major natural gas pipeline company for the alleged improper use and disposal of PCBs. Although similar penalties have not been asserted against the Company to date, no assurance can be given that the EPA may not seek such penalties in the future.
The Company has either been named as a potentially responsible party (PRP) or received an information request regarding its potential involvement at four federal "Superfund" waste disposal sites and one state waste disposal site. Based on present volumetric estimates, the Company believes its estimated aggregate exposure for remediation of these sites is approximately $500,000. Liability under CERCLA (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus the ultimate liability could be substantially greater than the amount estimated above. The anticipated remediation costs associated with these sites have been included in the $7 million to $11 million range discussed above. Although no assurances can be given, the Company does not believe that its PRP status will have a material adverse effect on its operations.
The Company is also subject to the Federal Clean Air Act and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to mobile sources, air toxics, ozone non-attainment areas and acid rain. In addition, pursuant to the 1990 Amendments, the EPA has issued regulations under which states must implement new air pollution controls to achieve attainment of national ambient air quality standards in areas where they are not currently
achieved. The Company has compressor stations in ozone non-attainment areas that could require additional air pollution reduction expenditures, depending on the requirements imposed. Additions to facilities for compliance with currently known Federal Clean Air Act standards and the 1990 Amendments are expected to cost in the range of $2 million to $3 million over the next five years and will be recorded as assets as the facilities are added.
D. ROYALTY CLAIMS AND LEGAL PROCEEDINGS
In connection with the Company's renegotiations of supply contracts with producers to resolve take-or-pay and other contract claims, the Company has entered into certain settlements which may require the indemnification by the Company of certain claims for royalties which a producer may be required to pay as a result of such settlements. On October 15, 1992, the United States Court of Appeals for the Fifth Circuit and the Louisiana Supreme Court, with respect to the same litigation in applying Louisiana law, determined that royalties are due on take-or-pay payments under the royalty clauses of the specific mineral leases reviewed by the Courts. Furthermore, the State Mineral Board of Louisiana has passed a resolution directing the State's lessees to pay to the State royalties on gas contract settlement payments. As a result of these and related developments, the Company has been made aware of demands on producers for additional royalties and may receive other demands which could result in claims against the Company pursuant to the indemnification provisions in its settlements. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the settlement between the producer and the Company. The Company may file to recover 75% of any such amounts it may be required to pay pursuant to indemnifications for royalties.
As discussed in Note C (see discussion on FERC Orders 500 and 528), on September 2, 1993, the Company made a filing pursuant to FERC Order 528 to recover 75% of approximately $3.4 million in additional take-or-pay settlement payments made by the Company as a result of certain obligations to indemnify a producer against additional royalty obligations arising out of the producer's prior take-or-pay settlement with the Company. Some additional indemnity payments may also be required with respect to such royalties.
In addition, two lawsuits have been filed against the Company in Louisiana, seeking reimbursement of certain royalties allegedly incurred by the producers on amounts previously paid the producers by the Company to settle past take-or-pay disputes and to reform the gas purchase contract pursuant to an "excess royalty" clause in a gas purchase contract. The amount in dispute is estimated to be less than $10 million. The Company disputes the application of the "excess royalty" clause to the particular royalties in question; however, to the extent any obligation to reimburse the producers exists, it is subject to the Company's ability to include such payments in its rates or cost of service.
Although no assurances can be given, the Company believes it has provided reserves which are adequate for the final resolution of its royalty claims and litigation and that the final resolution of these matters will not have a material adverse effect on its financial position or results of operations.
E. INCOME TAXES
Following is a summary of the provision for income taxes for 1993, 1992 and 1991 (expressed in thousands):
On August 10, 1993, the Omnibus Budget Reconciliation Act of 1993 was signed into law. Among its provisions was an overall increase in corporate federal income tax rates from 34% to 35%, effective January 1, 1993. The Company recorded in the third quarter of 1993 an adjustment to its existing deferred tax balances and current tax accruals subsequent to January 1, 1993 to reflect the effects of the increase in corporate federal income tax rates. The adjustment, which included a reduction to income taxes refundable to customers, did not have a material adverse effect on the Company's financial position or results of operations.
There are no material differences between the Company's effective tax rate and the statutory federal income tax rate for all periods presented.
Deferred income taxes result from temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years, or temporary differences resulting from events that have been recognized in the financial statements that will result in taxable or deductible amounts in future years. The tax effect of each type of temporary difference and carryforward reflected in deferred income tax benefits and liabilities as of December 31, 1993 and 1992 are as follows (expressed in thousands):
F. FINANCING
Long-term debt
At December 31, 1993 and 1992, long-term debt issues were outstanding as follows (expressed in thousands):
On July 8, 1992, the Company sold $100 million of 9 5/8% Notes due July 15, 1997. Proceeds from the sale of the Notes were used to retire the Company's 9.25% Debentures that matured July 15, 1992.
The Company's debentures and notes have restrictive covenants which provide that neither the Company nor any subsidiary may create, assume or suffer to exist any lien upon any principal property, as defined, to secure any indebtedness unless the debentures and notes shall be equally and ratably secured.
