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.
On December 12, 1994, Transco and The Williams Companies, Inc. (Williams) announced that they had entered into a merger agreement, which was amended on February 17, 1995, pursuant to which Williams agreed to commence a cash tender offer to acquire up to 24.6 million shares, or approximately 60%, of the outstanding shares of Transco's common stock for $17.50 per share. The cash offer would then be followed by a stock merger in which each share of Transco's common stock not purchased in the tender offer would be exchanged for 0.625 of a share of Williams' common stock. Pursuant to the merger agreement, on January 18, 1995, Williams accepted for payment 24.6 million shares of Transco's common stock for $17.50 per share as the first step in acquiring the entire equity interest of Transco. The conversion of the remaining outstanding shares of Transco's common stock to Williams' common stock will occur at the effective date of the merger, which is projected to be in April 1995.
Williams has indicated that it intends to cause Transco, as promptly as practicable following the merger and subject to receipt of any necessary consents, to declare and pay as dividends to Williams all of Transco's interests in its principal operating subsidiaries, including the Company.
Williams has indicated that is also intends to maintain and expand the existing core businesses of Transco, including the Company, and to promptly pursue new business opportunities made available as a result of the merger. In order to prepare for these opportunities, in January 1995, the Boards of Directors of Transco and Williams approved a proposed recapitalization plan for Transco under which Williams will advance or con- tribute to Transco up to an estimated $950 million to execute the proposed plan.
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*. This storage permits
_______________ * 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.
the Company's customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter periods. 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
Prior to 1984, 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 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 others and have it transported by the pipelines to the customers.
Faced with these changing conditions, increased competition and declining sales, the Company altered the manner in which it had traditionally conducted its business and began to transport a larger percentage of gas for customers that purchased such gas from others. As excess natural gas became available and prices declined, transportation of customer-owned gas increased. In 1988, the Company accepted a certificate and became a permanent open access pipeline system under FERC Orders 436 and 500.
During 1992, the FERC issued Orders 636, 636-A and 636-B (FERC Order 636) which made further 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 including equal access to all sources of gas; providing "no-notice" firm transportation services that are equal in quality to bundled sales service; establishing a capacity release program; 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 all prudently incurred costs associated with compliance
under FERC Order 636 (transition costs), including unrecovered gas costs and gas supply realignment (GSR) costs. FERC Order 636 is 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 con-tracts under the blanket certificate issued to it pursuant to that order. 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 three remaining customers with a total deliverability obligation of substantially less than 0.1 Bcf per day.
The only remaining sales administered by the Company are volumes purchased under 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:
Year Ended December 31, System deliveries (Bcf): 1994 1993 1992
Sales - 0% 51.5 7% 80.4 11% Long-haul transportation 602.9 77 519.6 67 402.2 55 Total mainline deliveries 602.9 77 571.1 74 482.6 66 Short-haul transportation 183.1 23 204.0 26 244.2 34 Total system deliveries 786.0 100% 775.1 100% 726.8 100%
The Company's facilities are divided into five rate zones. Generally, gas delivered in the northern four zones is classified as long-haul transportation. Gas delivered in the southernmost zone is classified as short-haul transportation. The Company's sales under the FERC Order 636 environment are generally made in the southernmost zone; however, the sales are made off system and, therefore, do not constitute system deliveries.
The decline in gas sales in 1993 and 1994 primarily was attributable to the Company's implementation of FERC Order 636. The increase in
transportation volumes resulted primarily from increased throughput in connection with restructured services resulting from the implementation of FERC Order 636 and increased service to other interstate natural gas pipelines. 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).
Year Ended December 31, 1994 1993 1992
The Cincinnati Gas & Electric Company Sales 9.3 1.0 3.0 Long-haul transportation 22.3 23.6 24.0
Indiana Gas Company, Inc. Sales 4.8 8.6 13.4 Long-haul transportation 25.9 21.9 19.1
Louisville Gas and Electric Company Sales - 5.3 15.3 Long-haul transportation 45.6 43.2 33.4
Transcontinental Gas Pipe Line Corporation Long-haul transportation 79.3 52.5 26.8
Western Kentucky Gas Company Sales 3.6 8.7 12.3 Long-haul transportation 28.4 21.1 16.0
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 pipelines 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 Orders 500 and 528, 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, made filings with the FERC for approval to flow these costs through to its customers. . On August 4, 1994, the FERC issued an order approving the settlement agreements of the Company and its upstream pipelines. Pursuant to the settlements, on September 30, 1994, the Company flowed through to its former sales customers $39.9 million. This order resolves all the Company's issues related to the flowthrough of upstream pipelines' producer settlement costs.
In September 1993, the Company filed to recover 75% of $3.4 million of its producer settlement costs under FERC Order 528 which resulted from reimbursements to producers for certain royalty payments. In December 1994, the FERC approved a settlement allowing for recovery of $0.9 million through direct bill and $1.7 million through a volumetric surcharge, both of which were 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 1990, the United States Court of Appeals for the District of Columbia overturned the FERC's authorization for pipelines to directly 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.
In April 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 Purchased Gas Adjustment (PGA) mechanism. In February 1993, the FERC
issued an order approving the settlement. On January 12, 1994, the FERC found that it 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 purchased gas costs and absorb the remaining $5.4 million. The Company filed for rehearing of this order and received an extension staying the effectiveness of this order until 30 days after the FERC's ruling on rehearing. On October 18, 1994, the FERC issued its "Order Denying Rehearing" which affirmed its January 12, 1994 order. On November 17, 1994, the Company made $4.3 million in refunds and filed for and received a stay of the order's requirement to make the remaining $9.2 million of refunds by November 17, 1994. The Company continues to believe that it is entitled to full recovery of these FERC-ordered costs and has filed a court appeal. On January 17, 1995, the Company filed a joint motion with Columbia, the party due the remaining refunds, to extend the time for making refunds until the court rules. The Company believes that its reserve of $5.4 million, plus interest, for this matter is adequate to provide for any costs the Company may ultimately be required to absorb.
