Back to GetFilings.com
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
For the fiscal year ended December 31, 1998
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from ____________ to______________
Commission file number 1-4169
TEXAS GAS TRANSMISSION CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 61-0405152
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
3800 Frederica Street, Owensboro, Kentucky 42301
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (502) 926-8686
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ____
State the aggregate market value of the voting stock held
by nonaffiliates of the registrant. The aggregate market
value shall be computed by reference to the price at which
stock was sold, or the average bid and asked prices of such
stock, as of a specified date within 60 days prior to the date
of filing. None
Indicate the number of shares outstanding of each of the
registrant's classes of common stock, as of the latest
practicable date. 1,000 shares as of March 25, 1999
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE
FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT.
TABLE OF CONTENTS
1998 FORM 10-K
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
Page
Part I
Item 1. Business................................................... 3
Item 2. Properties................................................. 7
Item 3. Legal Proceedings.......................................... 7
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters....................................... 8
Item 7. Management's Narrative Analysis of the Results of
Operations................................................ 8
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................... 13
Item 8. Financial Statements and Supplementary Data................ 14
Item 9. Disagreements on Accounting and Financial
Disclosure................................................ 35
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K............................................... 35
PART I
Item 1. Business.
GENERAL
Effective May 1, 1997, Texas Gas Transmission Corporation
and its wholly owned subsidiary, TGT Enterprises, Inc.,
(collectively, the Company) became a wholly owned subsidiary
of 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.
The Company is an interstate natural gas transmission
company which owns and operates a natural gas pipeline system
originating 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 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 the Northeast through
interconnections with unaffiliated pipelines.
TRANSPORTATION AND SALES
At December 31, 1998, the Company's system, having a
mainline delivery capacity of approximately 2.8 billion cubic
feet (Bcf) of gas per day, was composed of approximately 6,000
miles of mainline and branch transmission pipelines and 32
compressor stations having a sea-level-rated capacity totaling
approximately 555,000 horsepower.
The Company owns and operates natural gas storage
reservoirs in 10 underground storage fields located on or near
its pipeline system and/or market areas. The storage capacity
of the Company's certificated storage fields is approximately
177 Bcf of gas. The Company owns a majority of its storage
gas which it uses, in part to meet operational balancing needs
on its system, in part to meet the requirements of the
Company's firm and interruptible storage customers, and in
part to meet the requirements of the Company's "no-notice"
transportation service, which allows the Company's customers
to temporarily draw from the Company's storage gas to be
repaid in-kind during the following summer season. 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.
In 1998, the Company transported gas to customers in
Louisiana, Arkansas, Mississippi, Tennessee, Kentucky,
Indiana, Illinois and Ohio and to Northeast customers served
indirectly by the Company. Gas was transported for 108
distribution companies and municipalities for resale to
residential, commercial and industrial users. Transportation
services were provided to approximately 21 industrial
customers located along the system. At December 31, 1998,
the Company had transportation contracts with approximately
595 shippers. Transportation shippers include distribution
companies, municipalities, intrastate pipelines, direct
industrial users, electrical generators, marketers and
producers. The largest customer of the Company in 1998,
ProLiance Energy, LLC, accounted for approximately 13.9
percent of total operating revenues. No other customers
accounted for more than 10 percent of total operating revenues
during 1998. The Company's firm transportation and storage
agreements are generally long-term agreements with various
expiration dates and account for the major portion of the
Company's business. Additionally, the Company offers
interruptible transportation and storage services under
agreements that are generally short-term.
OPERATING STATISTICS
The following table summarizes the Company's total system
transportation volumes for the periods shown (expressed in
trillion British thermal units [TBtu]):
For the Year Ended December 31,
1998 1997 1996
Transportation Volumes 752.4 773.6 794.5
Average Daily Transportation Volumes 2.1 2.1 2.2
Average Daily Firm Reserved Capacity 2.2 2.2 2.1
REGULATORY MATTERS
The Company is subject to regulation by the Federal Energy
Regulatory Commission (FERC) under the Natural Gas Act of 1938
(Natural Gas Act) and under the Natural Gas Policy Act of 1978
(NGPA), and as such, its rates and charges for transportation
of natural gas in interstate commerce, the extension,
enlargement or abandonment of facilities, and its accounting,
among other things, are subject to regulation. 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.
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
The Company's rates are established primarily through the
FERC ratemaking process. Key determinants in the ratemaking
process are (1) costs of providing service, including
depreciation rates, (2) allowed rate of return, including the
equity component of the Company's capital structure, and (3)
volume throughput assumptions. The allowed rate of return is
determined by the FERC in each rate case. Rate design and the
allocation of costs between the demand and commodity rates
also impact profitability.
On April 30, 1997, the Company filed a general rate case
(Docket No. RP97-344) effective November 1, 1997, subject to
refund. On March 20, 1998, the Company filed an offer of
settlement. On July 15, 1998, the FERC issued an "Order
Approving Offer of Settlement and Remanding Case for Hearing"
which approved the settlement without modification, but
remanded the proceeding back to an administrative law judge
for the sole purpose of conducting a hearing on an issue
related to production area rates raised by a single
intervenor. On October 14, 1998, the FERC issued an "Order
Denying Rehearing and Providing Guidance on Hearing Issues."
On November 9, 1998, that intervenor filed a notice of
withdrawal from the case and on November 10, 1998, the
presiding administrative law judge issued an order suspending
the procedural schedule on the remanded hearing. No parties
requested rehearing of the October 14, 1998, order and on
November 30, 1998, the Company filed tariff sheets to
implement the settlement. The Company had established an
adequate reserve for the difference between collected rates
and the settlement rates. Refunds, including interest, of
$17.2 million were distributed to customers on January 13,
1999.
For discussion of other regulatory matters affecting the
Company, see Note C of Notes to Consolidated 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. For a complete
discussion of this issue, see Note C of Notes to Consolidated
Financial Statements contained in Item 8 hereof.
COMPETITION
The FERC continues to regulate interstate natural gas
pipeline companies pursuant to the Natural Gas Act and the
NGPA. However, competition has led to a buyers' market in the
natural gas industry for both the commodity and pipeline
capacity. This market is characterized by a shifting customer
base from local distribution companies to marketers and
producers and an increased reliance by customers on capacity
obtained through the release market. Low growth in demand,
excess supply, and an over-abundance of annual pipeline
capacity have all contributed to the current situation. In
addition, future load growth is expected to occur primarily in
price-sensitive markets, which will limit gas price increases
to the price of competing fuels. This problem is compounded
by the fact that large volumes of natural gas reserves found
in western Canada, previously confined to low growth,
competitive areas of North America, appear now to be headed
for the Chicago, Illinois area and the Northeast portion of
the United States where there is already adequate pipeline
capacity and growing supply access due to increased drilling
activity in the Gulf of Mexico states.
