TEXAS GAS TRANSMISSION CORP, 10-K, 1994-03-17

TEXAS GAS TRANSMISSION CORP
10-K, 1994-03-17
NATURAL GAS DISTRIBUTION

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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, 1993

[ ] 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 to

Commission file number 1-4169

TEXAS GAS TRANSMISSION CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 61-0405152
(State of 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 28, 1994

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

1993 FORM 10-K

TEXAS GAS TRANSMISSION CORPORATION

<TABLE>
<CAPTION>
ITEM
NO. PAGE
- ---- ----
<C> <S> <C>
PART I
1. Business......................................................................... 3
2. Properties....................................................................... 11
3. Legal Proceedings................................................................ 11
PART II
5. Market for Registrant's Common Equity and Related Stockholder Matters............ 11
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations..................................................................... 11
8. Financial Statements and Supplementary Data...................................... 19
9. Disagreements on Accounting and Financial Disclosure............................. 40
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................. 41
</TABLE>

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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.

The Company is a major interstate natural gas pipeline company primarily
engaged in the transportation of natural gas. The Company owns and operates an
extensive pipeline system originating in major gas supply areas in the Louisiana
Gulf Coast area and in East Texas and running generally north and east through
Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio,
with smaller diameter lines extending into Illinois. The Company's system
currently consists of approximately 6,050 miles of transmission lines. In
conjunction with its pipeline facilities, the Company owns and operates ten
underground storage reservoirs having a total capacity of 176.7 Bcf* and a
working capacity of 86.5 Bcf.

The Company's direct market area encompasses eight states in the South and
Midwest, and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati
and Dayton, Ohio; and Indianapolis, Indiana metropolitan areas. The Company also
has indirect market access to Northeast markets through interconnections with
Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation
(CNG) and Texas Eastern Transmission Corporation (Texas Eastern). A large
portion of the gas delivered by the Company to its market area is used for space
heating, resulting in substantially higher daily requirements during winter
months than summer months.

TRANSPORTATION AND SALES

Traditionally, interstate pipelines, including the Company, served
primarily as merchants of natural gas, purchasing gas under long-term contracts
with numerous producers in the production area and reselling gas to local
utilities in the market area under long-term sales agreements. Such merchant
service was known as bundled service.

Regulatory policies under the Natural Gas Act of 1938 (NGA), relating to
both pipeline rates and conditions of service, stressed security of gas supplies
and service, and the recovery by pipelines of their prudently incurred costs of
providing that service.

However, commencing in 1984, the Federal Energy Regulatory Commission
(FERC) issued a series of orders which have resulted in a major restructuring of
the natural gas pipeline industry and its business practices. With FERC Order
380, issued in 1984, the FERC freed pipeline customers from their contractual
obligations to purchase certain minimum levels of gas from their pipeline
suppliers. With implementation of "open access" transportation rules contained
in FERC Orders 436 and 500, the FERC afforded pipeline customers the opportunity
to purchase gas from third parties with pipelines transporting this supply to
the customers' markets. These FERC rules, coupled with a nationwide excess of
deliverable natural gas, have resulted in increased competition for markets and
decreases in natural gas prices.

Faced with these changing conditions and declining sales, the Company
altered the manner in which it had traditionally conducted its business. In
September 1984, the Company began transporting gas for industrial end-users
served by its direct-served local distribution customers. As excess natural gas
became available and prices declined, transportation of customer-owned gas
increased. In September 1988, the

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* As used in this report, the term "Mcf" means thousand cubic feet, the term
"MMcf" means million cubic feet, the term "Bcf" means billion cubic feet and
the term "Tcf" means trillion cubic feet. Unless otherwise stated in this
report, gas volumes are stated at a pressure base of 14.73 pounds per square
inch and at 60 degrees Fahrenheit.

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Company accepted a certificate and became a permanent open access pipeline
system under FERC Orders 436 and 500.

On April 8, 1992, the FERC issued Order 636 which brought about fundamental
changes in the way natural gas pipelines conduct their businesses. The FERC's
stated purpose of FERC Order 636 was to improve the competitive structure of the
natural gas pipeline industry by, among other things, unbundling a pipeline's
merchant role from its transportation services; ensuring "equality" of
transportation services; ensuring that shippers and customers have equal access
to all sources of gas; providing "no-notice" firm transportation services that
are equal in quality to bundled sales service; and changing rate design
methodology from Modified Fixed Variable (MFV) to Straight Fixed Variable (SFV),
unless the pipeline and its customers agree to a different form.

FERC Order 636 also set forth methods for recovery by pipelines of costs
associated with compliance under FERC Order 636 (transition costs), including
unrecovered gas costs, gas supply realignment (GSR) costs, the cost of stranded
pipeline investment and the costs of new facilities required.

On August 3, 1992, the FERC issued Order 636-A which modified the original
order to include one-part volumetric rates for small customers; the option of
unbundled gas sales to small customers at a cost-based rate for a one-year
period after the effective date of restructuring; a capacity release program;
recovery of certain transition costs through interruptible transportation (IT)
rates; and its use of either SFV methodology or other ratemaking techniques to
design rates which result in equitable treatment of customers with varying load
factors.

On November 27, 1992, the FERC issued Order 636-B which reaffirmed several
significant requirements of FERC Order 636-A. FERC Order 636-B marked the end of
the restructuring rulemaking. The FERC has stated that it will not accept
further rehearing petitions. FERC Orders 636, 636-A and 636-B are presently
subject to court appeals.

FERC Order 636 was implemented on the Company's system on November 1, 1993.
As a result of FERC Order 636, the Company's gas sales have been fundamentally
restructured. Prior to implementation of FERC Order 636, the Company had maximum
peak-day sales delivery obligations in excess of 1.7 Bcf per day under
individually certificated bundled sales contracts with more than 90 customers.
Effective November 1, 1993, all of these bundled sales services ceased and were
abandoned pursuant to FERC Order 636. Also as a result of FERC Order 636, the
Company entered into a limited number of new unbundled sales contracts under the
blanket certificate issued to it pursuant to that order. In compliance with
another FERC decision, FERC Order 497, the sales under this unbundled merchant
function are separately administered by Transco Gas Marketing Company (TGMC), an
affiliate of the Company. TGMC has been appointed the Company's exclusive agent
for the purpose of administering all existing and future sales and purchases for
the Company after implementation of FERC Order 636, except for the auction
transactions discussed below. Through its agent, TGMC, the Company currently
sells gas to fewer than ten customers with a total deliverability obligation of
substantially less than 0.2 Bcf per day.

The only remaining sales administered by the Company are volumes purchased
from a limited number of non-market-responsive gas purchase contracts which are
auctioned each month to the highest bidder. The Company may file to recover the
price differential, between the cost to buy the gas under these gas purchase
contracts and the price realized from the resale of the gas at the auction, as a
GSR cost pursuant to FERC Order 636.

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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:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
SYSTEMS DELIVERIES (BCF): 1993 1992 1991
--------------------------------------------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Sales........................................ 51.5 7% 80.4 11% 89.9 13%
Long-haul transportation..................... 519.6 67 402.2 55 382.1 55
----- --- ----- --- ----- ---
Total mainline deliveries.................. 571.1 74 482.6 66 472.0 68
Short-haul transportation.................... 204.0 26 244.2 34 225.6 32
----- --- ----- --- ----- ---
Total system deliveries............ 775.1 100% 726.8 100% 697.6 100%
----- --- ----- --- ----- ---
----- --- ----- --- ----- ---
</TABLE>

The Company's facilities are divided into five rate zones. Receipts and
deliveries are made in four zones to serve sales and long-haul transportation
markets. Receipts and deliveries in the remaining zone are made to serve sales
and short-haul transportation markets in southern Louisiana.

The decline in gas sales in 1993 primarily was attributable to the
Company's implementation of FERC Order 636. The increase in transportation
volumes resulted primarily from the Company's implementation of additional firm
service for Transcontinental Gas Pipe Line Corporation (TGPL), an affiliate of
the Company, implementation of FERC Order 636 and colder weather during the
winter months of 1993 than the winter months of 1992. The revenues associated
with short-haul transportation volumes are not material to the Company.

The following table sets forth the names of the Company's five largest
customers, along with the related sales and long-haul transportation volumes for
the periods shown (expressed in Bcf).

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
----------------------
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Indiana Gas Company, Inc.
Sales................................................................ 8.6 13.4 19.6
Long-haul transportation............................................. 21.9 19.1 16.3
Louisville Gas and Electric Company
Sales................................................................ 5.3 15.3 11.9
Long-haul transportation............................................. 43.2 33.4 36.5
Memphis Light, Gas and Water Division
Sales................................................................ 7.5 7.9 12.2
Long-haul transportation............................................. 18.4 12.5 11.4
Transcontinental Gas Pipe Line Corporation
Long-haul transportation............................................. 52.5 26.8 2.3
Western Kentucky Gas Company
Sales................................................................ 8.7 12.3 12.9
Long-haul transportation............................................. 21.1 16.0 20.6
</TABLE>

GAS SUPPLY

During 1993, as part of the Company's restructuring under FERC Order 636,
the Company has engaged in negotiations with suppliers which have resulted in
the successful termination of approximately 90% of the deliverability under its
non-market-responsive gas purchase contracts. Pursuant to FERC Order 636, the
Company is entitled to file for recovery of up to 100% of its prudently incurred
costs of terminating these contracts as GSR costs.

The Company's remaining gas purchase commitments at the end of 1993 consist
of both market-responsive and non-market-responsive contracts. Pursuant to FERC
Order 636, gas purchased from the Company's non-market-responsive contracts is
being resold at a monthly auction. The Company continues to

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pay to the supplier the actual contract price and is entitled to file for full
recovery of the difference between said contract price and the amount received
for sales at auction as GSR costs under FERC Order 636. The Company's
market-responsive contracts are being separately managed by its marketing
affiliate, TGMC. As a result of the foregoing, it is no longer material to the
Company's business to have proved gas reserves committed to the Company.

REGULATION

INTERSTATE GAS PIPELINE OPERATIONS

The Company is subject to regulation by the FERC as a "natural gas company"
under the NGA. The NGA grants to the FERC authority over the construction and
operation of pipeline and related facilities utilized in the transportation and
sale of natural gas in interstate commerce, including the extension, enlargement
and abandonment of such facilities. The FERC requires the filing of appropriate
applications by natural gas companies showing that the extension, enlargement or
abandonment of any facilities, as the case may be, is or will be required by a
certificate of public convenience and necessity. The Company holds certificates
of public convenience and necessity issued by the FERC authorizing it to
construct and operate all pipelines, facilities and properties now in operation
for which certificates are required, except for certain facilities that are not
material or with respect to which the FERC has issued temporary certificates.

The NGA also grants to the FERC authority to regulate rates, charges and
terms of service for natural gas transported in interstate commerce or sold by a
natural gas company in interstate commerce for resale, and to regulate
curtailments of sales to customers. The FERC has authorized the Company to
charge natural gas sales rates that are market-based. As necessary, the Company
files with the FERC changes in its transportation and storage rates and charges
designed to allow it to recover fully its costs of providing service to its
interstate system customers, including a reasonable rate of return. Regulation
of gas curtailment priorities and the importation of gas are, under the
Department of Energy Reorganization Act of 1977, vested in the Secretary of
Energy.

The Company is also subject to regulation by the Department of
Transportation under the Natural Gas Pipeline Safety Act of 1968 with respect to
safety requirements in the design, construction, operation and maintenance of
its interstate gas transmission facilities.

REGULATORY MATTERS

Pursuant to FERC Order 500, certain other pipelines, from which the Company
made gas purchases (upstream pipelines), had received approval from the FERC to
bill customers for their producer settlement costs. The Company had, in turn,
received FERC approval to flow these costs through to its customers under the
FERC Order 500 purchase deficiency-based direct bill methodology. Following the
issuance of FERC Order 528, which replaced the purchase deficiency-based
recovery methodology, the Company, in 1991, made a series of filings which
reallocated these costs among customers pursuant to the provisions of FERC Order
528. Pursuant to these filings, the Company proposed to ultimately flow through
to its customers approximately $64.3 million of costs billed from upstream
pipelines. The FERC has issued orders accepting these filings subject to the
ultimate outcome of the underlying filings of the upstream pipelines and future
settlement by the Company. Although the total billings to the Company are
unresolved and the Company may be required to refund certain amounts previously
collected, the Company believes that it will be entitled to ultimately collect
all amounts that are billed by the upstream pipelines.