FERC Order 636
Effective November 1, 1993, the Company restructured its business to implement the provisions of FERC Order 636 pursuant to a series of filings approved by the FERC. FERC Order 636 provides that pipelines should be allowed the opportunity to recover all prudently incurred transition costs. The Company's transition costs, which are not currently expected to exceed $90 million, are primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the Company's monthly gas auction process and unrecovered purchased gas costs. 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. Certain parties are, however, challenging the Company's right to fully recover its GSR costs. Settlement proceedings are pending at the FERC. Through December 31, 1994, the Company had paid a total of $46.4 million for GSR costs, primarily as a result of certain GSR contract terminations. During 1994, the Company made four quarterly filings to recover $37.8 million, plus interest, 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 August 1994, which are expected to be recovered via demand surcharges on its firm transportation rates. The Company continues to make quarterly filings to allow recovery of 90% of its GSR costs as such costs are paid. The remaining 10% of GSR costs is expected to be recovered from interruptible transportation service. On December 29, 1994, as revised on February 13, 1995, the Company made a filing to reflect that, for the ten months ended August 31, 1994, the Company allocated to and recovered from interruptible transportation service $4.2 million of GSR costs, pursuant to its FERC-approved Gas Tariff.
Pursuant to FERC Order 636, the Company terminated its PGA clause on November 1, 1993. The Company's right to file for future recovery, via additional direct billings, of pre-November 1, 1993 adjustments to purchased gas costs, was to expire on July 31, 1994. However, the Company
filed for and received an extension of the deadline for certain costs in dispute until the later of October 31, 1995 or 90 days after the final nonappealable resolution of any litigation, arbitration or administrative proceeding. During 1994, the Company made two filings to recover $12.3 million of pre-November 1, 1993 unrecovered purchased gas costs. The Company has no outstanding deferred gas cost issues pending in any other proceeding.
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, results of operations or net cash flows.
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 three to five years under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $6 million to $8 million. As of December 31, 1994, 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 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 $6 million to $8 million range discussed above. Civil penalties have been assessed by the EPA against other major natural gas pipeline companies 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 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 $6 million to $8 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, results of operations or net cash flows.
The Company considers 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, the Company has been permitted recovery of environmental costs incurred, and it is the Company's 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 in the accompanying balance sheets.
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. The Company is 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. 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 $1.3 million to $2.3 million over the next three to 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 (1) costs of providing service, (2) allowed rate of return, including the equity component of the Company's capital structure, and (3) volume throughput assumptions. 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 1993, the Company filed a general rate case (Docket No. RP93- 106) which became effective on November 1, 1993, subject to refund. The 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. A settlement agreement regarding the general rate case was filed on June 14, 1994, approved on September 21, 1994 and became final on October 21, 1994. On December 20, 1994, the Company made refunds of approximately $42.2 million, including interest. The Company previously had provided a reserve for these refunds.
On September 30, 1994, the Company filed a general rate case (Docket No. RP94-423) which will be effective April 1, 1995, subject to refund. This new rate case reflects a requested annual revenue increase of approximately $66.9 million, based on filed rates, primarily attributable to increases in the utility rate base, operating expenses and rate of return and related taxes.
During 1993 and 1994, the Company made filings to reflect changes in costs of transportation by others, pursuant to the Transportation Cost Adjustment tracker provisions of its approved tariff. Pursuant to that tariff, on December 30, 1993, the Company refunded $14.9 million of overcollected transportation costs.
On July 29, 1994, and in rehearing on September 16, 1994, the FERC issued an order accepting a filing made by the Company to resolve its transportation and exchange imbalances pre-dating its implementation of FERC Order 636. Following the parties' agreement as to the allocations, reconciled imbalances will be repaid in cash, or through receipt or delivery of gas, as permitted by operating conditions, by the end of 1995.
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. The Company believes that under FERC Order 636, with SFV rates, its rate structure will continue to 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
Liberty Pipeline Company
In 1992, Liberty Pipeline Company (Liberty), 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 per day in firm transportation service to the greater New York metropolitan area. The partnership presently is comprised of subsidiaries of Transco and two other interstate pipelines and subsidiaries of three TGPL customers in New York.
On August 1, 1994, Liberty asked the FERC to postpone indefinitely its review of the project. The decision followed the withdrawal of two key shippers from the project. The partners reaffirmed their belief that an additional delivery point to the New York facilities system, as proposed by Liberty, would be necessary in the future and advised the FERC that the Liberty partners would continue to pursue that goal at such time. On August 12, 1994, the FERC dismissed, without prejudice, the applications of Liberty and other upstream pipeline companies for authority to build the pipeline and other related facilities.
The Company had 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. These applications were also dismissed on August 12, 1994.
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 was completed and facilities were placed into service in April 1994. Total cost for this system was $4.0 million.
EMPLOYEE RELATIONS
The Company had 1,151 employees as of December 31, 1994. 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 198 of the Company's 492 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, 1994, 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 Narrative Analysis of the Results of Operations
Financial Analysis of Operations - 1994 Compared to 1993
As discussed in Note C of Notes to Financial Statements contained in Item 8
Item 8 hereof, on November 1, 1993, the Company implemented FERC Order 636, which required pipelines to "unbundle" services and offer transportation and storage services separately from the sale of gas. As a result, the Company's gas sales result primarily from requirements to meet its remaining gas purchase commitments. The Company's monthly gas purchases under non-market-responsive commitments are sold at auction with any underrecovery of such costs deferred as a regulatory asset for future recovery as transition costs. All other gas purchase and sales commitments are being managed by the Company's marketing affiliate, TGMC, as agent for the Company. The Company's gas sales currently have no impact on its results of operations.
The Company's implementation of FERC Order 636 included a change in its rate design method from Modified Fixed Variable (MFV) to Straight Fixed Variable (SFV). Under the MFV method, all fixed costs, with the exception of equity return and income taxes, were included in the demand component of the charge to customers; the equity return and income tax components of cost of service were included as part of the volumetric charge to customers. Under the SFV method, all fixed costs, including equity return and income taxes, are included in the demand charge to customers. Accordingly, under SFV, overall throughput has a less significant impact on the Company's results of operations.