When restructured tariffs became effective under FERC Order
636, all suppliers of natural gas were able to compete for any
gas markets capable of being served by the pipelines using
nondiscriminatory transportation services provided by the
pipelines. As the FERC Order 636 regulated environment has
matured, many pipelines have faced reduced levels of
subscribed capacity as contractual terms expire and customers
opt for alternative sources of transmission and related
services. This issue is known as "capacity turnback" in the
industry.
The Company is continuing to work diligently to replace any
and all markets made available by capacity turnback, as well
as to pursue new markets. During 1998, the Company remarketed
all capacity that was turned back without significant
discounting and has either renegotiated, extended, or renewed
contracts for over 80 percent of the capacity subject to
turnback in 1999. The Company anticipates that it will
continue to be able to remarket all future capacity subject to
turnback.
OWNERSHIP OF PROPERTY
The Company's pipeline system is owned in fee, with certain
portions, such as the offshore areas, being held jointly with
third parties. However, a substantial portion of the
Company's system is constructed and maintained pursuant to
rights-of-way, easements, permits, licenses or consents on and
across property owned by others. The majority of the
Company's compressor stations, with appurtenant facilities,
are located in whole or in part on lands owned in fee by the
Company, with a few sites held under long-term leases or
permits issued or approved by public authorities. Storage
facilities are either owned or contracted for under long-term
leases.
EMPLOYEE RELATIONS
The Company had 828 employees as of December 31, 1998.
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 Council of the United Food and
Commercial Workers Union Local 187 represents 149 of the
Company's 353 field operating employees. The current
collective bargaining agreement between the Company and Local
187 expires on April 30, 2001.
As discussed in Note F of Notes to Consolidated Financial
Statements contained in Item 8 hereof, approximately 9 percent
of the Company's employees elected to retire in 1998 under an
early retirement program offered by the Company.
The Company has a non-contributory, defined benefit 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.
FORWARD-LOOKING INFORMATION
Certain matters discussed in this report, excluding
historical information, include forward-looking statements.
Although the Company believes such forward-looking statements
are based on reasonable assumptions, no assurance can be given
that every objective will be reached. Such statements are
made in reliance on the safe harbor protections provided under
the Private Securities Litigation Reform Act of 1995.
As required by such Act, the Company hereby identifies
the following important factors that could cause actual
results to differ materially from any results projected,
forecasted, estimated or budgeted by the Company in forward-
looking statements: (i) risks and uncertainties related to
changes in general economic conditions in the United States,
availability and cost of capital, changes in laws and
regulations to which the Company is subject, including tax,
environmental and employment laws and regulations, the cost
and effects of legal and administrative claims and proceedings
against the Company or which may be brought against the
Company and the effect of changes in accounting policies; (ii)
risks and uncertainties related to the impact of future
federal and state regulation of business activities, including
allowed rates of return, the pace of deregulation in retail
natural gas markets, and the resolution of other regulatory
matters discussed herein; (iii) risks and uncertainties
related to the ability to develop expanded markets as well as
maintain existing markets; (iv) risks and uncertainties
related to year 2000 readiness of the Company, its customers,
and its vendors; and (v) risks and uncertainties related to
the Company's ability to control costs. In addition, future
utilization of pipeline capacity could depend on energy
prices, competition from other pipelines and alternate fuels,
the general level of natural gas demand, decisions by
customers not to renew expiring natural gas transportation
contracts, and weather conditions, among other things.
Further, gas prices which indirectly impact transportation and
operating profits may fluctuate in unpredictable ways.
Item 2. Properties.
See "Item 1. Business."
Item 3. Legal Proceedings.
For a discussion of the Company's current legal
proceedings, see Note C of Notes to Consolidated 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, 1998, all of the outstanding
shares of the Company's common stock are owned by Williams Gas
Pipeline Company, formerly Williams Interstate Natural Gas
Systems, Inc., a wholly owned subsidiary of Williams. The
Company's common stock is not publicly traded and there exists
no market for such common stock.
Item 7. Management's Narrative Analysis of the Results of
Operations.
Introduction
Property, plant and equipment at December 31, 1998,
includes an aggregate of approximately $430 million related to
amounts in excess of the original cost of regulated
facilities, as a result of the Williams' 1995 and prior
acquisitions. This amount is being amortized over 40 years,
the estimated remaining useful lives of the assets at the date
of acquisition, at approximately $11 million per year.
Current FERC policy does not permit the Company to recover
through its rates amounts in excess of original cost.
Effect of Inflation
The Company generally has experienced increased costs in
recent years due to the effect of inflation on the cost of
labor, materials and supplies, and property, plant and
equipment. A portion of the increased labor and materials and
supplies costs can directly affect income through increased
maintenance and operating costs. The cumulative impact of
inflation over a number of years has resulted in increased
costs for current replacement of productive facilities. The
majority of the Company's property, plant and equipment and
inventory is subject to ratemaking treatment, and under
current FERC practices, recovery is limited to historical
costs. While amounts in excess of historical cost are not
recoverable under current FERC practices, the Company believes
it will be allowed to recover and earn a return based on
increased actual cost incurred when existing facilities are
replaced. Cost based regulation along with competition and
other market factors limit the Company's ability to price
services or products based upon inflation's effect on costs.
Year 2000 Compliance
Williams, including the Company, initiated an enterprise-
wide project in 1997 to address the year 2000 compliance issue
for both traditional information technology areas and non-
traditional areas, including embedded technology that is
prevalent throughout the Company. 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 phases of
the project are awareness, inventory and assessment, renovation
and replacement, and testing and validation. The awareness and
inventory/assessment phases of this project as they relate to
both traditional and non-traditional information technology
areas have been substantially completed. During the inventory
and assessment phase, all systems with possible year 2000
implications were inventoried and classified into five
categories: 1) highest, business critical, 2) high,
compliance necessary within a short period of time following
January 1, 2000, 3) medium, compliance necessary within 30
days from January 1, 2000, 4) low, compliance desirable but
not required, and 5) unnecessary. Categories 1 through 3 were
designated as critical and are the major focus of this
project. Renovation/replacement and testing/validation of
critical systems is expected to be completed by June 30, 1999,
except for replacement of certain critical systems scheduled
for completion by September 1, 1999. Some non-critical
systems may not be compliant by January 1, 2000.
