UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

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 [  ]

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

The number of shares of Common Stock, par value $1.00 per share, outstanding as of September 30, 2004 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.

TRANSCONTINENTAL GAS PIPE LINE CORPORATION
INDEX

     Certain matters discussed in this report, excluding historical information, include forward-looking statements – statements that discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

     Forward-looking statements can be identified by words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled,” “could,” “continues,” “estimates,” “forecasts,” “might,” “potential,” “projects” or similar expressions. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that may cause future results to be materially different from the results stated or implied in this document. Additional information about issues that could cause actual results to differ materially from forward-looking statements is contained in our 2003 Annual Report on Form 10-K and 2004 First and Second Quarter Reports on Form 10-Q.

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PART 1 – 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.

3

TRANSCONTINENTAL GAS PIPE LINE CORPORATION

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

See accompanying notes.

4

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).

     In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation and unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as “we” “us” or “our.”

     The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. Companies in which we and our 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 our books and records. 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 our management, are necessary to present fairly our financial position at September 30, 2004, and results of operations for the three and nine months ended September 30, 2004 and 2003, and cash flows for the nine months ended September 30, 2004 and 2003. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2003 Annual Report on Form 10-K and 2004 First and Second Quarter Reports on Form 10-Q.

     As a participant in Williams’ cash management program, we have advances to and from Williams. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Prior to April 29, 2004, the advances were made to and from our parent company, WGP.

     Through an agency agreement, Williams Power Company (WPC), an affiliate of ours, manages all jurisdictional merchant gas sales for us, receives all margins associated with such business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

     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; 4) impairment assessments of

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long-lived assets; 5) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.

     Our Board of Directors declared cash dividends on common stock in the amounts of $50 million on June 30, 2004 and $25 million on September 30, 2004.

     Comprehensive income for the three and nine months ended September 30, 2004 and 2003 respectively, are as follows (in thousands):

     Recent accounting standards Emerging Issues Task Force (EITF) Issue No. 03-1, “The Meaning of Other Than Temporary Impairment and Its Application to Certain Investments,” contains recognition and measurement guidance that must be applied to investment impairment evaluations. Specifically, the Issue provides guidance to determine whether an investment is impaired and whether that impairment is other than temporary. The Issue applies to debt and equity securities, except equity securities accounted for under the equity method. The Financial Accounting Standards Board (FASB) is currently considering implementation guidance for the measurement and recognition provisions for this Issue and has delayed implementation. This Issue is required to be adopted on a prospective basis. We believe that the implementation of this Issue will not have a material impact on our results of operations or financial position.

     “In March 2004, the FASB issued an exposure draft of an accounting standard entitled “Share-Based Payment” to amend Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” and SFAS No. 95, “Statement of Cash Flows.” At its October 13, 2004 meeting, the FASB concluded that the final statement would be effective for any interim or annual period beginning after June 15, 2005. At this time, we continue to account for our stock-based compensation plans under Accounting Principles Board Opinion No. 25 while applying the proforma disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (see Note 4).

2. CONTINGENT LIABILITIES AND COMMITMENTS

Rate and Regulatory Matters

     General rate case (Docket No. RP01-245) On March 1, 2001, we submitted to the Federal Energy Regulatory Commission (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.

     In July, 2002, the FERC approved a Stipulation and Agreement (Settlement) which resolved all cost of service, throughput and throughput mix issues in this rate case proceeding 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. The other issues not resolved by the Settlement include various cost allocation, rate design and tariff matters.

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     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, among other things, that (1) our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable, (2) our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, and (3) our recovery of the costs of the Mobile Bay expansion project on a rolled-in basis is unjust and unreasonable. As to the Mobile Bay issue, the ALJ determined that we had the burden of establishing that roll-in of that project is just and reasonable, but did not address the issue of any potential refunds. Our current rates are based on the roll-in of the Mobile Bay expansion project.