There are various factors which may affect the Company's actual operating results, including, but not limited to, competition from other pipelines, its rate design structure, cost management and, to a lesser extent, fluctuations in its throughput which may result from a number of factors, including weather. The Company's interim operating results are impacted by customers' ability to reserve firm transportation levels on a seasonal basis; which, combined with SFV rate design, results in lower operating income in the second and third quarters than in the first and fourth quarters (see Note K of Notes to Financial Statements contained in Item 8 hereof). While the use of SFV rate design limits the Company's opportunity to earn incremental revenues through increased throughput, it
also minimizes the Company's fluctuations in revenue due to variations in throughput. The Company believes that under FERC Order 636, with SFV rates and its anticipated transition cost recovery, its rate structure will continue to remain competitive.
The acquisition of Transco by Williams (see Capital Resources and Liquidity - Introduction) will be accounted for using the purchase method of accounting. Accordingly, upon completion of the merger, the purchase price will be allocated to the net assets acquired, including the net assets of the Company. Current FERC policy does not permit the Company to recover through its rates amounts in excess of the original cost of its regulated facilities. As a result, absent any offsetting effects of the acquisition, future amortization of purchase price amounts allocated to the Company in excess of the current book value of the Company's net assets could cause the Company's operating income in 1995 to be lower than 1994.
Operating and Net Income
Operating income was $10 million lower for the year ended December 31, 1994, than for the year ended December 31, 1993. The decrease in operating income was primarily due to lower interruptible transportation revenues re- sulting from the implementation of FERC Order 636 and a lower stated rate of return under the Company's recently settled general rate case, partially offset by lower operating costs and expenses. Net income was $6.6 million lower for 1994 than for 1993 for the same reasons as operating income.
Operating Revenues
Operating revenues decreased $55 million, primarily as a result of $132 million lower gas sales revenues, partially offset by $77 million of higher gas transportation revenues. The increase in gas transportation revenues and the decrease in gas sales revenues were primarily the result of the conversion of customer's firm sales service to firm transportation service due to the implementation of FERC Order 636. Operating revenues were also lower due to the lower stated rate of return included in the October 21, 1994 final settlement of the Company's general rate case, Docket No. RP93-106. Although long-haul transportation volumes increased, the decrease in average commodity transportation rates, which resulted from the implementation of Order 636, SFV rate design and reduced interruptible transportation revenues, more than offset the effect on transportation revenues of the higher transportation volumes.
Operating Costs and Expenses
Costs of gas sold decreased $44 million from the prior year, primarily due to the implementation of FERC Order 636 and the resultant decrease in gas sales volumes. Operation and maintenance expenses for 1994 were $2 million higher than 1993 due primarily to a third quarter 1993 adjustment for income taxes refundable to customers as a result of an increase in federal income tax rates. Administrative and general expenses decreased $4 million, primarily due to a $4 million adjustment in 1994 of a provision for uncollectible accounts, which included the effects of the settlement of certain customer bankruptcy proceedings that had been recorded in 1993, partially offset by higher costs of $4 million for postretirement benefits other than pensions, which are included in rates.
The Company's depreciation and amortization expenses increased $3 million, primarily due to an increased depreciation base and higher stated depreciation rates included in the October 21, 1994 final settlement of the Company's general rate case, Docket No. RP93-106.
System Deliveries
As shown in the table below, the Company's total mainline deliveries for the year ended December 31, 1994 increased 31.8 Bcf, or 5.6%, as compared to the year ended December 31, 1993, primarily as a result of increased throughput in connection with restructured services resulting from the implementation of FERC Order 636 and increased service to other interstate natural gas pipelines. While presently not adding significantly to the Company's operating income, this increase shows the strength of the Company's franchise.
Year Ended December 31, System Deliveries (Bcf): 1994 1993
Sales - 51.5 Long-haul transportation 602.9 519.6 Total mainline deliveries 602.9 571.1 Short-haul transportation 183.1 204.0 Total system deliveries 786.0 775.1
The Company's facilities are divided into five rate zones. Generally, gas delivered in the northern four zones is classified as long-haul transportation. Gas delivered in the southernmost zone is classified as short-haul transportation. The Company's sales under the FERC Order 636 environment are generally made in the southernmost zone; however, the sales are made off system and, therefore, do not constitute system deliveries.
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. The Company believes that under FERC Order 636, with SFV rates, its rate structure will continue to 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.
Capital Resources and Liquidity
Introduction
On December 12, 1994, Transco and The Williams Companies, Inc. (Williams) announced that they had entered into a merger agreement, which was amended on February 17, 1995, pursuant to which Williams agreed to commence a cash tender offer to acquire up to 24.6 million shares, or approximately 60%, of the outstanding shares of Transco's common stock for $17.50 per share. The cash offer would then be followed by a stock merger in which each share of Transco's common stock not purchased in the tender offer would be exchanged for 0.625 of a share of Williams' common stock. Pursuant to the merger agreement, on January 18, 1995, Williams accepted for payment 24.6 million shares of Transco's common stock for $17.50 per share as the first step in acquiring the entire equity interest of Transco. The conversion of the remaining outstanding shares of Transco's common stock to Williams' common stock will occur at the effective date of the merger, which is projected to be in April 1995.
Williams has indicated that it intends to cause Transco, as promptly as practicable following the merger and subject to receipt of any necessary consents, to declare and pay as dividends to Williams all of Transco's interests in its principal operating subsidiaries, including the Company.
Williams has indicated that is also intends to maintain and expand the existing core businesses of Transco, including the Company, and to promptly pursue new business opportunities made available as a result of the merger. In order to prepare for these opportunities, in January 1995, the Boards of Directors of Transco and Williams approved a proposed recapitalization plan for Transco under which Williams will advance or con- tribute to Transco up to an estimated $950 million to execute the proposed plan.
