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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

Registrant’s telephone number, including area code (713) 215-2000

None
(Former name, former address and former fiscal year, if changed since last report)

     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 o

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes o No x

     The number of shares of Common Stock, par value $1.00 per share, outstanding as of June 30, 2003 was 100.

REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX

Certain matters discussed in this report, excluding historical information, include forward-looking statements. Although Transco believes such forward-looking statements are based on reasonable assumptions, no assurance can be given that every objective will be achieved. Such statements are made in reliance on the “safe harbor” protections provided under the Private Securities Litigation Reform Act of 1995. Additional information about issues that could lead to material changes in performance is contained in Transco’s 2002 Annual Report on Form 10-K and 2003 First Quarter Report on Form 10-Q.

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

     Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

     The condensed consolidated financial statements include the accounts of Transco and its majority-owned subsidiaries. Companies in which Transco and its subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method.

     The condensed consolidated financial statements have been prepared from the books and records of Transco. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. The condensed unaudited consolidated financial statements include all adjustments both normal recurring and others which, in the opinion of Transco’s management, are necessary to present fairly its financial position at June 30, 2003, and results of operations for the three and six months ended June 30, 2003 and 2002 and cash flows for the six months ended June 30, 2003 and 2002. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in Transco’s 2002 Annual Report on Form 10-K and 2003 First Quarter Report on Form 10-Q.

     Through an agency agreement, Williams Energy Marketing & Trading Company (WEM&T), an affiliate of Transco, manages all jurisdictional merchant gas sales of Transco, receives all margins associated with such business and, as Transco’s agent, assumes all market and credit risk associated with Transco’s jurisdictional merchant gas sales. Consequently, Transco’s merchant gas sales service has no impact on its operating income or results of operations. For a discussion of a settlement with the Federal Energy Regulatory Commission (FERC) affecting Transco’s jurisdictional merchant gas sales, see “Note 2. Contingent Liabilities and Commitments.”

     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 amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; and 4) impairment assessments of long-lived assets.

     Transco’s Board of Directors declared cash dividends on common stock in the amounts of $85 million on March 31, 2003 and $70 million on June 30, 2003.

     Comprehensive income for the three and six months ended June 30, 2003 and 2002 respectively, are as follows (in thousands):

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     Change in accounting policy Effective January 1, 2003, Williams and its subsidiaries, including Transco, adopted Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” The statement requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the associated asset retirement costs be capitalized as part of the carrying amount of the long-lived asset. As required by the new rules, Transco recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. The obligations relate to offshore transmission platforms. At the end of the useful life of each respective asset, Transco is legally obligated to dismantle offshore transmission platforms. The liabilities are partially offset by increases in net assets, net of accumulated depreciation, recorded as if the provisions of the statement had been in effect at the date the obligation was incurred. As a result of the adoption of SFAS No. 143, Transco recorded a long-term liability of $10.8 million and property, plant and equipment, net of accumulated depreciation, of $1.1 million. Transco also recorded a $9.7 million regulatory asset for the cumulative effect of adopting SFAS No. 143, which is expected to be recovered through regulated rates. Transco has not recorded liabilities for pipeline transmission assets and gas gathering systems. A reasonable estimate of the fair value of the retirement obligations for these assets cannot be made as the remaining life of these assets is not currently determinable. Had the statement been adopted at the beginning of 2002, the impact to Transco’s operating income and net income would have been immaterial.

     Recent accounting standards Effective July 1, 2003, Williams and its subsidiaries, including Transco, adopted Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities.” The Interpretation defines a variable interest entity (VIE) as an entity in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. The investments or other interests that will absorb portions of the VIE’s expected losses if they occur or receive portions of the VIE’s expected residual returns if they occur are called variable interests. Variable interests may include, but are not limited to, equity interests, debt instruments, beneficial interests, derivative instruments and guarantees. The Interpretation requires an entity to consolidate a VIE if that entity will absorb a majority of the VIE’s expected losses if they occur, receive a majority of the VIE’s expected residual returns if they occur, or both. If no party will absorb a majority of the expected losses or expected residual returns, no party will consolidate the VIE. The Interpretation also requires disclosure of significant variable interests in unconsolidated VIE’s. The Interpretation is effective for all new VIE’s created or acquired after January 31, 2003. For VIE’s created or acquired prior to February 1, 2003, the provisions of the Interpretation must be applied for the first interim or annual period beginning after June 15, 2003. Transco does not have any VIE’s as defined by the Interpretation.

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

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2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate and Regulatory Matters

     FERC settlement On December 11, 2002, the FERC staff informed Transco of a number of issues the FERC staff identified during the course of a formal, nonpublic investigation into the relationship between Transco and its marketing affiliate, WEM&T. The FERC staff asserted that WEM&T personnel had access to Transco data bases and other information, and that Transco had failed to accurately post certain information on its electronic bulletin board. Williams, Transco and WEM&T did not agree with all of the FERC staff’s allegations and furthermore believe that WEM&T did not profit from the alleged activities. Nevertheless, in order to avoid protracted litigation, on March 13, 2003, Williams, Transco and WEM&T executed a settlement of this matter with the FERC staff. An order approving the settlement was issued by the FERC on March 17, 2003. No requests for rehearing of the March 17, 2003 order were filed; therefore, the order became final on April 16, 2003. Pursuant to the terms of the settlement agreement, Transco will pay a civil penalty in the amount of $20 million, beginning with a payment of $4 million within thirty (30) days of the date the FERC order approving the settlement became final. The first payment was made on May 16, 2003, and the subsequent $4 million payments are due on or before the first, second, third and fourth anniversaries of the first payment. Transco recorded a charge to income and established a liability of $17 million in the fourth quarter of 2002 on a discounted basis to reflect the future payments to be made over the next four years. In addition, Transco has provided notice to its merchant sales service customers that it will be terminating such services when it is able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Most of these sales are made through a Firm Sales (FS) program, and under this program Transco must provide two-year advance notice of termination. Therefore, Transco notified the FS customers of its intention to terminate the FS service effective April 1, 2005. Through an agency agreement, WEM&T receives all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assumes all market and credit risk associated with Transco’s jurisdictional merchant gas sales. Consequently, Transco’s merchant gas sales service has no impact on Transco’s operating income or results of operations and, therefore, the anticipated termination of such service, pursuant to the terms of the FERC settlement discussed above, will have no impact on Transco’s operating income or results of operations. As part of the settlement, WEM&T has agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. Finally, Transco and certain affiliates have agreed to the terms of a compliance plan designed to ensure future compliance with the provisions of the settlement agreement and the FERC’s rules governing the relationship of Transco and WEM&T.

     General rate case (Docket No. RP01-245) On March 1, 2001, Transco submitted to the FERC a general rate filing principally designed to recover costs associated with an increase in rate base resulting from additional plant, an increase in rate of return and related taxes, and an increase in operation and maintenance expenses. The filing reflected an annual cost of service increase of approximately $227 million over the cost of service underlying the rates reflected in the settlement of Transco’s Docket No. RP97-71 rate proceeding, as subsequently adjusted pursuant to the terms of that settlement and FERC orders resolving issues reserved by the settlement for FERC decision. The filing also reflected certain changes to Transco’s tariff, cost allocation and rate design methods, including, among other things, the roll-in of Transco’s Mobile Bay expansion project, and a pro forma proposal to roll-in the costs of Transco’s SunBelt, Pocono and Cherokee expansion projects.