     On March 26, 2004, the FERC issued an order that affirmed, in part, and reversed, in part, the ALJ’s initial decision on the issues not resolved by the Settlement. On the issues discussed above, the FERC affirmed the ALJ’s determination that our existing treatment of the arrangement with our former affiliate relating to right of way is just and reasonable and our proposal to roll-in the costs of the Cherokee, Pocono and SunBelt projects is unjust and unreasonable, but reversed the ALJ’s rejection of our proposal to recover the costs of the Mobile Bay expansion project on a rolled-in basis and found that we had shown that our proposed rolled-in rates are just and reasonable. The FERC also affirmed the ALJ’s determination that we must separate our Emergency Eminence Withdrawal service from our Rate Schedule FT service and offer the Emergency Eminence Withdrawal service under a separate rate schedule, thereby permitting shippers to decide whether to take that service. Currently, the costs of the Emergency Eminence Withdrawal service is included as part of our Rate Schedule FT service for those shippers that can access the Eminence Storage Field. Under the FERC’s decision, we would be at risk for those costs to the extent that shippers did not elect to subscribe to all of the separately offered service. Pursuant to the Settlement, this change, if upheld, would be implemented on a prospective basis. On April 26, 2004, several parties, including Transco, filed requests for rehearing of the FERC’s March 26, 2004 order.

     General rate case (Docket No. RP97-71) On November 1, 1996, we submitted to the FERC a general rate case filing principally designed to recover costs associated with increased capital expenditures.

     The filing also included a pro-forma proposal to roll-in the costs of our Leidy Line and Southern expansion incremental projects.

     All issues in this proceeding previously were resolved through settlement or litigation, with the exception of the roll-in issues consolidated with Docket No. RP95-197, which is discussed below.

     General rate case (Docket No. RP95-197) Through settlement and litigation, all issues in this proceeding have been resolved, except a cost allocation issue related to our implementation of the roll-in of the costs of our Leidy Line and Southern Expansion projects.

     In April 1999, the FERC issued an order reversing a prior ALJ decision, and concluded that we had demonstrated that our proposed rolled-in rate treatment was just and reasonable. As a result, the FERC remanded to the ALJ issues regarding the implementation of our roll-in proposal. Several parties filed requests for rehearing of the FERC’s order but their requests, as well as subsequent court appeals, were denied.

     The ALJ generally ruled in favor of our implementation positions, with the major exception that the ALJ required that the roll-in of the costs of the incremental projects into Transco’s system rates be phased in over a three-year period. In October 2001, the FERC issued an order on the ALJ’s decision which generally upheld the decision, except that the FERC reversed the ALJ’s decision to phase the roll-in of the

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costs finding that the three-year phasing is not necessary in this case. In August 2002, we 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 December 12, 2002, the FERC issued an order accepting our 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 we improperly reallocated certain storage costs in implementing the roll-in.

     Gathering facilities spin-down order (Docket Nos. CP96-206-000 and CP96-207-000) In 1996, we 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 an affiliate, Williams Gas Processing — Gulf Coast Company (Gas Processing). The net book value of these facilities at September 30, 2004, was approximately $340 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. The FERC issued an order dismissing our application and Gas Processing’s petition for declaratory order and in 2001, the FERC issued an order that denied our request for rehearing. Certain parties, including us, filed in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) petitions for review of the FERC’s orders and in June 2003, those petitions were denied. Several parties petitioned the United States Supreme Court for review of the D.C. Circuit Court’s opinion, and on January 12, 2004, the Court denied those petitions.

     While the proceedings related to the 1996 application were pending, we filed with the FERC the applications described below seeking authorization to abandon portions of the facilities included in the 1996 application.

     North Padre Island/Central Texas Systems Spin-down Proceeding (Docket Nos. CP01-32 and CP01-34) In 2000, we filed an application with the FERC seeking authorization to abandon certain of our 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. The FERC approved the abandonment and the non-jurisdictional treatment of all of these facilities. Effective December 2001, we transferred to Gas Processing the North Padre Island facilities through a non-cash dividend of $3.3 million, which represents the net book value of the facilities as of that date. Parties filed petitions for review of the FERC’s 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 in June, 2003. In 2001, Shell Offshore, Inc. filed a complaint at the FERC against Gas Processing, Williams Field Services Company (WFS) and us alleging concerted actions by these affiliates frustrated the FERC’s regulation of us. The alleged actions are related to offers of gathering service by WFS and its subsidiaries with respect to the North Padre Island facilities. In 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 a gathering rate for service on these facilities, which is to be collected by us. Transco, Gas Processing and WFS each sought rehearing of the FERC’s order, and in May 2003, the FERC denied those requests for rehearing. Transco, Gas Processing and WFS filed petitions for review of the FERC’s orders with the D.C. Circuit Court and on July 13, 2004, the court granted the petitions, vacating the FERC’s orders and remanding the case to the FERC for further proceedings not inconsistent with the court’s opinion.