Through the years, the Company has consistently maintained its financial strength and experienced strong operational results. The Company expects that Transco's merger with Williams will further enhance its financial and operational strength, as well as allow the Company to take advantage of new opportunities for growth. If necessary, the Company also expects to be able to access public and private capital markets to finance its capital requirements.
Financing
As a subsidiary of Transco, the Company engages in transactions with Transco and other Transco subsidiaries characteristic of group operations. The Company meets its working capital requirements by participation in the Transco consolidated cash management program, pursuant to which the Company, for investment purposes, both makes advances to and receives repayments of advances from Transco, and by accessing capital markets to fund its long-term debt maturities. As general corporate policy, the interest rate on intercompany demand notes is 1 1/2% below the prime rate of Citibank, N.A., which was 8 1/2% at December 31, 1994.
At December 31, 1994, the Company had outstanding current and noncurrent advances to Transco of $28 million and $124 million, respectively. 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.
The Company and Transco's other subsidiaries pay dividends, based on the level of their earnings and net cash flows, to provide funds to Transco for debt service and dividend payments.
Transco had in place a $450 million working capital line with a group of fifteen banks and a $50 million reimbursement facility with a group of five banks, for which the Company was guarantor in part. Both facilities were terminated in January 1995, as part of the recapitalization plan discussed above.
In February 1995, Transco's working capital line was replaced by an $800 million credit agreement among Williams and certain of its subsidiaries, TGPL, the Company and Citibank, N.A. as agent and the Banks named therein, under which the Company may borrow up to $200 million.
On April 11, 1994, the Company sold $150 million of 8 5/8% Notes due April 1, 2004. Proceeds from the sale of the Notes were used to retire the Company's 10% Debentures that were to mature on November 1, 1994.
Cash Flows and Capitalization
Net cash inflows from operating activities for the year ended December 31, 1994 were approximately $32 million lower than for the year ended December 31, 1993, primarily as a result of net payments to former sales customers in resolution of FERC Order 528 flowthrough proceedings in the amount of $18 million and the payment of the Docket No. RP93-106 rate refunds in the amount of $42 million, partially offset by the 1993 payment of the Docket No. RP90-104 rate refunds in the amount of $36 million.
Net cash outflows from financing activities for the year ended December 31, 1994 were $8 million lower than for the year ended December 31, 1993, primarily as a result of lower dividends paid to Transco in 1994.
Net cash inflows from investing activities for the year ended December 31, 1994 were $25 million higher than for the year ended December 31, 1993, mainly due to a $32 million increase in repayments by Transco of cash advanced to Transco under Transco's cash management program, partially offset by $9 million higher additions to property, plant and equipment, net of allowance for equity funds used during construction.
The Company's 1994 capital expenditures of $43 million included $38 million for maintenance of existing facilities and $5 million for market and supply expansion projects.
The Company had participated in a program to sell up to $40 million of trade receivables without recourse. As of December 31, 1994 and 1993, $27
million and $34 million, respectively, in trade receivables were held by the investor. This program was terminated in January 1995, as part of the recapitalization plan discussed above, with the expectation that at some future time Williams will replace it with a new receivables program.
The Company's debt, less current maturities, as a percentage of total capitalization at December 31, 1994 and 1993 was 29% and 14%, respectively. The percentage change was due to the issuance in 1994 of the Company's 8 5/8% Notes, as discussed above, to refinance the Company's 10% Debentures, which were included in current maturities at December 31, 1993.
In February 1995, Standard & Poor's Corporation and Moody's Investors Service upgraded the Company's debt securities from BB and Ba2 to BBB and Baa1, respectively. A security rating is not a recommendation to buy, sell or hold securities; it may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.
Gas Supply Realignment Cost Recoveries
Through December 31, 1994, the Company had paid a total of $46 million for GSR costs, primarily as a result of certain GSR contract terminations. During 1994, the Company made four quarterly filings to recover $38 million, plus interest, 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 August 1994, which are expected to be recovered via demand surcharges on its firm transportation rates. The Company continues to make quarterly filings to allow recovery of 90% of its GSR costs as such costs are paid. The remaining 10% of GSR costs is expected to be recovered from interruptible transportation service. On December 29, 1994, as revised on February 13, 1995, the Company made a filing to reflect that, for the ten months ended August 31, 1994, the Company allocated to and recovered from interruptible transportation service $4 million of GSR costs, pursuant to its FERC- approved Gas Tariff.
Future Capital Expenditures
The Company's budgeted capital expenditures for 1995 of $39 million include $37 million for maintenance of current facilities and $2 million for market expansion projects.
Other Future Capital Requirements and Contingencies
FERC Order 636 Transition Costs
As discussed in Note C of Notes to Financial Statements contained in Item 8 hereof, FERC Order 636 provides that pipelines should be allowed the opportunity to recover all prudently incurred transition costs. The Company's transition costs, which are currently not expected to exceed $90 million, are primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the Company's monthly gas auction process and unrecovered purchased gas costs. 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. Certain parties are, however, challenging
the Company's right to fully recover its GSR costs. Settlement proceedings are pending at the FERC. Through December 31, 1994, the Company had paid a total of $46 million for GSR costs, primarily as a result of certain GSR contract terminations.
Although no assurances can be given, the Company does not believe that transition costs will have a material adverse effect on its financial position, results of operations, or net cash flows.
FERC Order 94-A
As discussed in Note C of Notes to Financial Statements contained in Item 8 hereof, the FERC has issued an order that would require the Company to make refunds to certain customers of $13 million, recover $3 million through direct billing of other customers, recover $5 million as part of the direct billing of its unrecovered purchased gas costs and absorb the remaining $5 million. The Company filed for rehearing of this order and received an extension staying the effectiveness of this order until 30 days after the FERC's ruling on rehearing. On October 18, 1994, the FERC issued its "Order Denying Rehearing" which affirmed its January 12, 1994 order. On November 17, 1994, the Company made $4 million in refunds and filed for and received a stay of the order's requirement to make the remaining $9 million of refunds by November 17, 1994. On January 17, 1995, the Company filed a joint motion with Columbia, the party due the remaining refunds, to extend the time for making refunds until the court rules. The Company continues to believe that it is entitled to full recovery of these FERC-ordered costs and has filed a court appeal. The Company believes that its reserve of $5 million, plus interest, for this matter is adequate to provide for any costs the Company may ultimately be required to absorb.