Testing and validation activities have begun and will
continue throughout the process. Year 2000 test labs are in
place and operational. As expected, few problems have been
detected during testing for items believed to be compliant.
The following table indicates the project status for
traditional information technology and non-traditional areas.
The tested category indicates the percentage that has been
fully tested or otherwise validated as compliant. The
untested category includes items that are believed to be
compliant but which have not yet been validated. The not
compliant category includes items which have been identified
as not year 2000 compliant.
Tested Untested Not Compliant
Traditional Information Technology: 78% 3% 19%
Non-Traditional Information Technology: 89 0 11
The Company initiated a formal communications process with
other companies in 1998 to determine the extent to which those
companies are addressing year 2000 compliance. In connection
with this process, the Company has sent approximately 1,200
letters and questionnaires to third parties including
customers, vendors and service providers. Additional
communications are being mailed during 1999. The Company is
evaluating responses as they are received or otherwise
investigating the status of these companies' year 2000
compliance efforts. As of December 31, 1998, the Company had
received responses to approximately 33 percent of its
inquiries and virtually all of these indicated that they are
already compliant or will be compliant on a timely basis.
Where necessary, the Company will be working with key business
partners to reduce the risk of a break in service or supply
and with non-compliant companies to mitigate any material
adverse effect on the Company.
Although all critical systems over which the Company has
control are planned to be compliant and tested before the year
2000, the Company has identified two areas that would equate
to a most reasonably likely worst case scenario. First is the
possibility of service interruptions due to non-compliance by
third parties. For example, power failures along the
communications network or transportation systems would cause
service interruptions. This risk should be minimized by
the enterprise-wide communications effort and evaluation of
third-party compliance plans. Another area of risk for non-
compliance is the delay of system replacements scheduled for
completion during 1999. The status of these systems is being
closely monitored to reduce the chance of delays in completion
dates. It is not possible to quantify the possible financial
impact if this most reasonably likely worst case scenario were
to come to fruition.
Initial contingency planning began during 1998; however,
significant focus on that phase of the project will not take
place until 1999. Guidelines for that process were issued in
January 1999 in the form of a formal business continuity plan.
Contingency plans are being developed for critical business
processes, critical business partners, suppliers and system
replacements that experience significant delays. These plans
are expected to be defined by August 31, 1999 and implemented
where appropriate.
The Company expects to utilize internal resources to
complete the year 2000 compliance project. The Company has a
core group of 20 people involved in this project. This
includes 4 individuals responsible for coordinating,
organizing, managing, communicating, and monitoring the
project and another 16 staff members responsible for
completing the project. Depending on which phase the project
is in and what area is being focused on at any given point in
time, there can be up to an additional 160 employees who are
also contributing a portion of their time to the completion of
this project. Costs incurred for new software and hardware
purchases are being capitalized and other costs are being
expensed as incurred. The Company currently estimates the
total cost of the project, including any accelerated system
replacements, will total less than $2 million. The Company
will update this estimate as additional information becomes
available. Less than $0.2 million of costs (including capital
expenditures) have been incurred through December 31, 1998.
The preceding discussion contains forward-looking
statements including, without limitation, statements relating
to the Company's plans, strategies, objectives, expectations,
intentions, and adequate resources, that are made pursuant to
the "safe harbor" provisions of the Private Securities
Litigation Reform Act of 1995. Readers are cautioned that
such forward-looking statements contained in the year 2000
update are based on certain assumptions which may vary from
actual results. Specifically, the dates on which the company
believes the year 2000 project will be completed and computer
systems will be implemented 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 modification plans and other
factors. However, there can be no guarantee that these
estimates will be achieved, or that there will not be a delay
in, or increased costs associated with, the implementation of
the year 2000 project. Other 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 year 2000 problem,
resulting in large part from the uncertainty of the year 2000
readiness of third parties, the Company cannot ensure its
ability to timely and cost effectively resolve problems
associated with the year 2000 issue that may affect its
operations and business, or expose it to third-party
liability.
Financial Analysis of Operations
The Company's gas sales result from requirements to meet
its pre-Order 636 gas purchase commitments, 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.
1998 Compared to 1997
Operating income was $6.3 million higher for the year ended
December 31, 1998, than for 1997. The increase in operating
income was primarily attributable to lower operation,
maintenance and administrative and general 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 $1.7 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 $31.6 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 752.4 trillion British thermal
units (TBtu) and 773.6 TBtu for the year ended December 31,
1998 and 1997, respectively, which also contributed to lower
revenues.
Operating costs and expenses decreased $37.9 million
primarily attributable to lower costs of gas sold and lower
costs of gas transportation, both of which are passed through
to customers, as well as lower operation, maintenance,
administrative and general expenses.
1997 Compared to 1996
Operating income was $2.9 million higher for the year ended
December 31, 1997, than for 1996. The increase in operating
income was primarily attributable to favorable resolutions in
1997 of certain contractual and regulatory issues and
efficiency gains, substantially offset by favorable 1996
adjustments to rate refund accruals and lower revenue from gas
processing. Compared to 1996, net income was $3.0 million
lower, due primarily to lower interest on advances to Williams
and higher effective income tax rates, partially offset by the
changes to operating income discussed above.
Operating revenues decreased $41.4 million primarily
attributable to lower gas sales, lower other revenues and
lower transportation revenues attributable to lower costs
passed through to customers as provided in the Company's
rates. System deliveries were 773.6 TBtu and 794.5 TBtu for
the years ended December 31, 1997 and 1996, respectively,
which also contributed to lower revenues.
Operating costs and expenses decreased $44.3 million
primarily attributable to lower costs of gas sold, lower costs
of gas transportation and efficiency gains. Costs of gas
transportation are passed through to customers and decreased
partially due to the suspension of the surcharge for the
collection of gas supply realignment costs applicable to firm
transportation, as discussed in Note C of Notes to
Consolidated Financial Statements contained in Item 8 hereof.
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 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 filed a Form S-3 Registration Statement with
the SEC on May 16, 1997, to register debt securities of $200
million to be offered for sale on a delayed or continuous
basis. On July 15, 1997, the Company sold $100 million of 7
1/4% Debentures due July 15, 2027. The Debentures have no
sinking funds and may be called at any time, at the Company's
option, in whole or in part, at a specified redemption price,
plus accrued and unpaid interest to the date of redemption.
Proceeds from the sale of the Debentures were used to retire
the Company's 9 5/8% Notes, which matured on July 15, 1997.