     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. In September 2002, the FERC issued an order requiring that, upon transfer of the Central Texas

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facilities, we acquire capacity on the transferred facilities and provide service to the existing customer under the original terms and conditions of service. Our request for rehearing was denied in May 2003. The FERC also required that we notify the FERC of Transco’s plans with regard to the transfer of the Central Texas facilities to Gas Processing. We replied that due to the numerous outstanding issues affecting the transfer of those facilities, we could not at that time predict the timing for the implementation of the transfer of the Central Texas facilities. Transco and the customer each also filed a request for rehearing of the FERC’s May 2003 order. On May 6, 2004, the FERC issued an order on rehearing effectively granting the customer’s request for rehearing. On June 7, 2004, we filed a request for rehearing of the May 6, 2004 order, which the FERC denied on July 6, 2004. On July 14, 2004, we filed a petition for review of the FERC’s orders with the D.C. Circuit Court. At September 30, 2004, the net book value of these facilities was $65 million including the Williams purchase price allocation pushed down to Transco.

     North High Island/West Cameron Systems and Central Louisiana System Spin-down Proceedings In 2001 the FERC issued orders authorizing us to spin down only a portion of these systems to Gas Processing. All legal challenges of these FERC orders have been exhausted and while we have not yet transferred any of the facilities authorized for spin down to our gas processing affiliate, we continue to evaluate the option of doing so. On May 6, 2004, the FERC issued an order relating to the Central Louisiana system spin-down proceeding in which the FERC required Transco and Gas Processing to show cause, due to developments in another proceeding, why certain of the Central Louisiana facilities previously found to be gathering should not be classified as jurisdictional transmission facilities. We filed our response to the show cause order on July 6, 2004, arguing that the FERC should not alter its conclusion that the facilities serve a gathering function.

     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.

     South Texas Pipeline Facilities Abandonment Proceeding In May 2003, the FERC denied our 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. On July 6, 2004, we executed another agreement to sell the South Texas pipeline facilities to a third party, and on July 28, 2004, we filed an application with the FERC for authorization to effectuate the sale. The net book value of such facilities as of September 30, 2004 was approximately $30 million, including the Williams purchase price allocation pushed down to Transco.

     1999 Fuel Tracker (Docket No. TM99-6-29) On March 1, 1999, we made our annual filing pursuant to our FERC Gas Tariff to recalculate the fuel retention percentages applicable to our 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. Certain parties objected to the inclusion of those adjustments and the FERC accepted the filing to be effective April 1, 1999, subject to refund and to further FERC action. In subsequent orders, the FERC initially disallowed most of the adjustments, but later reconsidered that decision and allowed us to make the adjustments, with the requirement we collect the adjustments over a seven-year period. Although several of our customers filed for rehearing of the FERC’s decision to allow us to recover the adjustments, the FERC denied the request for rehearing, and an appeal of the FERC’s decision was filed but later dismissed. In the second quarter of 2001, we 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.

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     The FERC then issued orders in which it addressed our proposed method for recovering the permitted adjustments. The FERC determined that rather than collecting the revenue (including interest) represented by the adjustments, we should collect only the actual volumes comprising the adjustments. In the third quarter of 2002, as a result of the FERC’s determination, we recorded $3 million of interest expense that had been previously reduced in the second quarter of 2001. Certain customers filed requests for rehearing of the FERC’s decision, and the FERC denied those requests. Several parties have filed a joint petition for review in the D.C. Circuit Court of the FERC’s order. In accordance with the FERC’s order, on January 21, 2004 we distributed refunds and assessed surcharges to our customers for the period April 1, 1999 through March 31, 2003. On March 10, 2004, we assessed further surcharges to our customers covering the period April 1, 2003 through January 31, 2004. We implemented the revised fuel retention factors resulting from application of the FERC’s order on a prospective basis beginning February 1, 2004.

