Contingencies.  We record liabilities for estimated loss contingencies when we believe a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect previous assumptions with respect to the likelihood or amount of loss.  Liabilities for contingent losses are based upon management’s assumptions and estimates, and advice of legal counsel or third parties regarding the probable outcomes of the matter.  Should the outcome differ from the assumptions and estimates, revisions to the liabilities for contingent losses would be required.

Impairment of Goodwill.  Our purchase price allocation reflects the underlying assumption that the historical net book value of regulatory related assets and liabilities are considered to be the fair value of those respective assets and liabilities.  Accordingly, the excess purchase price over the fair value of the assets and liabilities was allocated to goodwill.  SFAS 142 “Goodwill and Other Intangible Assets” requires the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired.  The annual impairment test is performed on December 31.   In accordance with SFAS 142, we have not amortized goodwill and there have been no impairments recorded in 2003.  

Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize.  The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Employee Benefits.  We have a defined-benefit pension plan for substantially all employees and a health care plan which accords postretirement medical benefits to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements.  Several statistical and other factors, which attempt to anticipate future events, are used in calculating the expense and liability related to the plans.  These factors include assumptions about the discount rate, expected return on plan assets, and rate of future compensation increases, within certain guidelines.  In addition, our actuarial consultants also use subjective factors such as withdrawal and mortality rates to estimate the projected benefit obligation.  The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants.  These differences may result in a significant impact on the amount of expense recorded in future periods.

Financial Analysis of Operations

This analysis discusses financial results of our operations for the years 2001 through 2003.  We have based our narrative analysis of our results of operations for the twelve-month periods then ended on the combined results of operations. As more fully discussed in the notes to financial statements, the Texas Gas purchase price allocation creates a new basis of accounting post-acquisition, necessitating the use of a bold vertical line in the statement of income.  For the purpose of our financial analysis of operations, we have combined the pre-acquisition and post-acquisition results for 2003.  This pro forma total combines two different bases of accounting, which qualifies as a non-GAAP measure.  However, due to the fact that our purchase price allocation considers that historical book value is equal to fair value, there are not significant differences between the two pres entations.  Depreciation expense and interest expense are impacted by the new purchase price allocation, and related financing, and we will indicate that specifically as we discuss operating variances.  As the excess of fair value paid over net book value was allocated to goodwill, which is non-amortizable, there is no impact on results of operations from that allocation item.  The discussion throughout this narrative refers to our consolidated companies unless otherwise noted, as TGT Pipeline has no assets, liabilities or operations other than its ownership of Texas Gas, $185 million outstanding debt and a note receivable from its parent, as noted previously.

2003 Compared to 2002

Operating revenues decreased $10.4 million, or 3.9 percent, in 2003 compared to 2002 primarily attributable to the following decreases:

•

 $10.2 million recognition of deferred revenues resulting from a favorable issue resolution related to Texas Gas’ rate case settlement in 2002;

•

  $3.1 million due to the expiration of transportation contracts on third party pipelines for which the costs were recovered in rates in 2003; and

•

 These decreases were partially offset by a colder than normal winter in the first quarter of 2003 and commodity price swings causing a greater utilization of Park and Loan services.

Operating costs and expenses decreased $20.0 million in 2003 compared to 2002 due primarily to the following:

•

$6.7 million relating to a change in depreciation resulting from a change in basis of plant from the purchase price allocation;

•

$3.5 million accrual in 2002 for a disputed regulatory issue;

•

$2.5 million in severance costs incurred in 2002;

•

$1.8 million due to the write off of cancelled capital projects in 2002;

•

$1.6 million due to the write off of unrecoverable aviation related costs in 2002;

•

$3.1 million due to the expiration of transportation contracts on third party pipelines in 2003 as discussed above; and

•

Other cost reductions were due to the elimination of services by Williams subsequent to the Acquisition in 2003.

These savings were partially offset by the following:

•

$2.7 million in transition costs as we migrated to a stand-alone organization after the Acquisition in 2003;

•

$3.3 million in costs for services provided by Loews in 2003; and

•

$1.8 million reduction in environmental costs resulting from an environmental insurance settlement in 2002.

Net income increased $5.2 million, or 9.2 percent, primarily due to the decrease in operating expenses explained above offset by the decrease in operating revenues.  Net miscellaneous other expenses were $0.7 million higher in 2003 than 2002 due to the increase in interest expense paid (acquisition-related financing) on the higher incremental debt issuance, offset by an increase in interest income due to higher note receivable and cash balances.  Other income in 2002 was higher due to a gain on the sale of airplanes of $1.1 million.  Income tax expense (charge-in-lieu-of) is $3.8 million higher in 2003 than 2002 due to the increase in net income.  

2002 Compared to 2001

Operating revenues increased $15.1 million, or 6 percent, in 2002 compared to 2001 primarily attributable to the following:

•

$10.2 million recognition of deferred revenues resulting from a favorable resolution of an issue related to Texas Gas’ rate case settlement and an increase in revenues from Park and Loan services; and

•

The remaining $4.9 million is due primarily to a 4.80% colder 2002 than 2001, as measured by degree days.  

Operating costs and expenses increased $0.5 million in 2002 compared to 2001, primarily due to the following:

•

$3.5 million accrual for a disputed regulatory issue;

•

$2.5 million in severance costs;

•

$1.8 million due to the write off of cancelled capital projects;

•

$1.6 million due to the write off of unrecoverable aviation related costs; and

•

$4.3 million in higher taxes, other than incomes taxes, due to the favorable settlement of tax issues in 2001 which resulted in the reversal of tax accruals related to the outstanding tax issues.  

The increase in operating costs and expenses was mostly offset by the following:

•

$8.0 million in lower depreciation expense due to lower depreciation rates approved in Texas Gas’ rate case settlement;

•

$1.8 million from an environmental insurance settlement; and

•

$3.0 million lower employee related expenses due to severance.

Net income increased $11.0 million, or 24 percent, primarily due to the higher operating income discussed above, $1.1 million for the gain on the sale of certain equipment, a $1.1 million reduction in costs from a receivable financing agreement that was cancelled in the third quarter of 2002, and lower interest expense resulting from the settlement of the rate case.  This increase was partially offset by lower interest income resulting from the lower advances to a Williams’ affiliate due primarily to the payout of refunds to customers.

Property, Plant and Equipment

Property, plant and equipment, net, at December 31, 2002, included approximately $347 million related to amounts in excess of the original cost of regulated facilities, as a result of the Williams' 1995 acquisition of Texas Gas.  The original amount of $430 million was being depreciated over 40 years, the estimated remaining useful lives of the assets at the date of Williams’ acquisition of Texas Gas, at approximately $11 million per year.  Excess depreciation of $4.1 million was recorded during the pre-Acquisition period of 2003, but is not reflected in the post-Acquisition property, plant and equipment amounts since the excess cost was allocated to goodwill at the time of Acquisition.  Current FERC policy does not permit Texas Gas to recover through its rates amounts in excess of original cost.

Income Tax

For a discussion of our income tax and its effect on our operations, see Note 6 of Notes to Financial Statements contained in Item 8 herein.

Effect of Inflation   

Texas Gas 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 operating and maintenance 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 Texas Gas’ property, plant and equipment and materials and supplies is subject to rate-making 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, Texas Gas believes it will be allowed to recover and earn a return based on the increased actual costs incurred when existin g facilities are replaced.  Cost-based regulation along with competition and other market factors limit Texas Gas’ ability to price services or products to ensure recovery of inflation’s effect on costs.

Financial Condition and Liquidity

Texas Gas funds its operations and capital requirements with cash flows from operating activities and repayments of funds advanced to TGT Pipeline.  TGT Pipeline advances funds to its parent company, Holding Corp.  TGT Pipeline’s capital requirements are to make interest payments on outstanding debt and advance funds to Holding Corp.  

Texas Gas makes advances to TGT Pipeline.  At December 31, 2003, the advances due Texas Gas by TGT Pipeline totaled $116.5 million.  The advances are represented by demand notes but are classified as noncurrent since Texas Gas does not anticipate demanding these funds during the next twelve months.  The interest rate on intercompany demand notes is the London Interbank Offered Rate on the first day of each three-month period plus one percent and is compounded monthly.