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     On March 28, 2001, the FERC issued an order accepting and suspending Transco’s March 1, 2001 general rate filing to be effective September 1, 2001, subject to refund and the outcome of a hearing.

     On April 12, 2002, Transco filed a Stipulation and Agreement (Settlement) for approval by the FERC, which resolves all cost of service, throughput and throughput mix issues, with the exception of one cost of service issue related to the valuation of certain right-of-way access for the installation of a fiber optic system by a then Transco affiliate, the resolution of which is to be applied prospectively. Issues not resolved by the Settlement are reserved for litigation or further settlement. Such issues include various cost allocation, rate design and tariff matters, and the cost of service issue described above. Pursuant to the terms of the Settlement, the resolution of those issues will be made effective prospectively, with the exception of the issue of whether the costs of Transco’s Mobile Bay expansion project should be rolled into Transco’s system rates or recovered from the Mobile Bay expansion shipper on an incremental basis. The parties have reserved the right to argue whether the resolution of the Mobile Bay issue should be made effective either prospectively or retroactive to September 1, 2001. Transco’s rates effective September 1, 2001 are based on the roll-in of the costs of the Mobile Bay expansion project. On July 23, 2002, the FERC issued an order approving the Settlement as in the public interest, and the Settlement became effective on October 1, 2002. In the third quarter of 2002, as a result of the FERC’s approval of the Settlement, Transco recorded additional revenues of $28 million, reduced depreciation expense by $3 million, reversed interest expense of $0.5 million, and reduced its estimated reserve for rate refunds by $24.5 million. Rate refunds required under the Settlement totaling approximately $140 million, including interest, were paid in late November 2002. Transco previously provided a reserve for the refunds.

     On December 3, 2002, an Administrative Law Judge (ALJ) issued his initial decision on the issues not resolved by the Settlement. In the initial decision, the ALJ determined that (1) no change to Transco’s tariff right of first refusal provisions is required, (2) Transco should not be required to convert certain of its Part 157 bundled storage services to Part 284 services, (3) Transco must modify certain of its tariff scheduling procedures for shippers taking released capacity, (4) Transco’s existing Rate Schedule GSS bundled storage service is just and reasonable, (5) Transco’s recovery of the costs of its Mobile Bay expansion project on a rolled-in basis is unjust and unreasonable, (6) Transco’s proposal to roll-in the costs of its Cherokee, Pocono and SunBelt projects is unjust and unreasonable, (7) Transco must modify its tariff to establish incremental fuel and electric power charges for its Mobile Bay expansion, Cherokee and SouthCoast projects, (8) Transco’s current allocation of storage costs to its transportation services is just and reasonable subject to Transco including a portion of its Rate Schedule LNG storage costs in that allocation, (9) Transco must unbundle its Emergency Eminence Storage withdrawal service, (10) Transco’s pooling point in its Rate Zone 4 is unjust and unreasonable and Transco must adopt a “paper” pooling method for that zone, (11) Transco must revise its method for the allocation of operation and maintenance and administrative and general costs to incremental projects, (12) Transco must revise its method for the allocation of administrative and general costs to LNG services and (13) Transco’s existing treatment of the arrangement with its former affiliate relating to right of way is just and reasonable. As stated above, pursuant to the terms of the Settlement, the resolution of all of those issues are effective prospectively, with the exception of the issue of the roll-in of the costs of Transco’s Mobile Bay expansion project, the resolution of which the parties have reserved the right to argue should be made effective either prospectively or retroactive to September 1, 2001. As to that issue, the ALJ determined that Transco has the burden of establishing that roll-in of that project is just and reasonable, but did not address the issue of any potential refunds. Transco’s rates effective September 1, 2001 are based on the roll-in of the Mobile Bay expansion project. The ALJ’s initial decision is subject to review by the FERC.

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     General rate case (Docket No. RP97-71) On November 1, 1996, Transco submitted to the FERC a general rate case filing principally designed to recover costs associated with increased capital expenditures. These increased capital expenditures primarily relate to system reliability, integrity and Clean Air Act compliance.

     When stated on a comparable basis, the rates Transco placed into effect on May 1, 1997, subject to refund, represented an annual cost of service increase of approximately $47 million over the cost of service underlying the rates contained in the settlement of Transco’s last general rate filing (Docket No. RP95-197).

     The filing also included (1) a pro-forma proposal to roll-in the costs of Transco’s Leidy Line and Southern expansion incremental projects and (2) a pro-forma proposal to make interruptible transportation (IT) backhaul rates equal to the IT forward haul rates.

     On November 29, 1996, the FERC issued an order accepting Transco’s filing, suspending its effectiveness until May 2, 1997 (subsequently revised, on rehearing, to May 1, 1997) and establishing a hearing to examine the reasonableness of Transco’s proposed rates. In addition, the order consolidated Transco’s pro forma roll-in proposal with the Phase II hearing in Docket No. RP95-197. With the exception of the roll-in issue consolidated with Docket No. RP95-197, which is discussed below, and one issue remanded to the FERC by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) relating to the rate paid by a shipper under its firm transportation contract, all issues in this proceeding have been resolved through settlement or litigation. As to the issue remanded to the FERC by the D.C. Circuit, on April 14, 2003, the shipper filed a motion with the FERC requesting expedited action on the remanded issue. The shipper requests that the FERC reinstate its discounted transportation rate under the firm transportation contract effective on June 1, 2003 or as soon as possible thereafter, that Transco be directed to make refunds of amounts collected from the shipper in excess of the discounted rate since February 1, 2001, with interest, and that Transco be authorized to make billing adjustments to recover the cost of the refunds from Transco’s other shippers. The shipper’s request is pending before the FERC.

     General rate case (Docket No. RP95-197) On March 1, 1995, Transco filed with the FERC a general rate case that proposed changes in the rates for Transco’s transportation, sales and storage service rate schedules effective April 1, 1995. On March 31, 1995, the FERC issued an order on Transco’s filing, which accepted and suspended the tariff sheets relating to Transco’s rates, to be effective September 1, 1995, subject to refund, and established hearing procedures. Through settlement and litigation, all issues in this proceeding have been resolved, except certain cost allocation and rate design issues discussed below.

     A hearing concerning the cost allocation and rate design issues not resolved by settlement concluded in November 1996. A supplemental hearing to consider Transco’s roll-in proposal filed in Docket No. RP97-71 was completed in June 1997. On March 24, 1998, the ALJ issued an initial decision on all of these issues. As to the main issue addressed in the decision, rolled-in pricing, the ALJ determined that Transco’s existing incremental rate treatment must remain in effect. On April 16, 1999, the FERC issued an order reversing the ALJ, concluding that Transco had demonstrated that its proposed rolled-in rate treatment was just and reasonable. As a result, the FERC remanded to the ALJ issues regarding the implementation of Transco’s roll-in proposal. Several parties filed requests for rehearing of the FERC’s April 16, 1999 order, and on March 28, 2001, the FERC issued an order denying those requests for rehearing. On April 27, 2001, several parties filed a request for rehearing of the March 28, 2001 order, and on June 13, 2001, the FERC denied that request for rehearing. On August 10, 2001, several parties filed a petition for review in the D.C. Circuit Court of the FERC’s April 16, 1999, March 28, 2001 and June 13, 2001 orders, and on January 17, 2003, the D.C. Circuit Court entered its judgment denying that petition for review. On March 3, 2003, the parties

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filed a petition for rehearing en banc (by all of the judges on the court) of the D.C. Circuit Court’s judgment denying their petition for review, and on March 18, 2003, the D.C. Circuit Court denied that petition for rehearing.