     Other Williams, including Transco, responded to a subpoena from the Commodities Futures Trading Commission (CFTC) and inquiries from the FERC related to investigations involving natural gas storage inventory issues. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC investigation is continuing. The FERC inquiries relate to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading. We own and operate natural gas storage facilities.

Legal Proceedings.

     Royalty claims and litigation In connection with our renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain settlements which may require that we indemnify producers for claims for additional royalties resulting from such settlements. Through our agent WPC, we continue 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. We have been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against us 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 us. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined.

     As a result of these settlements, we have been sued by certain producers seeking indemnification. We are currently a defendant in one such lawsuit. Freeport-McMoRan, Inc., filed a lawsuit against us in the 19^th Judicial District Court in East Baton Rouge, Louisiana in which it asserted damages, including interest calculated through September 30, 2004, of approximately $10 million. The case was tried in 2003 and resulted in a judgment favorable to us, which Freeport-McMoRan is appealing.

     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 us. 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. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, including the action filed against the Williams entities in the United States

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District Court for the District of Colorado. In October 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. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remain pending against Williams, including us, and the other defendants.

Environmental Matters

     We are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of pipeline facilities. Appropriate governmental authorities 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. Our 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. Since 1989, we have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that over the next five years environmental assessment and remediation costs under TSCA, RCRA, CERCLA and comparable state statutes will total approximately $26 million to $30 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 the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At September 30, 2004, Transco had a balance of approximately $26 million for these estimated costs recorded in current liabilities ($5 million) and other long-term liabilities ($21 million) in the accompanying Condensed Consolidated Balance Sheet.

     We consider prudently incurred environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs, through future 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.

     We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist, the costs of which are included in the $26 million to $30 million range discussed above.

     We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate

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exposure for remediation of these sites is less than $500,000. The estimated remediation costs for all of these sites have been included in the 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.

     We are 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 we have been installing new emission control devices required for new or modified facilities in areas designated as non-attainment by EPA. We operate some of our facilities in areas of the country currently designated as non-attainment with the one-hour ozone standard. In April 2004, EPA designated eight-hour ozone non-attainment areas. We also operate facilities in areas of the country now designated as non-attainment with the eight-hour ozone standard. 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, we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. We anticipate that additional facilities may be subject to increased controls within five years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission control costs. In March 2004 and June 2004, the EPA promulgated additional regulations regarding hazardous air pollutants; these regulations 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 include costs in the range of $230 million to $260 million subsequent to 2003. EPA’s recent designation of new non-attainment areas will result in new federal and state regulatory action that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are 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. Management 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 our rates.

Safety Matters

     Pipeline Integrity Regulations In December 2003, the United States Department of Transportation Office of Pipeline Safety issued a final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002 that was enacted in December 2002. The rule requires 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. Currently, we estimate that the cost to perform required assessments and repairs will be between $250 million and $300 million over the 2003 to 2012 period. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

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Summary

     Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in 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 our future financial position.

Other Commitments

     Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $59 million at September 30, 2004.

3. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facilities

     On May 3, 2004, Williams entered into a new three-year $1 billion secured revolving credit facility (Credit Agreement) which is available for borrowings and letters of credit. In August 2004, Williams expanded the credit facility by an additional $275 million. At September 30, 2004, letters of credit totaling $438 million, none of which are associated with us, have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to $400 million each under the facility. The new facility is secured by certain Williams’ midstream assets. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offering Rate (LIBOR) plus an applicable margin. Williams is also required to pay a commitment fee based on the unused portion of the facility, currently 0.375%. The applicable margins and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings.

Current Maturities of Long-term Debt

     The current maturities of long-term debt at September 30, 2004 are associated with $200 million of 6 1/8% Notes that mature on January 15, 2005. It is management’s intent to repay the notes from amounts due from Williams and possibly a debt issuance.