TGT Pipeline makes advances to Holding Corp.  At December 31, 2003, the advances due TGT Pipeline by Holding Corp. totaled $4.3 million.  The advances are represented by demand notes but are classified as noncurrent since TGT Pipeline does not anticipate demanding these funds during the next twelve months.  The interest rate on intercompany demand notes is the London Interbank Offered Rate on the first day of each three-month period plus one percent and is compounded monthly.

Prior to May 17, 2003, Texas Gas was a participant in Williams’ cash management program in which Texas Gas made advances to and received advances from an affiliate of Williams.  At December 31, 2002, the advances due Texas Gas by affiliates totaled $63.1 million.  This amount, as well as other assets and liabilities retained by Williams, was paid as a dividend to Williams prior to the Acquisition.

On October 23, 2003, the FERC issued a Final Rule on Order No. 634-A (Rule) that places restrictions on various types of cash management programs employed by companies in the energy industry, including Texas Gas.  In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs this Rule would preclude public utilities, natural gas companies and oil pipeline companies from participating in such programs unless the parent company and its FERC-regulated affiliate maintain investment-grade credit ratings and the FERC-regulated affiliate maintains stockholders equity of at least 30 percent of total capitalization.  Subsequent to the Acquisition, Texas Gas does not participate in a cash management or cash pooling program, as defined by this Rule.   For further discussion of this Rule, see Note 3 of Notes to Financial S tatements contained in Item 8 herein.

Through July 2002, Texas Gas, through a wholly-owned bankruptcy remote subsidiary, sold certain trade accounts receivable to a special-purpose entity in a securitization structure requiring annual renewal.  Texas Gas acted as the servicing agent for the sold receivables.  The sale of receivables program expired on July 25, 2002, and by the end of August 2002, Texas Gas completed the repurchase of approximately $10 million of trade accounts previously sold.

We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in our credit ratings given by Moody’s Investors Service, Standard & Poor’s and Fitch Ratings (rating agencies). Following the Acquisition, the rating agencies increased Texas Gas’ credit ratings on its senior unsecured long-term debt.  At December 31, 2003, our ratings were as follows:

A security rating is not a recommendation to buy, sell, or hold securities.  The rating is subject to revision or withdrawal at any time and each rating should be evaluated independently of any other rating.

Texas Gas’ capital expenditures, net of retirements and salvage, for 2003 and 2002 were $34.7 million and $27.4 million, respectively.  Capital expenditures for 2004 are expected to approximate $45.4 million.

As discussed in Note 3 of Notes to Financial Statements contained in Item 8 herein, on April 28, 2000, Texas Gas filed a general rate case (Docket No. RP00-260) which became effective November 1, 2000, subject to refund.  On March 4, 2002, the FERC issued an order approving the settlement and severing the Indicated Shippers from the settlement provisions.  On June 17, 2002, the FERC issued an order denying the Indicated Shippers’ request for rehearing of the March 4, 2002 order.  The settlement became effective 31 days after that order when no party filed any further requests for rehearing.  Thus, the settlement’s prospective rates went into effect on August 1, 2002, and refunds of approximately $37.5 million were made on September 16, 2002.  Texas Gas had provided an adequate reserve for amounts, including interest, which were refunded to customers.

The table below summarizes the more significant contractual obligations and commitments by period (in millions).

Although no assurances can be given, Texas Gas expects to fund its capital requirements through cash flows from its operating activities.  We anticipate payment of the $17.3 million debt due in April 2004 will be paid from cash on hand.  Texas Gas anticipates contributing $5.3 million to its other postretirement benefit plan during 2004 as discussed in Note 5 of Notes to Financial Statements contained in Item 8 herein.

Forward-Looking Statements

Documents we file with the Securities and Exchange Commission (SEC) may contain forward-looking statements.  In addition, our senior management and other authorized spokespersons may make forward-looking statements in print or orally to analysts, investors, the media and others.  Forward-looking statements concern plans, objectives, proposed capital expenditures and future events or performance, among other statements.  These statements reflect our current expectations and involve a number of risks and uncertainties.  Although we believe that our expectations are based on reasonable assumptions, actual results may differ materially from those suggested by the forward-looking statements.  Important factors that could cause actual results to differ include:

•

Regulatory issues, including those that affect allowed rates of return, terms and conditions of service, rate structures, depreciation and amortization policies, acquisitions, extension, abandonment of service or facilities.  No assurances can be given as to the financial outcome of our planned 2005 rate case relative to our current rates structure.

•

Residential, commercial and industrial growth in our service area.  The ability to grow our customer base and the pace of that growth are impacted by general business and economic conditions such as interest rates, inflation, fluctuations in the capital markets and the overall strength of the economy in the markets we serve.

•

Environmental legislation.  Our business will be subject to environmental legislation in all jurisdictions in which we operate, and any changes in such legislation could negatively affect our results of operations.

•

Potential changes in accounting policies by the Financial Accounting Standards Board (FASB), the FERC or the SEC for the energy industry might cause us to revise our financial accounting and/or disclosure in the future, which might change the way analysts measure our business or financial performance.

•

Our revenues are generated under contracts which expire periodically and must be renegotiated and extended or replaced.  Although we actively pursue the renegotiation, extension and/or replacement of these contracts we cannot make assurances that we will be able to extend or replace these contracts when they expire or that the terms of any renegotiated contracts will be as favorable as the existing contracts.  

•

The development of additional natural gas reserves requires significant capital expenditures by others for the exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline system.  Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development of additional reserves and production, gathering, storage and pipeline transmission and import and export of natural gas supplies.

•

The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in price for natural gas, which could affect the market for our gas transmission operations.  In addition, future acts of terrorism could be directed against companies operating in the United States, including domestic energy facilities.  While we are taking steps that we believe are appropriate to protect our facilities from these threats, there is no assurance that we can completely secure our assets or completely protect them against a terrorist attack.

All of these factors are difficult to predict and many are beyond our control.  Accordingly, while we believe the assumptions underlying these forward-looking statements to be reasonable, there can be no assurance that these statements will approximate actual experience or that the expectations derived from them will be realized.  When used in our documents or oral presentations, the words “anticipate,” “believe,” “seek,” “intend,” “plan,” “estimate,” “expect,” “objective,” “projection,” “budget,” “forecast,” “goal,” or similar words or future or conditional verbs such as “will,” “would,” “should,” “could,” or “may” are intended to identify forwarding-looking statements.

Forward-looking statements reflect our current expectations only as of the date they are made.  We assume no duty to update these statements should expectations change or actual results differ from current expectations except as required by applicable laws and regulations.  

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk.

Our market risk is limited to our long-term debt.  All interest on long-term debt is fixed in nature.  Total long-term debt at December 31, 2003, had a carrying value of  $548.1 million and a fair value of $538.3 million.  The weighted-average interest rate of TGT Pipeline’s long-term debt is 5.36%.  The weighted-average interest rate of Texas Gas’ long-term debt is 6.07%.  Texas Gas’ $17.3 million (8.625%), $250 million (4.600%) and $100 million (7.250%) long-term debt issues mature in 2004, 2015 and 2027, respectively.  TGT Pipelines’ $185 million (5.200%) long-term debt issue matures in 2018.

Item 8.   Financial Statements and Supplementary Data

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of TGT Pipeline, LLC, and Texas Gas Transmission, LLC:

We have audited the accompanying consolidated statement of financial position of TGT Pipeline, LLC and separate statement of financial position of Texas Gas Transmission, LLC (formerly Texas Gas Transmission Corporation) as of December 31, 2003, and the related consolidated statements of operations, member’s equity, and cash flows for the period May 16, 2003 (Inception) through December 31, 2003 for TGT Pipeline, LLC, and the related statements of operations, stockholder’s and member’s equity, and cash flows for the periods January 1, 2003 through May 16, 2003 (pre-acquisition) and May 17, 2003 through December 31, 2003 (post-acquisition) for Texas Gas Transmission, LLC.  These financial statements are the responsibility of TGT Pipeline, LLC’s and Texas Gas Transmission, LLC’s management.  Our responsibility is to express an opinion on the financial statements based on our aud its.  