     On April 4, 2000, the ALJ issued an initial decision on the remanded issues relating to the implementation of Transco’s roll-in proposal. The ALJ ruled in favor of Transco’s positions, with the exception of one of Transco’s proposed cost allocation changes and a requirement that the roll-in of the costs of the incremental projects into Transco’s system rates be phased in over a three-year period. On October 12, 2001 the FERC issued an order on the ALJ’s April 4, 2000 initial decision which generally upholds the decision, with the exception of the ALJ’s approval of a change in the allocation of costs to a Transco storage service and the ALJ’s decision to phase the roll-in of the costs of the incremental projects into Transco’s system rates. The FERC determined that Transco must retain its existing method of allocating costs to the storage service, and that it is not necessary to phase the roll-in of the costs. On November 13, 2001, Transco and certain other parties each filed requests for rehearing of the FERC’s October 12, 2001 order. On April 1, 2002, the FERC issued an order denying the requests for rehearing of the FERC’s October 12, 2001 order. On August 30, 2002, Transco filed to implement, among other things, the FERC’s decision on the roll-in of the costs of the incremental Leidy Line and Southern expansion projects. On September 30, 2002, the FERC issued an order that, as to roll-in, accepts Transco’s filing, subject to refund, a compliance filing and certain conditions, to be effective October 1, 2002. On December 12, 2002, the FERC issued an order accepting Transco’s compliance filing effective October 1, 2002. On January 13, 2003, certain parties filed for rehearing of the FERC’s December 12, 2002 order, arguing that Transco improperly reallocated certain storage costs in implementing the roll-in.

     Production area rate design (Docket Nos. RP92-137 and RP93-136) Transco has expressed to the FERC concerns that inconsistent treatment under Order 636 of Transco and its competitor pipelines with regard to rate design and cost allocation issues in the production area may result in rates which could make Transco less competitive, both in terms of production-area and long-haul transportation. A hearing before an ALJ (Docket Nos. RP92-137 and RP93-136), dealing with, among other things, Transco’s production-area rate design, concluded in June 1994. On July 19, 1995, the ALJ issued an initial decision finding that Transco’s proposed production area rate design, and its existing use of a system wide cost of service and allocation of firm capacity in the production area are unjust and unreasonable. The ALJ therefore recommended that Transco divide its costs between its production area and market area, and permit its customers to renominate their firm entitlements.

     On July 3, 1996, the FERC issued an order on review of the ALJ’s initial decision concerning, among other things, Transco’s production area rate design. The FERC rejected the ALJ’s recommendations that Transco divide its costs between its production area and market area, and permit its customers to renominate their firm entitlements. The FERC also concluded that Transco may offer firm service on its supply laterals through an open season and eliminate its IT feeder service in favor of an interruptible service option that does not afford shippers feeding firm transportation on Transco’s production area mainline a priority over other interruptible transportation. On December 18, 1996, the FERC denied rehearing of its July 3, 1996 Order. Several parties, including Transco, filed petitions for review in the D.C. Circuit Court of the FERC’s orders addressing production area rate design issues. Transco subsequently withdrew its appeal. On March 24, 2000, the D.C. Circuit Court issued its opinion in the remaining appeal. The court determined that the FERC failed to adequately explain its decision to reject Transco’s production area rate design proposal for its supply laterals, and remanded the case back to the FERC for further action. In response to an order issued by the FERC on July 31, 2000, the parties submitted briefs on the issues in order to assist the FERC in determining how best to proceed in this case. On May 31, 2001, the FERC issued its order on remand,

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addressing the issues briefed by the parties. The FERC held that Transco’s “firm-to-the-wellhead” proposal would abrogate shipper contracts in a manner not authorized by those contracts, and therefore rejected the proposal. As a result, Transco’s current production area rate design and service structure remains in effect. Transco and other parties each filed a request for rehearing of the FERC’s order, and on July 27, 2001, the FERC denied those requests. Several parties, including Transco, filed petitions for review in the D.C. Circuit Court of the FERC’s May 31 and July 27, 2001 orders. On January 17, 2003, the D.C. Circuit Court entered its judgment on the petitions for review and remanded the case back to the FERC for further action, finding that the FERC had failed to adequately support its findings in rejecting Transco’s “firm-to-the-wellhead” proposal. On July 30, 2003, the FERC issued an order on remand in response to the D.C. Circuit Court’s January 17, 2003 judgment, and reaffirmed its prior rejection of Transco’s “firm-to-the-wellhead” proposal.

     Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000) In February 1996, Transco filed an application with the FERC for an order authorizing the abandonment of certain facilities located onshore and offshore in Texas, Louisiana and Mississippi by conveyance to Williams Gas Processing – Gulf Coast Company (Gas Processing), an affiliate of Transco. The net book value recorded by Transco at June 30, 2003 of the facilities was approximately $375 million. Concurrently, Gas Processing filed a petition for declaratory order requesting a determination that its gathering services and rates be exempt from FERC regulation under the NGA. On September 25, 1996, the FERC issued an order dismissing Transco’s application and Gas Processing’s petition for declaratory order. On October 25, 1996, Transco and Gas Processing filed a joint request for rehearing of the FERC’s September 25 order, and in August 1997, filed a request that rehearing be expedited. On June 14, 2001, the FERC issued an order that denied the request for rehearing filed by Transco and Gas Processing. Certain parties, including Transco, filed petitions for review of the FERC’s orders in the D.C. Circuit Court. On June 20, 2003, the D.C. Circuit Court issued its opinion denying the petitions for review of the FERC’s orders, including Transco’s, and finding that the FERC’s determinations regarding the gathering status of the facilities under the NGA were reasonable. On August 4, 2003, Transco and Gas Processing filed a joint petition for rehearing and suggestion for rehearing en banc of the D.C. Circuit Court’s June 20, 2003 opinion.

     In addition, Transco has pending with the FERC the four applications described below seeking authorization to abandon portions of the facilities included in the February 1996 application.

     North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and CP01-34) In November 2000, Transco filed an application with the FERC seeking authorization to abandon certain of Transco’s offshore Texas facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. On July 25, 2001, the FERC approved the abandonment and the non-jurisdictional treatment of all the facilities requested in the applications of Transco and Gas Processing. Effective December 1, 2001, a portion of the applicable facilities was spun down by Transco through a non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that date. At June 30, 2003, the net book value of the facilities remaining to be spun down in this proceeding was approximately $69 million including the Williams purchase price allocation pushed down to Transco. The transfer of these facilities will not have a material impact on Transco’s results of operations and financial position. Parties have filed petitions for review of the FERC’s July 25, 2001 order to the D.C. Circuit Court which were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and which were denied by the D.C. Circuit Court in its opinion issued on June 20, 2003. On November 30, 2001, Shell Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services Company (WFS) and Transco alleging concerted actions by these affiliates frustrating the FERC’s regulation of Transco. The alleged actions are related to offers of