4. STOCK-BASED COMPENSATION

     Employee stock-based awards are accounted for under Accounting Principles Board 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 net income if we had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123,“Accounting for Stock-Based Compensation” (in thousands).

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     Pro forma amounts for 2004 include compensation expense from awards made in 2004, 2003, 2002 and 2001. Also included in pro forma expense for the three and nine months ended September 30, 2004, is $0.2 million and $0.5 million, respectively, of incremental expense associated with the stock option exchange program discussed below. Pro forma amounts for 2003 include compensation expense from awards made in 2003, 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 program, eligible 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 options were granted on December 29, 2003. We did not recognize any expense pursuant to the stock option exchange. However, for purposes of pro forma disclosures, we recognized additional expense related to these new options and will amortize the remaining expense on the cancelled options through year-end 2004.

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

Regulatory Matters

     Order Nos. 2004, et seq. (Docket No. RM01-10-000) On November 25, 2003, the FERC issued Order No. 2004 adopting 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 standards regulate the conduct of transmission providers with their energy affiliates. In Order No. 2004, the FERC defined energy affiliates broadly to include any non-transmission provider affiliate that engages in or is involved in transmission (gas or electric) transactions, manages or controls transmission capacity or that buys, sells, trades or administers natural gas or electric energy, engages in financial transactions relating to the sale or transmission of natural gas or electricity, and Hinshaw and intrastate pipelines. In Order No. 2004-A, issued on April 16, 2004, the FERC, among other things, clarified the definition of energy affiliates in a manner that narrowed its scope. On August 2, 2004, the FERC issued Order No. 2004-B, which, among other things, further clarified the definition of energy affiliates and deferred the implementation date for the new standards of conduct until September 22, 2004. We posted our procedures implementing the requirements of Order No. 2004 on September 22, 2004, in compliance with the new standards of conduct.

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     Beginning in May 1995, Williams Field Services Company (WFS), an affiliated company, operated our production area facilities pursuant to the terms of an operating agreement. In response to FERC Order No. 2004, we terminated the operating agreement and effective June 1, 2004, we resumed operating these facilities. We anticipate that the increased costs resulting from the additional employees required to operate these facilities will be offset by the discontinuation of the operating fee we were paying to WFS under the terms of the operating agreement.

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 our 2003 Annual Report on Form 10-K and in our 2004 First and Second Quarter Reports 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

     Our operating income for the nine months ended September 30, 2004 was $255.3 million compared to operating income of $283.9 million for the nine months ended September 30, 2003. Net income for the nine months ended September 30, 2004 was $130.8 million compared to $150.1 million for the nine months ended September 30, 2003. The lower operating income of $28.6 million was primarily the result of lower transportation revenues, lower other operating revenues, higher administrative and general cost and higher other operating expenses, partially offset by lower depreciation and amortization expense as discussed below. The decrease in net income of $19.3 million was attributable to the decreased operating income and higher net expenses as discussed below in Other Income and Other Deductions.

Transportation Revenues

     Our operating revenues related to transportation services for the nine months ended September 30, 2004 were $586.6 million, compared to $592.9 million for the nine months ended September 30, 2003. The lower transportation revenues of $6.3 million were primarily due to a decrease of $15.7 million of reimbursable costs that are included in operating expenses and recovered in our rates and a $4.6 million decrease in commodity revenues which is due primarily to lower interruptible transportation. This was partially offset by increased demand revenues of $14.3 million mostly resulting from new expansion projects (Momentum Phase 1 placed into service on May 1, 2003, Trenton-Woodbury placed into service on November 1, 2003, and Momentum Phase 2 placed into service on February 1, 2004).

     As shown in the table below, our total market-area deliveries for the nine months ended September 30, 2004 increased 29.0 trillion British Thermal Units (TBtu) (2.5%) when compared to the same period in 2003. Increased deliveries were associated with an increase in power generation relative to the same period in 2003. Our production area deliveries for the nine months ended September 30, 2004 increased 26.9 TBtu (12.2%) when compared to the same period in 2003. This is primarily due to increased deliveries to production area interconnects and increased deliveries to production area processing plants.

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     Our 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.