The Company is a participant in Williams' cash management
program. The advances due the Company by Williams are
represented by demand notes payable. The interest rate on
intercompany demand notes is the London Interbank Offered Rate
on the first day of the month plus 0.325%.
In May 1995, the Company entered into a program with a bank
to sell up to $35 million of trade receivables with limited
recourse. As of December 31, 1998 and 1997, $19.6 million and
$29.6 million, respectively, of such receivables were sold.
The Company's capital expenditures for the years ended
December 31, 1998 and 1997, were $60.8 million and $74.5
million, respectively. The Company's budgeted capital
expenditures for 1999 are $78.5 million.
The Company's debt as a percentage of total capitalization
at December 31, 1998 and 1997, was 28.4% and 28.1%,
respectively.
On April 30, 1997, the Company filed a general rate case
(Docket No. RP97-344) effective November 1, 1997, subject to
refund. On March 20, 1998, the Company filed an offer of
settlement. On July 15, 1998, the FERC issued an "Order
Approving Offer of Settlement and Remanding Case for Hearing"
which approved the settlement without modification, but
remanded the proceeding back to an administrative law judge
for the sole purpose of conducting a hearing on an issue
related to production area rates raised by a single
intervenor. On October 14, 1998, the FERC issued an "Order
Denying Rehearing and Providing Guidance on Hearing Issues."
On November 9, 1998, that intervenor filed a notice of
withdrawal from the case and on November 10, 1998, the
presiding administrative law judge issued an order suspending
the procedural schedule on the remanded hearing. No parties
requested rehearing of the October 14, 1998, order and on
November 30, 1998, the Company filed tariff sheets to
implement the settlement. The Company had established an
adequate reserve for the difference between collected rates
and the settlement rates. Refunds, including interest, of
$17.2 million were distributed to customers on January 13,
1999.
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk.
The Company's market risk is limited to its long-term debt.
All interest on long-term debt is fixed in nature. Total long-
term debt at December 31, 1998, had a carrying value of $251
million and a fair value of $271 million. The weighted-
average interest rate of the Company's long-term debt is
8.08%. All of the Company's long-term debt matures after
2003.
Item 8. Financial Statements and Supplementary Data
REPORT OF INDEPENDENT AUDITORS
Board of Directors
Texas Gas Transmission Corporation
We have audited the accompanying consolidated balance
sheets of Texas Gas Transmission Corporation and subsidiary as
of December 31, 1998 and 1997, and the related consolidated
statements of income, retained earnings and paid-in capital
and cash flows for each of the three years in the period ended
December 31, 1998. These consolidated financial statements
are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements
referred to above present fairly, in all material respects,
the consolidated financial position of Texas Gas Transmission
Corporation and subsidiary at December 31, 1998 and 1997, and
the consolidated results of its operations and its cash flows
for each of the three years in the period ended December 31,
1998, in conformity with generally accepted accounting
principles.
/s/ Ernst & Young LLP
ERNST & YOUNG LLP
Tulsa, Oklahoma
February 26, 1999
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, December 31,
ASSETS 1998 1997
Current Assets:
Cash and temporary cash investments $ 201 $ 235
Receivables:
Trade 8,493 2,937
Affiliates 1,049 284
Other 702 1,945
Transportation and exchange receivable 2,807 1,890
Advances to affiliates 82,755 93,500
Inventories 15,341 15,386
Deferred income taxes 14,496 18,179
Costs recoverable from customers 10,085 16,311
Gas stored underground 10,409 11,115
Other 1,676 1,690
Total current assets 148,014 163,472
Investments, at cost 340 1,224
Property, Plant and Equipment, at cost:
Natural gas transmission plant 918,747 885,763
Other natural gas plant 150,512 136,891
1,069,259 1,022,654
Less - Accumulated depreciation and
amortization 128,759 98,649
Property, plant and equipment, net 940,500 924,005
Other Assets:
Gas stored underground 113,468 97,984
Costs recoverable from customers 52,358 45,504
Other 38,991 24,954
Total other assets 204,817 168,442
Total Assets $1,293,671 $1,257,143
The accompanying notes are an integral part of these
consolidated financial statements.
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31, December 31,
1998 1997
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Payables:
Trade $ 3,016 $ 3,007
Affiliates 17,828 11,939
Other 7,026 7,853
Gas payables:
Transportation and exchange 12,764 1,173
Storage 13,010 13,343
Accrued taxes 22,752 21,776
Accrued interest 6,557 6,557
Other accrued liabilities 48,253 51,517
Reserve for regulatory and rate matters 20,150 11,319
Total current liabilities 151,356 128,484
Long-Term Debt 251,160 251,433
Other Liabilities and Deferred Credits:
Deferred income taxes 156,253 150,113
Postretirement benefits other than pensions 41,392 35,683
Other 60,213 49,040
Total other liabilities and deferred
credits 257,858 234,836
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 627,046 636,046
Retained earnings 6,250 6,343
Total stockholder's equity 633,297 642,390
Total Liabilities and Stockholder's
Equity $1,293,671 $1,257,143
The accompanying notes are an integral part of these
consolidated financial statements.
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
For the Year Ended December 31,
1998 1997 1996
Operating Revenues:
Gas transportation $269,457 $291,209 $300,792
Gas sales 13,537 25,413 56,700
Other 3,792 1,715 2,286
Total operating revenues 286,786 318,337 359,778
Operating Costs and Expenses:
Cost of gas transportation 14,321 31,314 39,289
Cost of gas sold 13,359 25,454 56,013
Operation and maintenance 59,943 62,340 65,014
Administrative and general 51,348 57,551 61,685
Depreciation and amortization 42,764 42,538 41,531
Taxes other than income taxes 14,626 15,019 15,015
Total operating costs and expenses 196,361 234,216 278,547
Operating Income 90,425 84,121 81,231
Other (Income) Deductions:
Interest expense 21,226 20,026 20,923
Interest income (4,956) (7,220) (12,450)
Miscellaneous other (income)
deductions, net (224) (274) 606
Total other deductions 16,046 12,532 9,079
Income Before Income Taxes 74,379 71,589 72,152
Provision for Income Taxes 29,472 28,370 25,972
Net Income $ 44,907 $ 43,219 $ 46,180
The accompanying notes are an integral part of these
consolidated financial statements.
