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

ITEM 1. BUSINESS.
GENERAL
Transco Energy Company is engaged primarily in the natural gas pipeline (Pipelines) and the natural gas marketing (Gas Marketing) businesses. Transco also has investments in coal mining and marketing operations (Coal), natural gas liquids processing, natural gas gathering and a nonoperating interest in a coalbed methane project in Alabama. In October 1991, Transco's Board of Directors approved a comprehensive strategic and financial plan (Plan) designed to stabilize Transco's financial position, improve its financial flexibility and restore its earnings. Since the Plan's adoption, Transco has made significant progress in the implementation of the Plan, including the sale of certain non-core and non-strategic businesses, reduction in capital expenditures, resolution of certain material litigation and improvement in its results of operations and financial flexibility.
In September 1993, Transco successfully exited the power generation business by selling Transco Energy Ventures Company (TEVCO) to National Power America, Inc. for $150 million. The sale of TEVCO allowed Transco to exit a business that it saw growing increasingly international. The exit was also consistent with the Company's strategic focus and near-term funding abilities. In August 1993, Transco transferred its interest in the coalbed methane properties in the Black Warrior Basin in Alabama to TECO Energy Inc., in exchange for $15.5 million and future production payments. The decision to make this transfer was based upon the Company's desire to eliminate the need for future capital investments and to improve earnings by eliminating losses incurred in the operation of the properties.
As used herein the terms "Transco" or the "Company" refer to Transco Energy Company together with its wholly-owned subsidiaries unless the context otherwise requires.
The number of full-time employees of Transco at December 31, 1993, was 4,583.
Set forth below is a description of the principal business segments of Transco. For financial information regarding the major industry segments, see the "Schedule of Segment Information" contained in the Consolidated Financial Statements incorporated herein by reference in Item 8 hereof.
PIPELINES
The Company's pipeline business is conducted through Transcontinental Gas Pipe Line Corporation (TGPL) and Texas Gas Transmission Corporation (Texas Gas). These companies, which are regulated by the Federal Energy Regulatory Commission (FERC), principally transport natural gas from the Gulf of Mexico and the Gulf Coast regions to markets in the eastern half of the United States through their respective 10,500 and 6,050 mile interstate pipeline systems.
Prior to 1984, interstate pipelines, including TGPL and Texas Gas, served primarily as merchants of natural gas, purchasing gas under long-term contracts with numerous producers in production areas and transporting and reselling gas to local utilities in market areas under long-term sales agreements. Such 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 FERC issued a series of orders which have resulted in a major restructuring of the natural gas transmission industry and its business practices. With 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 others and have it transported to the customers by pipelines.
Faced with these changing conditions, increased competition and declining bundled sales, TGPL and Texas Gas altered the manner in which they had traditionally conducted their businesses and began to transport a larger percentage of gas for customers that purchased such gas from others. In 1988, TGPL and
Texas Gas accepted certificates to become permanent open access pipeline systems under FERC Orders 436 and 500.
On April 8, 1992, the FERC issued Order 636 which made further 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 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, and the FERC approves, a different form of rate design methodology. Effective November 1, 1993, both TGPL and Texas Gas implemented their Order 636 restructuring plans. For a complete discussion of Order 636 see "Regulatory Matters -- Order 636" below.
As a result of the Order 636 requirement that a pipeline unbundle its merchant role from its transportation services, Transco determined to implement a plan to consolidate its gas marketing businesses under the common management of TGMC. In January 1993, TGMC, through an agency agreement, began to manage all jurisdictional sales of TGPL. In November 1993, TGMC, through an agency agreement, began to manage all jurisdictional sales of Texas Gas, except for the sale of gas purchased by Texas Gas under certain contracts with pricing provisions that are not variable market based which is being resold by Texas Gas at monthly auction pursuant to Order 636. See "Gas Marketing."
MARKETS
TGPL's principal markets encompass eleven Southeast and Atlantic seaboard states, and include the New York City and Philadelphia metropolitan areas. A large portion of the gas transported by TGPL to its market areas is used for space heating, resulting in substantially higher daily delivery requirements for TGPL's customers during the winter months than during the summer months. TGPL has working storage capacity in five underground storage fields, located on or near its pipeline system and/or market areas, and operates three of these storage fields. The certificated storage capacity available to TGPL and its customers is approximately 213 Bcf*.
Texas Gas' direct market area encompasses eight states in the South and Midwest, and includes the Memphis, Louisville, Cincinnati, Dayton, and Indianapolis metropolitan areas. Texas Gas also has indirect market access to Northeast markets through interconnections with Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation and Texas Eastern Transmission Corporation (Texas Eastern). A large portion of the gas transported by Texas Gas to its market areas is used for space heating, resulting in substantially higher daily requirements during the winter months than the summer months. Texas Gas owns and operates ten underground storage reservoirs in or near its market area, with certificated storage capacity available to Texas Gas of approximately 176.7 Bcf.*
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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, the term "Tcf" means trillion cubic feet, the term "MMcf/d" means million cubic feet per day, the term "MMBtu" means million British Thermal Units and the term "MMGals" means million gallons.
TGPL and Texas Gas' total system deliveries and the mix of sales and transportation volumes for the years 1993, 1992 and 1991 are shown below. Sales as shown below include only bundled sales. See "Gas Marketing."
TGPL's facilities are divided into six rate zones. Three are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.
As shown in the table above, TGPL's total market-area deliveries for 1993 were comparable to those in 1992. Production-area deliveries decreased 28.1 Bcf, or 14 percent for 1993 compared to 1992, primarily due to increased competition for production-area transportation. However, as a result of the new SFV rate structure that went into effect September 1, 1992, subject to refund, these decreased deliveries had no significant impact on TGPL's operating income.
Texas Gas' facilities are divided into five rate zones. Receipts and deliveries are made in four rate zones to service 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 was primarily attributable to the conversion of customers' firm sales service to firm transportation service due to Texas Gas' implementation of Order 636. The increase in transportation volumes was principally the result of the conversion of customers' sales service, additional firm service for TGPL and colder weather during the winter months of 1993 compared to the winter months of 1992. The revenues associated with short-haul transportation volumes are not material to Texas Gas.
PIPELINE PROJECTS
Liberty Pipeline Company
In 1992, Liberty Pipeline Company, a partnership of interstate pipelines and local distribution companies, filed for FERC approval to construct and operate a natural gas pipeline to provide 500 MMcf/d in firm transportation service to the greater New York City area. The partnership is comprised of subsidiaries of Transco and two other interstate pipelines and subsidiaries of three Transco customers in New York.
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. The pipeline will offer a new firm transportation route from TGPL and another interstate pipeline to a proposed new delivery point on Long Island near the John F. Kennedy Airport.
Liberty Operating Company (LOC), an affiliate of TGPL, will construct and operate the pipeline. LOC has begun design work, permit application, and survey and right-of-way acquisition. The FERC has issued a notice that it intends to prepare an Environmental Impact Statement associated with the Liberty Pipeline.
