UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission file number 1-4169
TEXAS GAS TRANSMISSION CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 61-0405152
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3800 Frederica Street, Owensboro, Kentucky 42301
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (502) 926-8686
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_
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
1,000 shares as of November 10, 1998
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS
H(1)(a) and (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM
WITH THE REDUCED DISCLOSURE FORMAT.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
TABLE OF CONTENTS
Page
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets - Assets.......................... 3
Consolidated Balance Sheets - Liabilities and Stockholder's
Equity...................................................... 4
Consolidated Statements of Income............................. 5 - 6
Consolidated Statements of Cash Flows......................... 7
Condensed Notes to Consolidated Financial Statements.......... 8
Item 2. Management's Narrative Analysis of the Results of Operations.. 12
Part II. Other Information
Item 6. Exhibits and Reports on Form 8-K.............................. 15
Signature.............................................................. 16
Certain matters discussed in this report, excluding historical
information, include forward-looking statements. Although Texas
Gas Transmission Corporation believes such forward-looking
statements are based on reasonable assumptions, no assurance can
be given that every objective will be achieved. Such statements
are made in reliance on the "safe harbor" protections provided
under the Private Securities Reform Act of 1995. Additional
information about issues that could lead to material changes in
performance is contained in Texas Gas Transmission Corporation's
1997 Annual Report on Form 10-K and 1998 First and Second Quarter
Reports on Form 10-Q and the year 2000 disclosures contained in
this document.
<PAGE>
Item 1. Financial Statements
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
ASSETS 1998 1997
<S> <C> <C>
Current Assets:
Cash and temporary cash investments $ 119 $ 235
Receivables:
Trade 2,718 2,937
Affiliates 273 284
Other 795 1,945
Transportation and exchange receivable 2,056 1,890
Advances to affiliates 58,466 93,500
Inventories 15,833 15,386
Deferred income taxes 20,352 18,179
Costs recoverable from customers 11,924 16,311
Gas stored underground 10,409 11,115
Other 2,288 1,690
Total current assets 125,233 163,472
Investments, at cost 626 1,224
Property, Plant and Equipment, at cost:
Natural gas transmission plant 1,054,491 1,022,654
Less -- Accumulated depreciation and
amortization 119,298 98,649
Property, plant and equipment, net 935,193 924,005
Other Assets:
Gas stored underground 113,152 97,984
Costs recoverable from customers 51,952 45,504
Other 35,235 24,954
Total other assets 200,339 168,442
Total Assets $1,261,391 $1,257,143
</TABLE>
The accompanying condensed notes are an integral part of these
consolidated financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
LIABILITIES AND STOCKHOLDER'S EQUITY 1998 1997
<S> <C> <C>
Current Liabilities:
Payables:
Trade $ 4,538 $ 3,007
Affiliates 4,075 11,939
Other 3,868 7,853
Gas Payables:
Transportation and exchange 13,466 1,173
Storage 11,271 13,343
Accrued taxes 22,801 21,776
Accrued interest 1,511 6,557
Other accrued liabilities 43,296 51,517
Reserve for regulatory and rate matters 19,749 11,319
Total current liabilities 124,575 128,484
Long-Term Debt 251,230 251,433
Other Liabilities and Deferred Credits:
Deferred income taxes 153,301 150,113
Postretirement benefits other than pensions 41,616 35,683
Other 58,926 49,040
Total other liabilities and
deferred credits 253,843 234,836
Contingent Liabilities and Commitments - -
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 631,046 636,046
Retained earnings 696 6,343
Total stockholder's equity 631,743 642,390
Total Liabilities and
Stockholder's Equity $1,261,391 $1,257,143
</TABLE>
The accompanying condensed notes are an integral part of these