On September 2, 1993, the Company filed to recover 75% of $3.4 million of
its producer settlement costs under FERC Order 528 which have resulted from
reimbursements to producers for certain royalty payments. A FERC order,
accepting the filing subject to refund and certain conditions, was issued on
October 1, 1993, allowing for recovery of $0.9 million through direct bill and
$1.7 million through a volumetric surcharge, both to be collected over a
12-month period which began October 3, 1993.

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FERC ORDER 94-A

In 1983, the FERC issued FERC Order 94-A, which permitted producers to
collect certain production-related gas costs from pipelines on a retroactive
basis. The FERC subsequently issued orders allowing pipelines, including the
Company, to bill their customers for such production-related costs through fixed
monthly charges based on a customer's historical purchases. In February 1990,
the D.C. Circuit Court overturned the FERC's authorization for pipelines to bill
production-related costs to customers based on gas purchased in prior periods
and remanded the matter to the FERC to determine an appropriate recovery
mechanism.

On April 28, 1992, the Company filed a settlement with the FERC providing
for a reallocation of the FERC Order 94-A payments previously collected from
customers. The settlement provided for net refunds of $8.1 million to certain
customers and direct bill recovery of $2.7 million from other customers. The
remaining $5.4 million would be recovered through the PGA mechanism. On February
11, 1993, the FERC issued an order approving the settlement. Certain parties
filed for rehearing of the settlement. On January 12, 1994, the FERC issued its
"Order Granting Rehearing" which found that the FERC had committed a legal error
in allowing the previously mentioned direct bill of FERC Order 94-A costs. The
effect of this order as issued would be to require the Company to make refunds
to certain customers of $13.5 million, recover $2.7 million through direct
billing of other customers, recover $5.4 million as part of the direct billing
of its unrecovered purchase gas costs and absorb the remaining $5.4 million. The
Company believes it is entitled to full recovery of these FERC-ordered costs.
The Company has filed for rehearing of this order and has received an extension
staying the effectiveness of this order until 30 days after the FERC rules on
rehearing. The Company believes that its reserve for regulatory and rate matters
is adequate to provide for any costs which the Company may ultimately be
required to absorb.

FERC ORDER 636

The Company has restructured its business to implement the provisions of
FERC Order 636. On October 1, 1993, the FERC issued its "Order on Compliance
Filing and Granting, In Part, and Denying, In Part, Rehearing and
Clarification," which essentially approved the major aspects of the Company's
FERC Order 636 compliance plan. The Company filed revised tariff sheets and
other changes pursuant to the October 1, 1993 order on October 18, 1993, which
permitted implementation of FERC Order 636 restructured services on November 1,
1993. On December 16, 1993, the FERC issued another order which required minor
tariff modifications. The Company submitted a filing in compliance with this
order on January 7, 1994. This filing was accepted by an order issued on
February 10, 1994. The Company's analysis of FERC Order 636 indicates that the
Company's transition costs are not currently expected to exceed $90 million,
primarily related to GSR contract termination costs, GSR pricing differential
costs incurred pursuant to the auction transactions, as discussed below, and
unrecovered purchased gas costs. As of December 31, 1993, the Company had
recorded $38 million of GSR costs.

FERC Order 636 provides that pipelines should be allowed the opportunity to
recover all prudently incurred transition costs. Therefore, the Company expects
that any transition costs incurred should be recovered from its customers,
subject only to the costs and other risks associated with the difference between
the time such costs are incurred and the time when those costs may be recovered
from customers. On January 28, 1994, the Company submitted its first filing to
recover $11.5 million of GSR costs pursuant to the transition cost recovery
provisions of FERC Order 636 and the Company's FERC-approved Gas Tariff. This
amount represents 90% of the total GSR costs paid through November 30, 1993,
which are expected to be recovered over a 12-month period by application of a
demand surcharge to its firm transportation rates. The remaining 10% is expected
to be recovered from interruptible transportation service. The Company plans to
make quarterly filings to allow recovery of its GSR costs as such costs are
paid.

As part of its implementation of FERC Order 636, the Company has been
allowed to retain its storage gas, in part to meet operational balancing needs
on its system, and in part to meet the requirements of the Company's "no-notice"
transportation service, which allows customers to temporarily draw from the
Company's storage gas to be repaid in-kind during the following summer season.

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Although no assurances can be given, the Company does not believe the
implementation of FERC Order 636 will have a material adverse effect on its
financial position or results of operations.

For further discussion of regulatory matters, see Note C of Notes to
Financial Statements contained in Item 8 hereof.

ENVIRONMENTAL MATTERS

The Company is subject to extensive federal, state and local environmental
laws and regulations which affect the Company's operations related to the
construction and operation of its pipeline facilities. Appropriate governmental
authorities may enforce these laws and regulations with a variety of civil and
criminal enforcement measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future compliance. The Company's
use and disposal of hazardous materials are subject to the requirements of the
federal Toxic Substances Control Act (TSCA), the federal Resource Conservation
and Recovery Act (RCRA) and comparable state statutes. The Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA), also known as
"Superfund," imposes liability, without regard to fault or the legality of the
original act, for release of a "hazardous substance" into the environment.
Because these laws and regulations change from time to time, practices which
have been acceptable to the industry and to the regulators have to be changed
and assessment and monitoring have to be undertaken to determine whether those
practices have damaged the environment and whether remediation is required.
Since 1989, the Company has had studies underway to test its facilities for the
presence of toxic and hazardous substances to determine to what extent, if any,
remediation may be necessary. On the basis of the findings to date, the Company
estimates that environmental assessment and remediation costs that will be
incurred over the next five years under TSCA, RCRA, CERCLA and comparable state
statutes will total approximately $7 million to $11 million. As of December 31,
1993, the Company had a reserve of approximately $7 million for these estimated
costs. This estimate depends upon a number of assumptions concerning the scope
of remediation that will be required at certain locations and the cost of
remedial measures to be undertaken. The Company is continuing to conduct
environmental assessments and is implementing a variety of remedial measures
that may result in increases or decreases in the total estimated costs.

The Company has used lubricating oils containing polychlorinated biphenyls
(PCBs) and, although the use of such oils was discontinued in the 1970s, has
discovered residual PCB contamination in equipment and soils at certain gas
compressor station sites. The Company continues to work closely with the
Environmental Protection Agency (EPA) and state regulatory authorities regarding
PCB issues and has programs to assess and remediate such conditions where they
exist, the costs of which are a significant portion of the $7 million to $11
million range discussed above. Proposed civil penalties have been assessed by
the EPA against another major natural gas pipeline company for the alleged
improper use and disposal of PCBs. Although similar penalties have not been
asserted against the Company to date, no assurance can be given that the EPA may
not seek such penalties in the future.

The Company has either been named as a potentially responsible party (PRP)
or received an information request regarding its potential involvement at four
federal "Superfund" waste disposal sites and one state waste disposal site.
Based on present volumetric estimates, the Company believes its estimated
aggregate exposure for remediation of these sites is approximately $500,000.
Liability under CERCLA (and applicable state law) can be joint and several with
other PRPs. Although volumetric allocation is a factor in assessing liability,
it is not necessarily determinative; thus the ultimate liability could be
substantially greater than the amount estimated above. The anticipated
remediation costs associated with these sites have been included in the $7
million to $11 million range discussed above. Although no assurances can be
given, the Company does not believe that its PRP status will have a material
adverse effect on its financial position or results of operations.

The Company is currently recovering in its rates amounts approximately
equal to its annual expenditures for these environmental matters. The Company
considers these expenditures prudent operating and maintenance expenses incurred
in the ordinary course of business and anticipates that these costs will
continue to be recoverable through its rates.

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The Company is also subject to the Federal Clean Air Act and to the Federal
Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to
the existing requirements established by the Federal Clean Air Act. The 1990
Amendments required that the EPA issue new regulations, mainly related to mobile
sources, air toxics, ozone non-attainment areas and acid rain. In addition,
pursuant to the 1990 Amendments, the EPA has issued regulations under which
states must implement new air pollution controls to achieve attainment of
national ambient air quality standards in areas where they are not currently
achieved. The Company has compressor stations in ozone non-attainment areas that
could require additional air pollution reduction expenditures, depending on the
requirements imposed. Additions to facilities for compliance with currently
known Federal Clean Air Act standards and the 1990 Amendments are expected to
cost in the range of $2 million to $3 million over the next five years and will
be recorded as assets as the facilities are added. The Company considers costs
associated with compliance with environmental laws to be prudent costs incurred
in the ordinary course of business and, therefore, recoverable through its
rates.

RATES

GENERAL

The Company's rates are established primarily through the FERC ratemaking
process. Key determinants in the ratemaking process are (i) volume throughput
assumptions, (ii) costs of providing service and (iii) allowed rate of return.
The allowed rate of return is determined by the FERC in each rate case. Rate
design and the allocation of costs between the demand and commodity rates also
impact profitability.

RATE ISSUES

In April 1990, the Company filed a general rate case (Docket No. RP90-104),
which became effective in November 1990, subject to refund. A settlement
agreement was filed on July 22, 1991, and approved by the FERC's "Order Granting
Reconsideration," on October 21, 1992. Refunds, including interest, of $36.3
million were made to customers on January 19, 1993.

On April 29, 1993, the Company filed a general rate case (Docket No.
RP93-106) which, pursuant to the FERC's Suspension Order issued May 28, 1993,
became effective on November 1, 1993, subject to refund. The new rate case was
filed to satisfy the three-year filing requirements of the FERC's regulations,
to recover increased operating costs, to provide a return on increased capital
investment in pipeline facilities, to implement the SFV rate design methodology
and to facilitate resolution of various rate-related issues in the Company's
FERC Order 636 restructuring proceeding. The Company is currently engaged in
settlement proceedings regarding this case. The Company has established a
reserve, which it believes to be adequate, to reflect the difference between the
rates currently being charged and the rates expected to ultimately be effective
upon settlement of the case.

During 1993, the Company made several filings under the provisions of its
approved tariff and FERC Orders 483 and 483-A to reflect changes in its
purchased gas costs. The Company also made filings to reflect changes in costs
of transportation by others, pursuant to the Transport Cost Adjustment (TCA)
tracker provisions of the approved tariff. Pursuant to that tariff, on December
30, 1993, the Company refunded $14.9 million of overcollected transportation
costs. The Annual PGA filing for gas costs incurred through August 1992 (Docket
No. TA93-1-18) was accepted by FERC Letter Order dated January 29, 1993, with no
purchasing practice issues being raised.

On November 1, 1993, the Company implemented the provisions of FERC Order
636 (see discussion on FERC Order 636). Pursuant to FERC Order 636, the Company
terminated its PGA clause on that date. On January 31, 1994, the Company filed a
limited Section 4(e) filing pursuant to its approved FERC Gas Tariff to direct
bill the balance of its unrecovered purchase gas costs at October 31, 1993, to
its former sales customers. This filing is necessary to recover $3.0 million of
deferred gas costs applicable to the period September 1992 through October 1993.
The Company has no outstanding deferred gas cost issues pending in any other
proceeding.

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COMPETITION

The Company and its primary market area competitors (ANR Pipeline Company,
Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Texas Eastern,
Columbia, Tennessee Gas Pipeline Company and Midwestern Gas Transmission
Company) implemented FERC Order 636 on their respective systems during the
period May 1993 to November 1993. The Company and its major competitors all
employ SFV rate design for firm transportation as mandated by FERC Order 636.

Future utilization of the Company's pipeline capacity will depend on
competition from other pipelines and alternative fuels, the general level of
natural gas demand and weather conditions. Although some of the Company's major
competitors implemented FERC Order 636 and SFV rates prior to the Company's
implementation, the impact on the Company's throughput was minimal. The Company
believes that under FERC Order 636, with SFV rates, its rate structure will
remain competitive and surcharges for recovery of its total transition costs
will not make its rates noncompetitive in its market as competitor pipelines are
believed to have transition costs also to be recovered in their rates.

The end-use markets of several of the Company's customers have the ability
to switch to alternative fuels. To date, however, losses from fuel switching
have not been significant.

PIPELINE PROJECTS

The Company is involved in expanding its markets through the following
projects:

LIBERTY PIPELINE COMPANY

In 1992, Liberty Pipeline Company (Liberty Pipeline), a partnership of
interstate pipelines and local distribution companies, filed for FERC approval
to construct and operate a natural gas pipeline to provide up to 500 MMcf per
day in firm transportation service to the greater New York City area. The
partnership is comprised of subsidiaries of Transco, two other interstate
pipelines and subsidiaries of three of Transco's customers in New York,
collectively known as The New York Facilities Group.

The pipeline is expected to cost approximately $162 million and is proposed
to be in service by the 1995-1996 winter heating season, subject to timely FERC
approval. Liberty Operating Company, a subsidiary of Transco, will construct and
operate the pipeline for the partnership.