Sales Revenues

     We make 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 us at market-responsive prices in exchange for a demand charge payment. Pursuant to the terms of an agreement with the FERC which resolved an open investigation, we have notified our merchant sales customers that we will be terminating the merchant sales service when we are able to do so under the terms of any applicable contracts and FERC certificates authorizing such services. Under the FS program we must provide two-year advance notice of termination. Therefore, we notified the FS customers of our intention to terminate the FS service effective April 1, 2005.

     Through an agency agreement, WPC manages our jurisdictional merchant gas sales, excluding our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WPC remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue 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 WPC. WPC receives all margins associated with jurisdictional merchant gas sales business and, as our agent, assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations and, therefore, the anticipated termination of such services in April 2005, will have no impact on our operating income or results of operations.

     In addition to our merchant gas sales, we also have cash out sales, which settle gas imbalances with shippers. The cash out sales have no impact on our operating income or results of operations.

     Operating revenues related to our sales services were $302.8 million for the nine months ended September 30, 2004, compared to $359.0 million for the same period in 2003. The decrease was primarily due to a lower volume of merchant sales during the first nine months of 2004 compared to the same period in 2003. This was partially offset by increases resulting from higher cash out sales volumes related to the

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monthly settlement of imbalances and a higher average sales price of $5.93 per dekatherm (dt) for the nine months ending September 30, 2004 compared to $5.66 for the same period of 2003.

Storage Revenues

     Our operating revenues related to storage services of $92.4 million for the nine months ended September 30, 2004 were comparable to revenues of $94.4 million for the same period in 2003.

Other Revenues

     Our other operating revenues were $7.5 million for the nine months ended September 30, 2004 compared to $15.3 million for the same period in 2003. The reduction was primarily due to a decrease in the sale of environmental mitigation credits.

Operating Costs and Expenses

     Excluding the cost of natural gas sales of $301.3 million for the nine months ended September 30, 2004 and $359.0 million for the comparable period in 2003, our operating expenses for the nine months ended September 30, 2004, were approximately $14.0 million higher than the comparable period in 2003. This was attributable to increases in operation and maintenance expenses, administrative and general expenses, taxes other than income taxes and other operating costs and expenses, partially offset by lower cost of natural gas transportation and depreciation and amortization expense. The increase in operation and maintenance expense in 2004 of $4.7 million is due primarily to increased materials and supplies cost of $3.1 million and higher maintenance cost of $1.3 million for right-of-way clearing. The increase in administrative and general expense of $11.4 million is mostly due to increased management services billed to us by Williams. As a result of recent changes within Williams, we are receiving an increased share of the management services allocation. The higher management services are also due to increased third-party costs associated with Sarbanes-Oxley Act compliance activities and with efforts at Williams to evaluate and implement certain cost reduction strategies through internal initiatives and outsourcing of certain services. The $4.2 million increase in taxes other than income taxes was mostly due to an increase in franchise taxes in the various states in which we operate. The higher other operating costs and expenses of $8.1 million were primarily due to a reduction of accrued liabilities in the third quarter of 2003 for claims associated with certain producer indemnities. The lower cost of natural gas transportation of $3.8 million resulted from a decrease of $12.9 million in 2004 of reimbursable costs that are recovered in our rates and a $4.0 million charge in the third quarter of 2003 associated with the write-off of certain receivables. These decreases were partially offset by an increase in fuel expense of $13.1 million due to the benefit of pricing differentials in 2003 related to volumes of gas used in operations. The lower depreciation and amortization expense of $10.7 million was due to decreases of $4.9 million associated with lower environmental mitigation development costs, $4.0 million resulting from an adjustment to depreciation previously recognized and $1.8 million due primarily to decreased computer software and hardware assets.

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Other Income and Other Deductions

     Other income and other deductions for the nine months ended September 30, 2004 resulted in higher net expenses of $3.5 million compared to the same period in 2003. This was primarily due to a decrease in the allowance for funds used during construction resulting from a lower amount of capital projects under construction.

CAPITAL RESOURCES AND LIQUIDITY

Method of Financing

     We fund our capital requirements with cash flows from operating activities, by repayments of funds advanced to Williams, by accessing capital markets, and, if required, by borrowings under the Credit Agreement and advances from Williams.