consolidated financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended September 30,
1998 1997
<S> <C> <C>
Operating Revenues:
Gas transportation $ 49,065 $ 52,993
Gas sales 3,362 4,049
Other 872 116
Total operating revenues 53,299 57,158
Operating Costs and Expenses:
Cost of gas transportation 1,402 5,693
Cost of gas sold 3,321 3,949
Operation and maintenance 14,599 15,918
Administrative and general 12,822 14,509
Depreciation and amortization 10,581 10,696
Taxes other than income taxes 3,483 3,587
Total operating costs and expenses 46,208 54,352
Operating Income 7,091 2,806
Other Deductions (Income):
Interest expense 5,238 4,880
Interest income (1,159) (1,537)
Miscellaneous other income (397) (258)
Total other deductions 3,682 3,085
Income (Loss) Before Income Taxes 3,409 (279)
Provision for (Benefit from) Income Taxes 1,368 (233)
Net Income (Loss) $ 2,041 $ (46)
</TABLE>
The accompanying condensed notes are an integral part of these
consolidated financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
1998 1997
<S> <C> <C>
Operating Revenues:
Gas transportation $191,473 $209,256
Gas sales 11,750 18,412
Other 2,236 1,044
Total operating revenues 205,459 228,712
Operating Costs and Expenses:
Cost of gas transportation 11,843 25,449
Cost of gas sold 11,598 18,471
Operation and maintenance 42,876 45,613
Administrative and general 37,453 42,875
Depreciation and amortization 31,865 31,883
Taxes other than income taxes 11,148 11,408
Total operating costs and expenses 146,783 175,699
Operating Income 58,676 53,013
Other Deductions (Income):
Interest expense 15,817 14,904
Interest income (4,019) (6,164)
Miscellaneous other income (213) (426)
Total other deductions 11,585 8,314
Income Before Income Taxes 47,091 44,699
Provision for Income Taxes 18,738 17,665
Net Income $ 28,353 $ 27,034
</TABLE>
The accompanying condensed notes are an integral part of these
consolidated financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended September 30,
1998 1997
<S> <C> <C>
OPERATING ACTIVITIES:
Net income $ 28,353 $ 27,034
Adjustments to reconcile to cash provided
from operations:
Depreciation and amortization 31,865 31,883
Provision for deferred income taxes 1,015 (5,037)
Changes in receivables sold (16,400) (9,200)
Changes in receivables 17,602 14,456
Changes in inventories (447) (234)
Changes in other current assets (1,837) 12,303
Changes in accounts payable (6,217) (4,498)
Changes in accrued liabilities 14,314 (56)
Other, including changes in noncurrent
assets and liabilities (22,581) (19,300)
Net cash provided by operating
activities 45,667 47,351
FINANCING ACTIVITIES:
Proceeds from long-term debt - 99,031
Payment of long-term debt - (100,000)
Dividends and returns of capital (39,000) (76,036)
Other - (8,163)
Net cash (used in) financing activities (39,000) (85,168)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of AFUDC (43,254) (59,601)
Proceeds from sales and salvage values,
net of costs of removal 817 1,288
Advances to affiliates, net 35,034 96,295
Proceeds from sale of long-term investments 620 146
Net cash (used in) provided by investing
activities (6,783) 38,128
(Decrease) increase in cash and cash equivalents (116) 311
Cash and cash equivalents at beginning of period 235 115
Cash and cash equivalents at end of period $ 119 $ 426
</TABLE>
The accompanying condensed notes are an integral part of these
consolidated financial statements.
<PAGE>
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
A. Corporate Structure and Control, Nature of Operations and
Basis of Presentation
Corporate Structure and Control
Texas Gas Transmission Corporation and its wholly owned
subsidiary, TGT Enterprises, Inc., (collectively, the Company) is
wholly owned by Williams Gas Pipeline Company, formerly Williams
Interstate Natural Gas Systems, Inc., which is a wholly owned
subsidiary of The Williams Companies, Inc. (Williams). Prior to
May 1, 1997, the Company was a wholly owned subsidiary of
Williams.
Seasonal Variation
Operating income may vary by quarter. Based on its current
rate structure, the Company experiences higher operating income
in the first and fourth quarters as compared to the second and
third quarters.