The Company has filed two separate applications with the FERC requesting
authority to expand its pipeline facilities to provide upstream transportation
service in connection with the Liberty Pipeline project. One application
requests authority to construct facilities at an estimated cost of $59.4 million
to provide an incremental 100 MMcf per day of firm service for The New York
Facilities Group and KIAC Partners, a cogeneration affiliate of The Brooklyn
Union Gas Company. The Company plans, subject to FERC approval, to construct $16
million of facilities to implement 30.3 MMcf per day of this incremental firm
service for the 1995-1996 winter heating season with the remaining $43.4 million
of facilities being constructed during 1996 to provide the remaining 69.7 MMcf
per day of incremental service for the 1996-1997 winter heating season. This
volume of gas will ultimately be transported by TGPL for redelivery to Liberty
Pipeline. The second application requests authority to expand the Company's
facilities to provide an incremental 35 MMcf per day of firm service for The
Power Authority of the State of New York at an estimated cost of $20.9 million.
The Company plans, subject to FERC approval, to construct the $20.9 million of
facilities during 1995 in order to implement the incremental firm transportation
service for The Power Authority of New York in time for the 1995-1996 winter
heating season.

WEST TENNESSEE PIPELINE EXPANSION

In January 1994, the Company received approval from the FERC to expand its
Jackson-Ripley pipeline system located in northwest Tennessee to provide 4.6
MMcf per day of additional firm deliveries to three West Tennessee customers and
to construct additional pipeline looping providing system security on that part
of the Company's system. Construction is anticipated to commence during the
first quarter of 1994. Total cost for

10
<PAGE> 11

this system expansion is expected to be $3.2 million, which the Company
anticipates it will incur during the first half of 1994.

EMPLOYEE RELATIONS

The Company had 1,155 employees as of December 31, 1993. Certain of those
employees were covered by a collective bargaining agreement. A favorable
relationship existed between management and labor during the period.

The International Chemical Workers Local 187 represents 199 of the
Company's 494 field operating employees. The current collective bargaining
agreement between the Company and Local 187 expires on April 30, 1995.

The Company has a non-contributory pension plan and various other plans
which provide regular active employees with group life, hospital and medical
benefits as well as disability benefits and savings benefits. Officers and
directors who are full-time employees may participate in these plans.

ITEM 2. 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.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

(a) and (b) As of December 31, 1993, all of the outstanding shares of the
Company's common stock are owned by Transco Gas Company, a wholly owned
subsidiary of Transco. The Company's common stock is not publicly traded and
there exists no market for such common stock.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

FINANCIAL ANALYSIS OF OPERATIONS

1993 COMPARED TO 1992

As discussed in Note C of Notes to Financial Statements contained in Item 8
hereof, FERC Order 636 required pipelines to "unbundle" services; transportation
and storage services must be offered separately from the sale of gas. As a
result, effective November 1, 1993, the Company's remaining 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 a transition cost. All other gas purchase and sales
commitments are being managed by the Company's marketing affiliate as agent for
the Company. The Company's gas sales currently have no impact on its results of
operations.

The Company's November 1, 1993 implementation of FERC Order 636 also
included a change in its rate design method from MFV to SFV. Under the MFV
method, all fixed costs, with the exception of equity return

11
<PAGE> 12

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, overall throughput has a less
significant impact on the Company's operating income than under the MFV method.

Effective November 1, 1993, the Company placed rates into effect, subject
to refund, under a new general rate case (see discussion in Note C of Notes to
Financial Statements contained in Item 8 hereof). Certain parties to the rate
case proceedings are seeking to change the capital structure and reduce the
Company's return on equity included in rates.

The Company's earnings may be impacted by 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 believes that under FERC Order 636, with SFV
rates and its anticipated transition cost recovery, its rate structure will
remain competitive. However, the resolution of pending rate case issues
discussed above could negatively impact the Company's results of operations
under the pending rate case. Furthermore, while the use of SFV rate design
limits the Company's opportunity to earn incremental revenues through increased
throughput, it also minimizes the Company's risk associated with fluctuations in
throughput.

Operating and Net Income

Operating income was $7 million higher for the year ended December 31, 1993
than for the year ended December 31, 1992. The increase in operating income was
primarily due to higher gas transportation revenues, partially offset by lower
net gas sales revenues and increased other operating costs and expenses. Each of
these factors is discussed below.

Excluding the Company's $4 million after-tax gain on the sale of its
subsidiary in 1992, net income was $3 million higher than 1992 for the same
reasons that resulted in higher operating income.

Operating Revenues

Operating revenues increased $2 million, primarily as a result of $48
million higher gas transportation revenues, partially offset by $45 million
lower gas sales revenues. The increase in gas transportation revenues was
primarily due to higher firm transportation demand revenues primarily as a
result of the conversion of customer's firm sales service to firm transportation
service due to the implementation of FERC Order 636 and higher long-haul
transportation volumes. Gas sales revenues decreased primarily as a result of
the conversion of customer's sales service and decreased commodity volumes.

Operating Costs and Expenses

Costs of gas sold decreased $22 million from the prior year. This decrease
was primarily due to the implementation of FERC Order 636 and the resultant
decrease in gas sales volumes.

The Company's administrative and general expenses increased $16 million.
The increase was primarily due to $6 million higher labor and employee benefits
costs, a $5 million provision for uncollectible accounts, which includes $2
million in claims filed under customer bankruptcy proceedings, and $3 million in
higher management services fees allocated from Transco.

System Deliveries

As shown in the table below, the Company's total mainline deliveries for
the year ended December 31, 1993 increased 88.5 Bcf, or 18.3%, as compared to
the year ended December 31, 1992, primarily as a result of increased throughput
in connection with the Company's 1992 mainline expansion project, and, during
the winter months of 1993, 13% colder weather on a degree-day basis in the
Company's primary market area

12
<PAGE> 13

compared to the winter months of 1992. The revenues associated with short-haul
transportation volumes are not material to the Company.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------
SYSTEM DELIVERIES (BCF): 1993 1992
--------------------------------------------------------------------- ----- -----
<S> <C> <C>
Sales................................................................ 51.5 80.4
Long-haul transportation............................................. 519.6 402.2
----- -----
Total mainline deliveries.................................. 571.1 482.6
Short-haul transportation............................................ 204.0 244.2
----- -----
Total system deliveries.................................... 775.1 726.8
----- -----
----- -----
</TABLE>

The Company's facilities are divided into five rate zones. Receipts and
deliveries are made in four rate zones to service sales and long-haul
transportation markets. Receipts and deliveries in the remaining zone are made
to serve sales and short-haul transportation markets in southern Louisiana.

1992 COMPARED TO 1991

The table below shows the net income of the Company for the years ended
December 31, 1992 and 1991 and the effects of certain selected items that have
impacted those results (expressed in millions):

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------
1992 1991
----- -----
<S> <C> <C>
Net income before selected items..................................... $36.5 $23.5
Gain on sale of subsidiary........................................... 4.4 --
Benefits of resolution of certain rate issues........................ -- 2.5
Provision for severance costs........................................ -- (3.9)
Loss on proposed capital project..................................... -- (0.7)
----- -----
Net Income................................................. $40.9 $21.4
----- -----
----- -----
</TABLE>

Operating and Net Income

Excluding the pre-tax effects of the selected items shown in the table
above, operating income was $25 million higher for the year ended December 31,
1992 than for the year ended December 31, 1991. The increase in operating income
was primarily due to higher mainline revenues, net of cost of natural gas sold
and transported ($17 million) primarily attributable to increased transportation
revenues discussed below, and lower labor and related benefits costs as a result
of the Company's early retirement program offered during the fourth quarter of
1991 ($9 million). Excluding the net income impact of the selected items shown
in the table above net income was $13 million greater than 1991 for the same
reasons that resulted in higher operating income, partially offset by lower
interest income due to lower interest rates on advances to affiliates.

Operating Revenues

Excluding the pre-tax effects of the selected items shown in the table
above, operating revenues decreased $4 million or 1%, primarily as a result of
$40 million lower gas sales revenues, partly offset by $36 million higher gas
transportation revenues. Gas sales decreased as a result of lower demand
revenues, decreased sales volumes and lower average rates. The increase in gas
transportation revenues was primarily due to higher firm transportation demand
revenues, primarily attributable to customers switching from firm sales to firm
transportation contracts and higher rate realization and increased long-haul
transportation volumes.

13
<PAGE> 14

Operating Costs and Expenses

Costs of gas sold and transportation of gas by others decreased $15 million
from the prior year. This decrease was primarily the result of lower cost of gas
sold due to lower gas sales volumes, partially offset by an increase in expense
for transportation of gas by others.

Excluding costs of gas sold and transportation of gas by others and the
pre-tax effect of the selected items, the Company's operating expenses decreased
$14 million. The decrease in other operating expenses was primarily due to lower
labor and related benefits costs in 1992 as a result of the Company's early
retirement program offered during the fourth quarter of 1991.

System Deliveries

As shown in the table below, the Company's total mainline deliveries for
the year ended December 31, 1992 increased 10.6 Bcf, or 2%, as compared to the
year ended December 31, 1991, primarily as a result of increased throughput in
connection with the Company's 1992 mainline expansion project, tariff rate
competitiveness relative to spot market prices, and discounting. Total system
deliveries for the year ended December 31, 1992 were greater than those for
1991, mainly due to an increase in short-haul transportation. The revenues
associated with these short-haul volumes were not significant.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------
SYSTEM DELIVERIES (BCF): 1992 1991
--------------------------------------------------------------------- ----- -----
<S> <C> <C>
Sales................................................................ 80.4 89.9
Long-haul transportation............................................. 402.2 382.1
----- -----
Total mainline deliveries.................................. 482.6 472.0
Short-haul transportation............................................ 244.2 225.6
----- -----
Total system deliveries.................................... 726.8 697.6
----- -----
----- -----
</TABLE>

The Company's throughput is impacted by seasonal changes in weather, as
well as competition from other gas pipelines. The weather in the Company's
primary market area during the winter months of 1992 was 14% warmer than normal.
During 1992, the Company continued to discount certain of its transportation
rates in response to competitive pressures and/or to gain incremental markets
for the purpose of increasing system throughput and associated revenues. The
discounted rates were provided on both a generic and selective basis after
analyzing the competitive and economic factors of each specific situation.

COMPETITION

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.

14
<PAGE> 15

CAPITAL RESOURCES AND LIQUIDITY

INTRODUCTION

Through the years, the Company has consistently maintained its financial
strength and experienced strong operational results. Since its 1989 acquisition
by Transco, the Company has continued to enjoy financial and operational
strength. As an indirect wholly owned subsidiary of Transco, the Company may be
affected by the financial position and performance of Transco and its other
subsidiaries. The Company does not currently anticipate that such relationship
will have a material adverse effect on its financial position or results of
operations.

In October 1991, Transco's Board of Directors approved a comprehensive
strategic and financial plan (Plan) designed to stabilize Transco's financial
position, improve financial flexibility and restore earnings. Since the Plan's
adoption, Transco has made significant progress in its implementation, including
the sale of certain non-core and non-strategic businesses, reduction in capital
expenditures, resolution of certain material litigation and improvement in its
results of operations and financial flexibility.

Transco remains committed to deleveraging its balance sheet, further
eliminating or mitigating the potentially adverse impact from resolution of
remaining litigation and contingencies and improving financial results.

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.

At December 31, 1993, the Company had outstanding current and non-current
advances to Transco of $66 million and $137 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 non-current.

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.

To meet the working capital requirements of Transco and its subsidiaries,
Transco has in place a $450 million working capital line with a group of fifteen
banks. The Company is guarantor of up to $180 million of this working capital
line. At December 31, 1993, Transco had no outstanding borrowings under this
facility.

Transco also has in place a $50 million reimbursement facility, dated as of
December 31, 1993, between Transco and a group of five banks. This facility
provides Transco the opportunity to obtain standby letters of credit under
certain circumstances from the banks. The Company is guarantor of up to $20
million of the obligations that arise under this facility. At December 31, 1993,
Transco had no amounts outstanding under this facility.

These credit facilities prohibit the Company from, among other things,
incurring or guaranteeing any additional indebtedness (except for indebtedness
incurred to refinance existing indebtedness), issuing preferred stock or
advancing cash to affiliates other than Transco. Further, these credit
facilities and Transco's indentures contain restrictive covenants which could
limit Transco's ability to make additional borrowings and, therefore, under
certain circumstances, its ability to repay advances or make capital
contributions to the Company.