We conducted our audits in accordance with auditing standards generally accepted in the United States of America.  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, such financial statements present fairly, in all material respects, the consolidated financial position of TGT Pipeline, LLC and the financial position of Texas Gas Transmission, LLC as of December 31, 2003, and the results of their operations and their cash flows for the period May 16, 2003 (Inception) through December 31, 2003 for TGT Pipeline, LLC and for the periods January 1, 2003 through May 16, 2003 (pre-acquisition) and  May 17, 2003 through December 31, 2003 (post-acquisition) for Texas Gas Transmission, LLC, in conformity with accounting principles generally accepted in the United States of America.  

DELOITTE & TOUCHE LLP

Chicago, Illinois

March 3, 2004

REPORT OF INDEPENDENT AUDITORS

The Board of Directors

Texas Gas Transmission, LLC

      We have audited the accompanying statement of financial position of Texas Gas Transmission, LLC (formerly Texas Gas Transmission Corporation) as of December 31, 2002, and the related statements of operations, cash flows, and stockholder’s and member’s equity for each of the two years in the period ended December 31, 2002.  These financial statements are the responsibility of the Company's management.  Our responsibility is to express an opinion on these financial statements based on our audits.

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

      In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Texas Gas Transmission, LLC at December 31, 2002, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States.

  /s/  Ernst & Young LLP

Houston, Texas

March 5, 2003

TGT PIPELINE, LLC

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2003

(Thousands of Dollars)

TGT PIPELINE, LLC

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2003

(Thousands of Dollars)

TGT PIPELINE, LLC

CONSOLIDATED STATEMENT OF OPERATIONS

 (Thousands of Dollars)

TGT PIPELINE, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

TGT PIPELINE, LLC

CONSOLIDATED STATEMENT OF

MEMBER’S EQUITY

(Thousands of Dollars)

TEXAS GAS TRANSMISSION, LLC

STATEMENT OF FINANCIAL POSITION

(Thousands of Dollars)

TEXAS GAS TRANSMISSION, LLC

STATEMENT OF FINANCIAL POSITION

(Thousands of Dollars, except for share data)

TEXAS GAS TRANSMISSION, LLC

STATEMENT OF OPERATIONS

(Thousands of Dollars)

TEXAS GAS TRANSMISSION, LLC

 STATEMENT OF CASH FLOWS

(Thousands of Dollars)

TEXAS GAS TRANSMISSION, LLC

  STATEMENT OF STOCKHOLDER’S AND MEMBER’S EQUITY

  (Thousands of Dollars)

TGT PIPELINE, LLC

TEXAS GAS TRANSMISSION, LLC

NOTES TO FINANCIAL STATEMENTS

Note 1: Corporate Structure

Texas Gas Transmission, LLC is a wholly-owned subsidiary of TGT Pipeline, LLC, (TGT Pipeline). TGT Pipeline is a wholly-owned subsidiary of TGT Pipeline Holding Corporation (Holding Corp.), which is wholly-owned by Loews Corporation (Loews).  TGT Pipeline was formed in April 2003, with an initial capitalization on May 16, 2003 (Inception), of $804 million, to acquire all of the outstanding capital stock of Texas Gas Transmission Corporation from a subsidiary of The Williams Companies, Inc. (Williams) (Acquisition). Texas Gas Transmission Corporation subsequently converted to a limited liability company and is now known as Texas Gas Transmission, LLC (Texas Gas). TGT Pipeline has no assets, liabilities or operations other than its ownership of Texas Gas, $185 million outstanding debt, as discussed in Note 4, and a note receivable from its parent, Holding Corp.  Texas Gas is the owner and operator of the pipeline system and related assets.

The discussion throughout these notes refers to TGT Pipeline and its consolidated wholly-owned subsidiary, Texas Gas (we/our/us), unless otherwise noted.

The accompanying financial statements of TGT Pipeline and Texas Gas were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for financial information and with the instructions on Form 10-K and Regulation S-X.  As a result of the change in control of Texas Gas, the financial statements of Texas Gas presented for the period after the Acquisition reflect a new basis of accounting.  Accordingly, the Texas Gas Statement of Financial Position and the Statements of Operations and Cash Flows have been separated by a bold vertical line into a pre-Acquisition period and a post-Acquisition period.     

Basis of Presentation

The accompanying pre-Acquisition financial statements reflect a purchase price allocation associated with the acquisition of Texas Gas by Williams in 1995.  Included in property, plant and equipment, net at December 31, 2002, is approximately $347 million related to amounts in excess of the original cost of regulated facilities from that acquisition.  The accompanying post-Acquisition financial statements reflect the pushdown of 100% of the purchase price resulting from the Acquisition. A preliminary allocation of the purchase price was assigned to the assets and liabilities of Texas Gas, based on their estimated fair values in accordance with GAAP.  As Texas Gas’ rates are regulated by the FERC, and the FERC does not allow recovery in rates of amounts in excess of original cost, our historical net book value of regulatory related assets and liabilities are considered to be the fair value of those respective assets and liabilities. The excess purchase price above the historical net book value was allocated to goodwill.  The accounting for the effects of the Acquisition included recognizing unfunded benefit obligations related to postretirement benefits other than pensions and pension benefits with a corresponding offset to costs recoverable from customers, due to the probable future rate recovery of these costs.  As of December 31, 2003, we had $169.3 million of goodwill recorded as an asset on our balance sheet.  Texas Gas may make further adjustments to the purchase price allocation pending resolution of certain revenue refund issues, as well as certain revisions to the tax basis of assets and liabilities assumed in the Acquisition.

The Acquisition was treated as an acquisition of assets for income tax purposes and, accordingly, we will have tax basis in our net assets approximately equal to the Acquisition price.   In connection with the terms of this election, temporary differences that existed prior to the Acquisition no longer exist and differences between the new allocated purchase price for book and income tax are established as part of the purchase price allocation.  Therefore, deferred tax asset and liability balances existing prior to the Acquisition have been eliminated.  We engaged a third-party consultant to assist in the appraisal of the assets and liabilities for income tax purposes, and adjusted our purchase price allocation to reflect the appropriate amounts of deferred tax assets and liabilities. As previously discussed, Texas Gas was converted into a limited liability company immediat ely following the Acquisition.  The financial statements contained herein reflect a Charge-In-Lieu of Income Taxes subsequent to the Acquisition in recognition of the ratemaking allowed for such costs.   

The following unaudited pro forma financial information is presented as if Texas Gas had been acquired as of the beginning of each period presented.  The pro forma amounts include certain adjustments, including a reduction of depreciation expense based on the preliminary allocation of the Acquisition purchase price to property, plant and equipment; adjustment of interest expense to reflect the issuance of post-Acquisition debt by Texas Gas, and the application of a portion of the proceeds of such debt to prepay $132.7 million principal amount of Texas Gas’ existing notes.  Since TGT Pipeline had no activity prior to the Acquisition, there are no pro forma amounts to be presented.

Note 2:  Accounting Policies

Principles of Consolidation

The consolidated TGT Pipeline financial statements include the accounts of TGT Pipeline and its wholly-owned subsidiary, Texas Gas, after elimination of inter-company transactions.

Goodwill

As part of the allocation of the purchase price of the Acquisition, the excess purchase price over the fair value of the assets and liabilities was allocated to goodwill.  SFAS 142 “Goodwill and Other Intangible Assets” requires the evaluation of goodwill for impairment at least annually or more frequently if events and circumstances indicate that the asset might be impaired.  The annual impairment test is performed on December 31.   In accordance with SFAS 142, we have not amortized goodwill and there have been no impairments recorded in 2003.  

Segment Information

We operate in one segment - gas transportation and integrated underground gas storage.  This segment consists of an interstate natural gas pipeline system originating in the Louisiana Gulf Coast area and in East Texas and running north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller diameter lines extending into Illinois, with 5,800 miles of mainline, storage and branch transmission pipelines.  Our segment also consists of natural gas storage reservoirs in nine underground storage fields located in or near our natural gas pipeline system in Indiana and Kentucky.

