UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (FEE REQUIRED)
For the fiscal year ended December 31, 1994
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from ________________ to ________________
Commission file number 1-4169
TEXAS GAS TRANSMISSION CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 61-0405152
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3800 Frederica Street, Owensboro, Kentucky 42301
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (502) 926-8686
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that
the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes X No____
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant. The aggregate market value shall be
computed by reference to the price at which stock was sold, or the average
bid and asked prices of such stock, as of a specified date within 60 days
prior to the date of filing. None
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. 1,000 shares
as of February 20, 1995
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION
J(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM WITH THE
REDUCED DISCLOSURE FORMAT.
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TABLE OF CONTENTS
1994 FORM 10-K
TEXAS GAS TRANSMISSION CORPORATION
Page
Part I
Item 1. Business. 3
Item 2. Properties. 13
Item 3. Legal Proceedings. 13
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters. 14
Item 7. Management's Narrative Analysis of the Results of Operations 14
Item 8. Financial Statements and Supplementary Data 21
Item 9. Disagreements on Accounting and Financial Disclosure. 48
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K 49
<PAGE>
Part I
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.
<PAGE>
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
<PAGE>
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
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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.
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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. Properties.
See "Item 1. Business."
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.
<PAGE>
PART II
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. 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 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
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION
BALANCE SHEETS
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31, December 31,
1994 1993
ASSETS
<S> <C> <C>
Current Assets:
Cash and temporary cash investments $ 885 $ 292
Receivables:
Trade 8,227 16,441
Affiliates 15,616 4,761
Other 1,038 1,934
Advances to affiliates 27,963 65,667
Transportation and exchange gas receivable 8,451 25,112
Costs recoverable from customers:
Gas purchase 9,270 5,590
Gas supply realignment 26,710 19,231
Other 22,451 3,886
Inventories 15,183 14,724
Deferred income tax benefits - 17,680
Other 3,535 2,932
Total current assets 139,329 178,250
Advances to Affiliates 124,000 137,000
Investments, at Cost 2,552 2,635
Property, Plant and Equipment, at cost:
Natural gas transmission plant 740,445 706,668
Other natural gas plant 132,962 128,376
873,407 835,044
Less - Accumulated depreciation and
amortization 217,580 173,201
Property, plant and equipment, net 655,827 661,843
Other Assets:
Gas stored underground 90,653 92,103
Other 42,345 60,515
Total other assets 132,998 152,618
Total Assets $1,054,706 $1,132,346
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION
BALANCE SHEETS
(Thousands of Dollars)
<TABLE>
<CAPTION>
December 31, December 31,
1994 1993
LIABILITIES AND STOCKHOLDER'S EQUITY
<S> <C> <C>
Current Liabilities:
Current maturities of long-term debt $ - $ 150,000
Payables:
Trade 8,979 13,821
Affiliates 3,219 13,274
Other 14,517 30,714
Advances from affiliates 1,769 1,576
Transportation and exchange gas payable 5,856 17,109
Accrued liabilities 41,247 44,134
Accrued gas supply realignment costs - 24,750
Costs refundable to customers 11,443 6,844
Deferred income taxes 2,742 -
Reserve for regulatory and rate matters 16,258 23,063
Total current liabilities 106,030 325,285
Long-Term Debt 246,442 98,678
Other Liabilities and Deferred Credits:
Income taxes refundable to customers 6,827 7,243
Deferred income taxes 41,911 35,348
Upstream producer settlement costs - 16,145
Other 40,771 42,411
Total other liabilities
and deferred credits 89,509 101,147
Stockholder's Equity:
Common stock, $1.00 par value, 1,000
shares authorized, issued and outstanding 1 1
Premium on capital stock and other
paid-in capital 584,712 584,712
Retained earnings 28,012 22,523
Total stockholder's equity 612,725 607,236
Total Liabilities and Stockholder's
Equity $1,054,706 $1,132,346
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF INCOME
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Operating Revenues:
Gas sales $116,079 $247,946 $292,978
Gas transportation 291,869 215,210 167,133
Other 2,278 2,303 3,754
Total operating revenues 410,226 465,459 463,865
Operating Costs and Expenses:
Cost of gas sold 114,653 158,890 181,047
Cost of transportation of gas by others 52,064 54,622 55,813
Operation and maintenance 57,081 54,803 53,898
Administrative and general 59,127 62,702 46,267
Depreciation and amortization 41,075 38,330 37,637
Taxes other than income taxes 13,066 13,075 13,265
Total operating costs and expenses 337,066 382,422 387,927
Operating Income 73,160 83,037 75,938
Other (Income) Deductions:
Interest expense 27,481 25,578 26,684