15
<PAGE> 16

CASH FLOWS AND CAPITALIZATION

Net cash inflows from operating activities for the year ended December 31,
1993 were approximately $38 million lower than for the year ended December 31,
1992, primarily as a result of the payment of the RP90-104 rate refunds in the
amount of $36.3 million. Net cash inflows from operating activities for the year
ended December 31, 1992 were approximately $14 million higher than for the year
ended December 31, 1991, primarily as a result of an increase in payables due to
higher gas volumes being purchased at higher prices on the spot market in the
last quarter of 1992 than in the last quarter of 1991 and increased net income,
partially offset by higher net gas storage injections.

Net cash outflows from financing activities for the year ended December 31,
1993 were comparable to the year ended December 31, 1992. Net cash outflows from
financing activities for the year ended December 31, 1992 were $15 million
higher than the year ended December 31, 1991, primarily as a result of increased
dividends paid to Transco and the net effect of the debt repayment and proceeds
from the Company's 1992 debt issue.

Net cash outflows from investing activities for the year ended December 31,
1993 were $35 million lower than the year ended December 31, 1992, mainly due to
a decrease in cash advanced to Transco under Transco's cash management program,
partially offset by the prior year proceeds from the sale of the Company's
subsidiary. Net cash outflows from investing activities for the year ended
December 31, 1992 were $3 million lower than the year ended December 31, 1991,
mainly due to a decrease in capital additions, partially offset by an increase
in cash advanced to Transco under Transco's cash management program and a
decrease in recoveries of producer settlements. The decrease in capital
additions was primarily due to lower expenditures for market expansion projects
and maintenance of current facilities.

The Company's 1993 capital expenditures of $33 million included $27 million
for maintenance of existing facilities and $6 million for market and supply
expansion projects.

The Company's debt, less current maturities, as a percentage of total
capitalization for the years ended December 31, 1993 and 1992 was 14% and 29%,
respectively. The Company intends to issue long-term public debt in the second
quarter of 1994 to refinance the maturities of its 10% debentures, which will
restore the above ratio to 29%.

In September 1993, the Company entered into a new program to sell monthly
trade receivables, which replaced the Company's previous program. The new trade
receivables program, which expires in September 1995, provides for the sale of
up to $40 million of trade receivables without recourse. As of December 31,
1993, $34 million in trade receivables were held by the investor.

GAS SUPPLY REALIGNMENT COST RECOVERIES

On January 28, 1994, the Company submitted its first filing to recover
$11.5 million of GSR costs pursuant to the transition costs recovery provisions
of FERC Order 636 and the Company's approved FERC Gas Tariff. This amount
represents 90% of the total GSR costs paid through November 30, 1993, which are
expected to be recovered over a 12-month period by application of a demand
surcharge to its firm transportation rates. The remaining 10% is expected to be
recovered from interruptible transportation service. The Company plans to make
quarterly filings to allow recovery of its GSR costs as such costs are paid.

FUTURE CAPITAL EXPENDITURES

The Company's budgeted capital expenditures for 1994 of $41 million include
$36 million for maintenance of current facilities, $3 million for market
expansion in connection with the West Tennessee pipeline expansion project, $1
million for market expansion in connection with the Liberty Pipeline expansion
project and $1 million for other market expansion projects.

If the Liberty Pipeline and The Power Authority of the State of New York
projects are constructed, the Company expects to expand its pipeline facilities
at a cost currently estimated to be $80 million, the majority of which, subject
to FERC approval, will be spent in 1995 and 1996 (see "Business -- Pipeline
Projects").

16
<PAGE> 17

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, the Company's analysis of FERC Order 636 indicates that the Company's
transition costs are not currently expected to exceed $90 million, primarily
related to GSR contract termination costs, GSR pricing differential costs
incurred pursuant to the auction process, as discussed below, and unrecovered
purchased gas costs. FERC Order 636 provides that pipelines should be allowed
the opportunity to recover all prudently incurred transition costs. Therefore,
the Company expects that any transition costs incurred should be recovered from
its customers, subject only to the costs and other risks associated with the
difference between the time such costs are incurred and the time when those
costs may be recovered from customers.

Although no assurances can be given, the Company does not believe that
transition costs will have a material adverse effect on its financial position
or results of operations.

Long-term Gas Purchase Contracts

Gas purchased under the Company's 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. As
discussed in Note C of Notes to Financial Statements contained in Item 8 hereof,
through December 31, 1993, the Company had paid or committed to pay a total of
$38 million for GSR costs, primarily as a result of contract terminations.
Pursuant to FERC Order 636, the Company is entitled to file to recover 100% of
these costs as GSR costs.

The Company does not believe that financial risks associated with its
long-term gas purchase contracts are material to the Company's financial
position or results of operations.

Rate Matters

As discussed in Note C of Notes to Financial Statements contained in Item 8
hereof, the Company has a pending rate case that may require refunds, including
interest, during 1994. The Company has established a reserve for various
regulatory and rate issues which it believes is adequate to provide for the
refunds that will ultimately be required.

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 purchase gas costs and absorb the remaining $5 million. The
Company believes it is entitled to full recovery of these FERC-ordered costs.
The Company has filed for rehearing of this order and has received an extension
staying the effectiveness of this order until 30 days after the FERC rules on
rehearing. The Company believes that its reserve for regulatory and rate matters
is adequate to provide for any costs the Company may ultimately be required to
absorb.

Environmental Matters

FERC Orders 500 and 528

See Note C of Notes to Financial Statements contained in Item 8 hereof for
a description of the status of the Company's filings pursuant to FERC Order 528.

17
<PAGE> 18

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 or
results of operations.

CONCLUSION

Although no assurances can be given, the Company currently believes that
the aggregate of cash flows from operating activities, supplemented by
refinancing of maturing debt and, if necessary, by repayments of funds advanced
to Transco, will provide the Company with sufficient liquidity to meet its
capital requirements.

18
<PAGE> 19

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Texas Gas Transmission Corporation:

We have audited the accompanying balance sheets of Texas Gas Transmission
Corporation (a Delaware corporation and an indirect wholly owned subsidiary of
Transco Energy Company) as of December 31, 1993 and 1992, and the related
statements of income, retained earnings and paid-in capital and cash flows for
each of the three years in the period ended December 31, 1993. These financial
statements and the schedules referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and schedules based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Texas Gas Transmission
Corporation as of December 31, 1993 and 1992, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
1993, in conformity with generally accepted accounting principles.

Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedules listed
in the index to Part IV, Item 14(a)2 are presented for purposes of complying
with the Securities and Exchange Commission's rules and are not part of the
basic financial statements. These financial statement schedules have been
subjected to the auditing procedures applied in the audits of the basic
financial statements and, in our opinion, fairly state in all material respects
the financial data required to be set forth therein in relation to the basic
financial statements taken as a whole.

ARTHUR ANDERSEN & CO.

Houston, Texas
February 18, 1994

19
<PAGE> 20

MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS

The financial statements have been prepared by the management of Texas Gas
Transmission Corporation (the Company) in conformity with generally accepted
accounting principles. Management is responsible for the fairness and
reliability of the financial statements and other financial data included in
this report. In the preparation of the financial statements, it is necessary to
make informed estimates and judgments of the effects of certain events and
transactions based on currently available information.

The Company maintains accounting and other controls that management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded and that transactions are properly recorded in accordance
with management's authorizations. However, limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed benefits derived.

The Company's independent auditors, Arthur Andersen & Co., are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards to enable
them to report that the financial statements present fairly, in all material
respects, the financial position, results of operations and cash flows of the
Company in conformity with generally accepted accounting principles.

The Audit Committee of the Board of Directors of Transco Energy Company
(Transco), composed of three directors who are not employees of Transco, meets
regularly with the independent auditors and management. The independent auditors
have full and free access to the Audit Committee and meet with them, with and
without management being present, to discuss the results of their audits and the
quality of financial reporting.

20
<PAGE> 21

TEXAS GAS TRANSMISSION CORPORATION

BALANCE SHEETS
(THOUSANDS OF DOLLARS)

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1993 1992
------------ ------------
<S> <C> <C>
Current Assets:
Cash and temporary cash investments....................................... $ 292 $ 560
Receivables:
Trade................................................................... 16,441 12,997
Affiliates.............................................................. 4,761 10,605
Other................................................................... 1,934 829
Advances to affiliates.................................................... 65,667 75,493
Transportation and exchange gas receivable................................ 25,112 48,587
Costs recoverable from customers:
Gas purchase............................................................ 5,590 --
Producer settlement..................................................... 1,067 2,397
Gas supply realignment.................................................. 19,231 --
Inventories............................................................... 14,724 14,369
Gas stored underground -- LIFO............................................ -- 85,240
Deferred income tax benefits.............................................. 17,680 15,140
Other..................................................................... 5,751 6,267
------------ ------------
Total current assets............................................... 178,250 272,484
------------ ------------
Advances to Affiliates...................................................... 137,000 145,165
------------ ------------
Investments, at Cost........................................................ 2,635 3,731
------------ ------------
Property, Plant and Equipment, at Cost:
Natural gas transmission plant............................................ 706,668 679,802
Other natural gas plant................................................... 128,376 126,221
------------ ------------
835,044 806,023
Less -- Accumulated depreciation and amortization.................. 173,201 131,642
------------ ------------
Property, plant and equipment, net................................. 661,843 674,381
------------ ------------
Other Assets:
Gas stored underground.................................................... 92,103 --
Other..................................................................... 60,515 44,203
------------ ------------
Total other assets................................................. 152,618 44,203
------------ ------------
Total Assets....................................................... $1,132,346 $1,139,964
------------ ------------
------------ ------------
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt...................................... $ 150,000 $ --
Payables:
Trade................................................................... 13,821 40,303
Affiliates.............................................................. 13,274 4
Other................................................................... 30,714 12,858
Advances from affiliates.................................................. 1,576 1,088
Transportation and exchange gas payable................................... 17,109 36,536
Accrued liabilities....................................................... 45,659 69,765
Accrued gas supply realignment costs...................................... 24,750 --
Costs refundable to customers............................................. 4,643 12,959
Reserve for regulatory and rate matters................................... 23,063 15,215
Other..................................................................... 676 1,517
------------ ------------
Total current liabilities.......................................... 325,285 190,245
------------ ------------
Long-Term Debt.............................................................. 98,678 248,305
------------ ------------
Other Liabilities and Deferred Credits:
Income taxes refundable to customers...................................... 7,243 13,698
Deferred income taxes..................................................... 35,348 28,246
Other..................................................................... 58,556 56,566
------------ ------------
Total other liabilities and deferred credits....................... 101,147 98,510
------------ ------------
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......................................................... 22,523 18,191
------------ ------------
Total stockholder's equity......................................... 607,236 602,904
------------ ------------
Total Liabilities and Stockholder's Equity......................... $1,132,346 $1,139,964
------------ ------------
------------ ------------
</TABLE>

The accompanying notes are an integral part of these financial statements.

21
<PAGE> 22

TEXAS GAS TRANSMISSION CORPORATION

STATEMENTS OF INCOME
(THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
Operating Revenues:
Gas sales................................................ $247,946 $292,978 $332,780
Gas transportation....................................... 215,210 167,133 131,063
Other.................................................... 2,303 3,754 4,266
-------- -------- --------
Total operating revenues......................... 465,459 463,865 468,109
-------- -------- --------
Operating Costs and Expenses:
Cost of gas sold......................................... 158,890 181,047 201,972
Cost of transportation of gas by others.................. 54,622 55,813 49,789
Operation and maintenance................................ 54,803 53,898 57,126
Administrative and general............................... 62,702 46,267 58,907
Depreciation and amortization............................ 38,330 37,637 36,959
Taxes other than income taxes............................ 13,075 13,265 12,743
Provision for severance costs............................ -- -- 6,259
Provision for producer settlements....................... -- -- (3,473)
-------- -------- --------
Total operating costs and expenses............... 382,422 387,927 420,282
-------- -------- --------
Operating Income........................................... 83,037 75,938 47,827
-------- -------- --------
Other (Income) Deductions:
Interest expense......................................... 25,578 26,684 26,580
Interest income.......................................... (10,616) (12,107) (14,237)
Equity in earnings of unconsolidated affiliate........... -- (563) (1,985)
Gain on sale of subsidiary............................... -- (6,948) --
Miscellaneous other deductions........................... 2,463 1,491 1,126
-------- -------- --------
Total other (income) deductions.................. 17,425 8,557 11,484
-------- -------- --------
Income Before Income Taxes................................. 65,612 67,381 36,343
Provision for Income Taxes................................. 26,555 26,463 14,894
-------- -------- --------
Net Income................................................. $ 39,057 $ 40,918 $ 21,449
-------- -------- --------
-------- -------- --------
</TABLE>

The accompanying notes are an integral part of these financial statements.