Regulatory Accounting

We are regulated by the FERC.  Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” requires that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates.  In applying SFAS No. 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods.

We monitor the regulatory and competitive environment in which we operate to determine that our regulatory assets continue to be probable for recovery.  If we were to determine that all or a portion of these regulatory assets no longer met the criteria for continued application of SFAS No. 71, we would write off that portion which we could not recover, net of any regulatory liabilities which would be deemed no longer appropriate.  Texas Gas has various mechanisms whereby rates or surcharges are established and revenues are collected and recognized based on estimated costs.   None of our regulatory assets as of December 31, 2003 and 2002 were earning a return.

The amounts recorded as regulatory assets and liabilities in the Texas Gas balance sheet as of December 31, 2003 and 2002, are summarized as follows (shown in thousands):

The table above includes amounts related to unamortized debt expense and unamortized discount on long-term debt.  While these amounts are not regulatory assets and liabilities as defined by SFAS No. 71, they are a critical component of our embedded cost of debt financing utilized in our rate proceedings.   Certain amounts in the table are reflected as a negative, or a reduction, to be consistent with the manner in which we record these items in our regulatory books of account.  

For the years ended December 31, 2003 and 2002, negative salvage amounts have been reclassified from accumulated depreciation to appropriately reflect such balances as a regulatory liability in accordance with GAAP. For further discussion of SFAS No. 143 and its effect on these financial statements, see Recent Accounting Standards in this Note 2.

Excise Taxes

Texas Gas collects from customers certain excise taxes imposed by state or local governments upon customers.  These amounts do not impact the statements of operations and are accumulated as a liability until remitted to the state or local taxing authority.

Accounting Policies and Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those related to revenues subject to refund, bad debts, materials and supplies obsolescence, investments, intangible assets and goodwill, property and equipment and other long-lived assets, income taxes, workers' insurance, pensions and other post-retirement and employment benefits and contingent liabilities. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Cash and Cash Equivalents

Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid investments with an original maturity of three months or less.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs.  Texas Gas establishes an allowance for doubtful accounts receivable on a case-by-case basis when we believe the required payment of specific amounts owed is unlikely to occur.  Uncollectible accounts receivable are written off when a settlement is reached for an amount that is less than the outstanding historical balance.  This allowance was approximately $0.2 million and $0.6 million at December 31, 2003 and 2002, respectively.  We expensed ($0.4) million in post-Acquisition 2003, $0.0 in pre-Acquisition 2003 and $0.0 in 2002 on our statement of operations to write off doubtful accounts.

Advances to Affiliates

TGT Pipeline makes advances to Holding Corp.  Texas Gas makes advances to TGT Pipeline.  These advances are represented by demand notes.  Advances are stated at historical carrying amounts.  Interest income and expense is recognized when chargeable and collection is reasonably assured. Holding Corp. and TGT Pipeline have the positive intent and ability to repay advances made to them. The advances are classified as noncurrent since neither TGT nor Texas Gas anticipates demanding these funds during the next twelve months.  The interest rate on intercompany demand notes is the London Interbank Offered Rate on the first day of each three-month period plus one percent and is compounded monthly.

During 2002, as a participant in Williams’ cash management program, Texas Gas made advances to and received advances from Williams through a Williams’ affiliate.  The advances were represented by demand notes and were stated at the historical carrying amounts.  

Securitizations and Transfers of Financial Instruments

Through July 2002, Texas Gas, through a wholly-owned bankruptcy remote subsidiary, sold certain trade accounts receivable to a special-purpose entity in a securitization structure requiring annual renewal.  Texas Gas acted as the servicing agent for the sold receivables.  The sale of receivables program expired on July 25, 2002, and by the end of August 2002, Texas Gas completed the repurchase of approximately $10 million of trade accounts previously sold.

Materials and Supplies

Materials and supplies are carried at the lower of average cost or market less an allowance for obsolescence.  Such allowance was $0.6 million and $0.7 million at December 31, 2003 and 2002 respectively.  

Property, Plant and Equipment

Depreciation is provided primarily on the straight-line method at FERC prescribed rates, over estimated useful lives.  Reflecting the application of composite depreciation, gains and losses from the ordinary sale and retirement of property, plant and equipment (PP&E) generally do not impact net PP&E.  Other gains and losses are recorded in net income.  Depreciation and amortization expense for the period prior to Acquisition in 2003 was $16.1 million and for the period after Acquisition, $20.5 million, and for the years ended December 31, 2002, and 2001, was $37.8 million and $45.8 million, respectively.  

The lower depreciation expense in 2002 is due primarily to lower depreciation rates, retroactive to November 1, 2000, approved in Texas Gas’ general rate case.  See Note 3.

The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values.  These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations.  

Gas in Storage

Texas Gas’ gas stored underground, 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 Texas Gas’ firm and interruptible storage customers, and in part to meet the requirements of Texas Gas’ "No-Notice" (NNS) transportation service, which allows customers to temporarily draw from Texas Gas’ storage gas to be repaid in-kind during the following summer season.  The accompanying statements of cash flows presents certain changes in operating assets and liabilities reflecting the utilization of gas in storage for the purposes indicated above.  While changes in these assets and liabilities adjust net income in order to reconcile to cash provided from operations, there is no impact on net cash provided by operating activities relating to gas stored unde rground.  A small amount of storage gas is also used to provide "Summer No-Notice" (SNS) transportation service, designed primarily to meet the needs of summer-season electrical power generation facilities.  SNS customers may temporarily draw from Texas Gas' storage gas in the summer, to be repaid during the same summer season.  In accordance with FERC Order 581, that portion of gas stored underground which exceeds Texas Gas’ system management requirements, as approved by the FERC, has been classified as a current asset in the accompanying 2002 balance sheets.  At the end of 2003, we had no gas in storage available for resale.

Impairment of Long-Lived Assets

Texas Gas evaluates long-lived assets for impairment when, in management’s judgment, events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.  When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred.  If an impairment of the carrying value has occurred, the amount of impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.   

Gas Receivables/Payables

In the course of providing transportation and storage services to customers, Texas Gas 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.  Gas receivables/payables are valued at Texas Gas’ historical cost of gas in storage.

Revenue Recognition

Revenues from the transportation of gas are recognized in the period the service is provided based on contractual terms and the related transported volumes.  Texas Gas is subject to FERC regulations and, accordingly, certain revenues collected may be subject to possible refunds upon final orders in pending cases. Texas Gas records rate refund liabilities considering Texas Gas and third-party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks.

Repair and Maintenance Costs

Texas Gas accounts for repair and maintenance costs under the guidance of FERC regulations, which is consistent with GAAP.  The FERC identifies installation, construction and replacement costs that are to be capitalized.  All other costs are expensed as incurred.

Income Taxes

As previously discussed, Texas Gas was converted into a limited liability company immediately following the Acquisition.  The accompanying financial statements reflect a Charge-In-Lieu of Income Taxes subsequent to the Acquisition in recognition of the ratemaking allowed for such costs.   We include an appropriate allowance for income taxes in cost of service and derivation of tariff rates and, accordingly, design our rates to recover such costs.  The effective tax rate for the period subsequent to the Acquisition, represented by our Charge-In-Lieu of Income Taxes, is substantially equal to the statutory rate. The effective tax rate for the period prior to the Acquisition was slightly higher than the statutory rate.

Deferred income tax is computed using the liability method and is provided on all temporary differences between the book basis and the tax basis of our assets and liabilities.

For federal income tax reporting, we are included in the consolidated federal income tax return of Loews Corporation.  The tax sharing agreement with Loews requires us to remit to Loews on a quarterly basis any charges-in-lieu of federal income tax due as if we were filing a separate return.  Loews will remit to us the value of any federal income tax losses or other benefit at such time that we would be able to utilize the benefit on a separate-return basis.

Prior to the Acquisition, Texas Gas was included in the consolidated federal income tax return of Williams.  It was Williams’ policy to charge or credit Texas Gas with an amount equivalent to its federal income tax expense or benefit as if Texas Gas filed a separate return.