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. See Note C of Notes to Financial Statements contained in Item 8 hereof for further discussion.
Royalty Claims
As discussed in Note D of Notes to Financial Statements contained in Item 8 hereof, the Company has been named as defendant in two lawsuits involving claims by royalty owners for additional royalties. Although no assurances can be given, the Company believes that the final resolution of its royalty claims and litigation will not have a material adverse effect on its financial position, results of operations or net cash flows.
Conclusion
Although no assurances can be given, the Company currently believes that the aggregate of cash flows from operating activities supplemented, when necessary, by repayments of funds advanced to Transco, will provide the Company with sufficient liquidity to meet its capital requirements. If necessary, the Company also expects to be able to access public and private capital markets to finance its capital requirements.
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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Texas Gas Transmission Corporation as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP
Houston, Texas February 20, 1995
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 LLP, 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)
The accompanying notes are an integral part of these financial statements.
TEXAS GAS TRANSMISSION CORPORATION
BALANCE SHEETS (Thousands of Dollars)
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)
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.
On December 12, 1994, Transco and The Williams Companies, Inc. (Williams) announced that they had entered into a merger agreement, which was amended on February 17, 1995, pursuant to which Williams agreed to commence a cash tender offer to acquire up to 24.6 million shares, or approximately 60%, of the outstanding shares of Transco's common stock for $17.50 per share. The cash offer would then be followed by a stock merger in which each share of Transco's common stock not purchased in the tender offer would be exchanged for 0.625 of a share of Williams' common stock. Pursuant to the merger agreement, on January 18, 1995, Williams accepted for payment 24.6 million shares of Transco's common stock for $17.50 per share as the first step in acquiring the entire equity interest of Transco. The conversion of the remaining outstanding shares of Transco's common stock to Williams' common stock will occur at the effective date of the merger, which is projected to be in April 1995.
Williams has indicated that it intends to cause Transco, as promptly as practicable following the merger and subject to receipt of any necessary consents, to declare and pay as dividends to Williams all of Transco's interests in its principal operating subsidiaries, including the Company.
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
Transco's acquisition of the Company was accounted for using the purchase method of accounting. Accordingly, the acquisition debt and the purchase price were allocated to the net assets of the Company 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.
The financial statements do not reflect an allocation of the purchase price that will be recorded by Williams as a result of the merger.
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., which was 8 1/2% and 6% at December 31, 1994 and 1993, respectively. Net interest income on advances to or from associated companies was $10.4 million, $9.4 million and $9.6 million for the years ended December 31, 1994, 1993 and 1992, respectively.
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, 1994, 1993 and 1992, the Company was charged $7.1 million, $6.7 million and $4.2 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 year ended December 31, 1994 and the two months ended December 31, 1993, the Company paid TGMC agency fees of $1.9 million and $0.7 million, respectively, for these services.
Included in the Company's gas sales revenues for the years ended December 31, 1994 and 1993 is $42.2 million and $4.2 million, respectively, applicable to gas sales to the Company's affiliate, TGMC. There were no intercompany gas sales for the year ended December 31, 1992.
Included in the Company's gas transportation revenues for the years 1994, 1993 and 1992 are amounts applicable to transportation for affiliates as follows (expressed in thousands):
Year Ended December 31, 1994 1993 1992
TGMC $ 2,866 $ 2,609 $ 3,635 TGPL 35,705 33,913 20,380 $ 38,571 $36,522 $24,015
Included in the Company's cost of gas sold for the years ended December 31, 1994, 1993 and 1992, is $58.5 million, $11.1 million and $4.2 million, respectively, applicable to gas purchases from the Company's affiliate, TGMC.
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 1994, 1993 and 1992 are as follows:
Depreciation Rates 1994 1993 1992
Transmission-Onshore 2.25% 2.25% 2.00% Transmission-Offshore 6.00% 6.00% 6.00% Storage Plant 2.55% 2.55% 2.30% Other 0.75 - 15.0% 0.75 - 15.0% 0.75 - 15.0%
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.
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 $7.5 million and $7.9 million at December 31, 1994 and 1993, 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 costs refundable to customers.
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, 1994, 1993 and 1992 was $0.3 million, $0.2 million and $0.6 million, respectively. The allowance for equity funds for the years ended December 31, 1994, 1993 and 1992 was $0.5 million, $0.5 million and $1.2 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 classified in other noncurrent assets in the accompanying balance sheets.
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 in the accompanying balance sheets. 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.
Allowances for Doubtful Receivables
Due to its customer base, the Company has not historically experienced recurring credit losses in connection with its receivables. As a result, receivables determined to be uncollectible are reserved or written off in the period of such determination. At December 31, 1994 and 1993, the Company had no allowance for doubtful receivables.
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.
Reclassifications
Certain reclassifications have been made in the 1993 and 1992 financial statements to conform to the 1994 presentation.
C. Regulatory and Rate Matters
FERC Order 636
Effective November 1, 1993, the Company restructured its business to implement the provisions of FERC Order 636 pursuant to a series of filings approved by the FERC. 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 including equal access to all sources of gas; providing "no-notice" firm transportation services that are equal in quality to bundled sales service; establishing a capacity release program; 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 all prudently incurred costs associated with compliance under FERC Order 636 (transition costs), including unrecovered gas costs and gas supply realignment (GSR) costs. FERC Order 636 is presently subject to court appeals. The Company's transition costs, which are currently not expected to exceed $90 million, are primarily related to GSR contract termination costs, GSR pricing differential costs incurred pursuant to the Company's monthly gas auction process and unrecovered purchased gas costs. As of December 31, 1994, the Company had paid a total of $46.4 million of GSR costs, as discussed below in "Long-term Gas Purchase Contracts." 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. Certain parties are,
however, challenging the Company's right to fully recover its GSR costs. Settlement proceedings are pending at the FERC.