Transco Liberty Pipeline Company, an affiliate of TGPL, owns a 35 percent interest in the pipeline, which will be project-financed. Transco Liberty Pipeline Company expects its equity contribution to be approximately $14 million. In addition, TGPL anticipates investing approximately $78 million in existing TGPL facilities upstream of Liberty Pipeline to provide additional transportation capacity for subsequent delivery to the Liberty Pipeline. The expenditures involve looping existing facilities and adding compression in Pennsylvania and New Jersey. Texas Gas plans to spend approximately $80 million on expansion projects to provide upstream transportation capacity to the Liberty Pipeline. The expenditures involve constructing approximately 51 miles of pipeline looping from Kentucky to Ohio. The expansion will permit delivery of an additional 135 MMcf/d to Lebanon, Ohio, for subsequent delivery to Liberty Pipeline customers. The expenditures for the equity contribution as well as the majority of the expenditures for the TGPL and Texas Gas upstream expansions are expected to be made in 1995 and 1996.
Southeast Expansion Projects
In November 1993, TGPL filed for FERC approval of its Southeast Expansion Projects. These new expansion projects will provide additional firm transportation capacity to growing southeastern markets in Alabama, Georgia, South and North Carolina and Virginia.
The proposed Southeast Expansion Projects are expected to be phased into service beginning in 1994 and, upon completion, will provide a total of 200 MMcf/d of firm transportation capacity to TGPL's southeast customers by the 1996-1997 winter heating season. The new firm transportation capacity will extend from TGPL's Mobile Bay lateral interconnect, near Butler, Alabama, to delivery points upstream of TGPL's Compressor Station 165 near Chatham, Virginia. The expansion projects will include approximately 25 miles of pipeline replacement and looping and the installation of additional compression totaling approximately 70,000 horsepower. TGPL estimates the cost of the expansion to be $125 million and has proposed rates based on the SFV rate design methodology.
The 1994 Southeast Expansion Project (SE94) will provide 35 MMcf/d of incremental firm capacity by the 1994-1995 winter heating season. The 1995-1996 Southeast Expansion Project (SE95-96) will be constructed in two phases: Phase I will add 115 MMcf/d of incremental firm capacity for the 1995-1996 winter heating season, and Phase II will add the remaining 50 MMcf/d for the 1996-1997 winter heating season.
Subject to FERC approval, construction on SE94 is scheduled to begin in June 1994. TGPL expects to invest approximately $45 million in these projects in 1994.
Eminence Storage Field Expansion Project
During 1993, TGPL completed the first phase of its Eminence storage field expansion project, expanding the working capacity from 6 Bcf to 9 Bcf and increasing the withdrawal rate from 750 MMcf/d to 1.3 Bcf/d. The expansion of the salt-dome structure, located at TGPL's Compressor Station 77, near Seminary, Mississippi, will give TGPL additional flexibility to meet the peak-day and emergency demands of its customers. High deliverability from storage helps assure pipelines, such as TGPL, of gas availability for their customers during adverse weather conditions.
TGPL plans further expansions of the storage field in 1994 and 1995, allowing for withdrawals of up to 1.5 Bcf/d and ultimately increasing the working capacity of the storage field to 15 Bcf.
Mobile Bay Pipeline Expansion Project
In September, the FERC issued an order authorizing the joint ownership and expansion of TGPL's Mobile Bay lateral with Florida Gas Transmission Company (Florida Gas). The lateral transports gas from the prolific Mobile Bay gas supply basin to the TGPL mainline, near Butler, Alabama, and the expansion will increase the capacity from 462 MMcf/d to 829 MMcf/d. The expansion will be accomplished through the addition of compression facilities and will include a new interconnection on the lateral with the Florida Gas mainline.
The cost of the expansion project will be funded entirely by Florida Gas, and TGPL will receive approximately $13 million from Florida Gas for the sale of a partial interest in the lateral. The expansion will increase the TGPL portion of pipeline capacity by approximately 60 MMcf/d to 520 MMcf/d. The Mobile Bay lateral expansion is expected to be placed in service by December 1994.
Also, TGPL and Exxon have agreed to construct a two-mile pipeline in 1994 to allow for connection of Exxon's recently constructed treatment plant to the Mobile Bay lateral.
Both of these expansion projects will not only enhance TGPL's overall access to supply, but will also provide additional supply for the Southeast Expansion Projects.
West Tennessee Pipeline Expansion
In January 1994, Texas Gas received approval from the FERC to expand its Jackson-Ripley pipeline system located in northwest Tennessee to provide 4.6 MMcf/d of additional firm deliveries to three West Tennessee customers and to construct additional pipeline looping providing system security on that part of Texas Gas' 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 Texas Gas anticipates it will incur during the first half of 1994.
REGULATORY MATTERS
Rates
General
TGPL and Texas Gas' transportation rates are established 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. Rate design and the allocation of costs and return on equity between the demand and commodity rates also impact profitability.
TGPL, effective September 1, 1992 and Texas Gas, effective November 1, 1993, changed from the MFV method of rate design to the SFV method of rate design. Under MFV rate design, all fixed costs, with the exception of return on equity and income taxes, are included in a demand charge to customers and return on equity and income taxes are recovered as part of a volumetric charge to customers. Accordingly, under MFV rate design overall throughput has a significant impact on operating income. Under the SFV method of rate design, all fixed costs, including return on equity and income taxes, are included in a demand charge to
customers and all variable costs are recovered through a commodity charge to customers. While the use of SFV rate design limits TGPL and Texas Gas' opportunity to earn incremental revenues through increased throughput, it also minimizes TGPL and Texas Gas' risk associated with fluctuations in throughput.
TGPL
On June 4, 1992, the FERC issued its final order on rehearing in TGPL's Rate Settlement and Gas Inventory Charge (GIC) Settlement (Docket No. RP90-8). This order became effective in July 1992. As a result, in August 1992, TGPL made refunds of approximately $102 million, including interest, for differences between filed rates and settlement rates. Certain parties appealed the FERC's June 4, 1992 order to the United States Court of Appeals for the D.C. Circuit (D.C. Circuit Court). On December 17, 1993, the D.C. Circuit Court issued its opinion affirming the FERC's order, except for one issue not material to TGPL which was remanded to the FERC for further consideration.
On March 2, 1992, TGPL filed with the FERC a general rate case (Docket No. RP92-137). The general rate filing proposed an increase in transportation rates, based primarily on increases in operating and maintenance costs, including those associated with additional services provided to TGPL's markets since its last general rate filing, and increased cost of capital. The filing also included a change to SFV rate design and an increase in rate base resulting from additional plant and equipment costs and higher working capital requirements. On September 1, 1992, the increased rates went into effect subject to refund.
On September 17, 1992, the FERC issued a decision addressing the single issue of the appropriate rate of return in Docket No. RP92-137. The FERC, using a hypothetical capital structure based on the average capital structure of a group of seven publicly-traded companies with pipeline subsidiaries, determined TGPL's appropriate after-tax rate of return on equity to be 14.45%. The FERC did not determine TGPL's cost of debt and preferred stock, suggesting that this issue should be the subject of further proceedings in the context of the general rate case. Consequently, TGPL's current rates reflect an after-tax rate of return on equity of 14.45% but, consistent with the FERC order, the rates continue to reflect the cost of debt and preferred stock originally filed in the general rate case. The issue of the appropriate rate of return for TGPL is currently on appeal before the D.C. Circuit Court. TGPL appealed seeking to increase the rate of return and certain other parties have appealed seeking to lower the rate of return.