Capitalized Interest

The allowance for funds used during construction represents the cost of funds applicable to the 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 pre- and post-Acquisition periods in 2003 and the years ended December 31, 2002 and 2001, was $0.3 million, $0.0 million, $0.9 million and $0.6 million, respectively.   The allowance for equity funds used during construction for the pre- and post-Acquisition periods in 2003 and the years ended December 31, 2002 and 2001, was $0.7 million, $0.2 million, $2.4 million and $1.3 million, respectively.  The allowance for borrowed funds used during construction reduces interest expense and the allowance for equity funds is included in miscellaneous other income.

Employee Stock Based Awards

Subsequent to the Acquisition, stock-based awards were discontinued and all outstanding awards expired on November 17, 2003, no later than six months after the Acquisition.

Prior to the Acquisition, Williams’ employee stock-based awards were 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 generally did not result in compensation expense because the exercise price of the stock options equaled the market price of the underlying stock on the date of grant.  The plans are described more fully in Note 5.  

The following table illustrates the effect on net income if Texas Gas had applied the fair value recognition provisions of SFAS No. 123 to stock-based compensation (expressed in thousands):

The pro forma net income for the 2003 pre-Acquisition period through May 16, 2003, would not be materially different than the amount as reported, reflecting the expiration of outstanding stock options as a result of the Acquisition.

Pro forma amounts for 2002 include compensation expense from Williams awards made in 2002 and 2001 and compensation expense from certain Williams awards made in 1999.  

Pro forma amounts for 2001 include compensation expense from Williams awards made in 2001and compensation expense from certain Williams awards made in 1999.  

The effects of applying SFAS 123 pro forma net income to recognition of compensation expense provided for the periods shown above may not be representative of the effects on reported net income for future years.  The fair value of each award was estimated using the Black-Scholes options pricing model.  See Note 5 for the assumptions used in the calculation of fair value.

Cash flows from operating activities

We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities.

Recent Accounting Standards

Effective January 1, 2003, we adopted SFAS No. 132 (revised), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”, which revises employer’s disclosures about pension plans and other postretirement benefit plans.  The revision of SFAS No. 132 was developed to provide the readers of financial statements more information about pension plan assets, obligations, benefit payments, contributions, and net benefit cost.   Additional disclosures have been added to include information describing the types of plan assets, investment strategy, measurement dates, plan obligations, cash flows, and components of net periodic benefit cost recognized during interim periods.  These additional disclosures have been incorporated in Note 5 of these financial statements.

Effective January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" (Statement 143), which addresses accounting and reporting for legal asset retirement obligations associated with the retirement of long-lived assets.  Statement 143 requires entities to record the fair value of a liability for an asset retirement obligation during the period in which the liability is incurred, if a reasonable estimate of fair value can be made.  We have determined that asset retirement obligations exist for certain of our utility assets; however, the fair value of the obligations cannot be determined because the end of the utility system life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligations.

Depreciation rates for utility plant are approved by the FERC.  The approved depreciation rates are comprised of two types; one based on economic service life (capital recovery) and one based on net costs of removal (negative salvage).  Therefore, we accrue estimated net costs of removal of long-lived assets through negative salvage expense.  Accordingly, we have collected a certain amount in rates representing estimated net costs of removal, which do not represent a legal obligation.  We have reclassified these amounts in the accompanying statement of financial position as Provision for asset retirement.  

Reclassifications

Certain reclassifications have been made in the 2002 and 2001 financial statements to conform to the 2003 presentation.

Note 3:  Commitments and Contingencies

Regulatory and Rate Matters and Related Litigation

FERC Order No. 637

On February 9, 2000, the FERC issued a Final Rule, Order No. 637, in which the FERC adopted certain policies that it found necessary to adjust its regulatory model to the needs of the evolving markets, but determined that any fundamental changes to its regulatory policy would be considered after further study and evaluation of the evolving marketplace.  Texas Gas submitted an Order No. 637 compliance filing on August 15, 2000, which contained pro forma tariff sheets designed to comply with certain directives in the order regarding the conduct of daily business transactions.  A technical conference was held on May 24, 2001, to initiate informal discussions with all parties regarding Order No. 637 compliance for Texas Gas.  Texas Gas filed a contested offer settlement on May 14, 2002.  On August 27, 2002, the FERC issued its “Order on Order Nos. 637, 587-G, and 587-L 8; which accepted many of the provisions of the May 14 settlement of required modifications as specified in the body of the August 27, 2002 order.  Ordering paragraph A directed Texas Gas to file actual tariff sheets, including modifications, within thirty days of the issuance of the order, while ordering paragraph B prohibited Texas Gas from placing the tariff sheets into effect before further order of the FERC.  Texas Gas made the required compliance filing on September 30, 2002.  Texas Gas and several other parties requested rehearing and/or clarification of the August 27, 2002, order.  On December 24, 2002, the FERC issued its “Order on Rehearing” which granted rehearing in part and denied rehearing in part and directed Texas Gas to file revised tariff sheets.  Texas Gas made the required compliance filing on January 23, 2003, and one party protested that filing.  In an order dated May 22, 2003, the FERC issued an “Order on Compliance Filings,” in which i t conditionally accepted most of Texas Gas’ proposed tariff sheets, to be effective November 1, 2002, while ordering minor modifications to others.  That order approved Texas Gas’ new Hourly Overrun Transportation Service, but required Texas Gas to further revise its tariff to eliminate restrictions on the segmentation of capacity outside the primary path, to keep detailed records of segmentation transactions for one year, and to restructure its overrun penalty process.  In response to that order, Texas Gas submitted a compliance filing on June 2, 2003, and also sought rehearing and clarification of the order. On July 21, 2003, the FERC issued an “Order Granting Rehearing for Further Consideration,” a tolling order allowing additional time for consideration of the matters in the dockets. The FERC issued an order on October 7, 2003, denying all rehearing requests, granting the request for clarification, and accepting the June 2, 2003 compliance filing, subject to minor modificati ons stated in the order. The October 7 order also granted Texas Gas an extension of time until November 1, 2004, to complete the necessary computer programming to implement the new segmentation rights approved in this proceeding.   In that order, the FERC accepted Texas Gas’s revised tariff sheets, subject to Texas Gas re-filing them for incorporation into its new FERC Gas Tariff, Second Revised Volume No. 1, within thirty days of the order. Texas Gas submitted the required tariff filing on November 6, 2003, and Texas Gas currently awaits the FERC’s final action in this docket. Order No. 637 compliance is not expected to have a material impact on Texas Gas’ financial condition or results of operations.

General Rate Case (Docket No. RP00-260)

On April 28, 2000, Texas Gas filed a general rate case (Docket No. RP00-260,) which became effective November 1, 2000, subject to refund.  Texas Gas proposed in this rate case to implement value-based, term-differentiated seasonal rates for short-term services effective November 1, 2000, as permitted by FERC Order No. 637.  On May 31, 2000, the FERC issued its “Order Accepting and Suspending Tariff Sheets Subject to Refund, Rejecting Other Tariff Sheets, and Establishing Hearing and Settlement Procedures,” and established administrative procedures for the case.  Although the case was set for hearing, the hearing was held in abeyance pending the filing of additional information related to the value-based rate proposal for short-term firm transportation service.  Texas Gas made that supplemental filing on June 30, 2000.  On October 27, 2000, the FERC issued an order on that supplemental filing referring all issues in the case for hearing.  The participants engaged in informal settlement negotiations to attempt to resolve all issues without a formal hearing.  On August 14, 2001, Texas Gas submitted an offer of settlement proposing to dispose of all issues outstanding in the proceedings.  Only one group of participants (Indicated Shippers) protested the settlement.  On September 26, 2001, the Administrative Law Judge severed the Indicated Shippers, and certified the settlement to the FERC as uncontested for the remaining parties.  On March 4, 2002, the FERC issued an order approving the settlement and severing the Indicated Shippers from the settlement provisions.  On June 17, 2002, the FERC issued an order denying the Indicated Shippers’ request for rehearing of the March 4, 2002 order.  The settlement became effective 31 days after that order when no party filed any further requests for rehearing.  Thus, the settlement& #146;s prospective rates went into effect on August 1, 2002, and refunds of approximately $37.5 million were made on September 16, 2002.  Texas Gas had provided an adequate reserve for amounts, including interest, which were refunded to customers.  Additionally, on July 15, 2002, Texas Gas filed an offer of settlement with the Indicated Shippers to resolve all remaining issues in the case.  The FERC issued an order on October 10, 2002, approving the settlement.  No additional refunds were due as a result of the settlement with the Indicated Shippers.  In the third quarter of 2002, as a result of the settlement, Texas Gas recorded additional revenues of $0.3 million and reduced its estimated reserve for rate refunds by an equal amount.  Texas Gas also recorded $10.2 million of revenues and reduced depreciation expense by $5.7 million to implement provisions of the settlement.