22
<PAGE> 23

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, 1990.............................................. $ 13,091 $584,712
Add (deduct):
Net income......................................................... 21,449 --
Cash dividends on common stock..................................... (22,404) --
--------- --------
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
--------- --------
--------- --------
</TABLE>

The accompanying notes are an integral part of these financial statements.

23
<PAGE> 24

TEXAS GAS TRANSMISSION CORPORATION

STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1993 1992 1991
-------- --------- --------
<S> <C> <C> <C>
Cash Flows From Operating Activities:
Net income................................................ $ 39,057 $ 40,918 $ 21,449
Adjustments to reconcile net income to net cash from
operating activities:
Depreciation and amortization.......................... 39,783 39,150 38,543
Deferred income taxes.................................. 4,563 19,319 (4,650)
Provision for severance costs.......................... -- -- 6,259
Provision for producer settlements..................... -- -- (3,473)
Nonrecoverable producer settlements.................... (1,914) -- --
Equity in undistributed earnings of unconsolidated
affiliate............................................ -- (563) (1,985)
Distributions from unconsolidated affiliate............ -- -- 3,600
Gain on sale of subsidiary............................. -- (6,948) --
Decrease (increase) in:
Receivables.......................................... 1,319 (8,120) 13,194
Transportation and exchange gas receivable........... 23,475 (12,164) (7,281)
Inventories.......................................... (355) (17,367) 3,614
Deferred gas costs................................... (9,161) (15,854) (11,574)
Other current assets................................. (12,986) 13,578 12,127
Increase (decrease) in:
Payables............................................. 4,644 7,987 (21,398)
Transportation and exchange gas payable.............. (19,426) 16,515 1,130
Accrued liabilities.................................. (24,036) (13,165) (2,581)
Reserve for regulatory and rate matters.............. 15,506 7,023 26,937
Other current liabilities............................ (5,585) 7,124 1,201
Other, net............................................. (11,907) 3,843 (7,411)
-------- --------- --------
Net cash from operating activities................ 42,977 81,276 67,701
-------- --------- --------
Cash Flows From Financing Activities:
Advances from affiliates, net............................. 150 101 (12)
Dividends and returns of capital on common stock.......... (34,725) (34,863) (22,404)
Long-term debt -- repayment............................... -- (100,000) --
-- borrowing, net........................ (1) 97,693 --
-------- --------- --------
Net cash from financing activities................ (34,576) (37,069) (22,416)
-------- --------- --------
Cash Flows From Investing Activities:
Property, plant and equipment, net of equity AFUDC........ (33,014) (38,236) (57,238)
Recoverable producer settlements.......................... (5,743) -- --
Recovery of producer settlements.......................... 3,831 16,115 32,621
Advances to affiliates, net............................... 18,336 (32,025) (21,962)
Other, net................................................ 7,921 10,230 (39)
-------- --------- --------
Net cash from investing activities................ (8,669) (43,916) (46,618)
Net Increase (Decrease) in Cash and Cash Equivalents........ (268) 291 (1,333)
-------- --------- --------
Cash and Cash Equivalents at Beginning of Period............ 560 269 1,602
-------- --------- --------
Cash and Cash Equivalents at end of Period........ $ 292 $ 560 $ 269
-------- --------- --------
-------- --------- --------
Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized)................... $ 28,654 $ 23,924 $ 25,965
Income taxes, net...................................... 6,433 16,149 23,723
</TABLE>

The accompanying notes are an integral part of these financial statements.

24
<PAGE> 25

TEXAS GAS TRANSMISSION CORPORATION

NOTES TO FINANCIAL STATEMENTS

A. CORPORATE STRUCTURE AND CONTROL AND BASIS OF PRESENTATION

Corporate Structure and Control

Texas Gas Transmission Corporation (the Company) is a wholly owned
subsidiary of Transco Gas Company (TGC), which is a wholly owned subsidiary of
Transco Energy Company (Transco). As used herein, the term Transco refers to
Transco Energy Company and its wholly owned subsidiary companies; the term TGMC
refers to Transco Gas Marketing Company, a wholly owned subsidiary of Transco,
and its wholly owned subsidiary companies; and the term TGPL refers to
Transcontinental Gas Pipe Line Corporation, a wholly owned subsidiary of TGC,
unless the context otherwise requires.

The Company's sole subsidiary, Texam Offshore Gas Transmission, Inc.
(Texam), was sold on July 20, 1992 (see Note H). The financial information
presented for periods prior to the date of sale represents the Company's
consolidated financial position and results of operations.

Basis of Presentation

The acquisition of the Company was accounted for using the purchase method
of accounting. Accordingly, the acquisition debt and the purchase price were
"pushed down" and recorded in the Company's financial statements. Retained
earnings, deferred taxes and accumulated depreciation and amortization were
eliminated at the date of acquisition.

Included in property, plant and equipment as of the date of Transco's
acquisition of the Company in 1989 is an aggregate of $226 million related to
amounts in excess of the original cost of the regulated facilities. This amount
is amortized over the estimated life of the assets acquired at approximately $9
million per year. Current Federal Energy Regulatory Commission (FERC) policy
does not permit the Company to recover through its rates amounts in excess of
original cost.

Related Parties

As a subsidiary of Transco, the Company engages in transactions with
Transco and other Transco subsidiaries characteristic of group operations. For
consolidated cash management purposes, the Company makes interest-bearing
advances to Transco. These advances are represented by demand notes payable to
the Company. Those amounts that the Company anticipates Transco will repay in
the next twelve months are classified as current assets, while the remainder are
classified as noncurrent. As general corporate policy, the interest rate on
intercompany demand notes is 1 1/2% below the prime rate of Citibank, N.A. Net
interest income on advances to or from associated companies was $9.4 million,
$9.6 million and $11.5 million for the years ended December 31, 1993, December
31, 1992 and December 31, 1991, respectively. See Note F for a discussion of
Transco's credit facilities and indentures as they relate to the Company.

Transco has a policy of charging subsidiary companies for management
services provided by the parent company and other affiliated companies. During
the years ended December 31, 1993, December 31, 1992 and December 31, 1991, the
Company was charged $6.7 million, $4.2 million and $4.4 million, respectively,
for Transco management services. Management considers the cost of these services
reasonable.

Effective November 1, 1993, the Company contracted with TGMC to become the
Company's agent for the purpose of administering all existing and future gas
sales and market-responsive purchase obligations, except for its auction gas
transactions. Sales and purchases under this agreement do not impact the
Company's results of operations. For the two months ended December 31, 1993, the
Company paid TGMC agency fees of $0.7 million for these services.

Included in the Company's gas sales revenues for the year ended December
31, 1993 is $4.2 million applicable to gas sales to the Company's affiliate,
TGMC. There were no intercompany gas sales for the years ended December 31, 1992
and December 31, 1991.

25
<PAGE> 26

Included in the Company's gas transportation revenues for the years 1993,
1992 and 1991 are amounts applicable to transportation for affiliates as follows
(expressed in thousands):

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1993 1992 1991
------- ------- ------
<S> <C> <C> <C>
TGMC........................................... $ 2,609 $ 3,635 $4,436
TGPL........................................... 33,913 20,380 1,614
------- ------- ------
$36,522 $24,015 $6,050
------- ------- ------
------- ------- ------
</TABLE>

Included in the Company's cost of gas sold for the years ended December 31,
1993 and December 31, 1992, is $11.1 million and $4.2 million, respectively,
applicable to gas purchases from the Company's affiliate, TGMC. There were no
intercompany gas purchases for the year ended December 31, 1991.

B. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

The Company recognizes revenues for the sale and transportation of natural
gas in the period of sale and in the period service is provided, respectively.
Pursuant to FERC regulations, a portion of the revenues being collected may be
subject to possible refunds upon final orders in pending rate cases. The Company
has established reserves, where required, for such cases (see Note C for a
summary of pending rate cases before the FERC).

Costs Recoverable from/Refundable to Customers

The Company has various mechanisms whereby rates or surcharges are
established and revenues are collected and recognized based on estimated costs.
Costs incurred over or under approved levels are deferred and recovered or
refunded through future rate or surcharge adjustments (see Note C for a
discussion of the Company's rate matters).

Depreciation and Amortization

The Company's depreciation rates are principally mandated by the FERC.
Depreciation rates used for regulated gas plant facilities at year end 1993,
1992 and 1991 are as follows:

<TABLE>
<CAPTION>
DEPRECIATION RATES
-----------------------------------------------
1993 1992 1991
------------- ------------ ------------
<S> <C> <C> <C>
Transmission -- Onshore......................... 2.00% 2.00% 2.00%
Transmission -- Offshore........................ 6.00% 6.00% 6.00%
Storage Plant................................... 2.30% 2.30% 2.30%
Other........................................... 0.75% - 15.0% 0.75 - 15.0% 0.75 - 15.0%
</TABLE>

Tax Policy

Transco and its wholly owned subsidiaries file a consolidated federal
income tax return. It is Transco's policy to charge or credit each subsidiary
with an amount equivalent to its federal income tax expense or benefit computed
as if each subsidiary had a separate return, but including benefits from each
subsidiary's losses and tax credits that may be utilized only on a consolidated
basis.

Accounting for Income Taxes

The Company uses the liability method of accounting for deferred taxes
which requires, among other things, adjustments to the existing deferred tax
balances for changes in tax rates, whereby such balances will more closely
approximate the actual taxes to be paid.

26
<PAGE> 27

Liabilities to customers of $7.9 million and $15.2 million at December 31,
1993 and December 31, 1992, respectively, resulting from net tax rate reductions
related to regulated operations and to be refunded to customers over the average
remaining life of natural gas transmission plant, have been shown in the
accompanying balance sheets as income taxes refundable to customers, the current
portion of which is included in other current liabilities.

In the first quarter of 1993, the Company adopted Statement of Financial
Accounting Standards (SFAS) 109, "Accounting for Income Taxes," which superseded
SFAS 96, "Accounting for Income Taxes." Due to the Company's prior adoption of
SFAS 96 in 1987, the adoption of SFAS 109 did not have a material effect on its
financial position or results of operations.

Capitalized Interest

The allowance for funds used during construction represents the cost of
funds applicable to regulated natural gas transmission plant under construction
as permitted by FERC regulatory practices. The allowance for borrowed funds used
during construction and capitalized interest for the years ended December 31,
1993, December 31, 1992 and December 31, 1991, was $0.2 million, $0.6 million
and $0.7 million, respectively. The allowance for equity funds for the years
ended December 31, 1993, December 31, 1992 and December 31, 1991, was $0.5
million, $1.2 million and $1.3 million, respectively.

Gas in Storage

Gas Imbalances

In the course of providing transportation services to customers, the
Company may receive different quantities of gas from shippers than the
quantities delivered on behalf of those shippers. These transactions result in
imbalances which are repaid or recovered in cash or through the receipt or
delivery of gas in the future. Customer imbalances to be repaid or recovered
in-kind are recorded as transportation and exchange gas receivable or payable on
the accompanying balance sheet. Settlement of imbalances requires agreement
between the pipelines and shippers as to allocations of volumes to specific
transportation contracts and timing of delivery of gas based on operational
conditions.

The Company's tariff includes a provision whereby imbalances generated
after November 1, 1993 are settled on a monthly basis. The Company anticipates
filing for a mechanism whereby imbalances pre-dating November 1, 1993 will be
recovered or repaid in cash or through the future receipt or delivery of gas
upon agreements for allocation and as permitted by operating conditions.

Cash Flows from Operating Activities

The Company uses the indirect method to report cash flows from operating
activities, which requires adjustments to net income to reconcile to net cash
flows from operating activities. The Company includes short-term highly-liquid
investments that have a maturity of three months or less in cash equivalents.

Postemployment Benefits

The Financial Accounting Standards Board has issued SFAS 112, "Employers'
Accounting for Post employment Benefits," which requires the Company, effective
January 1994, to accrue the estimated cost of providing postemployment benefits
to former or inactive employees after employment but before retirement if the
obligation is attributable to employees' services previously rendered,
employees' rights to those benefits accumulate or vest, payment of the benefits
is probable and the amount of the benefits can be reasonably

27
<PAGE> 28

estimated. The Company does not expect adoption of SFAS 112 to have a material
effect on its financial position or results of operations.

Reclassifications

Certain reclassifications have been made in the 1992 and 1991 financial
statements to conform to the 1993 presentation.