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gathering service by WFS and its subsidiaries with respect to the North Padre Island facilities. By order of the FERC, the matter was heard before an ALJ in April 2002. On June 4, 2002, the ALJ issued an initial decision finding that the affiliates acted in concert to frustrate the FERC’s regulation of Transco and recommending that the FERC reassert jurisdiction over the North Padre Island gathering system. Transco, Gas Processing and WFS believe their actions were reasonable and lawful and submitted briefs taking exceptions to the initial decision. On September 5, 2002, the FERC issued an order reasserting jurisdiction over that portion of the North Padre Island facilities previously transferred to WFS. The FERC also determined an unbundled gathering rate for service on these facilities, which is to be collected by Transco. Transco, Gas Processing and WFS each sought rehearing of the FERC’s order, and on May 15, 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and WFS have filed petitions for review of the FERC’s orders with the D.C. Circuit Court, and have filed a joint motion to consolidate their appeals. With regard to the approval of the spin-down of the Central Texas facilities, a Transco customer filed a complaint with the FERC in Docket No. RP02-309 seeking the revocation of the FERC’s spin-down approval. On September 5, 2002, the FERC issued an order requiring that, upon transfer of the Central Texas facilities, Transco acquire capacity on the transferred facilities and provide service to the existing customer under the original terms and conditions of service. Transco sought rehearing of the FERC’s September 5, 2002 order, and on May 15, 2003, the FERC issued an order denying Transco’s request for rehearing and clarifying the September 5, 2002 order. The FERC also required that Transco notify the FERC of Transco’s plans with regard to the transfer of the Central Texas facilities to Gas Processing. Transco filed a notification on June 16, 2003, stating that due to the numerous outstanding issues affecting the transfer of those facilities, Transco could not at that time predict the timing for the implementation of the transfer of the Central Texas facilities. Transco also filed a request for rehearing of the FERC’s May 15, 2003 order, and has filed a petition for review of the FERC’s orders with the D.C. Circuit Court. The transfer of these facilities has not been implemented.

     North High Island/West Cameron Systems Spin-down Proceeding (Docket Nos. CP01-103 and CP01-104) In March 2001, Transco filed an application with the FERC seeking authorization to abandon certain of Transco’s offshore Texas and offshore and onshore Louisiana facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. On July 25, 2001, the FERC approved the abandonment and the non-jurisdictional treatment of a portion of the facilities requested in the applications of Transco and Gas Processing. On August 24, 2001, Transco and Gas Processing filed a Request for Rehearing and Limited Stay, and on December 19, 2001, the FERC issued an Order on Rehearing denying the requests to reclassify the remaining facilities as non-jurisdictional gathering. Certain parties, including Transco, filed petitions for review of the July 25 and December 19, 2001 orders with the D.C. Circuit Court. These appeals were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and were denied by the D.C. Circuit Court in its opinion issued on June 20, 2003. The transfer of these facilities has not been implemented.

     Central Louisiana System Spin-down Proceeding (Docket Nos. CP01-368 and CP01-369) In May 2001, Transco filed an application with the FERC seeking authorization to abandon certain of Transco’s offshore and onshore Louisiana facilities by conveyance to Gas Processing. Gas Processing filed a contemporaneous request that the FERC declare that the facilities sought to be abandoned would be considered nonjurisdictional gathering facilities upon transfer to Gas Processing. On August 31, 2001, the FERC approved the abandonment and the non-jurisdictional treatment of a portion of the facilities requested in the applications of Transco and Gas Processing. On October 1, 2001, Transco and Gas Processing filed a Request for Rehearing and Limited Stay, and on December 19, 2001, the FERC issued an Order on Rehearing denying the request to reclassify the remaining facilities as non-jurisdictional gathering. Certain

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parties, including Transco, filed petitions for review of the August 31 and December 19, 2001 orders with the D.C. Circuit Court. These appeals were consolidated with the appeals of the FERC’s orders in CP96-206 and CP96-207, discussed above, and were denied by the D.C. Circuit Court in its opinion issued on June 20, 2003. The transfer of these facilities has not been implemented.

     The net book value, at the application date, of the North High Island/West Cameron and Central Louisiana facilities included in these two applications was approximately $65 million including the Williams purchase price allocation pushed down to Transco. The transfer of these facilities will not have a material impact on Transco’s results of operations and financial position.

     South Texas Pipeline Facilities Abandonment Proceeding (Docket No. CP02-141) In April 2002, Transco filed an application with the FERC seeking authorization to abandon certain of Transco’s onshore South Texas pipeline facilities by conveyance to a non-affiliated third party intrastate entity. The application also requested that the FERC find that, upon abandonment and conveyance, these facilities would be considered non-jurisdictional intrastate facilities. The net book value of the South Texas pipeline facilities as of the date of Transco’s FERC application was approximately $32 million, including the Williams purchase price allocation pushed down to Transco. On January 29, 2003, the FERC issued an order granting the requested authorizations, subject to the condition that Transco, after transfer of the facilities to the third party, acquire capacity on the transferred facilities and provide service to an existing customer under the original terms and conditions of service. Transco filed a request for rehearing of the January 29 order, specifically requesting that the FERC reconsider such condition to the abandonment. In addition, the Indicated Shippers filed a request for rehearing of the January 29 order, challenging the FERC’s finding that the abandonment is in the public interest. On May 2, 2003, the FERC issued an order granting the Indicated Shippers’ request for rehearing of the January 29 order, thereby denying Transco’s request to abandon the South Texas pipeline facilities by sale to a third party. On June 25, 2003, Transco and the third party purchaser announced that they had agreed to terminate the purchase and sale agreement for the facilities.

     1999 Fuel Tracker (Docket No. TM99-6-29) On March 1, 1999, Transco made its annual filing pursuant to its FERC Gas Tariff to recalculate the fuel retention percentages applicable to Transco’s transportation and storage rate schedules, to be effective April 1, 1999. Included in the filing were two adjustments that increased the estimated gas required for operations in prior periods by approximately 8 billion cubic feet. By letter order dated March 31, 1999, the FERC accepted the filing to be effective April 1, 1999, subject to refund and to further FERC action.

     On February 23, 2000, the FERC issued an order disallowing the major portions of the adjustments reflected in the March 1, 1999 filing. The FERC determined that Transco’s tariff does not permit those adjustments, and as a result, the pass through of those prior period adjustments must be determined on a case by case basis, based on the relative equities involved. Based on its analysis of the facts in this case, the FERC found in the February 23, 2000 order that the equities weighed against Transco. On March 24, 2000, Transco filed a request for rehearing of the February 23, 2000 order and on October 30, 2000, the FERC issued an order granting rehearing. The FERC found that its decision to disallow the adjustments amounted to a “penalty” that is not equitable to Transco. The FERC therefore permits Transco to make the adjustments, but requires Transco to collect the revenue associated with the adjustments over a seven-year period. On November 29, 2000, several of Transco’s customers jointly filed for rehearing of the FERC’s October 30 order. On November 29 and December 29, 2000, Transco filed tariff sheets and supporting documentation in compliance with the FERC’s October 30 order, and certain parties protested that filing. On May 30, 2001, the FERC issued an order that denied the joint request for rehearing, and on July 19, 2001, certain customers filed an appeal of the FERC’s October 30 and May 30 orders with the D.C. Circuit Court. The appeal was

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dismissed in December 2002. In the second quarter of 2001, Transco recorded a $15 million reduction in the cost of natural gas transportation and reduced the related interest expense by $3 million to reflect the regulatory approval to recover the cost of gas required for operations in prior periods. On October 10, 2002, the FERC issued an order rejecting Transco’s November 29 and December 29, 2000 compliance filings, finding that Transco had not complied with the October 30 order in seeking to collect the revenue (including interest) represented by the permitted adjustments. The FERC determined that its October 30 order permits Transco only to collect the actual volumes comprising the adjustments, and directed Transco to file tariff sheets and work papers reflecting the inclusion of the actual volume (amortized over seven years) of the permitted adjustments in its recalculated fuel retention percentages effective April 1, 1999. In the third quarter of 2002, as a result of the FERC’s October 10 order, Transco recorded $3 million of interest expense that had been previously reduced in the second quarter of 2001. Any adjustment that may be required to the $15 million reduction in the cost of natural gas transportation recorded in the second quarter of 2001 is not expected to be significant. On November 12, 2002, certain customers filed a joint request for rehearing of the FERC’s October 10 order asking that the FERC only allow Transco to recover the value of the gas adjustment (without interest), and not the volume of the adjustment. On December 9, 2002, Transco submitted its filing to comply with the FERC’s October 10 order, and on December 23, 2002, several parties, including those that sought rehearing of the October 10 order, filed protests to the December 9, 2002 compliance filing.