On May 3, 1993, TGPL filed with the FERC an Offer of Settlement (the Settlement) with regard to Docket No. RP92-137. On November 4, 1993, the FERC issued an order accepting the Settlement. The Settlement resolves all issues in Docket No. RP92-137 except (i) issues relating to TGPL's rate of return which are on appeal before the D.C. Circuit Court (see discussion above), and (ii) the issue of appropriate load factor for the design of TGPL's interruptible rates which the FERC referred to a hearing in Docket No. RP92-137 for prospective effect only (see "Regulatory Matters-Order 636" for discussion of additional issues referred to this hearing). On December 16, 1993, TGPL filed a request to accelerate partial refunds under the Settlement on the ground that those refunds could be made without prejudice to the pending requests for rehearing or clarification. TGPL's request was granted by order of the FERC dated February 14, 1994. In early 1994, TGPL will make the initial refunds (approximately $100 million including interest) under RP92-137. TGPL has previously provided a reserve for that refund. TGPL has also provided a reserve which it believes is sufficient for any additional refunds that may be required under Docket No. RP92-137.
Texas Gas
On April 29, 1993, Texas Gas filed a general rate case (Docket No. RP93-106), which, pursuant to the FERC's Suspension Order issued May 28, 1993, became effective 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 Texas Gas' Order 636 restructuring proceeding. Texas Gas is currently engaged in settlement proceedings regarding this case. Texas Gas 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.
Fuel Retention Proceedings
On February 23, 1989, the FERC issued an order which found, among other things, that TGPL had overcollected for fuel from transportation customers during the period April 1, 1984 to April 1, 1987. The order required TGPL to refund the difference between the amount collected and the rate allowed for fuel retention. Accordingly, TGPL made refunds to customers of approximately $35 million, including interest. In response to subsequent FERC orders, TGPL recalculated the refund and on November 30, 1993, under this revised calculation, TGPL made additional refunds of approximately $11.6 million, including interest. TGPL had previously provided a reserve that was sufficient for these refunds. On February 9, 1994, the FERC issued an order accepting TGPL's refund report, stating that TGPL made the refunds in accordance with the FERC's orders.
Order 94-A
In 1983, the FERC issued 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 several pipelines, including TGPL and Texas Gas, 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.
TGPL's GIC Settlement contains a provision pursuant to which TGPL's customers, with the exception of Columbia, have agreed not to contest the Order 94-A payments previously made by them. TGPL had billed to and recovered from Columbia approximately $7 million of Order 94-A costs. On October 26, 1993, TGPL and Columbia executed a letter agreement by which the parties resolved the amount of refunds to be made to Columbia in this proceeding. Pursuant to the letter agreement, TGPL and Columbia agreed that TGPL shall refund $1.4 million to Columbia, which amount is inclusive of principal and interest, in full and final settlement of all issues in this proceeding. The letter agreement was filed with the FERC on October 26, 1993 and is subject to approval by the FERC. TGPL has provided a reserve which is sufficient to cover the refunds provided for by the letter agreement. On January 26, 1994, Columbia filed a letter with the FERC stating that, due to developments in other pipeline company proceedings involving settlements of the issue of recovery of Order 94-A costs from Columbia, Columbia could no longer support, pending rehearing in those proceedings, the letter agreement between TGPL and Columbia. Columbia requested that the FERC hold any action on the letter agreement in abeyance pending action on rehearing in the other proceedings. On February 4, 1994, TGPL filed a response opposing Columbia's January 26 letter, stating that the October 26 letter agreement constitutes a valid and binding agreement between TGPL and Columbia and requesting that the FERC approve that letter agreement without delay. This matter is pending before the FERC.
On April 28, 1992, Texas Gas filed a settlement with the FERC providing for a reallocation of the Order 94-A payments previously collected from its 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 Texas Gas' purchased gas adjustment 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 Order 94-A costs. The effect of this order as issued would be to require Texas Gas 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. Texas Gas believes it is entitled to full recovery of these FERC-ordered costs. Texas Gas 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. Texas Gas
has provided a reserve which it believes is adequate to provide for any costs which it may ultimately be required to absorb.
Although no assurances can be given, Transco believes that the final resolution of the recovery of production-related costs will not have a material adverse effect on its financial position or results of operations.
Order 636
TGPL
On November 1, 1993, TGPL implemented Order 636. In connection with its implementation of Order 636, TGPL received orders from the FERC which, among other things, (i) required TGPL to revise its throughput projection for rate purposes to reflect a mix of throughput that includes a higher level of interruptible transportation, (ii) accepted TGPL's proposal for rolled-in rate treatment of its Mobile Bay facilities and exempted TGPL from having to reflect Mobile Bay transportation volumes and related revenues in an interruptible revenue crediting mechanism, (iii) approved a Stipulation and Agreement filed with the FERC by TGPL and its sales customers resolving certain sales service issues and mooting potential issues regarding TGPL's recovery of gas supply realignment (GSR) costs associated with TGPL's firm sales service, and (iv) referred to the hearing in Docket No. RP92-137 the following issues: TGPL's limited Section 4 filing with the FERC relating to TGPL's production-area rate design, the allocation of certain costs to TGPL's sales service, TGPL's use of a system-wide cost of service, the level of TGPL's gathering rates and aggregation/pooling services in TGPL's production area. Any changes in TGPL's rates or services resulting from this hearing would have a prospective effect only. Order 636 provides that pipelines should be allowed the opportunity to recover all prudently incurred transition costs, including GSR costs. TGPL does not expect to incur any GSR costs associated with its firm sales service. TGPL's non-GSR transition costs are anticipated to be in a range of $5 million to $10 million.
TGPL and certain other parties have filed appeals of certain of the FERC's orders to the D. C. Circuit Court. These appeals have been held in abeyance pending completion of the FERC's rehearing process and the expiration of the time to seek judicial review.
TGPL has expressed to the FERC concerns that inconsistent treatment under Order 636 of TGPL and its competitor pipelines with regard to rate design and cost allocation issues in the production area may result in rates which could make TGPL less competitive, both in terms of production-area and long-haul transportation rates. A hearing before a FERC Administrative Law Judge (ALJ) dealing with, among other things, TGPL's production-area rate design has been set for April 1994. TGPL is unable at this time to fully assess the competitive effect and resulting financial impact on TGPL of having to maintain its current production-area rate design which is different than that of its competitors.
Texas Gas
Texas Gas has restructured its business to implement the provisions of 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 Texas Gas' Order 636 compliance plan. Texas Gas filed revised tariff sheets and other changes pursuant to the October 1, 1993 order on October 18, 1993, which permitted implementation of Order 636 restructured services on November 1, 1993. On December 16, 1993, the FERC issued another order which required minor tariff modifications. Texas Gas submitted a filing in compliance with this order on January 7, 1994. This filing was accepted by an order issued on February 10, 1994. Texas Gas' analysis of Order 636 indicates that Texas Gas' transition costs are not currently expected to exceed $90 million, and are primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the auction process, as discussed below, and unrecovered purchased gas costs.
During 1993, as part of Texas Gas' restructuring under Order 636, Texas Gas engaged in negotiations which have resulted in the successful termination of approximately 90% of Texas Gas' deliverability under its gas purchase contracts with pricing provisions that are not variable market based. Gas purchased under its
remaining gas purchase contracts with pricing provisions that are not variable market based is being resold at a monthly auction pursuant to Order 636. Texas Gas continues to pay to the supplier the actual contract price and is entitled to file for full recovery of the difference between the contract price and the amount received for sales at auction as GSR costs under Order 636.