C. REGULATORY AND RATE MATTERS

FERC Order 636

In 1992, the FERC issued Order 636 which brought about fundamental changes
in the way natural gas pipelines conduct their businesses. The FERC's stated
purpose of Order 636 was to improve the competitive structure of the natural gas
pipeline industry by, among other things, unbundling a pipeline's merchant role
from its transportation services; ensuring "equality" of transportation
services; ensuring that shippers and customers have equal access to all sources
of gas; providing "no-notice" firm transportation service that is equal in
quality to bundled sales service; and changing rate design methodology from
Modified Fixed Variable (MFV) to Straight Fixed Variable (SFV), unless the
pipeline company and its customers agree to a different form.

FERC Order 636 also set forth methods for recovery by pipelines of costs
associated with compliance under FERC Order 636 (transition costs), including
unrecovered gas costs, GSR costs, the cost of stranded pipeline investment and
costs of new facilities required.

The Company has restructured its business to implement the provisions of
FERC Order 636. On October 1, 1993, the FERC issued its "Order on Compliance
Filing and Granting, In Part, and Denying, In Part, Rehearing and
Clarification," which essentially approved the major aspects of the Company's
FERC Order 636 compliance plan. The Company filed revised tariff sheets and
other changes pursuant to the October 1, 1993 order on October 18, 1993, which
permitted implementation of FERC Order 636 restructured services on November 1,
1993. On December 16, 1993, the FERC issued another order which required minor
tariff modifications. The Company submitted a filing in compliance with this
order on January 7, 1994. This filing was accepted by an order issued on
February 10, 1994. The Company's analysis of FERC Order 636 indicates that the
Company's transition costs are not currently expected to exceed $90 million,
primarily related to GSR contract termination costs, GSR pricing differential
costs incurred pursuant to the auction process and unrecovered purchased gas
costs. As of December 31, 1993, the Company had paid or committed to pay $38
million of GSR costs, as discussed below in "Long-term Gas Purchase Contracts."
FERC Order 636 provides that pipelines should be allowed the opportunity to
recover all prudently incurred transition costs. Therefore, the Company expects
that any transition costs incurred should be recovered from its customers,
subject only to the costs and other risks associated with the difference between
the time such costs are incurred and the time when those costs may be recovered
from customers.

Although no assurances can be given, the Company does not believe the
implementation of FERC Order 636 will have a material adverse effect on its
financial position or results of operations.

General Rate Issues

In April 1990, the Company filed a general rate case (Docket No. RP90-104),
which became effective in November 1990, subject to refund. A settlement
agreement was filed on July 22, 1991, and approved by the FERC's "Order Granting
Reconsideration," on October 21, 1992. The refunds, including interest, of $36.3
million were distributed to customers on January 19, 1993.

28
<PAGE> 29

On April 29, 1993, the Company filed a general rate case (Docket No.
RP93-106) which, pursuant to the FERC's Suspension Order issued May 28, 1993,
became effective on November 1, 1993, subject to refund. The new rate case was
filed to satisfy the three-year filing requirement of the FERC's regulations, to
recover increased operating costs, to provide a return on increased capital
investment in pipeline facilities, to implement the SFV rate design methodology
and to facilitate resolution of various rate-related issues in the Company's
FERC Order 636 restructuring proceeding. The Company is currently engaged in
settlement proceedings regarding this case. The Company has established a
reserve, which it believes to be adequate, to reflect the difference between the
rates currently being collected and the rates expected to ultimately be
effective upon settlement of the rate case.

During 1993, the Company made several filings under the provisions of its
approved tariff and FERC Orders 483 and 483-A to reflect changes in its
purchased gas costs. The Company also made a filing to reflect changes in costs
of transportation by others, pursuant to the Transport Cost Adjustment (TCA)
tracker provisions of the approved tariff. Pursuant to that tariff, on December
30, 1993, the Company refunded $14.9 million of overcollected transportation
costs. The Annual PGA filing for gas costs incurred through August 1991 (Docket
No. TA92-2-18) was accepted by FERC Letter Orders dated January 31, 1992 and May
22, 1992, with no purchasing practice issues being raised. The Annual PGA filing
for gas costs incurred through August 1992 (Docket No. TA93-1-18) was accepted
by FERC Letter Order dated January 29, 1993, with no purchasing practice issues
being raised.

On November 1, 1993, the Company implemented the provisions of FERC Order
636 (see discussion on FERC Order 636). Pursuant to FERC Order 636, the Company
terminated its PGA clause on that date. On January 31, 1994, the Company filed a
limited Section 4(e) filing, pursuant to its FERC-approved FERC Gas Tariff, to
direct bill the balance of its unrecovered purchase gas costs at October 31,
1993 to its former sales customers. This filing is necessary to recover $3.0
million of deferred gas costs applicable to the period September 1992 through
October 1993. The Company has no outstanding deferred gas cost issues pending in
any other proceeding.

FERC Orders 500 and 528

Pursuant to FERC Order 500, certain other pipelines, from which the Company
made gas purchases (upstream pipelines), had received approval from the FERC to
bill customers for their producer settlement costs. The Company had, in turn,
received FERC approval to flow these costs through to its customers under the
FERC Order 500 purchase deficiency-based direct bill methodology. Following the
issuance of FERC Order 528, which replaced the purchase deficiency-based
recovery methodology, the Company, in 1991, made a series of filings which
reallocated these costs among customers. Pursuant to these filings, the Company
proposed to ultimately flow through to its customers approximately $64.3 million
of costs billed from upstream pipelines. The FERC has issued orders accepting
these filings subject to the ultimate outcome of the underlying filings of the
upstream pipelines and future settlement by the Company. Although the total
billings to the Company are unresolved and the Company may be required to refund
certain amounts previously collected, the Company believes that it will be
entitled to ultimately collect all amounts that are billed by the upstream
pipelines.

FERC Order 94-A

29
<PAGE> 30

overturned the FERC's authorization for pipelines to bill production-related
costs to customers based on gas purchased in prior periods and remanded the
matter to the FERC to determine an appropriate recovery mechanism.

On April 28, 1992, the Company filed a settlement with the FERC providing
for a reallocation of the FERC Order 94-A payments previously collected from
customers. The settlement provided for net refunds of $8.1 million to certain
customers and direct bill recovery of $2.7 million from other customers. The
remaining $5.4 million would be recovered through the PGA mechanism. On February
11, 1993, the FERC issued an order approving the settlement. Certain parties
filed for rehearing of the settlement. On January 12, 1994, the FERC issued its
"Order Granting Rehearing" which found that the FERC had committed a legal error
in allowing the previously mentioned direct bill of FERC Order 94-A costs. The
effect of this order as issued would be to require the Company to make refunds
to certain customers of $13.5 million, recover $2.7 million through direct
billing of other customers, recover $5.4 million as part of the direct billing
of its unrecovered purchase gas costs and absorb the remaining $5.4 million. The
Company believes it is entitled to full recovery of these FERC-ordered
costs. The Company has filed for rehearing of this order and has received an
extension staying the effectiveness of this order until 30 days after the FERC
rules on rehearing. The Company believes that its reserve for regulatory and
rate matters is adequate to provide for any costs which the Company may
ultimately be required to absorb.

Reserve for Regulatory and Rate Matters

The Company has established reserves for its outstanding regulatory and
rate matters which it believes are adequate to provide for any costs incurred or
refunds to be made in regard to the resolution of its regulatory and rate
issues, including general rate matters and the royalty claims discussed in Note
D. Although no assurances can be given, the Company believes that the resolution
of these matters will not have a material adverse effect on its financial
position or results of operations.

Long-term Gas Purchase Contracts

During 1993, as part of the Company's restructuring under FERC Order 636,
the Company engaged in negotiations which have resulted in the successful
termination of approximately 90% of the Company's deliverability under its
non-market responsive gas purchase contracts. Gas purchased under its remaining
non-market responsive contracts is being resold at a monthly auction pursuant to
FERC Order 636. The Company continues to pay to the supplier the actual contract
price and is entitled to file for full recovery of the difference between said
contract price and the amount received for sales at auction as GSR costs under
FERC Order 636.

Through December 31, 1993, the Company had paid or committed to pay a total
of $38.2 million for GSR costs, primarily as a result of the contract
terminations. As of December 31, 1993, the Company had paid $13.4 million of
such costs; the remaining $24.8 million is recorded as a current liability in
the accompanying balance sheet. Pursuant to FERC Order 636, the Company may file
to recover 100% of these costs as GSR costs.

This amount represents 90% of the total GSR costs paid through November 30,
1993, which are expected to be recovered over a 12-month period by application
of a surcharge to its firm transportation demand rates. The remaining 10% is
expected to be recovered from interruptible transportation service. The Company
plans to make quarterly filings to allow recovery of its GSR costs as such costs
are paid.

The Company's market-responsive gas purchase contracts are being separately
managed by its marketing affiliate, TGMC.

30
<PAGE> 31

Environmental Matters

The Company is subject to extensive federal, state and local environmental
laws and regulations which affect the Company's operations related to the
construction and operation of its pipeline facilities. Appropriate governmental
authorities may enforce these laws and regulations with a variety of civil and
criminal enforcement measures, including monetary penalties, assessment and
remediation requirements and injunctions as to future compliance. The Company's
use and disposal of hazardous materials are subject to the requirements of the
federal Toxic Substances Control Act (TSCA), the federal Resource Conservation
and Recovery Act (RCRA) and comparable state statutes. The Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA), also known as
"Superfund," imposes liability, without regard to fault or the legality of the
original act, for release of a "hazardous substance" into the environment.
Because these laws and regulations change from time to time, practices which
have been acceptable to the industry and to the regulators have to be changed
and assessment and monitoring have to be undertaken to determine whether those
practices have damaged the environment and whether remediation is
required. Since 1989, the Company has had studies underway to test its
facilities for the presence of toxic and hazardous substances to determine to
what extent, if any, remediation may be necessary. On the basis of the findings
to date, the Company estimates that environmental assessment and remediation
costs that will be incurred over the next five years under TSCA, RCRA, CERCLA
and comparable state statutes will total approximately $7 million to $11
million. As of December 31, 1993, the Company had a reserve of approximately $7
million for these estimated costs. This estimate depends upon a number of
assumptions concerning the scope of remediation that will be required at certain
locations and the cost of remedial measures to be undertaken. The Company is
continuing to conduct environmental assessments and is implementing a variety of
remedial measures that may result in increases or decreases in the total
estimated costs.

The Company has used lubricating oils containing polychlorinated biphenyls
(PCBs) and, although the use of such oils was discontinued in the 1970's, has
discovered residual PCB contamination in equipment and soils at certain gas
compressor station sites. The Company continues to work closely with the
Environmental Protection Agency (EPA) and state regulatory authorities regarding
PCB issues and has programs to assess and remediate such conditions where they
exist, the costs of which are a significant portion of the $7 million to $11
million range discussed above. Proposed civil penalties have been assessed by
the EPA against another major natural gas pipeline company for the alleged
improper use and disposal of PCBs. Although similar penalties have not been
asserted against the Company to date, no assurance can be given that the EPA may
not seek such penalties in the future.

The Company has either been named as a potentially responsible party (PRP)
or received an information request regarding its potential involvement at four
federal "Superfund" waste disposal sites and one state waste disposal
site. Based on present volumetric estimates, the Company believes its estimated
aggregate exposure for remediation of these sites is approximately $500,000.
Liability under CERCLA (and applicable state law) can be joint and several with
other PRPs. Although volumetric allocation is a factor in assessing liability,
it is not necessarily determinative; thus the ultimate liability could be
substantially greater than the amount estimated above. The anticipated
remediation costs associated with these sites have been included in the $7
million to $11 million range discussed above. Although no assurances can be
given, the Company does not believe that its PRP status will have a material
adverse effect on its operations.

31
<PAGE> 32

achieved. The Company has compressor stations in ozone non-attainment areas that
could require additional air pollution reduction expenditures, depending on the
requirements imposed. Additions to facilities for compliance with currently
known Federal Clean Air Act standards and the 1990 Amendments are expected to
cost in the range of $2 million to $3 million over the next five years and will
be recorded as assets as the facilities are added.

D. ROYALTY CLAIMS AND LEGAL PROCEEDINGS

In connection with the Company's renegotiations of supply contracts with
producers to resolve take-or-pay and other contract claims, the Company has
entered into certain settlements which may require the indemnification by the
Company of certain claims for royalties which a producer may be required to pay
as a result of such settlements. On October 15, 1992, the United States Court of
Appeals for the Fifth Circuit and the Louisiana Supreme Court, with respect to
the same litigation in applying Louisiana law, determined that royalties are due
on take-or-pay payments under the royalty clauses of the specific mineral leases
reviewed by the Courts. Furthermore, the State Mineral Board of Louisiana has
passed a resolution directing the State's lessees to pay to the State royalties
on gas contract settlement payments. As a result of these and related
developments, the Company has been made aware of demands on producers for
additional royalties and may receive other demands which could result in claims
against the Company pursuant to the indemnification provisions in its
settlements. Indemnification for royalties will depend on, among other things,
the specific lease provisions between the producer and the lessor and the terms
of the settlement between the producer and the Company. The Company may file to
recover 75% of any such amounts it may be required to pay pursuant to
indemnifications for royalties.