Basis of Presentation
The consolidated financial statements have been prepared from
the books and records of the Company without audit, pursuant to
the rules and regulations of the Securities and Exchange
Commission. Certain information and footnote disclosures
normally included in consolidated financial statements prepared
in accordance with generally accepted accounting principles have
been condensed or omitted. The accompanying unaudited
consolidated financial statements include all adjustments, both
normal recurring and others, which, in the opinion of the
Company's management, are necessary to present fairly its
financial position at September 30, 1998 and December 31, 1997;
results of operations and cash flows for the nine months ended
September 30, 1998 and 1997; and results of operations for the
three months ended September 30, 1998 and 1997. These
consolidated financial statements should be read in conjunction
with the financial statements, notes thereto and management's
narrative analysis contained in the Company's 1997 Annual Report
on Form 10-K and the Company's 1998 First and Second Quarter
Reports on 10-Q.
Certain reclassifications have been made in the 1997 financial
statements to conform to the 1998 presentation.
<PAGE>
B. Contingent Liabilities and Commitments
Regulatory and Rate Matters and Related Litigation
FERC Order 636
Effective November 1, 1993, the Company restructured its
business to implement the provisions of Federal Energy Regulatory
Commission (FERC) Order 636, which, among other things, required
pipelines to unbundle their merchant roles from their
transportation services. FERC Order 636 also provides that
pipelines should be allowed the opportunity to recover all
prudently incurred transition costs which, for the Company, are
primarily related to gas supply realignment (GSR) costs and
unrecovered purchased gas costs. Certain aspects of the Company's
FERC Order 636 restructuring are under appeal.
In July 1996, the United States Court of Appeals for the
District of Columbia issued an order which in part affirmed and
in part remanded FERC Order 636. On February 27, 1997, FERC
issued Order 636-C in response to the court's remand affirming
that pipelines may recover all of their GSR costs, but requiring
pipelines to individually propose the percentage of such costs to
be allocated to interruptible transportation services, instead of
a uniform 10 percent allocation. The Company's GSR settlement,
discussed below, is not subject to appeal and should be
unaffected by this Order. The Order also prospectively relaxed
the eligibility requirements for receiving no-notice service and
reduced the right of first refusal matching period from 20 years
to five years. Certain aspects of FERC Order 636-C are subject
to appeal.
In September 1995, the Company received FERC approval of a
settlement agreement which resolves all issues regarding the
Company's recovery of GSR costs. The settlement provides that
the Company will recover 100 percent of its GSR costs up to $50
million, will share in costs incurred between $50 million and $80
million and will absorb any GSR costs above $80 million. Under
the settlement, all challenges to these costs, on the grounds of
imprudence or otherwise, will be withdrawn and no future
challenges will be filed. Ninety percent of the cost recovery is
collected through demand surcharges on the Company's firm
transportation rates; the remaining 10 percent should be
recovered from its interruptible transportation service.
Effective July 1, 1997, the FERC allowed the Company to suspend
its GSR surcharge applicable to firm transportation (FT) services
due to the full recovery of incurred GSR costs allocated to firm
services. The GSR cost increment included in the interruptible
transportation rates, as well as no-notice and FT overrun rates,
remains in effect. To date, the Company has paid $76.2 million
and collected $66.1 million, plus interest, related to GSR. The
Company expects to pay less than $80 million for its total GSR
costs, primarily as a result of contract terminations, and has
provided reserves for the remaining GSR costs it may be required
to pay, as well as a regulatory asset for the estimated future
amounts recoverable.