Through December 31, 1993, Texas Gas 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, Texas Gas had paid $13.4 million of such costs; the remaining $24.8 million was recorded as a current liability. Pursuant to Order 636, Texas Gas may file to recover 100% of these costs as GSR costs.
On January 28, 1994, Texas Gas submitted its first filing to recover $11.5 million of GSR costs pursuant to the transition costs recovery provisions of Order 636 and Texas Gas' 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. Texas Gas plans to make quarterly filings to allow recovery of its GSR costs as such costs are paid.
As part of its implementation of Order 636, Texas Gas 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 Texas Gas' "no-notice" transportation service, which allows customers to temporarily draw from Texas Gas' storage gas to be repaid in-kind during the following summer season.
Consolidated
Transco expects that any Order 636 transition costs incurred should be recovered from TGPL and Texas Gas' customers, subject only to the costs and other risks associated with the difference between the time such costs are incurred and the time those costs may be recovered from customers. Although no assurances can be given, Transco does not believe that the implementation of Order 636 by TGPL and Texas Gas will have a material adverse effect on its financial position or results of operations.
Order 500 and Order 528
Pursuant to Order 500, certain other pipelines from which Texas Gas made gas purchases (upstream pipelines) have received approval from the FERC to bill customers for their producer settlement costs. Texas Gas had, in turn, received FERC approval to flow these costs through to its customers under the Order 500 purchase deficiency-based direct bill methodology. Following the issuance of Order 528, which replaced the purchase deficiency-based recovery methodology, Texas Gas, in 1991, made a series of filings which reallocated these costs among customers. Pursuant to these filings, Texas Gas proposed to ultimately flow through to its customers approximately $64 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 Texas Gas. Although the total billings to Texas Gas are unresolved and Texas Gas may be required to refund certain amounts previously collected, Texas Gas believes that it will be entitled to ultimately collect all amounts that are billed by the upstream pipelines.
Under Order 528, Texas Gas may file to recover 75% of its producer settlement costs, including amounts it may be required to pay producers pursuant to indemnifications for royalties. On September 2, 1993, Texas Gas filed to recover 75% of $3.4 million of such producer settlement costs. 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 beginning October 3, 1993. See Note C "Legal Proceedings -- Other Litigation and Claims" of the Notes to Consolidated Financial Statements incorporated herein by reference in Item 8 hereof.
COMPETITION
General
Competition for gas transportation has intensified in recent years due to customer access to other pipelines, rate competitiveness between pipelines and the customers' desire to have more than one supplier. The FERC's stated purpose of Order 636 is to improve the competitive structure of the natural gas pipeline industry. TGPL and Texas Gas implemented Order 636 on November 1, 1993. Future utilization of pipeline capacity will depend on competition from other pipelines and alternative fuels, the general level of natural gas demand and weather conditions.
TGPL
TGPL and its primary market-area competitors (Texas Eastern, Columbia, Southern Natural Gas Company, Tennessee Gas Pipeline Company (Tennessee) and Iroquois Gas Transmission System) implemented Order 636 on their respective systems during the period June 1993 to November 1993. TGPL and its major competitors all employ SFV rate design for firm transportation as mandated by Order 636. However, TGPL has expressed to the FERC concerns that inconsistent treatment under Order 636 of TGPL and its competitor pipelines with regard to rate design and cost allocation issues in TGPL's production area may result in rates which could make TGPL less competitive, both in terms of production-area and long-haul transportation rates. A hearing before a FERC ALJ dealing with, among other things, TGPL's production-area rate design has been set for April 1994. TGPL is unable at this time to fully assess the competitive effect and resulting financial impact on TGPL of having to maintain its current production-area rate design which is different than that of its competitors.
TGPL does not expect to incur GSR costs associated with its firm sales service. TGPL's non-GSR transition costs are anticipated to be in a range of $5 million to $10 million; therefore, TGPL believes the demand charges to recover these costs will not make its rates noncompetitive in its markets. See "Regulatory Matters -- Order 636."
Although a significant portion of TGPL's firm customers have relatively secure residential and commercial end-users, virtually all of TGPL's local distribution customers (LDCs) have some price-sensitive end-users that could switch to alternate fuels. Approximately one-third of TGPL's customer deliveries are at risk to such fuel switching; however, a recent survey of TGPL's largest customers suggests that end-users will pay a premium to burn natural gas and that LDCs will aggressively price their system transportation to stay competitive in alternate-fuel markets.
Texas Gas
Texas Gas and its primary market-area competitors (ANR Pipeline Company, Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Texas Eastern, Columbia, Tennessee and Midwestern Gas Transmission Company) implemented Order 636 on their respective systems during the period May 1993 to November 1993. Texas Gas and its major competitors all employ SFV rate design for firm transportation as mandated by Order 636. Although some of Texas Gas' major competitors implemented Order 636 and SFV rates prior to Texas Gas' implementation, the impact on Texas Gas' throughput was minimal.
Texas Gas' analysis of Order 636 indicates that Texas Gas' 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 as discussed above and unrecovered gas purchase costs. Texas Gas believes that under 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. See "Regulatory Matters -- Order 636."
The end-use markets of several of Texas Gas' customers have the ability to switch to alternate fuels. To date, however, such losses from fuel switching have not been significant.
GAS SUPPLY
As a result of the fundamental business changes resulting from FERC Order 636, especially the shifting of the responsibility for gas supply from the pipeline companies to local distribution companies, committed proved gas reserves are no longer material to TGPL and Texas Gas' businesses. See "Pipelines," "Regulatory Matters -- Order 636" and "Capital Resources and Liquidity -- Other Capital Requirements and Contingencies -- Long-term gas purchase contracts" contained in Management's Discussion and Analysis of Financial Condition and Results of Operations incorporated herein by reference in Item 7 hereof.
GAS MARKETING
Prior to 1993, TGPL and Texas Gas were responsible for all jurisdictional gas sales to their pipeline customers and Transco Energy Marketing Company (TEMCO) and TXG Gas Marketing Company (TXG Marketing) were responsible for all non-jurisdictional gas sales. After FERC approval in January 1993, Transco began to implement a plan to consolidate its gas marketing businesses under the common management of TGMC. These changes were needed to more closely coordinate gas marketing operations to improve efficiencies, reduce costs and improve profitability. In January 1993, TGMC, through an agency agreement, began to manage all jurisdictional sales of TGPL. In November 1993, TGMC, through an agency agreement, began to manage all jurisdictional sales of Texas Gas, except for the sale of gas purchased by Texas Gas under certain contracts with pricing provisions that are not variable market based which is being resold by Texas Gas at a monthly auction pursuant to Order 636. See "Regulatory Matters -- Order 636." TGMC also manages all non-jurisdictional sales that are offered by TEMCO and TXG Marketing. TEMCO buys, arranges transportation for, and sells natural gas, primarily in the eastern and midwestern United States and Gulf Coast region. TXG Marketing markets natural gas, primarily to customers in the midwestern United States.