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
AND PAID-IN CAPITAL
(Thousands of Dollars)
Retained Paid-in
Earnings Capital
Balance, December 31, 1995 $ 4,791 $740,446
Add (deduct):
Net income 46,180 -
Dividends on common stock
and returns of capital (44,238) (62,300)
Balance, December 31, 1996 6,733 678,146
Add (deduct):
Net income 43,219 -
Dividends on common stock
and returns of capital (43,609) (42,100)
Balance, December 31, 1997 $ 6,343 $636,046
Add (deduct):
Net income 44,907 -
Dividends on common stock
and returns of capital (45,000) (9,000)
Balance, December 31, 1998 $ 6,250 $627,046
The accompanying notes are an integral part of these
consolidated financial statements.
TEXAS GAS TRANSMISSION CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
For the Year Ended December 31,
1998 1997 1996
OPERATING ACTIVITIES:
Net income $ 44,907 $ 43,219 $ 46,180
Adjustments to reconcile to cash
provided from operations:
Depreciation and amortization 42,764 42,538 41,531
Provision (benefit) for deferred
income taxes 9,823 (6,408) 12,778
Changes in receivables sold (10,000) 5,400 (2,900)
Changes in receivables 4,769 (1,620) 2,775
Changes in inventories 45 (450) (374)
Changes in other current assets 614 10,959 13,265
Changes in accounts payable (4,581) (3,242) (13,483)
Changes in accrued liabilities 25,706 27,799 (48,656)
Other, including changes in non-
current assets and liabilities (11,727) (29,534) 33,713
Net cash provided by
operating activities 102,320 88,661 84,829
FINANCING ACTIVITIES:
Proceeds from long-term debt - 99,031 -
Payment of long-term debt - (100,000) -
Dividends and returns of capital (54,000) (85,709) (102,080)
Other, net (1) (8,173) -
Net cash (used in)
financing activities (54,001) (94,851) (102,080)
INVESTING ACTIVITIES:
Property, plant and equipment:
Capital expenditures, net of AFUDC (60,781) (74,549) (50,091)
Proceeds from sales and salvage values,
net of costs of removal 770 2,059 849
Advances to affiliates, net 10,745 78,644 66,145
Proceeds from sale of long-term
investments 913 156 257
Net cash (used in) provided by
investing activities (48,353) 6,310 17,160
(Decrease) increase in cash and cash
equivalents (34) 120 (91)
Cash and cash equivalents at beginning
of period 235 115 206
Cash and cash equivalents at end of
period $ 201 $ 235 $ 115
Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized) $ 19,587 $ 21,806 $ 23,426
Income taxes, net 21,903 33,944 9,431
The accompanying notes are an integral part of these
consolidated financial statements.
TEXAS GAS TRANSMISSION CORPORATION AND SUBISIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Corporate Structure and Control, Nature of Operations and
Basis of Presentation
Corporate Structure and Control
Effective May 1, 1997, Texas Gas Transmission Corporation
and its wholly owned subsidiary, TGT Enterprises, Inc.,
(collectively, the Company) became a wholly owned subsidiary
of 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.
Nature of Operations
The Company is an interstate natural gas transmission
company which owns and operates a natural gas pipeline system
originating 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 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 the Northeast through
interconnections with unaffiliated pipelines.
Basis of Presentation
The Company's 1995 acquisition by Williams has been
accounted for using the purchase method of accounting.
Accordingly, an allocation of the purchase price was assigned
to the assets and liabilities of the Company, based on their
estimated fair values. The accompanying financial statements
reflect the pushdown of the purchase price allocation (amounts
in excess of book value) to the Company. Included in
property, plant and equipment at December 31, 1998, is an
aggregate of approximately $430 million related to amounts in
excess of the original cost of the regulated facilities as a
result of the Williams' and prior acquisitions. This amount
is being amortized over 40 years, the estimated useful lives
of these assets at the date of acquisition, at approximately
$11 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.
Effective November 1, 1993, the Company contracted with a
gas marketing affiliate 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 as discussed in Note B. Sales and purchases
under this agreement do not impact the Company's results of
operations.
B. Summary of Significant Accounting Policies
Revenue Recognition
The Company recognizes revenues for the sale of natural gas
when products have been delivered and for the transportation
of natural gas based upon contractual terms and the related
transportation volumes through month-end. Pursuant to FERC
regulations, a portion of the revenues being collected may be
subject to 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 in anticipation of recovery
or refunds through future rate or surcharge adjustments (see
Note C for a discussion of the Company's rate matters).
Property, Plant and Equipment
Depreciation is provided primarily on the straight-line
method over estimated useful lives. Gains or losses from the
ordinary sale or retirement of property, plant and equipment
generally are credited or charged to accumulated depreciation;
other gains or losses are recorded in net income.
Income Taxes
Deferred income taxes are computed using the liability
method and are provided on all temporary differences between
the book basis and the tax basis of the Company's assets and
liabilities.
For federal income tax reporting, the Company is included
in the consolidated federal income tax return of Williams. It
is Williams' policy to charge or credit each subsidiary with
an amount equivalent to its federal income tax expense or
benefit as if each subsidiary filed a separate return.
Gas Sales and Purchases
Since November 1, 1993, the only gas sales administered by
the Company have been volumes purchased under a limited number
of non-market-responsive gas purchase contracts which were
auctioned each month to the highest bidder. The Company filed
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 gas supply
realignment (GSR) cost pursuant to FERC Order 636. Effective
November 1, 1996, the auction sales and the related pricing
differential mechanism terminated in accordance with the
Company's GSR settlement (see Note C).
A gas marketing affiliate of the Company has been appointed
as the Company's exclusive agent for the purpose of
administering all existing and future purchases of gas under
market-responsive gas purchase contracts and the resale of
these purchases.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management
to make estimates and assumptions that affect the amounts
reported in the financial statements and accompanying notes.
Actual results could differ from those estimates.
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, 1998, 1997 and 1996, was $0.7 million, $0.7
million and $0.4 million, respectively. The allowance for
equity funds for the years ended December 31, 1998, 1997 and
1996, was $1.4 million, $1.6 million and $0.7 million,
respectively.
Gas in Storage
The Company's storage gas, which is valued at historical
cost, is used for system management, in part to meet
operational balancing needs on its system, in part to meet the
requirements of the Company's firm and interruptible storage
customers, 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 gas to be
repaid in-kind during the following summer season. In
accordance with FERC Order 581, that portion of the Company's
gas stored underground which exceeded its system management
requirements, as approved by the FERC, has been classified as
a current asset in the accompanying balance sheets.
Gas Imbalances
In the course of providing transportation services to
customers, the Company may receive different quantities of gas
from shippers than the quantities delivered on behalf of those
shippers. These transactions result in imbalances, which are
repaid or recovered in cash or through the receipt or delivery
of gas in the future. Customer imbalances to be repaid or
recovered in-kind are recorded as a receivable or payable in
the accompanying balance sheets. Settlement of imbalances
requires agreement between the pipeline and shippers as to
allocations of volumes to specific transportation contracts
and timing of delivery of gas based on operational conditions.