General Rate Issues
On April 30, 1997, the Company filed a general rate case
(Docket No. RP97-344) effective November 1, 1997, subject to
refund. This rate case reflects a requested annual revenue
increase of approximately $70.9 million, based on filed rates,
primarily attributable to increases in the utility rate base,
<PAGE>
operating expenses and rate of return and related taxes. The
Company, FERC staff, and all intervenors but one have reached a
proposed settlement which was filed with the FERC on March 20,
1998. On April 28, 1998, the Presiding Administrative Law Judge
issued an order certifying the settlement to the FERC. On July
15, 1998, the Commission issued an "Order Approving Offer of
Settlement and Remanding Case for Hearing." Applications for
rehearing of this order were filed, and an "Order Denying
Rehearing and Providing Guidance on Hearing Issues" was issued
October 14, 1998. The Company believes it has provided an
adequate reserve for amounts, including interest, which may be
refunded to customers.
Royalty Claims and Producer Litigation
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. 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 provision 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. Pursuant to such an indemnity, in January 1998, the
Company reimbursed a producer for approximately $1.7 million in
costs paid to settle a take-or-pay royalty claim. The Company
may file to recover 75 percent of any such amounts it may be
required to pay pursuant to indemnifications for royalties under
the provisions of FERC Order 528. The Company has provided
reserves for the estimated settlement costs of its royalty claims
and litigation.
Environmental Matters
As of September 30, 1998, the Company had a reserve of
approximately $1.8 million for estimated costs associated with
environmental assessment and remediation, including remediation
associated with the historical use of polychlorinated biphenyls
and hydrocarbons. 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 currently is either named as a potentially
responsible party or has received an information request
regarding its potential involvement at certain Superfund and
state waste disposal sites. The anticipated remediation costs,
if any, associated with these sites have been included in the
reserve discussed above.
The Company considers environmental assessment and remediation
costs and costs associated with compliance with environmental
standards to be recoverable through rates, as they are prudent
costs incurred in the ordinary course of business. The actual
costs incurred will depend on the actual amount and extent of
contamination discovered, the final cleanup standards mandated by
the U.S. Environmental Protection Agency or other governmental
authorities, and other factors.
<PAGE>
Summary of Contingent Liabilities and Commitments
While no assurances may be given, the Company does not believe
that the ultimate resolution of the foregoing matters, taken as a
whole and after consideration of amounts accrued, insurance
coverage, potential recovery from customers or other
indemnification arrangements, will have a materially adverse
effect on the Company's future financial position, results of
operations or cash flow requirements.
C. Adoption of Accounting Standards
The Financial Accounting Standards Board has issued Statement
of Financial Accounting Standards (SFAS) No. 131, "Disclosures
about Segments of an Enterprise and Related Information" and SFAS
No. 132, "Employer's Disclosures About Pension and Other Post
Retirement Benefits," both effective for fiscal years beginning
after December 15, 1997. SFAS Nos. 131 and 132 are disclosure
oriented; therefore, these pronouncements are not expected to
have an effect on the Company's financial position, results of
operations or cash flow requirements.
<PAGE>
Item 2. Management's Narrative Analysis of the Results of
Operations
(Filed Pursuant to General Instruction H)
Financial Analysis of Operations
Nine Months Ended September 30, 1998 Compared to
Nine Months Ended September 30, 1997
The Company's gas sales result from requirements to meet its
pre-Order 636 gas purchase commitments, substantially all of
which are managed by the Company's gas marketing affiliate,
Williams Energy Services Company, as exclusive agent for the
Company. Although the sales and purchase commitments remain in
the Company's name, their management and any associated profit or
loss is solely the responsibility of the agent. Therefore, the
resulting sales and purchases have no impact on the Company's
results of operations.
Operating income was $5.7 million higher for the nine months
ended September 30, 1998, than for the nine months ended
September 30, 1997. The increase in operating income was due
primarily to lower operation, maintenance, general and
administrative expenses, and higher revenues related to new
services and higher cost recovery due to the current rate case,
partially offset by the effect of favorable resolutions in 1997
of certain contractual issues. Compared to 1997, net income was
$1.3 million higher due to the reasons discussed above, offset by
higher interest expense due to pending refunds to customers and
lower interest income as a result of lower interest rates and
advances to Williams.