TGMC is also engaged, through its subsidiary, Transco Liquids Company (TLC), in the purchase and processing of natural gas and the sale of natural gas liquids and separation, terminalling and storage of condensate. TLC owns varying ownership interests in three natural gas processing facilities. TLC operates and owns a 50 percent joint ownership interest in the Cameron Meadows Complex, a gas processing facility located in southwestern Louisiana, with a capacity to extract natural gas liquids from an inlet gas stream of approximately 500 MMcf/d. TLC also has a 50 percent partnership interest in the Bee County Plant, a 60 MMcf/d cryogenic extraction facility located in south Texas as well as an approximately 19 percent joint ownership interest in the Sabine Pass Plant, a 200 MMcf/d cryogenic extraction facility located in southwestern Louisiana. TLC also processes natural gas at third-party owned facilities. In addition to its processing business, TLC owns and operates the Crystal Beach Separation Facility and owns the stock of the HI-BOL Pipeline Company which owns and operates the HI-BOL Pipeline. TLC's net investment in wholly-owned or joint venture natural gas processing and liquids separation and transportation facilities and HI-BOL Pipeline totaled $27.5 million at December 31, 1993.
The following table sets forth the Gas Marketing sales volumes during 1993, 1992 and 1991.
Gas sales volumes increased due primarily to the inclusion in 1993 of TGPL's sales service volumes of 234.5 Bcf and Texas Gas' sales service volumes of 6.9 Bcf. TGPL's sales service volumes in 1992 and 1991 were 221.1 Bcf and 241.6 Bcf, respectively. The revenues associated with such volumes in 1992 and 1991 were
reported in the Pipelines segment. See "Results of Operations -- Pipelines" contained in Management's Discussion and Analysis of Financial Condition and Results of Operations incorporated herein by reference in Item 7 hereof. Liquids sales volumes decreased due to processing curtailments beginning in May 1993 and the discontinuation of naptha processing in August 1992 due to product-price economics, which are largely dictated by crude oil prices.
Gas Marketing's profitability is determined by volumes and margins, both of which are heavily influenced by gas demand, alternate fuels, competition and commodity price volatility. Moreover, the costs associated with maintaining Gas Marketing's long-term supply portfolio must be recovered in premiums paid by customers pursuant to long-term contracts in order to avoid a loss on such sales to the spot market. See "Capital Resources and Liquidity -- Other Capital Requirements and Contingencies -- Long-term gas purchase contracts" contained in Management's Discussion and Analysis of Financial Condition and Results of Operations incorporated herein by reference in Item 7 hereof.
COMPETITION
Changes in the natural gas industry over the past several years have substantially increased competition for gas sales. TGMC's competitors include other natural gas marketers and producers.
COAL
Transco Coal Company (TCC) is engaged in the surface and deep mining, preparation and marketing of various grades of bituminous steam coal. In addition, TCC purchases minimal amounts of coal from independent producers for resale to customers. As used herein, the term TCC refers to Transco Coal Company, together with its wholly-owned subsidiaries, unless the context otherwise requires.
SALES AND MARKETING
TCC, through its subsidiaries, owns and currently operates 4 deep mines and 5 surface mines in eastern Kentucky and Tennessee. TCC sells coal, both under long-term supply agreements and in the spot market, to electric utilities and industrial customers located primarily in the southeastern United States. Sales in 1993 totaled 8.9 million tons, compared to 1992 sales of 9.0 million tons.
Generally under TCC's major sales agreements, contract duration may be extended at the option of the utility, quantities may be decreased or increased within specified ranges at the option of the utility, quantities may be decreased by a force majeure event causing a utility to decrease power production, prices may be renegotiated in certain cases and other adjustments may occur under certain conditions. TCC's long-term contracts contain provisions for adjustments to the base price of coal in response to variations in quality and changes in economic indices. All of TCC's contracts contain quality specifications relating to moisture, ash, sulfur content and heating value (Btu). Premiums are generally paid per Btu value above the guaranteed contract minimum.
COMPETITION
The sale of coal is highly competitive. TCC must compete with other coal producers in negotiating coal sales contracts and spot sales. The primary factors in competition for contract and spot sales are price, quantity and the quality of coal reserves, production costs and the availability of economical transportation. In addition, the level of economic activity, energy conservation and the cost of complying with various environmental regulations directly affect the demand for coal. Steam grade coal competes with other fuels such as nuclear, oil and natural gas.
TCC's competition includes the Kentucky operations of Cyprus Minerals Company, Arch Mineral Corporation, Sun Coal Company and Ashland Coal, Inc., although any coal operation with the ability to provide at competitive prices the quantity and quality of coal needed by TCC's current customers could impact TCC's future sales.
RESERVES
All of TCC's coal reserves are held under coal leases in Kentucky and Tennessee. The coal reserves controlled by TCC are primarily leased from independent landowners. Terms of these leases vary considerably; however, the majority of these leases contain provisions allowing TCC to mine such properties until the mineable and merchantable coal thereunder is exhausted, provided that certain minimum production levels are maintained and royalty payments are made.
The following table sets forth TCC's estimates of its coal reserves in Kentucky and Tennessee as of December 31, 1993. It should be noted that the amounts reported are estimates only, based on geological observations and assumptions, and no assurance can be given that the amounts presented will ultimately be recovered.
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(1) The coal deposits which constitute TCC's coal reserves may extend beyond the seams used in the reserve computations, although the extent of such deposits and the degree to which such deposits may be mineable cannot be determined without further exploration.
(2) The estimated reserves stated herein were determined by TCC's experience in mining the present reserves and data compiled from maps and tests within TCC's present reserves. Such reserves do not represent the amount of coal that will ultimately be mined, processed and shipped to customers. Constantly changing factors which affect mining of the reserves include: loss from extraction processes, loss from preparation and cleaning processes, marketability, present and future government laws and regulations, and changes in mining technology.
Transco has identified its coal mining and marketing business as a business for which an exit strategy will be developed. In the interim, a new mining plan has been adopted to improve profitability and preserve value.
OTHER INVESTMENTS
GAS GATHERING
Transco Gas Gathering Company (TGGC) owns non-jurisdictional and intrastate gas-gathering lines located offshore and onshore Texas, as well as the Magnolia Pipeline in Alabama. In total, TGGC owns or has an interest in more than 500 miles of pipeline, and most of the gathering lines connect to TGPL. These systems have a combined capacity of approximately 800 MMcf/d.
At year-end 1993, TGGC's net investment in wholly-owned and joint venture gas gathering lines, including the Magnolia Pipeline, totaled $173 million.
At December 31, 1993, TGGC's investment in the Magnolia Pipeline totaled $68 million. The ultimate recovery of TGGC's investment in the Magnolia Pipeline is dependent on transportation of gas produced in the Black Warrior Basin, including production from the properties transferred to TECO Coalbed Methane, Inc. (TECO), a subsidiary of TECO Energy, Inc. (see "Coalbed Methane" below), as well as transportation of gas from other sources.
COALBED METHANE
In 1989 Transco began investing in certain coalbed methane properties in the Black Warrior Basin in Alabama. The coalbed methane project has not performed up to the original expectations and the project has encountered higher-than-originally-anticipated costs. Commencing in October 1991, a comprehensive study was undertaken to reevaluate the performance and economic viability of the coalbed methane project. This study included, among other things, a review of both the developed and undeveloped properties, applied
technologies and procedures and the causes for the higher-than-anticipated costs. As a result of the study, Transco recorded in the fourth quarter of 1991 a charge to earnings of $97.0 million, $64.0 million after-tax, $2.18 per share, attributable to a reduction in the book value of the coalbed methane properties.