     Notice of Proposed Rulemaking (Docket No. RM01-10-000) 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 rules define transmission providers as interstate natural gas pipelines and public utilities that own, operate or control electric transmission facilities. The proposed standards would regulate the conduct of transmission providers with their energy affiliates. The FERC proposes to define 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. Current rules regulate the conduct of Transco and its natural gas marketing affiliates. The FERC invited interested parties to comment on the NOPR. On April 25, 2002, the FERC issued its staff analysis of the NOPR and the comments received. The staff analysis proposes 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. If adopted, these new standards would require the adoption of new compliance measures by Transco which could result in increased costs to Transco.

     Interim Rule (Order No. 634, Docket No. RM02-14-000) On August 1, 2002, the FERC issued a NOPR that proposed restrictions on various types of cash management programs employed by companies in the energy industry such as Williams and its subsidiaries, including Transco. In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs, the FERC proposal, if made final, 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 stockholder’s equity of at least 30% of total capitalization. Williams’ and Transco’s current credit ratings are not investment grade. Transco 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. On June 26, 2003, the FERC issued an Interim Rule (Order No. 634), which requires FERC-regulated entities to have their cash management programs in writing and to have all such programs specify (i) the duties and responsibilities

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of administrators and participants, (ii) the methods for calculating interest and for allocating interest and expenses, and (iii) restrictions on borrowing from the programs. The Interim Rule was effective on August 7, 2003. The Interim Rule also seeks industry comment on new reporting requirements that would require FERC-regulated entities to file their cash management programs with the FERC and to notify the FERC when their proprietary capital ratio drops below 30% of total capitalization and when it subsequently returns to or exceeds 30%. The Interim Rule replaces the earlier NOPR on cash management described above.

Legal Proceedings

     Royalty claims and litigation In connection with Transco’s renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, Transco entered into certain settlements which may require the indemnification by Transco of certain claims for additional royalties which the producers may be required to pay as a result of such settlements. Transco, through its agent WEM&T, continues to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions, which have no carrying value. Transco has been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against Transco pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and Transco. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined.

     Transco was notified by Freeport-McMoRan, Inc. (FMP) in February 1995, that pursuant to a settlement with the Mineral Management Service (MMS) of the MMS’ claim for royalties due under gas contracts between Transco and FMP which had been modified pursuant to settlement agreements made in 1986 and 1989, FMP was asserting a claim for indemnification of approximately $6 million, including interest, under the excess royalty provisions of those settlement agreements. On or about March 30, 1995, FMP filed a petition for specific performance seeking recovery against Transco for the sums claimed under the settlement agreements. In May 1998, FMP filed a motion for summary judgment which Transco opposed. In September 1998, the court granted FMP’s motion finding that at least a portion of FMP’s payment to the MMS was subject to indemnification. Transco appealed the court’s ruling, and in March 2000, the appellate court reversed the trial court and remanded the case for trial, which began in July 2003. At the conclusion of the trial on July 11, 2003, the judge ruled from the bench in Transco’s favor. It is expected that the judge will enter a formal judgment reflecting his bench ruling in the near future. FMP’s claim, including interest calculated through June 30, 2003, is approximately $10 million.

     In August 1996, royalty owners in certain gas wells in Brooks County, Texas, filed a lawsuit against parties producing gas from the wells, claiming $50 million in damages for incorrectly calculated royalties since 1985. Transco purchased gas from the wells and was also named as a defendant. In July 2000, the lawsuit was settled. The settlement amount was funded by the defendants in proportion to their respective working interests in the wells. Since Transco never owned a working interest in any of the wells, it had no obligation to participate in the funding of the settlement amount. However, in August 2000, one defendant working-interest owner, Mobil, made a claim in the amount of $6.7 million against Transco for reimbursement of its settlement contribution and associated legal defense costs on the basis that such amount represented excess royalty payments under a gas purchase contract it had with Transco. In September 2001, Transco was informed that Mobil filed on August 30, 2000, but did not serve, a lawsuit against Transco seeking reimbursement for the payment made by Mobil to settle the litigation and one-half of the costs and expenses it incurred in defense of the litigation. Transco accepted service of the lawsuit on September 26,

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2001. The case is presently in the pretrial discovery phase and is set for trial on October 27, 2003. Mobil’s claim, including interest calculated through June 30, 2003, is approximately $8 million.

     In 1998, the United States Department of Justice (DOJ) 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 Transco. 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, royalty valuation 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. On April 9, 1999, the DOJ announced that it was declining to intervene in any of the Grynberg qui tam cases; including the action filed against the Williams entities in the United States District Court for the District of Colorado. On October 21, 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. On October 9, 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remain pending against Williams and the other defendants.

     On June 8, 2001, fourteen Williams entities, including Transco, were named as defendants in a nationwide class action lawsuit which has been pending against other defendants, generally pipeline and gathering companies, for more than one year. The plaintiffs allege that the defendants, including the Williams defendants, have engaged in mismeasurement techniques that distort the heating content of natural gas, resulting in an alleged underpayment of royalties to the class of producer plaintiffs. In September 2001, the plaintiffs voluntarily dismissed two of the fourteen Williams entities named as defendants in the lawsuit. In November 2001, Williams, along with other Coordinating Defendants, filed a motion to dismiss on nonjurisdictional grounds. In January 2002, most of the Williams defendants, along with a group of Coordinating Defendants, filed a motion to dismiss for lack of personal jurisdiction. On August 19, 2002, defendants’ motion to dismiss on nonjurisdictional grounds was dismissed. On September 17, 2002 the plaintiffs filed a motion for class certification. The Williams entities joined with other defendants in contesting certification of the class. On April 10, 2003, the court denied plaintiffs’ motion for class certification. The motion to dismiss for lack of personal jurisdiction remains pending. On May 13, 2003, plaintiffs filed a motion for leave to file 4th Amended Petition. On July 29, 2003, the Court granted plaintiffs’ motion to file the 4th Amended Petition. The amended petition removes Transco from the group of defendants.

Environmental Matters

     Transco is subject to extensive federal, state and local environmental laws and regulations which affect Transco’s operations related to the construction and operation of its pipeline facilities. Appropriate governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements and injunctions as to future compliance. Transco’s use and disposal of hazardous materials are subject to the requirements of the federal Toxic Substances Control Act (TSCA), the federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, for release of a “hazardous substance” into the environment. Because these laws and regulations change from time to time, practices that have been acceptable to the industry and to the regulators have to be changed and assessment and monitoring have to be undertaken to determine whether those practices have damaged the environment and whether remediation is required.

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Since 1989, Transco has had studies underway to test certain of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. On the basis of the findings to date, Transco estimates that environmental assessment and remediation costs that will be incurred over the next five years under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $30 million to $32 million, measured on an undiscounted basis. 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. Transco 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. At June 30, 2003, Transco had a balance of approximately $30 million for these estimated costs recorded in current liabilities ($3 million) and other long-term liabilities ($27 million) in the accompanying Condensed Consolidated Balance Sheet.