Inventory Valuation
The cost of materials and supplies inventories is
determined using the average-cost method.
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 in cash equivalents any
short-term highly-liquid investments that have a maturity of
three months or less when acquired.
Common Stock Dividends and Returns of Capital
The Company charges against paid-in capital that portion of
any common dividend declaration which exceeds the retained
earnings balance. Such charges are deemed to be returns of
capital.
Reclassifications
Certain reclassifications have been made in the 1997 and
1996 financial statements to conform to the 1998 presentation.
C. 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 FERC Order 636, which,
among other things, required pipelines to unbundle their
merchant role 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 GSR costs and
unrecovered purchased gas costs. Certain aspects of the
Company's FERC Order 636 restructuring are under 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 services; the remaining ten
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 services due to the full recovery of
incurred GSR costs allocated to these services. The GSR cost
increment included in the interruptible transportation rates,
as well as no-notice and firm transportation 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 no more than $80 million for
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. On March 20, 1998, the Company filed an offer of
settlement. On July 15, 1998, the FERC issued an "Order
Approving Offer of Settlement and Remanding Case for Hearing"
which approved the settlement without modification, but
remanded the proceeding back to an administrative law judge
for the sole purpose of conducting a hearing on an issue
related to production area rates raised by a single
intervenor. On October 14, 1998, the FERC issued an "Order
Denying Rehearing and Providing Guidance on Hearing Issues."
On November 9, 1998, that intervenor filed a notice of
withdrawal from the case and on November 10, 1998, the
presiding administrative law judge issued an order suspending
the procedural schedule on the remanded hearing. No parties
requested rehearing of the October 14, 1998, order and on
November 30, 1998, the Company filed tariff sheets to
implement the settlement. The Company had established an
adequate reserve for the difference between collected rates
and the settlement rates. Refunds, including interest, of
$17.2 million were distributed to customers on January 13,
1999.
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 December 31, 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.
Other Legal Issues
In 1998, the United States Department of Justice informed
Williams that Jack Grynberg, an individual, had filed claims
in the United States District Court for the District of
Colorado under the False Claims Act against Williams and
certain of its wholly owned subsidiaries including the
Company, Williams Gas Pipelines Central, Inc., Kern River Gas
Transmission Company, Northwest Pipeline Corporation, Williams
Gas Pipeline Company, Transcontinental Gas Pipe Line
Corporation, and Williams Production Company. Mr. Grynberg
has also filed claims against approximately 300 other energy
companies and alleges that the defendants violated the False
Claims Act in connection with the measurement and purchase of
hydrocarbons. The relief sought is an unspecified amount of
royalties allegedly not paid to the federal government, treble
damages, a civil penalty, attorneys' fees, and costs.
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.
D. Income Taxes
Following is a summary of the provision for income taxes
for the years ended December 31, 1998, 1997, and 1996
(expressed in thousands):
For the Year Ended December 31,
1998 1997 1996
Current provision:
Federal $16,288 $28,637 $11,054
State 3,361 6,141 2,139
19,649 34,778 13,193
Deferred (benefit) provision:
Federal 8,085 (5,274) 10,517
State 1,738 (1,134) 2,262
9,823 (6,408) 12,779
Income tax provision $29,472 $28,370 $25,972
Reconciliations from the income tax provision at the
statutory rate to the Company's income tax provision are as
follows (expressed in thousands):
For the Year Ended December 31,
1998 1997 1996
Provision at statutory rate $26,033 $25,056 $25,253
Increases in taxes resulting
from:
State income taxes 3,314 3,255 2,860
Provision adjustment to
prior year's tax return - - (2,271)
Other, net 125 59 130
Income tax provision $29,472 $28,370 $25,972
Significant components of deferred tax liabilities and
assets as of December 31, 1998 and 1997, are as follows
(expressed in thousands):
1998 1997
Deferred tax liabilities:
Costs refundable to customers - fuel $ 2,507 $ 1,198
Property, plant and equipment:
Tax over book depreciation, net of gains 63,721 56,221
Other basis differences 104,060 103,984
Other 5,659 5,332
Total deferred tax liabilities 175,947 166,735
Deferred tax assets:
Costs recoverable from customers:
Gas supply realignment 266 962
Transportation 272 1,422
Accrued employee benefits 13,150 9,949
Producer settlement costs 415 412
Reserve for rate refund 2,690 5,623
Miscellaneous deferrals 3,586 2,800
Gas stored underground - additional tax basis 2,464 2,465
Debt related items 3,308 3,779
Other 8,039 7,389
Total deferred tax assets 34,190 34,801
Net deferred tax liabilities $141,757 $131,934
E. Financing
At December 31, 1998 and 1997, long-term debt issues were
outstanding as follows (expressed in thousands):
1998 1997
Debentures:
7 1/4% due 2027 $100,000 $100,000
Notes:
8 5/8% due 2004 150,000 150,000
250,000 250,000
Unamortized debt premium, net 1,160 1,433
Total long-term debt $251,160 $251,433
The Company filed a Form S-3 Registration Statement with
the SEC on May 16, 1997, to register debt securities of $200
million to be offered for sale on a delayed or continuous
basis. On July 15, 1997, the Company sold $100 million of 7
1/4% Debentures due July 15, 2027. The Debentures have no
sinking funds and may be called at any time, at the Company's
option, in whole or in part, at a specified redemption price,
plus accrued and unpaid interest to the date of redemption.
Proceeds from the sale of the Debentures were used to retire
the Company's 9 5/8% Notes, which matured on July 15, 1997.
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 property to secure any indebtedness unless the debentures
and notes shall be equally and ratably secured.
The Company is a participant with other Williams
subsidiaries in a $1 billion credit agreement under which the
Company may 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.
F. Employee Benefit Plans
Retirement Plan
Substantially all of the Company's employees are covered
under a non-contributory, defined benefit retirement plan
(Retirement Plan) offered by the Company. The Company's
general funding policy is to contribute amounts deductible for
federal income tax purposes. Due to its fully funded status,
the Company has not been required to fund the Retirement Plan
since 1986.
In connection with a 1998 restructuring of the Company's
field operations area, the Company offered a special voluntary
retirement program with enhanced benefits. The program was
offered to all field employees who had five or more years of
service and were age 50 on or before June 30, 1998. There
were 85 employees who elected to retire, effective July 1,
1998, under this special retirement program.