FERC Order No. 2004 (Docket No. RM01-10)

On September 27, 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to adopt uniform standards of conduct for transmission providers.  The proposed rule defined transmission providers as interstate natural gas pipelines and public utilities that own, operate, or control electric transmission facilities. The NOPR proposed standards to regulate the conduct of transmission providers with their energy affiliates.  The proposed rule defined energy affiliates broadly to include any transmission provider affiliate that engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades, or administers natural gas or electric energy, or engages in financial transactions relating to the sale or transmission of natural gas or electricity.  The FERC invited interested parties to comment on the NO PR.  On April 25, 2002, the FERC issued its staff analysis of the NOPR and the comments received.  The staff analysis proposed redefining the definition of energy affiliates to exclude affiliated transmission providers.  On May 21, 2002, the FERC held a public conference concerning the NOPR and the FERC invited the submission of additional comments.  On November 25, 2003, the FERC issued its Final Rule in this matter (Order No. 2004,) “Standards of Conduct for Transmission Providers.” The Final Rule utilizes the same standards of conduct language for the interstate natural gas pipelines and public utility transmission providers; adopts the “no conduit rule” for implementing information disclosure prohibitions, which is more flexible than the “automatic imputation rule”; exempts FERC-jurisdictional transmission providers from the definition of Energy Affiliates; prohibits Transmission Providers from sharing employees and information with its Energy Affiliates, including affiliated asset managers, and trading and financial affiliates; prohibits the sharing of employees and information across industries; and requires mandatory training for employees and the designation of a Chief Compliance Officer. Unless exempted for good cause shown, the new standards will require the adoption of new compliance measures by Texas Gas.  As required by the rule, on February 9, 2003, Texas Gas filed with the Commission and posted on its Internet website its plans for compliance with Order No. 2004 stating that it would seek an exemption from the requirements of Order No. 2004 as Texas Gas has no sales function and no energy or marketing affiliates.  Even if Texas Gas is denied an exemption by the Commission this order is expected to have minimal impact.  If not exempted from the rule, Texas Gas must comply with the standard of conduct by June 1, 2004.

FERC Order No. 634-A (Docket No. RM02-14)

On August 1, 2002, the FERC issued a NOPR (Docket No. RM02-14) that proposed restrictions on various types of cash management programs employed by companies in the energy industry.  In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs, the FERC proposal would have precluded public utilities, natural gas companies and oil pipeline companies from participating in such programs, unless the parent company and its FERC-regulated affiliate maintain investment-grade credit ratings and the FERC-regulated affiliate maintains stockholders equity of at least 30 percent of total capitalization.  Texas Gas participated in comments filed in this proceeding on August 28, 2002, by the Interstate Natural Gas Association of America.  On September 25, 2002, the FERC convened a technical conference to discuss issues raised in the comments filed by parties in this proceeding.  The FERC established a “Final Rule” in this proceeding on October 23, 2003. The Final Rule required, among other things, that any natural gas company participating in a cash management program file its management agreements with the FERC. Cash management agreements established prior to the effective date of the Final Rule were required to be filed within ten days of such effective date and subsequent changes filed within ten days of the change. On December 9, 2003, Texas Gas notified the FERC that it does not currently participate in a cash management program, and, therefore, Texas Gas has no cash management agreements to file pursuant to the Final Rule.

FERC Notice of Inquiry (Docket No. PL02-6-000)

On July 17, 2002, the FERC issued a Notice of Inquiry to seek comments on its negotiated rate policies and practices.  The FERC states that it is undertaking a review of the recourse rate as a viable alternative and safeguard against the exercise of market power of interstate gas pipelines, as well as the entire spectrum of issues related to its negotiated rate program.  Texas Gas has negotiated certain rates under the FERC’s existing negotiated rate program, and Texas Gas participated in comments filed by Williams in this proceeding in support of the FERC’s existing negotiated rate program.  On July 25, 2003, the FERC issued an order modifying its negotiated rate policy to eliminate the use of price indices or gas price differentials in negotiated rate agreements and to impose new filing requirements for negotiated rate agreements and non-conforming contracts.  T his order has not had a significant impact on Texas Gas and is pending action of rehearing at the FERC.

Sales and Use Taxes

On June 1, 2003, the Commonwealth of Kentucky placed into effect a law requiring natural gas pipelines to collect sales and use tax on service charges for the distribution, transmission, or transportation of natural gas for use in Kentucky (excluding residential customers).  On July 3, 2003, Texas Gas filed a proposed tariff sheet (Docket No. RP03-544) on which it proposed to amend the General Terms and Conditions of its FERC Gas Tariff to provide for the collection of taxes, levies, or other charges imposed on Texas Gas’ customers for remittance to the respective regulatory agencies or taxing authorities.  The FERC approved the proposed tariff provision in its Director Letter Order, issued July 31, 2003, without reference to any subsequently filed protests. On August 4, 2003, Texas Gas filed to incorporate the approved language into its recently revised tariff.  In response to the August 4 filing, a customer filed a request for rehearing of its original protest in this docket and further requested the FERC to reject or hold in abeyance Texas Gas’ August 4, 2003, filing.  On September 3, 2003, the FERC conditionally accepted the revised tariff sheets, subject to FERC action on the customer’s request for rehearing.  The FERC issued an "Order on Rehearing" on October 28, 2003, in which it denied the customer’s request for rehearing and determined that the collection of sales tax and its remittance to the local state government has no impact on Texas Gas' cost of service or general rates.   On November 26, 2003, the protesting customer filed a Request for Reconsideration, Clarification or Rehearing on its objections to Texas Gas' approved tariff language.  The FERC, on December 24, 2003, issued a tolling order, “Order Granting Rehearing for Further Consideration,” which stated that the FERC antic ipates issuing an order on the merits in this proceeding by March 8, 2004.

Annual Fuel Filings

Texas Gas submits annual filings to the FERC to adjust its Fuel Retention Percentages, thereby allowing any under- or over-collections to be corrected by an adjustment in fuel rates.  On August 30, 2002, Texas Gas submitted its Fuel Tracker Filing (Docket No. RP02-515) reflecting a slight increase in fuel rates for the annual period November 1, 2002, through October 31, 2003, the majority of which is due to under-collections during the then­-most-recent-winter season.  The FERC responded on October 31, 2002, with an order accepting and suspending the tariff sheets, subject to refund.  The FERC also directed Texas Gas to submit detailed information supporting its request for a rate adjustment within 20 days of the order.  Texas Gas filed its response on November 20, 2002, and followed up with supplemental comments and explanations on December 6, 2002.  In its July 1 1, 2003, order, the FERC found that Texas Gas had satisfactorily complied with the conditions in the suspension order and concluded that no technical conference was necessary.  However, one party protested FERC’s position and this order remains subject to refund.   

On August 30, 2003, Texas Gas submitted its Fuel Tracker Filing (Docket No. RP03-588) reflecting a general decrease in fuel rates for the annual period November 1, 2003, through October 31, 2004. Overall, the impact of this filing would result in predominately moderate to significant reductions in fuel rates as compared to those filed in 2002.  On September 10, 2003, a customer amended its prior protest and request for a technical conference to include Texas Gas’ 2003 Fuel Tracker Filing as well. On October 24, 2003, the FERC issued a Letter Order in Docket No. RP03-588, in which it found that Texas Gas had utilized a FERC-approved tracker mechanism, and, accordingly, the FERC permitted the proposed fuel rates to become effective November 1, 2003, subject to refund.  Texas Gas awaits the FERC's ruling on the merits of the customer’s request for rehearing.