Pursuant to FERC Order 636, the Company terminated its Purchased Gas Adjustment (PGA) clause on November 1, 1993. The Company's right to file for future recovery, via additional direct billings, of pre-November 1, 1993 adjustments to purchased gas costs, was to expire on July 31, 1994. However, the Company filed for and received an extension of the deadline for certain costs in dispute until the later of October 31, 1995 or 90 days after the final nonappealable resolution of any litigation, arbitration or administrative proceeding. During 1994, the Company made two filings to recover $12.3 million of pre-November 1, 1993 unrecovered purchased gas costs. The Company has no outstanding deferred gas cost issues pending in any other proceeding.
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, results of operations or net cash flows.
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. Refunds, including interest, of $36.3 million were distributed to customers on January 19, 1993.
In April 1993, the Company filed a general rate case (Docket No. RP93- 106) which became effective on November 1, 1993, subject to refund. The 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. A settlement agreement regarding the general rate case was filed on June 14, 1994, approved on September 21, 1994, and became final on October 21, 1994. On December 20, 1994, the Company made refunds of approximately $42.2 million, including interest. The Company previously had provided a reserve for these refunds.
On September 30, 1994, the Company filed a general rate case (Docket No. RP94-423) which will be effective April 1, 1995, subject to refund. This new rate case reflects a requested annual revenue increase of approximately $66.9 million, based on filed rates, primarily attributable to increases in the utility rate base, operating expenses and rate of return and related taxes.
During 1993 and 1994, the Company made filings to reflect changes in costs of transportation by others, pursuant to the Transportation Cost Adjustment tracker provisions of its approved tariff. Pursuant to that tariff, on December 30, 1993, the Company refunded $14.9 million of overcollected transportation costs.
On July 29, 1994, and in rehearing on September 16, 1994, the FERC issued an order accepting a filing made by the Company to resolve its transportation and exchange imbalances pre-dating its implementation of FERC Order 636. Following the parties' agreement as to the allocations, reconciled imbalances will be repaid in cash, or through receipt or delivery of gas, as permitted by operating conditions, by the end of 1995.
FERC Orders 500 and 528
Pursuant to FERC Orders 500 and 528, 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, made filings with the FERC for approval to flow these costs through to its customers. . On August 4, 1994, the FERC issued an order approving the settlement agreements of the Company and its upstream pipelines. Pursuant to the settlements, on September 30, 1994, the Company flowed through to its former sales customers $39.9 million. This order resolves all the Company's issues related to the flowthrough of upstream pipelines' producer settlement costs.
In September 1993, the Company filed to recover 75% of $3.4 million of its producer settlement costs under FERC Order 528 which resulted from reimbursements to producers for certain royalty payments. In December 1994, the FERC approved a settlement allowing for recovery of $0.9 million through direct bill and $1.7 million through a volumetric surcharge, both of which were 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 1990, the United States Court of Appeals for the District of Columbia overturned the FERC's authorization for pipelines to directly 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.
In April 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. In February 1993, the FERC issued an order approving the settlement. On January 12, 1994, the FERC found that it 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 purchased gas costs and absorb the remaining $5.4 million. The Company filed for rehearing of this order and received an extension staying the effectiveness of this order until 30 days after the FERC's ruling on rehearing. On October 18, 1994, the FERC issued its "Order Denying Rehearing" which affirmed its January 12, 1994 order. On November 17,
1994, the Company made $4.3 million in refunds and filed for and received a stay of the order's requirement to make the remaining $9.2 million of refunds by November 17, 1994. The Company continues to believe that it is entitled to full recovery of these FERC-ordered costs and has filed a court appeal. On January 17, 1995, the Company filed a joint motion with Columbia, the party due the remaining refunds, to extend the time for making refunds until the court rules. The Company believes that its reserve of $5.4 million, plus interest, for this matter is adequate to provide for any costs 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, results of operations, or net cash flows.
Long-term Gas Purchase Contracts
During 1993, as part of the Company's restructuring under FERC Order 636, the Company engaged in negotiations which 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, 1994, the Company had paid a total of $46.4 million for GSR costs, primarily as a result of certain GSR contract terminations. During 1994, the Company made four quarterly filings to recover $37.8 million, plus interest, 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 August 1994, which are expected to be recovered via demand surcharges on its firm transportation rates. The Company continues to make quarterly filings to allow recovery of 90% of its GSR costs as such costs are paid. The remaining 10% of GSR costs is expected to be recovered from interruptible transportation service. On December 29, 1994, as revised on February 13, 1995, the Company made a filing to reflect that, for the ten months ended August 31, 1994, the Company allocated to and recovered from interruptible transportation service $4.2 million of GSR costs, pursuant to its FERC-approved Gas Tariff.
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 three to five years under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $6 million to $8 million. As of December 31, 1994, 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 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 $6 million to $8 million range discussed above. Civil penalties have been assessed by the EPA against other major natural gas pipeline companies 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 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 $6 million to $8
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, results of operations or net cash flows.
The Company considers 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, the Company has been permitted recovery of environmental costs incurred, and it is the Company's 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 in the accompanying balance sheets.
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. The Company is 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. 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 $1.3 million to $2.3 million over the next three to 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.
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. In October 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 under the provision of FERC Order 528.
As discussed in Note C (see discussion on FERC Orders 500 and 528), the FERC has approved a settlement allowing the Company 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, results of operations, or net cash flows.