     Transco considers environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, since they are prudent costs incurred in the ordinary course of business. To date, Transco has been permitted recovery of environmental costs incurred, and it is Transco’s intent to continue seeking recovery of such costs, as incurred, through rate filings. Therefore, these estimated costs of environmental assessment and remediation have been recorded as regulatory assets in current assets and other assets in the accompanying Condensed Consolidated Balance Sheet.

     Transco has used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, has discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. Transco has worked closely with the EPA and state regulatory authorities regarding PCB issues, and has a program to assess and remediate such conditions where they exist, the costs of which are included in the $30 million to $32 million range discussed above.

     Transco has been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, Transco’s estimated aggregate exposure for remediation of these sites is less than $500,000. The estimated remediation costs for all such sites have been included in Transco’s environmental reserve discussed above. Liability under CERCLA (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.

     Transco is also subject to the federal Clean Air Act and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air Act. The 1990 Amendments required that the EPA issue new regulations, mainly related to stationary sources, air toxics, ozone non-attainment areas and acid rain. During the last few years Transco has been acquiring all necessary permits and installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA and is continuing that process. Transco operates facilities in some areas of the country currently designated as non-attainment and it anticipates that during 2004 the EPA may designate additional new non-attainment areas which might impact Transco’s operations. Pursuant to non-attainment area requirements of the 1990 Amendments, and proposed EPA rules designed to mitigate the migration of ground-level ozone (NOx) in 22 eastern states, Transco is planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. Transco anticipates that additional facilities may be subject to increased controls within five years. For many of these facilities, Transco is developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not

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possible to precisely determine the ultimate emission control costs. Additionally, the EPA is expected to promulgate new rules regarding hazardous air pollutants in 2003 and 2004, which may impose controls in addition to the controls described above. The emission control additions required to comply with current federal Clean Air Act requirements, the 1990 Amendments, the hazardous air pollutant regulations, and the individual state implementation plans for NOx reductions are estimated to cost in the range of $300 million to $330 million. These costs may be incurred over the next four years 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 in 2004, which impact Transco’s operations, the cost of additions to property, plant and equipment is expected to increase. Transco is unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges discussed above. Transco considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.

Safety Matters

     Proposed Pipeline Integrity Regulations In January 2003, the United States Department of Transportation Office of Pipeline Safety issued a NOPR entitled “Pipeline Integrity Management in High Consequence Areas”. The proposed rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted in December 2002. It would 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. The final rule is expected to be issued in late 2003. Currently, Transco estimates that the cost to perform required assessments and repairs will be approximately between $190 million and $215 million over the 2003 to 2012 period. Developing and implementing the required public education program, including a process for measuring and evaluating the effectiveness of safety information distributed to various stakeholder groups, is expected to cost less than $1 million. These cost estimates may change depending on the content of the final rule. Transco considers the costs associated with compliance with the proposed rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through its rates.

Summary

     Litigation, arbitration, regulatory matters and environmental matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the net income of the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a materially adverse effect upon Transco’s future financial position.

Other Commitments

     Commitments for construction Transco has commitments for construction and acquisition of property, plant and equipment of approximately $33 million at June 30, 2003 of which the majority relates to construction materials for pipeline expansion projects.

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2. DEBT AND FINANCING ARRANGEMENTS

     On June 6, 2003, Williams entered into a two-year $800 million revolving credit facility, primarily for the purpose of issuing letters of credit. Williams, Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to all unborrowed amounts. The facility must be secured by cash and/or acceptable government securities with a market value of at least 105% of the then outstanding aggregate amount available for drawing under all letters of credit, plus the aggregate amount of all loans then outstanding. The new credit facility replaces a $1.1 billion credit line entered into in July 2002 that was comprised of a $700 million secured revolving credit facility and a $400 million secured letter of credit facility. The previous agreements were secured by substantially all of Williams’ midstream assets. The new agreement releases these assets as collateral. The interest rate on the new agreement is variable at the London Interbank Offered Rate (LIBOR) plus 0.75%. At June 30, 2003, letters of credit totaling $387 million have been issued by the participating financial institutions under this facility and no revolving credit loans were outstanding. At June 30, 2003, the amount of restricted investments securing this facility was $461.1 million, which collateralized the facility at 119.25%.

3. STOCK-BASED COMPENSATION

     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 generally 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. The following table illustrates the effect on Transco’s net income if Transco had applied the fair value recognition provisions of SFAS No. 123,“Accounting for Stock-Based Compensation”.

     Pro forma amounts for 2003 include compensation expense from awards made in 2003, 2002 and 2001. Pro forma amounts for 2002 include compensation expense from certain awards made in 1999 and compensation expense from awards made in 2002 and 2001.

     Since compensation expense for stock options is recognized over the future years’ vesting period for pro forma disclosure purposes and additional awards are generally made each year, pro forma amounts may not be representative of future years’ amounts.

     On May 15, 2003, Williams’ shareholders approved a stock option exchange program. Under this exchange program, eligible Williams employees were given a one time opportunity to exchange certain outstanding options for a proportionately lesser number of options at an exercise price to be determined at the grant date of the new options. Surrendered options were cancelled June 26, 2003, and replacement

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options will be granted no earlier than six months and one day after the cancellation date of each surrendered option. Under APB 25, Transco will not recognize any expense pursuant to the stock option exchange. However, for purposes of proforma disclosures, Transco will recognize additional expense related to these new options and the remaining expense on the cancelled options.

ITEM 2. Management’s Narrative Analysis of the Results of Operations.

WILLIAMS’ RECENT EVENTS

     As discussed in Transco’s Form 10-K for the year ended December 31, 2002, events in 2002 and the last half of 2001 significantly impacted Williams’ operations, both past and future. On February 20, 2003, Williams outlined its planned business strategy for the next several years which management believes to be a comprehensive response to the events which have impacted the energy sector and Williams. The plan focuses on retaining a strong, but smaller, portfolio of natural gas businesses and bolstering Williams’ liquidity through additional asset sales, strategic levels of financing at the Williams and subsidiary levels and additional reductions in its operating costs. The plan is designed to provide Williams with a clear strategy to address near-term and medium-term liquidity issues and further de-leverage the company with the objective of returning to investment grade status, while retaining businesses with favorable returns and opportunities for growth in the future. As part of this plan, Williams expects to generate proceeds, net of related debt, of nearly $4 billion from asset sales during 2003 and 2004. During the first half of 2003, Williams received $2.4 billion in net proceeds from the sales of assets and businesses. As previously announced, Williams intends to reduce its commitment to its energy marketing and trading business, which may be realized by entering into a joint venture with a third party or through the sale of a portion or all of the marketing and trading portfolio. Additionally, through the six month period ended June 30, 2003, Williams Energy Marketing and Trading (WEM&T) has sold contracts for proceeds totaling approximately $206 million.

     As of June 30, 2003, Williams has maturing notes payable and long-term debt through the first quarter of 2004 totaling approximately $1.8 billion. Williams anticipates that cash on hand, proceeds from additional asset sales and cash flows from retained businesses will enable Williams to meet its liquidity needs.

General

     The following discussion should be read in conjunction with the consolidated financial statements, notes and management’s narrative analysis contained in Items 7 and 8 of Transco’s 2002 Annual Report on Form 10-K and in Transco’s 2003 First Quarter Report on Form 10-Q and with the condensed consolidated financial statements and notes contained in this report.