FERC Notice of  Rulemaking on Financial Reporting (RM03-8-000)

On February 11, 2004, the FERC adopted new quarterly financial reporting requirements to strengthen their effort to identify and evaluate emerging trends, business conditions and financial issues affecting regulated energy companies.  The first report for the first quarter of 2004 will be required to be submitted on or before July 9, 2004.  After a transition period for 2004 and 2005, the financial reports will be due 60 days after the end of each quarter.  

Environmental and Safety Matters

As of December 31, 2003, Texas Gas had an accrued liability of approximately $1.1 million for estimated costs associated with environmental assessment and remediation, primarily for 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.  Texas Gas 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.

Texas Gas 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 liability discussed above.

We are also subject to the federal Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which added significant provisions to the existing federal CAA.  The Amendments require the Environmental Protection Agency (EPA) to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, and acid rain.  We operate one facility in an area designated as non-attainment for the current ozone standard (one hour standard) and are aware that during 2004 the EPA may designate additional areas as non-attainment based on implementation of the revised ozone standard (eight hour standard).  Additional areas designated as non-attainment under the revised standard may potentially impact our operations.  Emission control modifications of compression equipment located at facilities required to comply with current federal CAA provisions, the Amendm ents, and State Implementation Plans for nitrogen oxide (NOx) reductions are estimated to cost in the range of $6 million to $14 million by 2005 and will be recorded as additions to property, plant and equipment as the facilities are added.  If the EPA designates additional new non-attainment areas which impact our operations, the cost of additions to property, plant and equipment is expected to increase; however, we are unable at this time to estimate with any certainty the cost of additions that may be required.    Additionally, the EPA is expected to promulgate new rules regarding hazardous air pollutants in 2004, which may impose controls in addition to the control described above.  We cannot predict the costs with any certainty at this time resulting from the installation of these controls.  The effective compliance date for the hazardous air pollutants regulations and installation of associated controls is anticipated to be during 2007.

We consider environmental assessment, 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 EPA or other governmental authorities, and other factors.

In January 2003, the U.S. Department of Transportation Office of Pipeline Safety issued a NOPR entitled “Pipeline Integrity Management in High Consequence Areas”.  The proposed rule incorporated the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted in December 2002 and proposed  to require gas pipeline operators to develop integrity management programs for transmission pipelines that could affect high consequence areas in the event of pipeline failure, including a baseline assessment and periodic reassessments to be completed within specified timeframes.  A Final Rule was issued in December 2003.  This Final Rule is a very comprehensive regulation that will greatly affect how pipelines do business in the future.  We cannot at this time predict the exact costs that would be required under the rule.  We a re currently evaluating the rule and plan to develop and follow a written integrity management plan as required by the final rule no later than December 17, 2004.  We anticipate the costs of the baseline assessment to be incurred over the next ten years.  We consider the costs associated with compliance with the proposed rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Legal Proceedings

In the Acquisition purchase agreement, Williams agreed to indemnify us for any liabilities or obligations in connection with certain litigation or potential litigation including, among others, these previously disclosed matters:

•

   Litigation filed by Jack Grynberg alleging that approximately 300 energy companies, including Texas Gas, had violated the False Claims Act in connection with the measurement, royalty valuation, and purchase of hydrocarbons;

•

A nationwide class action lawsuit against pipeline and gathering companies, including Texas Gas, for alleged mismeasurement techniques resulting in the underpayment of royalties; and

•

A claim by certain parties for back rental associated with their alleged ownership of a partial mineral interest in a tract of land in a gas storage field owned by Texas Gas.  In December 2003, a lawsuit was filed against Texas Gas in Muhlenberg County, Kentucky seeking unspecified damages related to this claim.

As a result, Williams is defending these actions on behalf of Texas Gas.  Because Williams has retained responsibility for these claims, they are not likely to have a material affect upon our future financial condition or results of operations.

We are party to other on-going litigation as a normal part of our business that, in management’s opinion, is not likely to have a material impact on our financial condition or results of operations.

Summary of Commitments and Contingencies

While no assurances may be given, we do 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 our future financial position, results of operations or cash flow requirements.

Other Commitments

Commitments for Construction

Texas Gas has commitments for construction and acquisition of property, plant and equipment of approximately $8.4 million at December 31, 2003.

Note 4:  Financing

At December 31, 2003 and 2002, long-term debt issues were outstanding as follows (expressed in thousands):

Our debentures and notes have restrictive covenants which provide that, with certain exceptions, neither TGT Pipeline nor Texas Gas 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.  TGT Pipeline relies on distributions and advances from Texas Gas to fulfill its debt obligations.  All our obligations are unsecured.

On May 16, 2003, Texas Gas borrowed $275 million (Interim Loan) at 2.6% per annum and advanced the proceeds to TGT Pipeline under an interest bearing promissory note. On May 28, 2003, Texas Gas completed an offering of $250 million principal amount of notes issued at a discount, and TGT Pipeline completed a concurrent offering of $185 million principal amount of its notes issued at a discount, each in an offering exempt from registration under Rule 144A and Regulation S.  The notes issued by Texas Gas bear interest at a rate of 4.60% per annum and mature in 2015 with an effective rate of 4.77%. The notes issued by TGT Pipeline bear interest at a rate of 5.20% per annum and mature in 2018 with an effective rate of 5.39%.  These notes are collectively referred to as the “New Notes.”

We used approximately $275 million of the proceeds from the sale of the New Notes to repay the Interim Loan.  Texas Gas used additional proceeds from the sale of the New Notes to prepay $132.7 million principal amount of its outstanding $150 million in aggregate principal amount of 8.625% notes due April 2004 (Old Notes), plus accrued interest and premium, and intends to use the balance of such proceeds plus other available funds to repay the remaining Old Notes.

As required by the registration rights agreement entered into with the initial purchasers of the New Notes, on October 27, 2003, we consummated an exchange of the New Notes for substantially identical notes, the issuance of which was registered under the Securities Act of 1933.

Note 5:  Employee Benefits

Retirement Plan

Substantially all of Texas Gas’ employees are covered under a non-contributory, defined benefit retirement plan (Retirement Plan) offered by Texas Gas.  Texas Gas’ general funding policy is to contribute amounts deductible for federal income tax purposes.  Due to its fully funded status, Texas Gas has not been required to fund the Retirement Plan since 1986.  

As a result of the Acquisition, Texas Gas recognized $24.9 million of previously unrecognized market losses and prior service costs reducing our prepaid pension asset and corresponding regulatory liability.   To the extent our pension plan is overfunded, Texas Gas is required to record an offsetting regulatory liability since our ratepayers would be the beneficiaries of any overfunded pension assets if the pension plan were ever terminated.  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 Balance Sheet at December 31 of each year indicated (expressed in thousands).

Amounts recognized in the statement of financial position consist of:

Net pension benefit expense consists of the following:

Texas Gas’ pension plan weighted-average asset allocations at December 31, 2003 and 2002, by asset category are as follows:

Weighted-average assumptions used to determine benefit obligations for the periods indicated:

Weighted-average assumptions used to determine net periodic benefit cost for the periods indicated:

Other than Supplemental Retirement Plan (SERP) costs, Texas Gas recognizes expense concurrent with the recovery in rates.  Since Texas Gas’ Retirement Plan is fully funded, Texas Gas is not currently recovering any amounts through rates and does not anticipate contributing to the pension plan during 2004.  SERP expenses recognized by Texas Gas were:  $0.1 million post-acquisition 2003, $1.2 million pre-acquisition 2003, $1.1 million in 2002, and $0.5 million in 2001.  

Postretirement Benefits Other than Pensions

Prior to the Acquisition, Texas Gas’ Postretirement Benefits Other than Pensions was part of a multi-employer plan under Williams; however, for regulatory purposes Texas Gas’ liabilities and plan assets were accounted for separately.  After the Acquisition, Texas Gas’ Postretirement Benefits Other than Pension was segregated from Williams and is no longer considered a multi-employer plan.