Operating revenues decreased $23.3 million primarily
attributable to lower gas sales, lower transportation costs
charged to the Company by others and passed through to customers
as provided in the Company's rates, and the effect of favorable
resolutions in 1997 of certain contractual issues, partially
offset by higher revenues related to new services and higher cost
recovery due to the current rate case. Total deliveries were
550.1 TBtu and 562.8 TBtu for the first nine months of 1998 and
1997, respectively.
Operating costs and expenses decreased $28.9 million
primarily attributable to lower cost of gas sold and lower cost
of gas transportation, both of which are passed through to
customers, as well as lower operation, maintenance, general and
administrative expenses.
Financial Condition and Liquidity
Through the years, the Company has consistently maintained its
financial strength and experienced strong operational results.
Williams' ownership of the Company further enhances its financial
and operational strength, as well as allows the Company to take
advantage of new opportunities for growth. The Company expects
to access public and private capital markets, as needed, to
finance its own capital requirements.
The Company is a participant with other Williams subsidiaries
in a $1 billion credit agreement under which the Company may
<PAGE>
borrow up to $200 million, subject to borrowings by other
affiliated companies. Interest rates vary with current market
conditions. To date, the Company has no amounts outstanding
under this facility.
The Company is a participant in Williams' cash management
program. The advances due the Company by Williams are
represented by demand notes payable. Those amounts that the
Company anticipates Williams will repay in the next twelve months
are classified as current assets; any remainder is classified as
noncurrent. The interest rate on intercompany demand notes is
the London Interbank Offered Rate on the first day of the month
plus an applicable margin based on the current Standard and
Poor's Rating of the Borrower.
The Company's capital expenditures for the first nine months
of 1998 and 1997 were $43.3 million and $59.6 million,
respectively. Capital expenditures for 1998 are expected to
approximate $59.2 million. The Company's debt as a percentage of
total capitalization at September 30, 1998 and December 31, 1997
was 28.5% and 28.1%, respectively.
On July 21, 1997, the Company filed an application with the
FERC to authorize construction, installation and operation of a
4,600 horsepower compressor engine and associated facilities at
its Haughton Compressor Station in Louisiana. The Company
received an order on March 17, 1998, issuing a certificate
authorizing the construction and operation of facilities. The
project is expected to cost approximately $6 million, which is
included in the 1998 capital expenditure estimate above. The
facilities were tested and placed in service on November 1, 1998.
On April 30, 1997, the Company filed a general rate case
(Docket No. RP97-344) effective November 1, 1997, subject to
refund. This rate case reflects a requested annual revenue
increase of approximately $70.9 million, based on filed rates,
primarily attributable to increases in the utility rate base,
operating expenses and rate of return and related taxes. The
Company, FERC staff, and all intervenors but one have reached a
proposed settlement, which was filed with the FERC on March 20,
1998. On April 28, 1998, the Presiding Administrative Law Judge
issued an order certifying the settlement to the FERC. On July
15, 1998, the Commission issued an "Order Approving Offer of
Settlement and Remanding Case for Hearing." Applications for
rehearing of this order were filed, and an "Order Denying
Rehearing and Providing Guidance on Hearing Issues" was issued
October 14, 1998. The Company believes it has provided an
adequate reserve for amounts, including interest, which may be
refunded to customers.
Williams, including the Company, initiated an enterprise-wide
project in 1997 to address the year 2000 (Y2K) compliance issue
for both traditional information technology areas and non-
traditional areas, including embedded technology, which is
prevalent throughout the organization. This project focuses on
all technology hardware and software, external interfaces with
customers and suppliers, operations process control, automation
and instrumentation systems, and facility items. The assessment
phase of this project as it relates to both traditional and non-
traditional information technology areas has been substantially
completed. Necessary conversion and replacement activities have
begun and are targeted for completion by December 31, 1998, with
some exceptions. These exceptions include system replacements
and items dependent on information from third parties.