As discussed in Note C (see discussion on FERC Orders 500 and 528), on
September 2, 1993, the Company made a filing pursuant to FERC Order 528 to
recover 75% of approximately $3.4 million in additional take-or-pay settlement
payments made by the Company as a result of certain obligations to indemnify a
producer against additional royalty obligations arising out of the producer's
prior take-or-pay settlement with the Company. Some additional indemnity
payments may also be required with respect to such royalties.

In addition, two lawsuits have been filed against the Company in Louisiana,
seeking reimbursement of certain royalties allegedly incurred by the producers
on amounts previously paid the producers by the Company to settle past
take-or-pay disputes and to reform the gas purchase contract pursuant to an
"excess royalty" clause in a gas purchase contract. The amount in dispute is
estimated to be less than $10 million. The Company disputes the application of
the "excess royalty" clause to the particular royalties in question; however, to
the extent any obligation to reimburse the producers exists, it is subject to
the Company's ability to include such payments in its rates or cost of service.

Although no assurances can be given, the Company believes it has provided
reserves which are adequate for the final resolution of its royalty claims and
litigation and that the final resolution of these matters will not have a
material adverse effect on its financial position or results of operations.

32
<PAGE> 33

E. INCOME TAXES

Following is a summary of the provision for income taxes for 1993, 1992 and
1991 (expressed in thousands):

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
Current:
Federal......................................................... $18,330 $ 5,106 $15,528
State........................................................... 3,662 2,038 4,016
------- ------- -------
21,992 7,144 19,544
------- ------- -------
Deferred:
Federal......................................................... 3,753 16,359 (3,946)
State........................................................... 810 2,960 (704)
------- ------- -------
4,563 19,319 (4,650)
------- ------- -------
Provision for income taxes.............................. $26,555 $26,463 $14,894
------- ------- -------
------- ------- -------
</TABLE>

On August 10, 1993, the Omnibus Budget Reconciliation Act of 1993 was
signed into law. Among its provisions was an overall increase in corporate
federal income tax rates from 34% to 35%, effective January 1, 1993. The Company
recorded in the third quarter of 1993 an adjustment to its existing deferred tax
balances and current tax accruals subsequent to January 1, 1993 to reflect the
effects of the increase in corporate federal income tax rates. The adjustment,
which included a reduction to income taxes refundable to customers, did not have
a material adverse effect on the Company's financial position or results of
operations.

There are no material differences between the Company's effective tax rate
and the statutory federal income tax rate for all periods presented.

Deferred income taxes result from temporary differences between the tax
basis of an asset or liability and its reported amount in the financial
statements that will result in taxable or deductible amounts in future years, or
temporary differences resulting from events that have been recognized in the
financial statements that will result in taxable or deductible amounts in future
years. The tax effect of each type of temporary difference and carryforward
reflected in deferred income tax benefits and liabilities as of December 31,
1993 and 1992 are as follows (expressed in thousands):

<TABLE>
<CAPTION>
1993 1992
-------- --------
DEBIT/(CREDIT)
<S> <C> <C>
Deferred Income Tax Benefits, Net:
Current:
Unrecovered purchased gas costs............................. $ (2,180) $ (2,027)
Gas supply realignment costs................................ (2,534) --
Employee benefits........................................... 4,071 2,114
Additional inventory tax basis.............................. 3,205 2,564
Transportation cost adjustments............................. 1,811 7,324
Reserve for regulatory and rate matters..................... 8,296 2,012
Other....................................................... 5,011 3,153
-------- --------
Total Current.......................................... 17,680 15,140
-------- --------
Deferred Income Tax Liabilities, Net:
Noncurrent:
Tax depreciation in excess of books......................... (33,867) (27,136)
Reserve for regulatory and rate matters..................... 6,559 5,430
Book and tax basis differences.............................. (2,952) (2,162)
Allowance for funds used during construction................ (2,344) (2,096)
Gas supply realignment costs................................ (2,738) --
Other....................................................... (6) (2,282)
-------- --------
Total Noncurrent....................................... (35,348) (28,246)
-------- --------
Total deferred income taxes............................ $(17,668) $(13,106)
-------- --------
-------- --------
</TABLE>

33
<PAGE> 34

F. FINANCING

Long-term debt

At December 31, 1993 and 1992, long-term debt issues were outstanding as
follows (expressed in thousands):

<TABLE>
<CAPTION>
1993 1992
-------- --------
<S> <C> <C>
Debentures:
10% due 1994................................................... $150,000 $150,000
Notes:
9 5/8% due 1997................................................ 100,000 100,000
-------- --------
250,000 250,000
Less: Unamortized debt discount.................................. 1,322 1,695
-------- --------
Total long-term debt issues...................................... 248,678 248,305
Less: Amounts due within one year................................ 150,000 --
-------- --------
Total long-term debt, less current maturities.................. $ 98,678 $248,305
-------- --------
-------- --------
</TABLE>

On July 8, 1992, the Company sold $100 million of 9 5/8% Notes due July 15,
1997. Proceeds from the sale of the Notes were used to retire the Company's
9.25% Debentures that matured July 15, 1992.

The Company's debentures and notes have restrictive covenants which provide
that neither the Company nor any subsidiary may create, assume or suffer to
exist any lien upon any principal property, as defined, to secure any
indebtedness unless the debentures and notes shall be equally and ratably
secured.

Transco has in place a $450 million working capital line with a group of
fifteen banks. The Company is guarantor of up to $180 million of this working
capital line. At December 31, 1993, Transco had no outstanding borrowings under
this facility.

Transco also has in place a $50 million reimbursement facility dated as of
December 31, 1993 between Transco and a group of five banks. This facility
provides Transco the opportunity to obtain standby letters of credit under
certain circumstances from the banks. The Company is guarantor of up to $20
million of the obligations that arise under this facility. At December 31, 1993,
Transco had no amounts outstanding under this facility.

Sale of Receivables

In September 1993, the Company entered into a new program to sell monthly
trade receivables, which replaced the Company's previous program. The new trade
receivables program, which expires in September 1995, provides for the sale of
up to $40 million of trade receivables without recourse. As of December 31, 1993
and December 31, 1992, $33.6 million and $43.3 million, respectively, of trade
receivables were held by the investor.

Significant Group Concentrations of Credit Risk

As of December 31, 1993, the Company had trade receivables of $16.4
million. These trade receivables are primarily due from local distribution
companies and other pipeline companies predominantly located in the Midwestern
United States. The Company's credit risk exposure in the event of nonperformance
by the other parties is limited to the face value of the receivables. No
collateral is required on these receivables.

34
<PAGE> 35

G. EMPLOYEE BENEFIT PLANS

Retirement Plan

Substantially all of the Company's employees are covered under a retirement
plan (Retirement Plan) offered by the Company. The benefits under the Retirement
Plan are determined by a formula based upon years of service and the employee's
highest average base compensation during any five consecutive years within the
last ten years of employment. The Retirement Plan provides for vesting of
employees' benefits after five years of credited service. The Company's general
funding policy is to contribute amounts deductible for federal income tax
purposes. Due to its overfunded status, the Company has not been required to
fund the Retirement Plan since 1986. The Retirement Plan's assets, which are
managed by external investment organizations, include cash and cash equivalents,
corporate and government debt instruments, preferred and common stocks,
commingled funds, international equity funds and venture capital limited
partnership interests.

The Retirement Plan was amended effective November 15, 1991, to provide a
Voluntary Window Retirement Program with special retirement benefits for those
eligible members who elected to retire during the Window Period. The net cost of
the program to the Retirement Plan was approximately $5.1 million.

The following table sets forth the funded status of the Retirement Plan at
September 30, 1993 and September 30, 1992, and the amount of prepaid pension
costs as of December 31, 1993 and 1992 (expressed in thousands):

<TABLE>
<CAPTION>
1993 1992
-------- --------
<S> <C> <C>
Actuarial present value of accumulated benefit obligation,
including vested benefits of $46,750 at October 1, 1993 and
$35,748 at October 1, 1992..................................... $(47,542) $(36,319)
-------- --------
-------- --------
Actuarial present value of projected benefit obligation.......... $(83,557) $(63,269)
Plan assets at fair value........................................ 101,089 88,517
-------- --------
Projected benefit obligation less plan assets.................... 17,532 25,248
Unrecognized net loss............................................ 15,254 7,317
Unrecognized net asset at January 1, 1986 being recognized over
19 years....................................................... (12,733) (13,883)
Unrecognized prior service cost.................................. 4,369 4,652
-------- --------
Prepaid pension costs.................................. $ 24,422 $ 23,334
-------- --------
-------- --------
</TABLE>

Prepaid pension costs related to the Retirement Plan have been classified
as other assets in the accompanying balance sheets.

The following table sets forth the components of net pension cost for the
Retirement Plan, which is included in the accompanying financial statements, for
the years ended December 31, 1993, 1992 and 1991 (expressed in thousands):

<TABLE>
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
Service cost-benefits earned during the period......... $ 3,867 $ 4,116 $ 3,806
Interest cost on projected benefit obligation.......... 4,687 6,420 6,257
Actual return on plan assets........................... (13,595) (12,766) (29,345)
Net amortization and deferral.......................... 3,953 (687) 18,313
Early retirement termination benefits.................. -- -- 5,104
-------- -------- --------
Net Pension Expense (Income)................. $ (1,088) $ (2,917) $ 4,135
-------- -------- --------
-------- -------- --------
</TABLE>

35
<PAGE> 36

The projected unit credit method is used to determine the actuarial present
value of the accumulated benefit obligation and the projected benefit
obligation. The following table summarizes the various interest rate assumptions
used to determine the projected benefit obligation for the years 1993, 1992 and
1991:

<TABLE>
<CAPTION>
1993 1992 1991
----- ----- -----
<S> <C> <C> <C>
Discount rate................................................ 7.25% 7.50% 7.75%
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%
</TABLE>

Pension costs are determined using the assumptions as of the beginning of
the Retirement Plan year. The funded status is determined using the assumptions
as of the end of the Retirement Plan year.

Postretirement Benefits Other than Pensions

The Company's Employee Welfare Benefit Plan provides medical and life
insurance benefits to Company employees who retire under the Company's
Retirement Plan with at least five years of service. The Employee Welfare
Benefit Plan is contributory for medical benefits and for life insurance
benefits in excess of specified limits.

In the first quarter of 1993, the Company adopted SFAS 106, "Employer's
Accounting for Postretirement Benefits Other Than Pensions," which requires the
Company to accrue, during the years that employees render the necessary service,
the estimated cost of providing postretirement benefits other than pensions to
those employees. At the January 1, 1993 date of adoption of SFAS 106, the
Company's postretirement benefits obligation (transition obligation) was $68
million which is being amortized over the remaining life of active participants.

The medical benefits are currently funded for all retired Company employees
at a specified amount per quarter through a trust established under the
provisions of section 501(c)(9) of the Internal Revenue Code.

The following table sets forth the Employee Welfare Benefit Plan's funded
status at December 31, 1993, reconciled with the accrued postretirement benefits
cost included in the accompanying balance sheet at December 31, 1993 (in
thousands):

<TABLE>
<CAPTION>
1993
--------
<S> <C>
Accumulated postretirement benefit obligation:
Retirees................................................................ $(53,552)
Fully eligible active plan participants................................. (3,977)
Other active plan participants.......................................... (35,474)
--------
(93,003)
Plan assets at fair value................................................. 22,638
--------
Accumulated postretirement benefit obligation in excess of plan assets.... (70,365)
Unrecognized net loss..................................................... 1,189
Unrecognized transition obligation........................................ 64,753
--------
Accrued postretirement benefit cost....................................... $ (4,423)
--------
--------
</TABLE>

36
<PAGE> 37

The following table sets forth the components of the net periodic
postretirement benefit cost, net of deferred costs, which is included in the
accompanying financial statements for the year ended December 31, 1993 (in
thousands):

<TABLE>
<CAPTION>
1993
-------
<S> <C>
Service cost-benefits earned during the period............................. $ 2,430
Interest cost on accumulated postretirement benefit obligation............. 6,325
Actual return on plan assets............................................... (2,548)
Amortization of transition obligation...................................... 3,238
Net amortization and deferral.............................................. 1,356
-------
Net periodic postretirement benefit cost......................... 10,801
Less deferral of costs not included in jurisdictional rates................ 5,013
-------
Net periodic postretirement benefit cost net of deferred costs... $ 5,788
-------
-------
</TABLE>

The annual expense is subject to change in future periods as a result of,
among other things, the passage of time, changes in participants, changes in
Employee Welfare Benefit Plan benefits and changes in assumptions upon which the
estimates are made.