Transco, through its subsidiary Magnolia Methane Corp. (Magnolia), assumed operatorship of the coalbed methane project in February 1992. In order to eliminate the need for future capital investments by the Company and to eliminate losses incurred in the operation of these properties, on July 9, 1993, Magnolia agreed to transfer its interest in 500 wells in the Black Warrior Basin of Alabama to TECO. In exchange for the transfer of its interest, Magnolia received $15.5 million in cash plus future production payments based on various percentages of net proceeds, as defined, generated from gas production from the properties and tax credits under Section 29 of the Internal Revenue Code of 1986. The transaction was completed on August 6, 1993. The $15.5 million of proceeds were treated as a recovery of capitalized costs with no gain or loss recognized. Under the terms of the agreement, before Magnolia begins to receive payments for its nonoperating interest, TECO is entitled to recover its initial cash investment and a return thereon. Magnolia is entitled to receive production payments until the termination date which is the earlier of (i) December 31, 2005, or (ii) such date as it is determined that 85% of the economically recoverable reserves existing at July 1, 1993 have been recovered from the transferred properties. As of December 31, 1993, Transco had not received any payments pursuant to the agreement other than the initial $15.5 million cash payment. Although all future development costs will be borne by TECO, TECO is under no obligation to invest in or develop any gas production from the coalbed methane properties. Magnolia has agreed to indemnify TECO from certain liabilities (including environmental liabilities) relating to Magnolia's coalbed methane properties. Transco has guaranteed performance of Magnolia's obligations under the agreement and TEMCO's obligation to purchase gas from certain of the coalbed methane properties.
At December 31, 1993, a total of 500 wells had been drilled on the coalbed methane properties transferred to TECO, of which 322 were completed and 139 were producing gas at a combined rate of approximately 12 to 13 MMcf/d. Based on reserve engineering studies prepared by Ryder Scott Company and H.J. Gruy and Company, the Company estimates that proved gas reserves net to TECO and the Company's interest are approximately 75 Bcf as of January 1, 1994.
Transco has been advised by TECO that TECO's initial plans for the coalbed methane properties transferred from Magnolia include the completion of the shallow zones in an area with 75 producing wells because TECO believes that such development provides the best immediate opportunity for increases in production and favorable economic results from the required investment. Through December 31, 1993, TECO has made completions in shallow zones in five wells, four of which have been judged successful. During 1994, TECO expects to make shallow zone completions in additional wells that currently have completions in the deeper zones.
In another area, as of December 31, 1993, 145 wells have been drilled, of which 72 wells have been completed with 64 wells producing and 8 wells capable of production, but shut-in by TECO pending evaluation of these wells. Although no comprehensive evaluation plan has been prepared, in 1994 TECO expects to begin completing those wells that appear to provide the best opportunity for increased production. These wells may include nonproducing wells that have not been completed previously and/or producing wells with shallow zones that have not been completed. There are a number of shallow zones in this area that have not been completed. TECO expects to have its evaluation of this second area completed by the end of 1994.
In a third area, which is essentially an unevaluated area, there were 280 wells, 175 wells in which deep zones had been completed with 27 wells having been placed on production. However, all 27 wells, which were producing gas and water, have been shut-in since August 1993 because of low gas production volumes. No shallow zones have been completed in this area. From December 1993 through February 1994, TECO released three leases with 20 uncompleted wells and plans to release a fourth lease with 11 uncompleted wells in April 1994. TECO has advised Transco that it expects to have an evaluation of this area completed by the end of 1995.
Transco's remaining investment is subject to a ceiling test that limits the investment to the aggregate of the present value of future net revenues of proved properties and the lower of cost or fair value of unproved properties. Transco's limitation at December 31, 1993, was calculated using estimated future production payments to be received from TECO based on year-end gas prices and the cost of currently unevaluated properties. Based on that calculation, Transco recorded a non-cash charge of $70.0 million, $45.5 million after-tax, $1.16 per share, to reduce the book value of its nonoperating interest in the coalbed methane properties.
At December 31, 1993, Transco's investment totaled $131 million (after the effects of the $97 million charge in 1991, the $70 million charge in 1993 and the $15.5 million of cash proceeds received from TECO). Of the total $131 million investment, approximately $93 million relates to Transco's investment in unproved properties and was incurred primarily during 1991 and prior years. These unproved properties are excluded from amortization until a determination has been made as to the existence of proved reserves or that an impairment has occurred. Transco will continue to monitor the status of the unproved properties as well as TECO's future plans for development of the unproved properties.
There are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production and the timing and amount of future costs. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way and estimates of other engineers might differ materially from those of Ryder Scott Company and H.J. Gruy and Company. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate, and, as a general rule, reserve estimates based upon volumetric analysis are inherently less reliable than those based on lengthy production history. Accordingly, reserve estimates are often different from the quantities of oil and gas that ultimately are recovered.
The ultimate recovery of Transco's remaining investment depends on production from the properties and future gas prices. The Company cannot predict at this time the ultimate results of these operations or the amounts of reserves that may ultimately be recoverable. If future development operations do not result in establishing sufficient reserves to recover the Company's remaining coalbed methane investment, or if other factors cause the Company's evaluation of its investment to diminish, additional reductions in the book value of the Company's investment would be required in future periods through non-cash charges to earnings. Any resulting non-cash charge to earnings could reduce the Company's financial flexibility, including its ability to remain in compliance with certain restrictive provisions in various debt instruments and to pay dividends on its capital stock.
OFFICE BUILDING
TGPL has a 20-year lease agreement for 1,005,478 square feet at its headquarters building in Houston which expires in 2004. The lease is with Transco Tower Limited (TTL), a partnership in which Transco has an indirect 12.5% interest. For information concerning lease commitments see Note M of the Notes to Consolidated Financial Statements incorporated herein by reference in Item 8 hereof. On November 3, 1993, Transco received notice from McCue Street Investors Corporation ("McCue"), a partner in TTL, indicating that McCue had elected to initiate the Buy/Sell procedure pursuant to the TTL Partnership Agreement. Under the Buy/Sell procedure, McCue, the 75% partner in TTL, has offered to Post Oak/Alabama Partnership (PO/A), the 25% partner in TTL (of which Transco Tower Realty, Inc. a wholly owned subsidiary of Transco, owns a 50% interest), the option of either (i) buying McCue's interest in TTL for approximately $225 million or (ii) selling the PO/A interest in TTL to McCue for the net asset value of PO/A's interest in TTL. In the latter case, it is not anticipated that Transco's share of any net sales proceeds would be significant. PO/A has 270 days from the date of the offer to accept either of the two alternatives.
REGULATION
INTERSTATE GAS PIPELINE OPERATIONS
TGPL and Texas Gas are subject to regulation by the FERC as "natural gas companies" 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. TGPL and Texas Gas hold certificates of public convenience and necessity issued by the FERC authorizing them to construct and operate all pipelines, facilities and properties now in operation for which certificates are required.
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 TGPL and Texas Gas to charge natural gas sales rates that are market-based. As necessary, TGPL and Texas Gas file with the FERC changes in their respective transportation and storage rates and charges designed to allow them to recover fully their costs of providing service to their interstate systems' customers, including reasonable rates 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.
TGPL and Texas Gas also are 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 their interstate gas transmission facilities.
COAL OPERATIONS
The coal mining industry is subject to a number of federal, state and local statutes and regulations relating to health and safety standards and protection of the environment. These laws require procedures for obtaining mining permits and posting bonds, subject mining operations to compliance inspections, impose land reclamation responsibilities and control the discharge of water from mines and related facilities. Failure to comply with these laws may result in closure of mines, bond forfeitures and permit revocation, and other civil and criminal fines and penalties.