The following table presents the changes in benefit
obligations and plan assets for pension benefits for the years
indicated. It also presents a reconciliation of the funded
status of these benefits to the amount recognized in the
Consolidated Balance Sheet at December 31 of each year
indicated.
1998 1997
Change in benefit obligation:
Benefit obligation at beginning of year $ 68,714 $ 62,881
Service cost 4,133 3,016
Interest cost 6,097 4,646
Amendments (16,414) -
Settlement/curtailment gain (23,738) -
Special termination benefit cost 16,660 -
Actuarial loss 48,170 316
Benefits paid (28,108) (2,145)
Benefit obligation at end of year 75,514 68,714
Change in plan assets:
Fair value of plan assets at beginning
of year 132,262 116,317
Actual return on plan assets 16,048 18,090
Benefits paid (1,744) (2,145)
Settlement benefits paid (26,364) -
Fair value of plan assets at end of year 120,202 132,262
Funded status 44,688 63,548
Unrecognized net actuarial gain (3,497) (47,731)
Unrecognized prior service credit (16,325) (1,236)
Prepaid benefit cost $ 24,866 $ 14,581
Prepaid pension costs related to the Retirement Plan have
been classified as other assets in the accompanying balance
sheets.
Net pension benefit expense consists of the following:
For the Year Ended December 31,
1998 1997 1996
Components of net periodic pension
expense:
Service cost $ 4,133 $ 3,016 $ 3,029
Interest cost 6,097 4,646 4,295
Expected return on plan assets (12,081) (11,580) (9,891)
Amortization of prior service credit (1,251) (95) (95)
Recognized net actuarial gain (31) (2,176) (2,106)
Settlement/curtailment gain (23,811) - -
Special termination benefit cost 16,660 - -
Regulatory asset accrual 10,284 6,189 4,768
Net periodic pension expense $ - $ - $ -
The following are the weighted-average assumptions utilized as of
December 31 of the year indicated.
1998 1997 1996
Discount rate 7.00% 7.25% 7.50%
Expected return on plan assets 10.00% 10.00% 10.00%
Rate of compensation increase 5.00% 5.00% 5.00%
The Company recognizes expense concurrent with the recovery
in rates. Since the Company's Retirement Plan is fully
funded, the Company is not currently recovering any amounts
through rates.
Postretirement Benefits Other than Pensions
Effective January 1, 1996, the Company began participation
in Williams' health care plan which provides postretirement
medical benefits to retired employees who were employed full
time, hired prior to January 1, 1996, and have met certain
other requirements. The Company made contributions to the
Williams' postretirement health care plan of $4.5 million in
1998 and $10.3 million in both 1997 and 1996. The Company
contributes to the health care plan only the amount it is
allowed to recover through its rates by the FERC. The
settlement of the Company's latest rate case with the FERC
(Docket No. RP97-344) allows recovery of $5.9 million
annually, including amortization of previously deferred
postretirement benefit costs. Net postretirement benefit
expense related to the Company's participation in the
Williams' plan is $5.0 million for 1998 and $10.7 million for
both 1997 and 1996, including $1.9 million, $8.5 million and
$6.9 million of amortization of a regulatory asset,
respectively. The regulatory asset represents unrecovered
costs from prior years, including the unamortized transition
obligation under Statement of Financial Accounting Standard
(SFAS) No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions," which was recognized at the
date of acquisition by Williams. The regulatory asset balance
as of both December 31, 1998 and 1997 was $44 million. This
asset is being amortized concurrent with the recovery of these
costs through rates Based on the 1998 level of amortization,
the regulatory asset balance should be recovered through rates
in approximately 17 years.
Other
The Company maintains various defined contribution plans
covering substantially all employees. The Company's costs
related to these plans were $2.8 million in 1998, $2.6 million
in 1997 and $2.5 million in 1996.
G. Financial Instruments
The following methods and assumptions were used by the
Company in estimating its fair-value disclosures for financial
instruments:
Cash and Short-Term Financial Assets: For short-term
instruments, the carrying amount is a reasonable estimate of
fair value due to the short maturity of those instruments. As
discussed in Note H, advances to affiliates, which are
represented by demand notes payable, earn a variable rate of
interest which is adjusted regularly to reflect current market
conditions.
Long-Term Debt: All of the Company's long-term debt is
publicly traded; therefore, estimated fair value is based on
quoted market prices at December 31, 1998 and 1997.
The carrying amount and estimated fair values of the
Company's financial instruments as of December 31, 1998 and
1997, are as follows (expressed in thousands):
Carrying Fair
Amount Value
1998 1997 1998 1997
Financial Assets:
Cash and short-term financial assets $ 82,974 $ 93,736 $ 82,974 $ 93,736
Financial Liabilities:
Long-term debt 251,160 251,433 270,628 267,810
Sale of Receivables
The Company sells, with limited recourse, certain
receivables. The limit under the revolving receivables
facility was $35 million at December 31, 1998 and 1997. At
December 31, 1998 and 1997, $19.6 million and $29.6 million,
respectively, of such receivables had been sold. Based on
amounts outstanding at December 31, 1998, the maximum
contractual credit loss under these arrangements is
approximately $3.2 million, but the likelihood of loss is
remote.
Significant Group Concentrations of Credit Risk
The Company's 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. As a general policy, collateral is not required
for receivables, but customers' financial condition and credit
worthiness are evaluated regularly.
H. Transactions with Major Customers and Affiliates
Major Customers
The Company's only major customer for both 1998 and 1997
was ProLiance Energy, LLC. Revenues received from ProLiance
Energy, LLC were $39.9 million and $39.5 million for the years
ended December 31, 1998 and 1997, respectively, portions of
which are included in the refund reserves discussed in Note C.
The Company did not have any major customer which accounted
for more than ten percent of total operating revenues in 1996.
Related Parties
As a subsidiary of Williams, the Company engages in
transactions with Williams and other Williams subsidiaries
characteristic of group operations. The Company is a
participant in Williams' cash management program. The
advances due the Company by Williams are represented by demand
notes payable. The interest rate on intercompany demand notes
is the London Interbank Offered Rate on the first day of the
month plus 0.325%. Net interest income on advances to or from
affiliated companies was $4.8 million, $7.0 million and $12.0
million for the years ended December 31, 1998, 1997 and 1996,
respectively.
Williams has a policy of charging subsidiary companies for
management services provided by the parent company and other
affiliated companies. Amounts charged to expense relative to
management services were $5.2 million, $5.2 million, and $5.6
million for the years ended December 31, 1998, 1997 and 1996,
respectively. Management considers the cost of these services
reasonable.