For measurement purposes as of December 31, 1993, the initial annual rate
of increase in the per capita cost of covered health care benefits was assumed
to be 12%. The rate was assumed to decrease gradually to 6% for the year 2005
and remain at that level thereafter. The health care cost trend rate assumption
has a significant effect on the amounts reported. To illustrate, increasing the
assumed health care cost trend rate by one percentage point in each year would
increase the accumulated postretirement benefit obligation for health care
benefits as of January 1, 1994 by 16% and the aggregate of the service and
interest cost components of the net periodic postretirement health care benefit
cost for 1994 by 19%.

To determine the accumulated postretirement benefit obligation, the
Employee Welfare Benefit Plan used a discount rate of 7.25% and a salary growth
assumption of 5.0% per annum. Employee Welfare Benefit Plan assets are managed
by external investment organizations and include cash and cash equivalents,
commingled funds, preferred and common stocks and government and corporate debt
instruments. The expected long-term rate of return on Employee Welfare Benefit
Plan assets was 7% after taxes. Realized returns on Employee Welfare Benefit
Plan assets are subject to federal income taxes at a sliding scale that
increases up to a 39.6% tax rate.

In November 1993, the Company placed into effect a general rate case that
provides for the increase in postretirement benefits costs pursuant to SFAS 106
to be collected in rates. Prior to November 1, 1993 the Company deferred the
difference between its postretirement benefits expense accrued in 1993 under
SFAS 106 and the amount it collected in rates and recorded a regulatory asset of
approximately $5 million as of November 1, 1993. Pursuant to its rate case
filing, the Company proposes to recover the regulatory asset in rates over a
36-month period beginning November 1, 1993.

The Company believes that all costs of providing postretirement benefits to
its employees are necessary and prudent operating expenses and that such costs
will continue to be recoverable in rates. Adoption of SFAS 106 did not have a
material adverse effect on the Company's financial position or results of
operations.

H. SALE OF SUBSIDIARY

On June 8, 1992, Transco and certain of its subsidiaries (including the
Company) entered into a definitive agreement to sell their interests in certain
gas gathering and related facilities for $65 million in cash, subject to certain
adjustments. The sale, which was closed on July 20, 1992, included the stock of
the Company's subsidiary, Texam. Of the total sales price, $12.5 million was
allocated to the sale of Texam. The Company recognized a $6.9 million gain ($4.4
million after-tax) in connection with this sale.

37
<PAGE> 38

I. FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash and Short-Term Financial Assets and Liabilities

For short-term instruments, the carrying amount is a reasonable estimate of
fair value due to the short maturity of those instruments, except for the
Company's current maturities of long-term debt which is publicly traded.
Therefore, the fair value of these maturities is estimated based on quoted
market prices, less accrued interest, at December 31, 1993.

Long-Term Notes Receivable

The carrying amount for the long-term notes receivable, which are shown as
advances to affiliates on the balance sheet, is a reasonable estimate of fair
value. As discussed in Note A, the notes earn a variable rate of interest which
is adjusted regularly to reflect current market conditions.

Long-Term Debt

All of the Company's debt is publicly traded; therefore, fair value is
estimated based on quoted market prices, less accrued interest, at December 31,
1993 and 1992.

The carrying amount and estimated fair values of the Company's financial
instruments as of December 31, 1993 and 1992 are as follows (in thousands):

<TABLE>
<CAPTION>
CARRYING FAIR
AMOUNT VALUE
-------------------- --------------------
1993 1992 1993 1992
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Financial Assets:
Cash and short-term financial assets..... $ 92,261 $ 86,346 $ 92,261 $ 86,346
Long-term notes receivable............... 137,000 145,165 137,000 145,165
Financial Liabilities:
Short-term financial liabilities......... 224,953 70,287 223,563 70,287
Long-term debt........................... 100,000 250,000 102,252 245,015
</TABLE>

J. SUPPLEMENTARY PROFIT AND LOSS INFORMATION

Major Customers

Listed below are sales and transportation revenues received from the
Company's major customers in 1993, 1992 and 1991, portions of which are included
in the refund reserve discussed in Note C (expressed in thousands):

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1993 1992 1991
------- ------- -------
<S> <C> <C> <C>
Indiana Gas Company, Inc................................ $49,825 $57,304 $72,165
Louisville Gas and Electric Company..................... 45,176 63,485 56,764
Western Kentucky Gas Company............................ 41,314 45,144 47,607
</TABLE>

Expenditures for Maintenance and Repairs

Expenditures for maintenance and repairs for the years ended December 31,
1993, December 31, 1992 and December 31, 1991, were $16.8 million, $14.1 million
and $14.6 million, respectively.

38
<PAGE> 39

K. QUARTERLY INFORMATION (UNAUDITED)

The following summarizes selected quarterly financial data for 1993 and
1992 (expressed in thousands):

<TABLE>
<CAPTION>
1993
------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ------- ------- --------
<S> <C> <C> <C> <C>
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 deductions (income):
Interest expense................................ 6,215 6,229 6,250 6,393
Other (income), net............................. (1,775) (1,935) (1,968) (1,984)
-------- ------- ------- --------
Total other deductions (income)............ 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
-------- ------- ------- --------
-------- ------- ------- --------
</TABLE>

<TABLE>
<CAPTION>
1992
--------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ------- ------- --------
<S> <C> <C> <C> <C>
Operating revenues............................... $124,158 $98,731 $94,545 $146,431
Operating expenses............................... 101,117 86,451 79,381 120,978
-------- ------- ------- --------
Operating income......................... 23,041 12,280 15,164 25,453
-------- ------- ------- --------
Other deductions (income):
Interest expense.............................. 6,674 6,889 7,018 5,867
Other (income), net........................... (3,006) (8,918)(1) (2,193) (3,774)
-------- ------- ------- --------
Total other deductions (income).......... 3,668 (2,029) 4,825 2,093
-------- ------- ------- --------
Income before income taxes....................... 19,373 14,309 10,339 23,360
Provision for income taxes....................... 7,631 5,582 4,118 9,132
-------- ------- ------- --------
Net income....................................... $ 11,742 $ 8,727 $ 6,221 $ 14,228
-------- ------- ------- --------
-------- ------- ------- --------
</TABLE>

- ---------------

(1) Includes $6,948 gain on sale of subsidiary.

39
<PAGE> 40

ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

Not Applicable.

40
<PAGE> 41

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

(a) 1.* Financial Statements

Included in Item 8, Part II of this Report

Report of Independent Public Accountants on Financial Statements and
Schedules

Report of Management Responsibility for Financial Statements

Balance Sheets at December 31, 1993 and December 31, 1992

Statements of Income for the years ended December 31, 1993, December 31,
1992 and December 31, 1991.

Statements of Retained Earnings and Paid-In Capital for the years ended
December 31, 1993, December 31, 1992 and December 31, 1991.

Statements of Cash Flows for the years ended December 31, 1993, December
31, 1992 and December 31, 1991.

Notes to Financial Statements

(a) 2.* Financial Statement Schedules

Included in Item 14, Part IV of this Report

Financial Statement Schedules for the years ended December 31, 1993,
December 31, 1992 and December 31, 1991.

<TABLE>
<S> <C>
Schedule V -- Property, Plant and Equipment
Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and
Equipment
</TABLE>

Other schedules are omitted because of the absence of conditions under
which they are required or because the required information is given in the
financial statements or notes thereto.

(a) 3. Exhibits

<TABLE>
<S> <C>
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 November 1, 1987, securing 10% Debentures due
November 1, 1994. (incorporated by reference to Exhibit 4.1 of the
1987 Form 10-K -- File No. 1-4169).
4.2 -- 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).
</TABLE>

(b) Reports on Form 8-K

None.
- ---------------

* Filed herewith

41
<PAGE> 42

TEXAS GAS TRANSMISSION CORPORATION

SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
(THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
TRANSFERS BALANCE,
BEGINNING ADDITIONS RETIREMENTS AND OTHER END OF
DESCRIPTION BALANCE AT COST OR SALES CHANGES PERIOD
- --------------------------------------- --------- --------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
For the Year Ended December 31, 1993:
Natural Gas Transmission
Facilities........................ $ 679,802 $33,014 $(3,185) $(2,963) $706,668
Other Natural Gas Plant.............. 126,221 -- (1,284) 3,439 128,376
--------- --------- ----------- --------- --------
$ 806,023 $33,014 $(4,469) $ 476 $835,044
--------- --------- ----------- --------- --------
--------- --------- ----------- --------- --------
For the Year Ended December 31, 1992:
Natural Gas Transmission
Facilities........................ $ 647,729 $38,236 $(3,638) $(2,525) $679,802
Other Natural Gas Plant.............. 123,563 -- (1,342) 4,000 126,221
--------- --------- ----------- --------- --------
$ 771,292 $38,236 $(4,980) $ 1,475 $806,023
--------- --------- ----------- --------- --------
--------- --------- ----------- --------- --------
For the Year Ended December 31, 1991:
Natural Gas Transmission
Facilities........................ $ 598,306 $57,238 $(2,352) $(5,463) $647,729
Other Natural Gas Plant.............. 83,803 -- (1,458) 41,218(1) 123,563
--------- --------- ----------- --------- --------
$ 682,109 $57,238 $(3,810) $35,755 $771,292
--------- --------- ----------- --------- --------
--------- --------- ----------- --------- --------
</TABLE>

- ---------------

(1) Included in Transfers and Other Changes for Other Natural Gas Plant, for the
year ended December 31, 1991, is $33.8 million related to transfers of gas
stored underground-noncurrent.

42
<PAGE> 43

TEXAS GAS TRANSMISSION CORPORATION

SCHEDULE VI -- ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
(THOUSANDS OF DOLLARS)

<TABLE>
<CAPTION>
CLEARING SALVAGE
ACCOUNTS LESS TRANSFERS BALANCE,
BEGINNING DEPRECIATION AND REMOVAL RETIREMENTS AND OTHER END OF
DESCRIPTION BALANCE EXPENSE OTHERS COSTS OF SALES CHANGES PERIOD
- -------------------------- --------- ------------ -------- ------- ----------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
For the Year Ended
December 31, 1993:
Natural Gas Transmission
Facilities........... $ 118,892 $ 35,021 $ -- $3,834 $(3,185) $ 1,935 $156,497
Other Natural Gas
Plant................ 12,750 2,709 1,453 385 (1,284) 691 16,704
--------- ------------ -------- ------- ----------- --------- --------
$ 131,642 $ 37,730(1) $1,453 $4,219 $(4,469) $ 2,626 $173,201
--------- ------------ -------- ------- ----------- --------- --------
--------- ------------ -------- ------- ----------- --------- --------
For the Year Ended
December 31, 1992:
Natural Gas Transmission
Facilities........... $ 86,328 $ 34,248 $ -- $ (496 ) $(3,630) $ 2,442 $118,892
Other Natural Gas
Plant................ 8,979 2,789 1,514 401 (1,316) 383 12,750
--------- ------------ -------- ------- ----------- --------- --------
$ 95,307 $ 37,037(1) $1,514 $ (95 ) $(4,946) $ 2,825 $131,642
--------- ------------ -------- ------- ----------- --------- --------
--------- ------------ -------- ------- ----------- --------- --------
For the Year Ended
December 31, 1991:
Natural Gas Transmission
Facilities........... $ 54,870 $ 33,219 $ -- $ 128 $(2,352) $ 463 $ 86,328
Other Natural Gas
Plant................ 5,000 3,140 1,583 668 (1,458) 46 8,979
--------- ------------ -------- ------- ----------- --------- --------
$ 59,870 $ 36,359(1) $1,583 $ 796 $(3,810) $ 509 $ 95,307
--------- ------------ -------- ------- ----------- --------- --------
--------- ------------ -------- ------- ----------- --------- --------
</TABLE>

- ---------------

(1) Does not include amortization of intangible assets which are not classified
as property, plant and equipment.

43
<PAGE> 44

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

TEXAS GAS TRANSMISSION CORPORATION

BY /s/ E. J. RALPH
E. J. Ralph,
Vice President and Controller

DATE March 16, 1994

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.

<TABLE>
<S> <C>
/s/ JOHN P. DESBARRES Chairman of the Board and Chief Executive
John P. DesBarres Officer (Principal Executive Officer)

/s/ ROBERT W. BEST Director, President and Chief Operating
Robert W. Best Officer

/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 16, 1994
Date of all Signatures
</TABLE>