The Surface Mining Control and Reclamation Act of 1977, as amended, and the regulations promulgated thereunder by the Federal Office of Surface Mining Reclamation and the enforcement thereof by the Department of the Interior, established mining and reclamation standards for all aspects of surface mining as well as certain aspects of underground mining.
TCC's operations are also subject to the federal Clean Air Act, as amended, and the federal Water Pollution Control Act, as amended, and similar state laws which regulate the discharge of materials into the environment. While it is not possible to quantify the costs of compliance with these statutes, the costs have been and are expected to be significant. TCC believes that its operations are in substantial compliance with the foregoing legislation.
For the past several years, TCC has been liable under federal legislation for the payment of benefits to coal miners with pneumoconiosis (black lung). The Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977 (1977 Act) expanded the benefits for black lung disease and levied a tax on production of $0.50 per ton on underground mined coal and $0.25 per ton on surface mined coal, but not to exceed 2% of the sales price. Since the enactment date, this tax has increased twice. Effective April 1, 1986, the rates are $1.10 per ton for underground mined coal and $0.55 per ton for surface mined coal, but, not to exceed 4.4% of the sales price. In addition, the Black Lung Benefits and Revenue Amendments Act of 1981 (1981 Act) provides that certain claims which had previously been assigned to coal operators will be transferred to the Black Lung Disability Trust Fund. Further, the 1981 Act tightened standards set by the 1977 Act for establishing and maintaining eligibility for benefits. In addition to contributing to the federal
black lung program, TCC has established a reserve of approximately $7.1 million to cover future black lung payments.
With regard to quality of coal, important criteria include Btu, and sulfur and ash content. Many customers are required by environmental and other considerations to restrict their consumption of high sulfur content coal, although certain amounts of sulfur may be required by certain other users. TCC is able to meet current sulfur content requirements under existing sales agreements.
ENVIRONMENTAL
Transco and certain of its subsidiaries are subject to extensive federal, state and local environmental laws and regulations which affect Transco's operations related to the construction and operation of pipeline facilities, oil and gas exploration, development and production and coal mining. 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. Transco and certain of its subsidiaries' 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 the 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, TGPL and Texas Gas have had studies underway to test their 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, TGPL and Texas Gas estimate 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 $60 million to $75 million. 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. TGPL and Texas Gas are continuing to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 1993, Transco had a reserve of approximately $60 million for these estimated costs.
TGPL and Texas Gas consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, since they are prudent costs incurred in the ordinary course of business. To date, TGPL and Texas Gas have been permitted recovery of environmental costs incurred, and it is their intent to continue seeking recovery of such costs, as incurred, through rate filings. Therefore, these estimated costs of environmental assessment and remediation have been recorded as regulatory assets.
Since 1989, TGPL has been involved in discussions with the Pennsylvania Department of Environmental Resources (PADER) concerning environmental conditions at TGPL's operating sites in Pennsylvania. These discussions have resulted in the execution of a consent order and agreement in 1992 between PADER and TGPL. TGPL agreed to conduct an environmental assessment and remediation program at its Pennsylvania sites, fund certain beneficial environmental projects, pay oversight costs and pay a $425,000 civil penalty. Of such penalty, $142,000 remains to be paid in May 1994. The estimated costs of the environmental assessment and remediation program are included in the $60 million to $75 million range discussed above.
TGPL and Texas Gas have both used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. TGPL and Texas Gas have worked closely with the Environmental Protection Agency (EPA) and state regulatory authorities regarding PCB issues, and both have programs to assess and remediate such conditions where they exist, the costs of which are a significant portion of the $60 million to $75 million range discussed above. Proposed civil penalties have been assessed by the EPA against another major pipeline company for the alleged improper use and disposal of PCBs. Although
similar penalties have not been asserted against TGPL or Texas Gas to date, no assurances can be given that the EPA may not seek such penalties in the future.
TGPL has been named as a potentially responsible party (PRP) in one Superfund waste disposal site, the Combustion Inc. site, and in two state sites. Texas Gas has either been named as a PRP or received an information request regarding its potential involvement in four Superfund sites and one state site; while Transco Exploration Company (TXC), for itself and as managing general partner of Transco Exploration Partners, Ltd. has been named as a PRP in three Superfund sites and in two state sites. Based on present volumetric estimates, TGPL's exposure for remediation of the Combustion, Inc. site is estimated to be $500,000; Texas Gas' estimated aggregate exposure is approximately $500,000; and TXC's estimated exposure at two of the Superfund sites where it has been named as a PRP is less than $100,000. TXC's estimated exposure at the third Superfund site, based on a 1993 reallocation by the EPA, is approximately $300,000. TXC and TGPL's estimated individual exposure at each of the two state sites where they have been named as PRPs is less than $100,000 per site. The estimated remediation costs for all such sites have been included in Transco's environmental reserve discussed above. 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 amounts described above. Although no assurances can be given, Transco does not believe that the PRP status of TGPL, Texas Gas nor TXC will have a material adverse effect on its financial position or results of operations.
Transco and certain of its subsidiaries are 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. Transco is installing new emission control devices where required and conducting certain emission testing programs to comply with the federal Clean Air Act standards and the 1990 Amendments. 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. Both TGPL and Texas Gas have compressor stations in ozone non-attainment areas that could require substantial additional air pollution reduction expenditures, depending on the requirements imposed. While it will not be possible to estimate the ultimate costs of compliance with these new requirements until the states approve TGPL's proposed plans for modifications, Transco expects that significant capital spending may be required to modify Transco's facilities, particularly the compressor engines along TGPL's pipeline system. 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 $20 million to $35 million over the next five years and will be recorded as assets as the facilities are added.
ITEM 2.



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

ITEM 3. LEGAL PROCEEDINGS.
The information required by this item is contained in Note C of the Notes to Consolidated Financial Statements incorporated herein by reference in Item 8 hereof.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during the fourth quarter of the fiscal year covered by this report.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers as such term is defined in Rule 3b-7 promulgated under the Securities Exchange Act of 1934, as amended, of the Company as of March 7, 1994.
With the exception of the following, all officers of the Company have been employed by the Company or its subsidiaries for more than the last five years.
John P. DesBarres joined Transco in October 1991 as President and Chief Executive Officer. He was elected Chairman of the Board in May 1992. Prior to joining Transco, Mr. DesBarres served from April 1988 through September 1991 as Chairman, President and Chief Executive Officer of Santa Fe Pacific Pipelines, Inc. Prior to joining Santa Fe, he served as President of Sun Pipe Line Company, a subsidiary of Sun Company, Inc., a diversified energy company.
Nicholas J. Neuhausel joined Transco in June 1993 as Senior Vice President -- Human Resources & Administration. Prior to joining Transco, Mr. Neuhausel held various positions with Sun Company, Inc., a diversified energy company, and its subsidiaries, including Vice President of Human Resources and Administration.
The officers of the Company serve at the pleasure of the Board of Directors. No family relationship exists between any of them.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The information required by this item appears below and in Notes F and G of the Notes to Consolidated Financial Statements incorporated by reference in Item 8 hereof.