E. Income Taxes
Following is a summary of the provision for income taxes for 1994, 1993 and 1992 (expressed in thousands):
Year Ended December 31, 1994 1993 1992 Current: Federal $(3,645) $18,330 $ 5,106 State (278) 3,662 2,038 (3,923) 21,992 7,144 Deferred: Federal 21,868 3,753 16,359 State 5,117 810 2,960 26,985 4,563 19,319 Provision for income taxes $ 23,062 $26,555 $26,463
There are no material differences between the Company's effective federal income 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 in the accompanying balance sheets as of December 31, 1994 and 1993 are as follows (expressed in thousands):
1994 1993 Deferred Income Tax Benefits (Liabilities), Net: Current: Costs recoverable from/refundable to customers: Gas purchases $(3,668) $(2,180) Gas supply realignment (10,564) (7,498) Fuel (6,865) - Transportation 4,080 1,811 Gas stored underground--additional tax basis - 3,205 Accrued employee benefits 5,658 4,760 Reserve for rate refund - 8,296 Accrued gas supply realignment costs - 9,652 Producer settlement costs 5,163 - Deferred gas costs 3,850 - Other (396) (366) Total Current (2,742) 17,680
Noncurrent: Property, plant and equipment: Tax over book depreciation, net of gains (40,199) (36,695) Other basis differences (4,830) (3,820) Gas stored underground--additional tax basis 2,859 - Gas supply realignment costs - (2,738) Upstream producer settlement costs - 6,559 Other 259 1,346 Total Noncurrent (41,911) (35,348)
Total Deferred Income Tax Benefits (Liabilities), Net $(44,653) $(17,668)
F. Financing
Long-term Debt
At December 31, 1994 and 1993, long-term debt issues were outstanding as follows (expressed in thousands):
1994 1993 Debentures: 10% due 1994 $ - $150,000 Notes: 9 5/8% due 1997 100,000 100,000 8 5/8% due 2004 150,000 - 250,000 250,000 Less: Unamortized debt discount 3,558 1,322 Total long-term debt issues 246,442 248,678 Less: Amounts due within one year - 150,000 Total long-term debt, less current maturities $246,442 $ 98,678
On April 11, 1994, the Company sold $150 million of 8 5/8% Notes due April 1, 2004. Proceeds from the sale of the Notes were used to retire the Company's 10% Debentures that were to mature November 1, 1994.
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.
In February 1995, Standard & Poor's Corporation and Moody's Investors Service upgraded the Company's debt securities from BB and Ba2 to BBB and Baa1, respectively. A security rating is not a recommendation to buy, sell or hold securities; it may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating.
Recapitalization Plan
In January 1995, the Boards of Directors of Williams and Transco approved a proposed recapitalization plan for Transco, under which Williams will advance or contribute to Transco up to an estimated $950 million to execute the proposed plan.
Transco had in place a $450 million working capital line with a group of fifteen banks and a $50 million reimbursement facility with a group of five banks, for which the Company was guarantor in part. Both facilities were terminated in January 1995, as part of the recapitalization plan.
In February 1995, Transco's working capital line was replaced by an $800 million credit agreement among Williams and certain of its subsidiaries, TGPL, the Company and Citibank, N.A. as agent and the Banks named therein, under which the Company may borrow up to $200 million. Interest on borrowings is paid at a rate based on the base rate of Citibank
N.A., which at December 31, 1994 was 8.5%; the latest three-week moving average of secondary market morning offering rates in the United States for three-month certificates of deposit of major United States money market banks, which at December 31, 1994 was 6.31%, plus 1/2%; or the Federal Funds Rate in effect, which at December 31, 1994 was 5.45%, plus 1/2%.
Sale of Receivables
The Company had participated in a program to sell up to $40 million of trade receivables without recourse. As of December 31, 1994 and 1993, $27 million and $34 million, respectively, of trade receivables were held by the investor. This program was terminated in January 1995, as part of the recapitalization plan, with the expectation that at some future time Williams will replace it with a new receivables program.
Significant Group Concentrations of Credit Risk
As of December 31, 1994, the Company had trade receivables of $8.2 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 following table sets forth the funded status of the Retirement Plan at September 30, 1994 and 1993, and the amount of prepaid pension costs as of December 31, 1994 and 1993 (expressed in thousands):
1994 1993
Actuarial present value of accumulated benefit obligation, including vested benefits of $50,214 at October 1, 1994 and $46,750 at October 1, 1993 $(52,381) $(47,542)
Actuarial present value of projected benefit obligation $(88,641) $(83,557) Plan assets at fair value 102,992 101,089 Projected benefit obligation less plan assets 14,351 17,532 Unrecognized net loss 17,655 15,254 Unrecognized net asset at January 1, 1986 being recognized over 19 years (11,583) (12,733) Unrecognized prior service cost 4,447 4,369
Prepaid pension costs $ 24,870 $ 24,422
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, 1994, 1993 and 1992 (expressed in thousands):
1994 1993 1992
Service cost-benefits earned during the period $ 4,175 $ 3,867 $ 4,116 Interest cost on projected benefit obligation 5,993 4,687 6,420 Actual return on plan assets (3,431) (13,595) (12,766) Net amortization and deferral (7,185) 3,953 (687) Net pension income $ (448) $(1,088) $(2,917)
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 1994, 1993 and 1992:
1994 1993 1992
Discount rate 7.50% 7.25% 7.50% Rate of increase in future compensation levels 5.00% 5.00% 5.00% Expected long-term rate of return on assets 10.00% 10.00% 10.00%
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 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 service 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, 1994 and 1993, reconciled with the accrued postretirement benefit cost included in the accompanying balance sheets (expressed in thousands):
1994 1993 Accumulated postretirement benefit obligation: Retirees $(49,700) $(53,552) Fully eligible active plan participants (5,515) (3,977) Other active plan participants (31,815) (35,474) (87,030) (93,003) Plan assets at fair value 28,749 22,638 Accumulated postretirement benefit obligation in excess of plan assets (58,281) (70,365) Unrecognized net (gain) loss (9,417) 1,189 Unrecognized transition obligation 61,516 64,753 Accrued postretirement benefit cost $ (6,182) $ (4,423)
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 years ended December 31, 1994 and 1993 (expressed in thousands):
1994 1993
Service cost-benefits earned during the period $ 2,985 $ 2,430 Interest cost on accumulated postretirement benefit obligation 6,585 6,325 Actual return on plan assets (583) (2,548) Amortization of transition obligation 3,238 3,238 Net amortization and deferral (1,400) 1,356 Net periodic postretirement benefit cost $10,825 $10,801 Less deferral of costs not included in jurisdictional rates 543 5,013 Net periodic postretirement benefit cost, net of deferred costs $10,282 $ 5,788
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, 1994, the annual rate of increase in the per capita cost of covered health care benefits was assumed to be 11.4%. The rate was assumed to decrease gradually to 6% for the year 2004 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, 1995 by 14% and the aggregate of the service and interest cost components of the net periodic postretirement health care benefit cost for 1995 by 20%.