RESULTS OF OPERATIONS

Operating Income and Net Income

     Transco’s operating income for the six months ended June 30, 2003 was $191.6 million compared to operating income of $132.0 million for the six months ended June 30, 2002. Net income for the six months ended June 30, 2003 was $102.8 million compared to $76.3 million for the six months ended June 30, 2002. The higher operating income of $59.6 million was primarily the result of higher transportation revenues and lower cost of natural gas transportation and administrative and general cost as discussed below. The increase

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in net income of $26.5 million was attributable to the increased operating income and other items as discussed below.

Transportation Revenues

     Transco’s operating revenues related to its transportation services for the six months ended June 30, 2003 were $396.4 million, compared to $343.5 million for the six months ended June 30, 2002. The higher transportation revenues of $52.9 million were primarily due to increased demand revenues of $32.5 million resulting from (1) new expansion projects (Sundance, Market Link Phase 2 and Momentum Phase 1, placed into service on May 1, 2002, November 1, 2002 and May 1, 2003, respectively) and (2) approved settlement rates, implemented pursuant to the Settlement approved on July 23, 2002, to recover costs associated with increased rate base, rate of return and expenses contained in Transco’s general rate case (Docket No. RP01-245). In addition, transportation revenues increased due to a higher level of reimbursable costs of $10.0 million that are included in operating expenses and recovered in Transco’s rates and an increase of $10.5 million in commodity revenues.

     As shown in the table below, Transco’s total market-area deliveries for the six months ended June 30, 2003 increased 37.5 trillion British Thermal Units (TBtu) (4.8%) when compared to the same period in 2002. This is primarily the result of increased deliveries associated with new expansion projects and colder than normal temperatures in the market area during the first quarter of 2003. Transco’s production area deliveries for the six months ended June 30, 2003 increased 61.4 TBtu (81.4%) when compared to the same period in 2002. This is primarily due to higher deliveries to production area storage and higher deliveries in the production area as a result of new offshore production.

     As a result of a straight fixed-variable (SFV) rate design as used by Transco, increases or decreases in firm transportation volumes in comparable facilities have no significant impact on operating income; however, because interruptible transportation rates have components of fixed and variable cost recovery, increases or decreases in interruptible transportation volumes do have an impact on operating income.

     Transco’s facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.

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Sales Revenues

     Transco makes jurisdictional merchant gas sales to customers pursuant to a blanket sales certificate issued by the FERC, with most of those sales being made through a Firm Sales (FS) program which gives customers the option to purchase daily quantities of gas from Transco at market-responsive prices in exchange for a demand charge payment. For a discussion of a recent settlement with the FERC affecting Transco’s jurisdictional merchant gas sales, see “Item 1. Financial Statements — Notes to Condensed Consolidated Financial Statements — 2. Contingent Liabilities and Commitments.” Pursuant to the terms of this settlement, Transco has provided notice to merchant sales customers that it will be terminating the merchant sales service when it is able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Under the FS program, Transco must provide two-year advance notice of termination. Therefore, Transco notified the FS customers of its intention to terminate the FS service effective April 1, 2005. As part of the settlement, WEM&T has agreed, subject to certain exceptions, that it will not enter into new transportation agreements that would increase the transportation capacity it holds on certain affiliated interstate gas pipelines, including Transco. Finally, Transco and certain affiliates have agreed to the terms of an extensive compliance plan designed to ensure future compliance with the provisions of the settlement agreement and the FERC’s rules governing the relationship of Transco and WEM&T.

     Through an agency agreement with Transco, WEM&T, an affiliate of Transco, manages Transco’s jurisdictional merchant gas sales, excluding Transco’s cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WEM&T remain in Transco’s name, as do the corresponding sales of such purchased gas. Therefore, Transco continues to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WEM&T. Through the agency agreement, WEM&T receives all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assumes all market and credit risk associated with Transco’s jurisdictional merchant gas sales. Consequently, Transco’s merchant gas sales service has no impact on Transco’s operating income or results of operations and, therefore, the anticipated termination of such service, pursuant to the terms of the FERC settlement discussed above, will have no impact on Transco’s operating income or results of operations.

     In addition to its merchant gas sales, Transco also has cash out sales, which settle gas imbalances with shippers. The cash out sales have no impact on Transco’s operating income or results of operations.

     Transco’s operating revenues related to its sales services were $263.7 million for the six months ended June 30, 2003, compared to $185.3 million for the same period in 2002. The increase was primarily due to a higher average sales price of $5.93 per dekatherm (Dt) for the six months ending June 30, 2003, versus $2.92 per Dt for the same period of 2002.

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Storage Revenues

     Transco’s operating revenues related to storage services were $63.0 million for the six months ended June 30, 2003, compared to $69.7 million for the same period in 2002. The decrease was primarily due to a change in rate design (implementation of rolled-in rate treatment in Docket No. RP95-197) to recover certain costs through transportation rates which were previously recovered through certain storage rates.

Operating Costs and Expenses

     Excluding the cost of natural gas sales of $263.7 million for the six months ended June 30, 2003 and $185.3 million for the comparable period in 2002, Transco’s operating expenses for the six months ended June 30, 2003, were approximately $11.2 million lower than the comparable period in 2002. This decrease was primarily attributable to the lower cost of natural gas transportation, administrative and general expense, and other operating costs and expenses, partially offset by higher operation and maintenance expense and depreciation and amortization expense. The lower cost of natural gas transportation was due to a $12.2 million decrease in nontracked fuel expense primarily resulting from a reduction in fuel expense due to pricing differentials related to volumes of gas used in operations, partially offset by higher tracked fuel expense of $6.2 million. The lower administrative and general expense was primarily due to lower labor cost of $8.5 million and lower employee benefits expenses primarily resulting from the recording in 2002 of additional pension expense of $6.8 million associated with an enhanced-benefit early retirement option offer to certain Williams employee groups. These costs were partially offset by increased property and liability insurance of $1.6 million. The lower other operating costs and expenses were primarily due to reduced charitable contribution commitments by the company. Depreciation and amortization increased $8.6 million due primarily to the increase in property resulting from completion of recent construction projects. The higher operation and maintenance expense of $1.8 million was primarily due to severance costs applicable to employees whose positions have been eliminated and increases in storage rates charged to Transco by others.

Other Income and Other Deductions

     Other income and other deductions for the six months ended June 30, 2003 resulted in $14.3 million higher deductions than the comparable period in 2002. Interest expense was higher primarily due to a greater level of long-term debt outstanding in 2003 and higher interest rates associated with the long-term debt. The lower interest income was due to a reduction in intercompany demand notes and lower rates, which are based on the London Interbank Offering Rate (LIBOR). The allowance for funds used during construction was lower due to a lower amount of capital projects under construction. Miscellaneous other (income) deductions, net reflected higher deductions primarily as a result of a gain of $11.0 million recorded in 2002 associated with the disposition of securities received through a mutual insurance company reorganization. The impairment of an investment in an unconsolidated affiliate recorded in 2002 was due to the $12.3 million impairment of Transco’s investment in Independence Pipeline Company resulting from the FERC’s issuance of an order on July 19, 2002, vacating Independence’s certificate to construct the Independence Pipeline project.

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CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

     Transco funds its capital requirements with cash flows from operating activities, by accessing capital markets, by repayments of funds advanced to WGP and, if required, by borrowings under the Credit Agreement and advances from WGP.