Transco has in place a $450 million working capital line with a group of fifteen banks. The Company is guarantor of up to $180 million of this working capital line. At December 31, 1993, Transco had no outstanding borrowings under this facility.
Transco also has in place a $50 million reimbursement facility dated as of December 31, 1993 between Transco and a group of five banks. This facility provides Transco the opportunity to obtain standby letters of credit under certain circumstances from the banks. The Company is guarantor of up to $20 million of the obligations that arise under this facility. At December 31, 1993, Transco had no amounts outstanding under this facility.
These credit facilities prohibit the Company from, among other things, incurring or guaranteeing any additional indebtedness (except for indebtedness incurred to refinance existing indebtedness), issuing preferred stock or advancing cash to affiliates other than Transco. Further, these credit facilities and Transco's indentures contain restrictive covenants which could limit Transco's ability to make additional borrowings and, therefore, under certain circumstances, its ability to repay advances or make capital contributions to the Company.
Sale of Receivables
In September 1993, the Company entered into a new program to sell monthly trade receivables, which replaced the Company's previous program. The new trade receivables program, which expires in September 1995, provides for the sale of up to $40 million of trade receivables without recourse. As of December 31, 1993 and December 31, 1992, $33.6 million and $43.3 million, respectively, of trade receivables were held by the investor.
Significant Group Concentrations of Credit Risk
As of December 31, 1993, the Company had trade receivables of $16.4 million. These trade receivables are primarily due from local distribution companies and other pipeline companies predominantly located in the Midwestern United States. The Company's credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. No collateral is required on these receivables.
G. EMPLOYEE BENEFIT PLANS
Retirement Plan
Substantially all of the Company's employees are covered under a retirement plan (Retirement Plan) offered by the Company. The benefits under the Retirement Plan are determined by a formula based upon years of service and the employee's highest average base compensation during any five consecutive years within the last ten years of employment. The Retirement Plan provides for vesting of employees' benefits after five years of credited service. The Company's general funding policy is to contribute amounts deductible for federal income tax purposes. Due to its overfunded status, the Company has not been required to fund the Retirement Plan since 1986. The Retirement Plan's assets, which are managed by external investment organizations, include cash and cash equivalents, corporate and government debt instruments, preferred and common stocks, commingled funds, international equity funds and venture capital limited partnership interests.
The Retirement Plan was amended effective November 15, 1991, to provide a Voluntary Window Retirement Program with special retirement benefits for those eligible members who elected to retire during the Window Period. The net cost of the program to the Retirement Plan was approximately $5.1 million.
The following table sets forth the funded status of the Retirement Plan at September 30, 1993 and September 30, 1992, and the amount of prepaid pension costs as of December 31, 1993 and 1992 (expressed in thousands):
Prepaid pension costs related to the Retirement Plan have been classified as other assets in the accompanying balance sheets.
The following table sets forth the components of net pension cost for the Retirement Plan, which is included in the accompanying financial statements, for the years ended December 31, 1993, 1992 and 1991 (expressed in thousands):
The projected unit credit method is used to determine the actuarial present value of the accumulated benefit obligation and the projected benefit obligation. The following table summarizes the various interest rate assumptions used to determine the projected benefit obligation for the years 1993, 1992 and 1991:
Pension costs are determined using the assumptions as of the beginning of the Retirement Plan year. The funded status is determined using the assumptions as of the end of the Retirement Plan year.
Postretirement Benefits Other than Pensions
The Company's Employee Welfare Benefit Plan provides medical and life insurance benefits to Company employees who retire under the Company's Retirement Plan with at least five years of service. The Employee Welfare Benefit Plan is contributory for medical benefits and for life insurance benefits in excess of specified limits.
In the first quarter of 1993, the Company adopted SFAS 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions," which requires the Company to accrue, during the years that employees render the necessary service, the estimated cost of providing postretirement benefits other than pensions to those employees. At the January 1, 1993 date of adoption of SFAS 106, the Company's postretirement benefits obligation (transition obligation) was $68 million which is being amortized over the remaining life of active participants.
The medical benefits are currently funded for all retired Company employees at a specified amount per quarter through a trust established under the provisions of section 501(c)(9) of the Internal Revenue Code.
The following table sets forth the Employee Welfare Benefit Plan's funded status at December 31, 1993, reconciled with the accrued postretirement benefits cost included in the accompanying balance sheet at December 31, 1993 (in thousands):
The following table sets forth the components of the net periodic postretirement benefit cost, net of deferred costs, which is included in the accompanying financial statements for the year ended December 31, 1993 (in thousands):
The annual expense is subject to change in future periods as a result of, among other things, the passage of time, changes in participants, changes in Employee Welfare Benefit Plan benefits and changes in assumptions upon which the estimates are made.
For measurement purposes as of December 31, 1993, the initial annual rate of increase in the per capita cost of covered health care benefits was assumed to be 12%. The rate was assumed to decrease gradually to 6% for the year 2005 and remain at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. To illustrate, increasing the assumed health care cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation for health care benefits as of January 1, 1994 by 16% and the aggregate of the service and interest cost components of the net periodic postretirement health care benefit cost for 1994 by 19%.