We provide a health care plan which accords postretirement medical benefits to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. We made contributions to this plan in the amount of $2.7 million during the pre-Acquisition period in 2003, $5.4 million in 2002 and $5.2 million in 2001.  Texas Gas’ latest settled rate case with the FERC (Docket No. RP00-260) allows recovery of $5.3 million annually, including amortization of previously deferred postretirement benefit costs and as such, Texas Gas anticipates contributing $5.3 million to its other postretirement benefit plan during 2004. Net postretirement benefit expense related to Texas Gas’ participation in the Williams’ plan is $2.6 million for the 2003 pre-Acquistion period, $5.3 for 2002, and  $5.1 million for 2001, including $2.0 million, $3.6 milli on and $6.1 million of amortization of a regulatory asset, respectively.  The regulatory asset represents unrecovered costs from prior years, including the unamortized transition obligation under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which was recognized at the date of the Williams acquisition in 1995. The regulatory asset balance as of  May 16, 2003 and December 31, 2002 was $35.7 million and $28.6 million, respectively.  This asset is being amortized concurrently with the recovery of these costs through rates.   

The recently enacted Medicare Prescription Drug, Improvement and Modernizaton Act of 2003 (the Medicare Act) provides a prescription drug benefit as well as a federal subsidy to sponsors of certain retiree health care benefit plans.  As allowed by FASB Staff Position No. 106-1, Texas Gas has elected to defer reflecting the effects of the Medicare Act on the accumulated benefit obligation and net periodic postretirement benefit cost in these financial statements and accompanying notes.  Texas Gas’ deferral election expires upon the occurrence of any event  that triggers a required remeasurement of plan assets or obligations, or upon the issuance of specific authoritative guidance on the accounting for the federal subsidy.  Such guidance is pending and when issued could require Texas Gas to adjust previously reported information.

As a result of the Acquisition, Texas Gas recognized $7.7 million of previously unrecognized market losses and prior service costs.  This amount was recorded as a regulatory asset for recovery through rates.  

Postretirement Benefits Other than Pensions since the date of Acquisition is as follows:

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans.  A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Stock-Based Compensation

Subsequent to the Acquisition, we had no stock-based compensation.  Prior to the Acquisition, Williams had several plans providing for common-stock-based awards to its employees and employees of its subsidiaries.  The plans permitted the granting of various types of awards including, but not limited to, stock options, stock appreciation rights, restricted stock and deferred stock.  Awards may have been granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.  The purchase price per share for stock options and the grant price for stock appreciation rights could not be less than the market price of the underlying stock on the date of grant.  Stock options generally became exercisable in one-third increments each year from the anniversary of the grant or after three or five years, subject to accele rated vesting if certain future stock prices or if specific financial performance targets were achieved.  Due to the Acquisition, all Williams' stock options outstanding at December 31, 2002, issued to Texas Gas employees expired on November 17, 2003, six months after the Acquisition.

A summary of stock options previously granted to employees of Texas Gas under the plans is shown in the following table (options in thousands):

The estimated fair value at date of grant of stock options granted to employees of Texas Gas in 2002 and 2001, using the Black-Scholes option-pricing model, is as follows:

Other

We maintain various defined contribution plans covering substantially all employees.  Our costs related to these plans were $1.0 million in 2003 pre-Acquisition, $1.6 million post-Acquisition, $4.4 million in 2002 and $3.2 million in 2001.

Note 6:  Income Tax

Following is a summary of the provision for income taxes and charge-in-lieu of income taxes for the years ended December 31, 2003, 2002, and 2001 (expressed in thousands):

 Reconciliations from the (charge-in-lieu of) income tax provision at the statutory rate to our income tax provisions are as follows (expressed in thousands):

Significant components of deferred income tax liabilities and assets as of December 31, 2003 and 2002, are as follows (expressed in thousands):

As set forth above, the accompanying financial statements reflect a net deferred tax asset resulting from the tax basis allocation and the 338(h)(10) election.  Based on our estimates of future taxable income, we believe that no valuation reserve is required.  TGT Pipeline and Texas Gas also have estimated net operating loss carryforwards of $7.5 million and $4.3 million, respectively at December 31, 2003.  We anticipate the utilization of these carryforwards and have provided for the benefit in the financial statements.

Note 7:  Financial Instruments

The following methods and assumptions were used in estimating our fair-value disclosures for financial instruments:

Cash and Short-Term Financial Assets: For cash and short-term financial assets, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.  

Advances to Affiliates:  As discussed in Note 8, advances to affiliates, which are represented by demand notes, earn a variable rate of interest, which is adjusted regularly to reflect current market conditions.

Long-Term Debt:  All of our long-term debt is publicly traded; therefore, estimated fair value is based on quoted market prices at December 31, 2003 and 2002.

The carrying amount and estimated fair values of our financial instruments as of December 31, 2003 and 2002, are as follows (expressed in thousands):

Texas Gas makes advances to TGT Pipeline.  At December 31, 2003, the advances due Texas Gas by TGT Pipeline totaled $116.5 million.  The advances are represented by demand notes.  The interest rate on intercompany demand notes is the London Interbank Offered Rate on the first day of each three-month period plus one percent and is compounded monthly.

TGT Pipeline makes advances to Holding Corp. At December 31, 2003, the advances due TGT Pipeline by Holding Corp. totaled $4.3 million.  The advances are represented by demand notes.  The interest rate on intercompany demand notes is the London Interbank Offered Rate on the first day of each three-month period plus one percent and is compounded monthly.

Prior to the Acquisition, Texas Gas participated in Williams’ cash management program, Texas Gas made advances to and received advances from Williams through Texas Gas’ parent company, a Williams’ affiliate.  At December 31, 2002, the advances due Texas Gas by a Williams’ affiliate totaled $63.1 million.  The advances were represented by demand notes and were paid as a dividend to Williams as part of the Acquisition costs.   

Sale of Receivables

Through July 2002, Texas Gas, through a wholly-owned bankruptcy remote subsidiary, sold certain trade accounts receivable to a special-purpose entity in a securitization structure requiring annual renewal.  Texas Gas acted as the servicing agent for the sold receivables.  The sale of receivables program expired on July 25, 2002, and by the end of August 2002, Texas Gas completed the repurchase of approximately $10 million of trade accounts previously sold.  The sales of these receivables resulted in a charge to results of operations of approximately $0.2 million in 2002 and $1.3 million in 2001.

Note 8:  Transactions with Major Customers and Affiliates

Major Customers

Operating revenues received from the two major customers of Texas Gas (expressed in millions) and their percentage of revenues were:

Related Parties

In addition to advances to affiliates discussed above, Loews has a policy of charging subsidiary companies for management services provided by the parent company. During 2003, we were charged $3.3 million by Loews for management services provided after the Acquisition.   Williams also had 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 by Williams were $5.4 million prior to the Acquisition in 2003, $12.2 million in 2002 and $11.0 million in 2001.

Prior to its Acquisition by a subsidiary of Loews, Texas Gas had contracted with a gas marketing affiliate to be Texas Gas’ agent for the purpose of administering all existing and future gas sales and market-responsive purchase obligations.  Sales and purchases under this agreement did not impact Texas Gas’ operating income.  All such gas purchase contracts expired or were terminated prior to the Acquisition.  Texas Gas no longer has a marketing affiliate and it has made no unbundled sales of natural gas since the Acquisition.  We had no income from gas marketing affiliates in 2003.  Revenues applicable to gas sales to our gas marketing affiliates in Texas Gas’ other revenues for the years ended December 31, 2002 and 2001, were  $0.3 million, and $1.7 million, respectively.  On February 6, 2004, Texas Gas filed with the FERC to cancel the rate schedule that authorized it to make unbundled sales of natural gas.

Amounts applicable to transportation for affiliates included in Texas Gas’ gas transportation revenues for the period prior to the Acquisition in 2003, and for the years ended December 31, 2002 and 2001, are as follows (expressed in thousands):

Note 9:  Selected quarterly financial data (unaudited)

Our operating income may vary by quarter.  Based on the current rate structure, Texas Gas experiences higher income in the first and fourth quarters as compared to the second and third quarters.  The following tables summarize selected quarterly financial data for 2003 and 2002 for Texas Gas (expressed in thousands):