To determine the accumulated postretirement benefit obligation, the Employee Welfare Benefit Plan used a discount rate of 7.75% 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, international equity funds 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, which was approved by the FERC in September 1994 and became final in October 1994, that provides for postretirement benefit costs pursuant to SFAS 106 to be collected in rates and for the establishment of a regulatory asset for the difference between its postretirement benefits expense under SFAS 106 and the amount it collects in its rates. Pursuant to its latest rate case filing, the Company proposes to recover the regulatory asset in rates over an 8 1/2 year period from April 1, 1995.
In December 1992, the FERC issued a Statement of Policy which allows jurisdictional pipelines to recognize allowances for prudently incurred costs of postretirement benefits other than pensions on an accrual basis consistent with the accounting principles set forth in SFAS 106. The Company believes that all costs of providing postretirement benefits other than pensions to its employees are necessary and prudent operating expenses and that such costs are recoverable in rates. The Company has recognized and expects to continue to recognize these costs concurrent with the receipt of revenues. Therefore, the adoption of SFAS 106 did not have a material effect on the Company's financial position, results of operations or net cash flows.
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 December 31, 1993 current maturities of long-term debt which is publicly traded. The estimated fair value of these maturities is 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 in the accompanying balance sheets, 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, estimated fair value is based on quoted market prices, less accrued interest, at December 31, 1994 and 1993.
The carrying amount and estimated fair values of the Company's financial instruments as of December 31, 1994 and 1993 are as follows (expressed in thousands):
Carrying Fair Amount Value 1994 1993 1994 1993
Financial Assets: Cash and short-term financial assets $ 66,885 $ 92,261 $ 66,885 $92,261 Long-term notes receivable 124,000 137,000 124,000 137,000 Financial Liabilities: Short-term financial liabilities 34,326 224,953 34,326 223,563 Long-term debt 250,000 100,000 231,152 102,252
J. Supplementary Profit and Loss Information
Major Customers
Listed below are sales and transportation revenues received from the Company's major customers in 1994, 1993 and 1992, portions of which are included in the refund reserves discussed in Note C (expressed in thousands):
Year Ended December 31, 1994 1993 1992 The Cincinnati Gas & Electric Company $ 36,191 $18,362 $22,628 Indiana Gas Company, Inc. 35,712 49,825 57,304 Louisville Gas and Electric Company 31,660 45,176 63,485 Western Kentucky Gas Company 28,132 41,314 45,144
Expenditures for Maintenance and Repairs
Expenditures for maintenance and repairs for the years ended December 31, 1994, 1993 and 1992, were $13.3 million, $16.8 million and $14.1 million, respectively.
K. Quarterly Information (Unaudited)
The following summarizes selected quarterly financial data for 1994 and 1993 (expressed in thousands):
First Second Third Fourth Quarter Quarter Quarter Quarter
Operating revenues $134,238 $ 94,477 $75,923 $105,588 Operating expenses 103,064 85,312 70,488 78,202 Operating income 31,174 9,165 5,435 27,386 Other (income) deductions: Interest expense 6,447 7,159 6,976 6,899 Other (income), net (1,698) (2,745) (3,084) (2,335) Total other (income) deductions 4,749 4,414 3,892 4,564 Income before income taxes 26,425 4,751 1,543 22,822 Provision for income taxes 10,462 1,992 773 9,835
Net income $ 15,963 $ 2,759 $ 770 $ 12,987
First Second Third Fourth Quarter Quarter Quarter Quarter
Operating revenues $160,700 $ 95,711 $ 92,262 $116,786 Operating expenses 131,798 77,752 76,822 96,050 Operating income 28,902 17,959 15,440 20,736 Other (income) deductions: Interest expense 6,215 6,229 6,250 6,393 Other (income), net (1,775) (1,935) (1,968) (1,984) Total other (income) deductions 4,440 4,294 4,282 4,409 Income before income taxes 24,462 13,665 11,158 16,327 Provision for income taxes 9,594 5,289 5,175 6,497
Net income $ 14,868 $ 8,376 $ 5,983 $ 9,830
Item 9.
Item 9. Disagreements on Accounting and Financial Disclosure.
Not Applicable.
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, 1994 and 1993
Statements of Income for the years ended December 31, 1994, 1993 and 1992
Statements of Retained Earnings and Paid-In Capital for the years ended December 31, 1994, 1993 and 1992
Statements of Cash Flows for the years ended December 31, 1994, 1993 and
Notes to Financial Statements
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
3.1 Copy of Certificate of Incorporation of the Corporation (incorporated by reference to Exhibit 3.1 of the 1987 Form 10-K - File No. 1-4169).
3.2 Copy of Bylaws of the Corporation (incorporated by reference to Exhibit 3.2 of the 1991 Form 10-K - File No. 1-4169).
4.1 Indenture dated July 8, 1992, securing 9 5/8% Notes due July 15, 1997 (incorporated by reference to Form 8-K dated July 16, 1992 - File No. 1-4169).
4.2 Indenture dated April 11, 1994, securing 8 5/8% Notes due April 1, 2004 (incorporated by reference to Form 8-K dated April 13, 1994 - File No. 1-4169).
(b) Reports on Form 8-K
None.
______________
* Filed herewith
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 29, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
/s/ John P. DesBarres Chairman of the Board & Chief Executive Officer John P. DesBarres (Principal Executive Officer)
/s/ Robert W. Best Director, President and Chief Operating Officer Robert W. Best
/s/ Larry J. Dagley Director, Senior Vice President and Chief Larry J. Dagley Financial Officer (Principal Financial Officer)
/s/ E. Jack Ralph Vice President and Controller E. Jack Ralph
March 29, 1995 Date of all Signatures