Included in the Company's gas sales revenues for the years
ended December 31, 1998, 1997 and 1996, is $0.9 million, $5.7
million and $22.4 million, respectively, applicable to gas
sales to the Company's gas marketing affiliates.
Included in the Company's gas transportation revenues for
the years ended December 31, 1998, 1997 and 1996, are amounts
applicable to transportation for affiliates as follows
(expressed in thousands):
For the Year Ended December 31,
1998 1997 1996
Williams Energy Services Company $ 1,990 $ 3,183 $ 2,245
Transcontinental Gas Pipe Line Corporation 4,097 4,305 17,460
$ 6,087 $ 7,488 $19,705
Included in the Company's cost of gas sold for the years
ended December 31, 1998, 1997 and 1996, is $12.4 million,
$19.7 million and $31.5 million, respectively, applicable to
gas purchases from the Company's gas marketing affiliates.
I. Stock-Based Compensation
Williams has several plans providing for common stock-based
awards to its employees and employees of its subsidiaries.
The plans permit the granting of various types of awards
including, but not limited to, stock options, stock
appreciation rights, restricted stock and deferred stock. The
purchase price per share for stock options may not be less
than the market price of the underlying stock on the date of
grant. Stock options generally become exercisable after five
years, subject to accelerated vesting if certain future stock
prices are achieved. Stock options expire ten years after
grant.
Williams' employee stock-based awards are accounted for
under Accounting Principles Board (APB) Opinion No. 25,
"Accounting for Stock Issued to Employees" and related
interpretations. Williams' fixed plan common stock options do
not result in compensation expense because the exercise price
of the stock options equals the market price of the underlying
stock on the date of grant.
SFAS No. 123, "Accounting for Stock-Based Compensation,"
requires that companies who continue to apply APB Opinion No.
25 disclose pro forma net income assuming that the fair-value
method in SFAS No. 123 had been applied in measuring
compensation cost. Pro forma net income for the Company was
$43.7 million for 1998, $42.0 million for 1997 and $46.1
million for 1996. Reported net income was $44.9 million,
$43.2 million and $46.2 million for 1998, 1997 and 1996. Pro
forma amounts for 1998 and 1997 include the remaining total
compensation expense from the awards made in the prior year,
as these awards fully vested in 1998 and 1997, respectively,
as a result of the accelerated vesting provisions. Since
compensation expense from stock options is recognized over the
future years' vesting period, and additional awards generally
are made each year, pro forma amounts may not be
representative of future years' amounts.
A summary of stock options granted under the plans is shown
in the following table:
1998 1997 1996
Stock options granted 163,489 348,322 484,500
Stock options outstanding 1,397,913 1,343,949 1,102,140
Stock options exercisable 1,234,424 996,627 586,922
Weighted average grant fair value $8.19 $5.98 $3.92
J. Quarterly Information (Unaudited)
The following summarizes selected quarterly financial data
for 1998 and 1997 (expressed in thousands):
1998
First Second Third Fourth
Quarter Quarter Quarter Quarter
Operating revenues $ 91,789 $ 60,371 $ 53,299 $ 81,327
Operating expenses 49,960 50,615 46,208 49,578
Operating income 41,829 9,756 7,091 31,749
Interest expense 5,296 5,283 5,238 5,409
Other income, net (1,135) (1,541) (1,556) (948)
Income before income taxes 37,668 6,014 3,409 27,288
Provision for income taxes 14,981 2,389 1,368 10,734
Net income $ 22,687 $ 3,625 $ 2,041 $ 16,554
1997
First Second Third Fourth
Quarter Quarter Quarter Quarter
Operating revenues $107,939 $ 63,615 $ 57,158 $ 89,625
Operating expenses 65,504 55,843 54,352 58,517
Operating income 42,435 7,772 2,806 31,108
Interest expense 5,015 5,009 4,880 5,122
Other income, net (2,420) (2,375) (1,795) (904)
Income (loss) before income
taxes 39,840 5,138 (279) 26,890
Provision for (benefit from)
income taxes 15,850 2,048 (233) 10,705
Net income (loss) $ 23,990 $ 3,090 $ (46) $ 16,185
Item 9. Disagreements on Accounting and Financial Disclosure.
Not Applicable.
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 Auditors on Consolidated Financial Statements
Consolidated Balance Sheets at December 31, 1998 and 1997
Consolidated Statements of Income for the years ended December 31, 1998,
1997, and 1996
Consolidated Statements of Retained Earnings and Paid-In Capital for the
years ended December 31, 1998, 1997, and 1996
Consolidated Statements of Cash Flows for the years ended December 31,
1998, 1997, and 1996
Notes to Consolidated Financial Statements
Schedules are omitted because of the absence of conditions under which
they are required or because the required information is given in the
consolidated financial statements or notes thereto.
(a) 3. Exhibits
* 3.1 Copy of Certificate of Incorporation of the Corporation.
3.2 Copy of Bylaws of the Corporation (incorporated by reference
to Exhibit 3.2 of the 1995 Form 10-K - File No. 1-4169).
4.1 Indenture dated July 15, 1997, between the Company and
The Bank of New York relating to 7 1/4% Debentures, due 2027
(incorporated by reference to Exhibit 4.1 to Registration
Statement No. 333-27359, dated May 16, 1997).
4.2 Indenture dated April 11, 1994, securing 8 5/8% Notes due
April 1, 2004 (incorporated by reference to Form 8-K dated
April 13, 1994 - File No. 1-4169).
* 23 Consent of Independent Auditors.
* 24.1 Power of Attorney together with certified resolution.
* 27.1 Financial Data Schedule for Texas Gas Transmission
Corporation for the year ended December 31, 1998.
(b) Reports on Form 8-K
None.
______________
* Filed herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
TEXAS GAS TRANSMISSION CORPORATION
By: /s/ S. W. Harris
S. W. Harris
Controller and Chief Accounting
Officer
Dated: March 26, 1999
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and
on the date indicated.
/s/ Brian E. O'Neill * President and Chief Executive Officer
Brian E. O'Neill (Principal Executive Officer)
/s/ Nick A. Bacile Vice President and Chief Financial Officer
Nick A. Bacile (Principal Executive Officer)
/s/ Keith E. Bailey * Director
Keith E. Bailey
/s/ Gary D. Lauderdale * Director
Gary D. Lauderdale
*By: /s/ S. W. Harris Controller and Chief Accounting Officer
S. W. Harris
Dated: March 26, 1999