To determine the accumulated postretirement benefit obligation, the Employee Welfare Benefit Plan used a discount rate of 7.25% and a salary growth assumption of 5.0% per annum. Employee Welfare Benefit Plan assets are managed by external investment organizations and include cash and cash equivalents, commingled funds, preferred and common stocks and government and corporate debt instruments. The expected long-term rate of return on Employee Welfare Benefit Plan assets was 7% after taxes. Realized returns on Employee Welfare Benefit Plan assets are subject to federal income taxes at a sliding scale that increases up to a 39.6% tax rate.
In November 1993, the Company placed into effect a general rate case that provides for the increase in postretirement benefits costs pursuant to SFAS 106 to be collected in rates. Prior to November 1, 1993 the Company deferred the difference between its postretirement benefits expense accrued in 1993 under SFAS 106 and the amount it collected in rates and recorded a regulatory asset of approximately $5 million as of November 1, 1993. Pursuant to its rate case filing, the Company proposes to recover the regulatory asset in rates over a 36-month period beginning November 1, 1993.
The Company believes that all costs of providing postretirement benefits to its employees are necessary and prudent operating expenses and that such costs will continue to be recoverable in rates. Adoption of SFAS 106 did not have a material adverse effect on the Company's financial position or results of operations.
H. SALE OF SUBSIDIARY
On June 8, 1992, Transco and certain of its subsidiaries (including the Company) entered into a definitive agreement to sell their interests in certain gas gathering and related facilities for $65 million in cash, subject to certain adjustments. The sale, which was closed on July 20, 1992, included the stock of the Company's subsidiary, Texam. Of the total sales price, $12.5 million was allocated to the sale of Texam. The Company recognized a $6.9 million gain ($4.4 million after-tax) in connection with this sale.
I. FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash and Short-Term Financial Assets and Liabilities
For short-term instruments, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments, except for the Company's current maturities of long-term debt which is publicly traded. Therefore, the fair value of these maturities is estimated based on quoted market prices, less accrued interest, at December 31, 1993.
Long-Term Notes Receivable
The carrying amount for the long-term notes receivable, which are shown as advances to affiliates on the balance sheet, is a reasonable estimate of fair value. As discussed in Note A, the notes earn a variable rate of interest which is adjusted regularly to reflect current market conditions.
Long-Term Debt
All of the Company's debt is publicly traded; therefore, fair value is estimated based on quoted market prices, less accrued interest, at December 31, 1993 and 1992.
The carrying amount and estimated fair values of the Company's financial instruments as of December 31, 1993 and 1992 are as follows (in thousands):
J. SUPPLEMENTARY PROFIT AND LOSS INFORMATION
Major Customers
Listed below are sales and transportation revenues received from the Company's major customers in 1993, 1992 and 1991, portions of which are included in the refund reserve discussed in Note C (expressed in thousands):
Expenditures for Maintenance and Repairs
Expenditures for maintenance and repairs for the years ended December 31, 1993, December 31, 1992 and December 31, 1991, were $16.8 million, $14.1 million and $14.6 million, respectively.
K. QUARTERLY INFORMATION (UNAUDITED)
The following summarizes selected quarterly financial data for 1993 and 1992 (expressed in thousands):
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(1) Includes $6,948 gain on sale of subsidiary.
ITEM 9.

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not Applicable.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) 1.* Financial Statements
Included in Item 8, Part II of this Report
Report of Independent Public Accountants on Financial Statements and Schedules
Report of Management Responsibility for Financial Statements
Balance Sheets at December 31, 1993 and December 31, 1992
Statements of Income for the years ended December 31, 1993, December 31, 1992 and December 31, 1991.
Statements of Retained Earnings and Paid-In Capital for the years ended December 31, 1993, December 31, 1992 and December 31, 1991.
Statements of Cash Flows for the years ended December 31, 1993, December 31, 1992 and December 31, 1991.
Notes to Financial Statements
(a) 2.* Financial Statement Schedules
Included in Item 14, Part IV of this Report
Financial Statement Schedules for the years ended December 31, 1993, December 31, 1992 and December 31, 1991.
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
(a) 3. Exhibits
(b) Reports on Form 8-K
None. - ---------------
* Filed herewith
TEXAS GAS TRANSMISSION CORPORATION
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT (THOUSANDS OF DOLLARS)
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(1) Included in Transfers and Other Changes for Other Natural Gas Plant, for the year ended December 31, 1991, is $33.8 million related to transfers of gas stored underground-noncurrent.
TEXAS GAS TRANSMISSION CORPORATION
SCHEDULE VI -- ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (THOUSANDS OF DOLLARS)
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(1) Does not include amortization of intangible assets which are not classified as property, plant and equipment.
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.
TEXAS GAS TRANSMISSION CORPORATION
BY /s/ E. J. RALPH E. J. Ralph, Vice President and Controller
DATE March 16, 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 date indicated.