<PAGE>
The Company has begun testing activities, which will continue
throughout the process with substantial completion expected by
June 30, 1999. Y2K test labs are in place and operational. The
percent of inventoried items confirmed to be compliant through
testing activities ranges from approximately 42 percent of
information technology (IT) to 56 percent non-IT. As was
expected, few problems have been detected during testing with
items believed to be compliant.
The Company has initiated a formal communications process with
other companies to determine the extent to which those companies
are addressing their Y2K compliance. In connection with this
process, the Company has sent over 1,000 letters and
questionnaires to third parties and is evaluating those responses
as they are received. Where necessary, the Company will be
working with those companies to mitigate any materially adverse
effect on the Company.
The Company expects to utilize both internal and external
resources to complete the Y2K project. Costs incurred for new
software and hardware purchases will be capitalized and other
costs will be expensed as incurred. While the total cost of the
Company's project is still being evaluated, the Company estimates
that future costs necessary to complete the project within the
schedule described will total less than $2 million. The Company
will update this estimate as additional information becomes
available. Less than $0.1 million of costs (including capital
expenditures) have been incurred to date.
The Company anticipates that all Y2K compliance required
replacements will be completed on a timely basis. Although all
critical systems over which the Company has control are planned
to be compliant and tested, one area of risk could involve
isolated system interruptions or shutdowns which might occur if
significant third parties, such as vendors and customers that can
influence the smooth flow of gas transportation, are not Y2K
ready. However, steps are being taken to attempt to verify that
such third parties will achieve Y2K compliance on a timely basis.
All areas of the Company are currently examining the requirements
for contingency plans that would avoid or minimize the effect of
such interruptions. It is anticipated that all contingency plans
will be completed by June 30, 1999.
The costs of the project and the completion dates are based on
management's best estimates, which were derived utilizing
numerous assumptions of future events including the continued
availability of certain resources, third party Y2K compliance
modification plans, and other factors. There can be no guarantee
that these estimates will be achieved and actual results could
differ materially from these estimates. Specific factors that
might cause differences between the estimates and actual results
include, but are not limited to, the availability and cost of
personnel trained in these areas, the ability to locate and
correct all relevant computer code, timely responses to and
corrections by third-parties and suppliers, the ability to
implement interfaces between the new systems and the systems not
being replaced, and similar uncertainties. Due to the general
uncertainty inherent in the Y2K problem, resulting in part from
the uncertainty of the Y2K readiness of third-parties, the
Company cannot ensure its ability to timely and cost-effectively
resolve problems associated with the Y2K issue that may affect
its operations and business, or expose it to third-party
liability.
<PAGE>
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
* 27.1 Financial Data Schedule for Texas Gas Transmission
Corporation for the nine months ending
September 30, 1998.
(b) Reports on Form 8-K
None
_____________________________
* Filed herewith
<PAGE>
S I G N A T U R E
Pursuant to the requirements 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
DATE: November 13, 1998 BY: /s/ S. W. Harris
S. W. Harris
Controller and Chief Accounting Officer
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000097452
<NAME> TEXAS GAS TRANSMISSION CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 119
<SECURITIES> 0
<RECEIVABLES> 2,718
<ALLOWANCES> 0
<INVENTORY> 15,833
<CURRENT-ASSETS> 125,233
<PP&E> 1,054,491
<DEPRECIATION> 119,298
<TOTAL-ASSETS> 1,261,391
<CURRENT-LIABILITIES> 124,575
<BONDS> 251,300
0
0
<COMMON> 1
<OTHER-SE> 631,743
<TOTAL-LIABILITY-AND-EQUITY> 1,261,391
<SALES> 11,750
<TOTAL-REVENUES> 205,459
<CGS> 11,598
<TOTAL-COSTS> 66,317
<OTHER-EXPENSES> 43,013
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 15,817
<INCOME-PRETAX> 47,091
<INCOME-TAX> 18,738
<INCOME-CONTINUING> 28,353
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 28,353
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