Interest income (12,013) (10,616) (12,107)
Equity in earnings of unconsolidated
affiliate - - (563)
Gain on sale of subsidiary - - (6,948)
Miscellaneous other deductions 2,151 2,463 1,491
Total other (income) deductions 17,619 17,425 8,557
Income Before Income Taxes 55,541 65,612 67,381
Provision for Income Taxes 23,062 26,555 26,463
Net Income $32,479 $39,057 $40,918
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF RETAINED EARNINGS
AND PAID-IN CAPITAL
(Thousands of Dollars)
<TABLE>
<CAPTION>
Retained Paid-in
Earnings Capital
<S> <C> <C>
Balance, December 31, 1991 $12,136 $584,712
Add (deduct):
Net income 40,918 -
Cash dividends on common stock (34,863) -
Balance, December 31, 1992 18,191 584,712
Add (deduct):
Net income 39,057 -
Cash dividends on common stock (34,725) -
Balance, December 31, 1993 22,523 584,712
Add (deduct):
Net income 32,479 -
Cash dividends on common stock (26,990) -
Balance, December 31, 1994 $28,012 $584,712
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION
STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income $ 32,479 $39,057 $40,918
Adjustments to reconcile net income to
net cash from operating activities:
Depreciation and amortization 42,500 39,783 39,150
Deferred income taxes 26,985 4,563 19,319
Equity in undistributed earnings of
unconsolidated affiliate - - (563)
Gain on sale of subsidiary - - (6,948)
Decrease (increase) in:
Receivables 1,499 1,319 (8,120)
Transportation and exchange gas
receivable 16,661 23,475 (12,164)
Inventories (459) (355) (17,367)
Deferred gas costs 503 (9,161) (15,854)
Regulatory assets (15,167) (15,155) (166)
Other current assets (603) 2,169 13,744
Increase (decrease) in:
Payables (34,266) 4,644 7,987
Transportation and exchange gas
payable (11,254) (19,426) 16,515
Accrued liabilities (87,317) (24,036) (13,165)
Reserve for regulatory and rate matters 31,024 13,592 7,023
Other current liabilities 6,123 (5,585) 7,124
Other, net 2,597 (11,908) 1,536
Net cash from operating activities 11,305 42,976 78,969
Cash Flows From Financing Activities:
Advances from affiliates, net 193 150 101
Dividends on common stock (26,990) (34,725) (34,863)
Long-term debt - repayment (150,000) - (100,000)
- borrowing 150,000 - 100,000
Net cash from financing activities (26,797) (34,575) (34,762)
Cash Flows From Investing Activities:
Property, plant and equipment,
net of equity AFUDC (42,505) (33,014) (38,236)
Recovery of producer settlements 1,123 3,831 16,115
Advances to affiliates, net 50,704 18,336 (32,025)
Other, net 6,763 2,178 10,230
Net cash from investing activities 16,085 (8,669 (43,916)
Net Increase (Decrease) in Cash and Cash
Equivalents 593 (268) 291
Cash and Cash Equivalents at Beginning
of Period 292 560 269
Cash and Cash Equivalents at End of Period $ 885 $ 292 $ 560
_______________________________________________________________________
Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 25,432 $28,654 $23,924
Income taxes, net 14,714 6,433 16,149
The accompanying notes are an integral part of these financial statements.
</TABLE>
<PAGE>
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.
<PAGE>
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.
<PAGE>
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%
<PAGE>
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
<PAGE>
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,
<PAGE>
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.
<PAGE>
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,
<PAGE>
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.
<PAGE>
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
<PAGE>
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.
<PAGE>
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
<PAGE>
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)
<PAGE>
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
<PAGE>
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.
<PAGE>
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%
<PAGE>
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)
<PAGE>
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.
<PAGE>
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.
<PAGE>
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.
<PAGE>
K. Quarterly Information (Unaudited)
The following summarizes selected quarterly financial data for 1994 and
1993 (expressed in thousands):
1994
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
1993
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
<PAGE>
Item 9. Disagreements on Accounting and Financial Disclosure.
Not Applicable.
<PAGE>
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
1992
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
<PAGE>
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
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000097452
<NAME> TEXAS GAS TRANSMISSION CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 885
<SECURITIES> 0
<RECEIVABLES> 8,227
<ALLOWANCES> 0
<INVENTORY> 15,183
<CURRENT-ASSETS> 139,329
<PP&E> 873,407
<DEPRECIATION> 217,580
<TOTAL-ASSETS> 1,054,706
<CURRENT-LIABILITIES> 106,030
<BONDS> 246,442
<COMMON> 1
0
0
<OTHER-SE> 612,724
<TOTAL-LIABILITY-AND-EQUITY> 1,054,706
<SALES> 116,079
<TOTAL-REVENUES> 410,226
<CGS> 114,653
<TOTAL-COSTS> 223,798
<OTHER-EXPENSES> 54,141
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 27,481
<INCOME-PRETAX> 55,541
<INCOME-TAX> 23,062
<INCOME-CONTINUING> 32,479
<DISCONTINUED> 0
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