     Transco has an effective registration statement on file with the Securities and Exchange Commission. At June 30, 2003, $200 million of shelf availability remains under this registration statement which may be used to issue debt securities. Interest rates and market conditions will affect amounts borrowed, if any, under this arrangement. Transco believes any additional financing arrangements, if required, can be obtained from the capital markets on terms that are commensurate with its current credit ratings.

     On June 6, 2003, Williams entered into a two-year $800 million revolving credit facility, primarily for the purpose of issuing letters of credit. Williams, Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to all unborrowed amounts. The facility must be secured by cash and/or acceptable government securities with a market value of at least 105% of the then outstanding aggregate amount available for drawing under all letters of credit, plus the aggregate amount of all loans then outstanding. The new credit facility replaces a $1.1 billion credit line entered into in July 2002 that was comprised of a $700 million secured revolving credit facility and a $400 million secured letter of credit facility. The previous agreements were secured by substantially all of Williams’ midstream assets. The new agreement releases these assets as collateral. The interest rate on the new agreement is variable at the London Interbank Offered Rate (LIBOR) plus 0.75%. At June 30, 2003, letters of credit totaling $387 million have been issued by the participating financial institutions under this facility and no revolving credit loans were outstanding. At June 30, 2003, the amount of restricted investments securing this facility was $461.1 million, which collateralized the facility at 119.25%.

     As a participant in Williams’ cash management program, Transco and its subsidiaries have advances to and from Williams through Transco’s parent company, WGP. At June 30, 2003, the advances due Transco by WGP totaled $86.5 million. The advances are represented by demand notes. Effective June 2003, the interest rate on intercompany demand notes is the LIBOR on the first day of the month plus 0.75%. Due to its current cash balance and anticipated asset sales in the future, Williams has indicated that it currently believes that it will continue to have the financial resources and liquidity to repay these advances made by WGP which in turn allows WGP to repay Transco and its subsidiaries.

     On August 1, 2002, the FERC issued a NOPR that proposed restrictions on various types of cash management programs employed by companies in the energy industry such as Williams and its subsidiaries, including Transco. In addition to stricter guidelines regarding the accounting for and documentation of cash management or cash pooling programs, the FERC proposal, if made final, 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 stockholder’s equity of at least 30% of total capitalization. Williams’ and Transco’s current credit ratings are not investment grade. Transco 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. On June 26, 2003, the FERC issued an Interim Rule (Order No. 634), which requires FERC-regulated entities to have their cash management programs in writing and to have all such programs

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specify (i) the duties and responsibilities of administrators and participants, (ii) the methods for calculating interest and for allocating interest and expenses, and (iii) restrictions on borrowing from the programs. The Interim Rule was effective on August 7, 2003. The Interim Rule also seeks industry comment on new reporting requirements that would require FERC-regulated entities to file their cash management programs with the FERC and to notify the FERC when their proprietary capital ratio drops below 30% of total capitalization and when it subsequently returns to or exceeds 30%. The Interim Rule replaces the earlier NOPR on cash management described above.

Credit Ratings

     In the second quarter of 2003, Moody’s Investors Services and Fitch Ratings raised Transco’s credit rating on its senior unsecured long-term debt as shown below. The rating given by Standard & Poor’s is B+ which has not changed during 2003.

Capital Expenditures

     As shown in the table below, Transco’s capital expenditures and investments in affiliates for the six months ended June 30, 2003 were $112.0 million, compared to $227.2 million for the six months ended June 30, 2002.

     Transco’s capital expenditures estimate for 2003 and future capital projects are discussed in its 2002 Annual Report on Form 10-K and 2003 First Quarter Report on Form 10-Q. The following describes those projects and any new projects proposed by Transco.

     Momentum Expansion Project On February 14, 2002, the FERC issued an order granting a certificate of public convenience and necessity to Transco to construct and operate the Momentum Expansion Project, an expansion of Transco’s pipeline system from Station 65 in Louisiana to Station 165 in Virginia. On April 10, 2003, the FERC approved Transco’s application to amend the certificate to reduce the overall size of the expansion from approximately 347 MMcf/d to approximately 312 MMcf/d and to place the Momentum facilities into service in two phases. The first phase, consisting of approximately 260 MMcf/d, was placed into service on May 1, 2003. Transco plans to place the second phase, consisting of approximately 52 MMcf/d, into service on February 1, 2004. The reduction in the size of the expansion reflects the termination of two shippers under the project and the partial replacement of those shippers with the two shippers who had subscribed to service under Transco’s previously proposed Cornerstone Expansion Project. The revised project facilities include approximately 50 miles of pipeline looping and 45,000 horsepower of compression. The revised capital cost of the project is estimated to be approximately $189 million.

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     Trenton-Woodbury Expansion Project On May 6, 2002, Transco filed an application for FERC approval of a 49 MMcf/d expansion of Transco’s Trenton-Woodbury Line, which runs from Transco’s mainline at Station 200 in eastern Pennsylvania, around the metropolitan Philadelphia area and southern New Jersey area, to Transco’s mainline near Station 205. On September 24, 2002, the FERC issued a Preliminary Determination on Non-Environment Issues, finding that the project is required by the public convenience and necessity subject to the completion of the FERC’s environmental assessment of the project. On December 24, 2002, the FERC issued a final order authorizing Transco to construct and operate the project. Service agreements have been executed with two shippers for the 49 MMcf/d of incremental firm transportation capacity to be created by the expansion. The target in-service date for the project is November 1, 2003. The project will require approximately 7 miles of pipeline looping at a capital cost of approximately $20 million.

Other Capital Requirements and Contingencies

     Transco’s capital requirements and contingencies are discussed in its 2002 Annual Report on Form 10-K. Other than as described in Note 2 of the Notes to Condensed Consolidated Financial Statements, there have been no new developments from those described in Transco’s 2002 Annual Report on Form 10-K and 2003 First Quarter Report on Form 10-Q with regard to other capital requirements and contingencies.

CONCLUSION

     Although no assurances can be given, Transco currently believes that the aggregate of cash flows from operating activities, supplemented, when necessary, by repayments of funds advanced to WGP, advances or capital contributions from Williams and borrowings under the Credit Agreement will provide Transco with sufficient liquidity to meet its capital requirements. When necessary, Transco also expects to access public and private markets on terms commensurate with its current credit ratings to finance its capital requirements.

ITEM 4. Controls and Procedures.

     An evaluation of the effectiveness of the design and operation of Transco’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15(d)-(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of Transco’s management, including Transco’s Senior Vice President and Vice President and Treasurer. Based upon that evaluation, Transco’s Senior Vice President and Vice President and Treasurer concluded that, subject to the limitations noted below, these Disclosure Controls and procedures are effective.

     Transco’s management, including its Senior Vice President and Vice President and Treasurer, does not expect that Transco’s Disclosure Controls or its internal controls over financial reporting (Internal Controls) will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.

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     Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Transco monitors its Disclosure Controls and Internal Controls and makes modifications as necessary; Transco’s intent in this regard is that the Disclosure Controls and the Internal Controls will be maintained as systems change and conditions warrant.

There has been no change in Transco’s Internal Controls that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, Transco’s Internal Controls.

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See discussion in Note 2 of the Notes to Condensed Consolidated Financial Statements included herein.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

	(a)		Exhibits.
			The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
			(10)  Material contracts

(31)  Section 302 Certifications

(32)  Section 906 Certification

	(b)		Reports on Form 8-K.
			None.

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SIGNATURE

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.

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