Transco common stock is traded on the New York Stock Exchange and the Pacific Stock Exchange. The range of New York Stock Exchange composite trading prices and dividends paid during 1993 and 1992 by quarters were as follows:
The approximate number of holders of Transco common stock was 38,000 as of February 16, 1994. The approximate number of record holders as of the same date was 15,700.
TRANSCO ENERGY COMPANY AND SUBSIDIARIES
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA (EXPRESSED IN THOUSANDS, EXCEPT FOR PER SHARE AMOUNTS)
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(1) Excludes the results of Texas Gas prior to its April 3, 1989 acquisition date.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
The information required by this item appears under the caption "Financial Review" on pages 31 through 48 of the Annual Report and is incorporated herein by reference.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required by this item appears on pages 49 through 87 of the Annual Report and is incorporated herein by reference.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
Transco will file a definitive proxy statement with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934 (the Proxy Statement) not later than 120 days after the end of the fiscal year covered by this Form 10-K, relating to Transco's annual meeting of stockholders to be held on May 17, 1994. Information required by Part III will appear in the Proxy Statement and is incorporated herein by reference.
PART IV
ITEM 14.







ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
A. INDEX
The following schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto incorporated by reference herein:
I, II, VII, XI, XII and XIII.
3. EXHIBITS:
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
B. REPORTS ON FORM 8-K
Transco filed a Current Report on Form 8-K dated October 25, 1993, which reported the settlement of the Corpus Christi lawsuit and the charge to earnings related thereto.
C. OTHER MATTERS
For the purposes of complying with the amendments to the rules governing Form S-8 (effective July 13, 1990) under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into registrant's Registration Statements on Form S-8 File No. 33-28358 (filed April 28, 1989), No. 2-71716 (filed April 10, 1981), No. 33-11721 (filed February 3, 1987), No. 2-64025 (filed April 6, 1979), No. 33-31179 (filed September 20, 1979), No. 33-40495 (filed May 9, 1991), No. 33-44478 (filed December 12, 1991) and No. 33-47727 (filed May 7, 1992):
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
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, ON THIS 23RD DAY OF MARCH, 1994.
TRANSCO ENERGY COMPANY REGISTRANT
BY: LARRY J. DAGLEY (LARRY J. DAGLEY) Senior Vice President, Chief Financial Officer & Controller (principal financial officer and principal accounting officer)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED ON THIS 23RD DAY OF MARCH, 1994, BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES INDICATED.
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by reference of our report dated February 18, 1994 included in the 1993 annual report to stockholders of Transco Energy Company (Transco) and incorporated by reference in this Form 10-K, and of our report dated February 18, 1994, on the financial statement schedules included in this Form 10-K into Transco's previously filed registration statements on Form S-8 (File Nos. 2-64025, 2-71716, 33-28358, 33-11721, 33-31179, 33-40495, 33-44478 and 33-47727).
ARTHUR ANDERSEN & CO.
Houston, Texas March 22, 1994
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULES
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS, TRANSCO ENERGY COMPANY:
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements included in Transco Energy Company's 1993 annual report to stockholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 18, 1994. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The financial statement schedules listed in the index to Part IV, Item 14 are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These financial statement schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated 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 consolidated financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas February 18, 1994
TRANSCO ENERGY COMPANY
SCHEDULE III -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENT OF OPERATIONS (THOUSANDS OF DOLLARS)
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* Eliminated in consolidation.
This condensed statement should be read in conjunction with the Consolidated Financial Statements and Notes thereto which are incorporated herein by reference in Item 8 hereof.
TRANSCO ENERGY COMPANY
SCHEDULE III -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED BALANCE SHEET (THOUSANDS OF DOLLARS)
ASSETS
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* Eliminated in consolidation.
This condensed statement should be read in conjunction with the Consolidated Financial Statements and Notes thereto which are incorporated herein by reference in Item 8 hereof.
TRANSCO ENERGY COMPANY
SCHEDULE III -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT CONDENSED STATEMENT OF CASH FLOWS (THOUSANDS OF DOLLARS)
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* Eliminated in consolidation.
** 1992 includes $15,000 of common stock sold to a subsidiary, which is eliminated in consolidation.
This condensed statement should be read in conjunction with the Consolidated Financial Statements and Notes thereto which are incorporated herein by reference in Item 8 hereof.
TRANSCO ENERGY COMPANY
SCHEDULE IV -- INDEBTEDNESS OF AND TO RELATED PARTIES -- NOT CURRENT FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS)
Periodically, for consolidated cash management purposes, certain wholly owned subsidiaries make interest bearing advances to Transco Energy Company (Transco) and Transco makes interest bearing advances to certain of its wholly owned subsidiaries. The advances are represented by demand notes bearing interest at the rate of 1.5% below the prime rate of Citibank, N.A. The managements of Transco and the respective subsidiaries are of the opinion that such advances are of a noncurrent nature and do not expect to demand repayment during 1994.
TRANSCO ENERGY COMPANY
SCHEDULE IV -- INDEBTEDNESS OF AND TO RELATED PARTIES -- NOT CURRENT FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS)
TRANSCO ENERGY COMPANY AND SUBSIDIARIES
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT (1) FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS)
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(1) For a discussion of the methods and rates used to compute depreciation, depletion and amortization, this schedule should be read in conjunction with Note A of the Notes to Consolidated Financial Statements thereto which are incorporated herein by reference in Item 8 hereof.
(2) Transco acquired Texas Gas Transmission Corporation on April 3, 1989. Included in Natural Gas Transmission Plant as of the date of acquisition was an aggregate of $226 million related to amounts in excess of the original cost of the regulated facilities which is being amortized over the estimated life of the assets acquired.
(3) Includes assets acquired in the Corpus Christi litigation settlement.
(4) Transco's investment in the coalbed methane properties has been converted to a nonoperating interest and therefore has been reclassified from the Company's operating property, plant and equipment to other assets.
(5) Transfer from current gas stored underground to noncurrent gas stored underground included in property, plant and equipment.
TRANSCO ENERGY COMPANY AND SUBSIDIARIES
SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS)
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(1) Amortization charged to income and credited to property, plant and equipment.
(2) Excludes depreciation and amortization charged to income on other assets not included in property, plant and equipment.
(3) Includes a charge attributable to a reduction in the book value of conventional oil and gas properties.
(4) Transco's investment in the coalbed methane properties has been converted to a nonoperating interest and therefore has been reclassified from the Company's operating property, plant and equipment to other assets.
(5) Includes a charge attributable to a reduction in the book value of the coalbed methane properties.
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TRANSCO ENERGY COMPANY AND SUBSIDIARIES
SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS)
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(1) Includes deductions of $2,639 as a result of sale of TEVCO.
TRANSCO ENERGY COMPANY AND SUBSIDIARIES
SCHEDULE IX -- SHORT-TERM BORROWINGS FOR YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (THOUSANDS OF DOLLARS EXCEPT INTEREST RATES)
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(1) Reference is made to Management's Discussion and Analysis of Financial Condition and Results of Operations and Note E of the Notes to Consolidated Financial Statements which are incorporated herein by reference in Items 7 and 8 hereof.
(2) Total of daily outstanding principal divided by the actual number of days in the year.
(3) Actual interest expense on short-term borrowings divided by the average borrowings outstanding during the period.
TRANSCO ENERGY COMPANY AND SUBSIDIARIES
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION (THOUSANDS OF DOLLARS)
INDEX TO EXHIBITS