     We have an effective registration statement on file with the Securities and Exchange Commission. At September 30, 2004, $200 million of shelf availability remains under this registration statement which may be used to issue debt securities. However, the ability to utilize this registration statement is restricted by certain covenants of Williams’ debt agreements. Interest rates, market conditions, and industry conditions will affect amounts borrowed, if any, under this arrangement. We believe any additional financing arrangements, if required, can be obtained from the capital markets on terms that are commensurate with our current credit ratings.

     On May 3, 2004, Williams entered into a new three-year $1 billion secured revolving credit facility which is available for borrowings and letters of credit. In August 2004, Williams expanded the credit facility by an additional $275 million. At September 30, 2004, letters of credit totaling $438 million, none of which are associated with us, have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Transco and Northwest Pipeline Corporation, a subsidiary of WGP, have access to $400 million each under the facility. The new facility is secured by certain Williams’ midstream assets. Additionally, the facility is guaranteed by WGP. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the facilitating bank’s base rate plus an applicable margin or a periodic fixed rate equal to LIBOR plus an applicable margin. Williams is also required to pay a commitment fee based on the unused portion of the facility, currently 0.375%. The applicable margins and commitment fee are based on the relevant borrower’s senior unsecured long-term debt ratings.

     As a participant in Williams’ cash management program, we have advances to and from Williams. At September 30, 2004, the advances due to us by Williams totaled $183.4 million. The advances are represented by demand notes. We anticipate demanding repayment of a significant portion of these advances to Williams for use in retiring the $200 million of 6 1/8% Notes that mature on January 15, 2005. Effective September 2003, the interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. Previously, the interest rate on intercompany demand notes was based on the LIBOR plus an applicable margin. Williams has indicated that it currently believes that it will continue to have the financial resources and liquidity to repay these advances. Prior to April 29, 2004, the advances were made to and from our parent company, WGP.

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Williams’ Recent Events

     In February 2003, Williams outlined its planned business strategy in response to the events that significantly impacted the energy sector and Williams during late 2001 and much of 2002. The plan focused on migrating to an integrated natural gas business comprised of a strong, but smaller portfolio of natural gas businesses, reducing debt and increasing Williams’ liquidity through assets sales, strategic levels of financing and reductions in operating costs. The plan was designed to address near-term and medium-term debt and liquidity issues, to de-leverage Williams with the objective of returning to investment grade status and to develop a balance sheet and cash flows capable of supporting and ultimately growing its remaining businesses.

     As discussed in our Annual Report on Form 10-K for the year ended December 31, 2003, Williams successfully executed certain critical components of its plan during 2003. Key execution steps for 2004 and beyond included the completion of planned asset sales, additional reductions of Williams’ selling, general and administrative (SG&A) costs, the replacement of its cash-collateralized letter of credit and revolver facility with facilities that do not encumber cash and continuation of efforts to exit from the power business.

     Asset sales during 2004 were expected to generate proceeds of approximately $800 million. In the first quarter of 2004, Williams completed an asset sale for approximately $304 million. In July 2004, Williams completed the sale of additional assets for approximately $544 million, including amounts paid to its subsidiaries for amounts previously due from the assets that were sold.

     In September 2004, Williams’ Board of Directors approved the decision to retain Williams’ power business and end its efforts to exit that business. Williams will continue its current program of managing this business to minimize financial risk and maximize cash flow associated with its long-term contracts.

Credit Ratings

     The credit ratings on our senior unsecured long-term debt did not change during the first nine months of 2004 and, as of September 30, 2004, are as follows:

Capital Expenditures

     As shown in the table below, our capital expenditures for the nine months ended September 30, 2004 were $109.0 million, compared to $145.4 million for the nine months ended September 30, 2003. We currently estimate that capital expenditures for the year 2004 will be approximately $160 million compared to the approximately $191 million detailed in our 2003 Annual Report on Form 10-K.

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     Our capital expenditures estimate for 2004 and future capital projects are discussed in our 2003 Annual Report on Form 10-K and 2004 First and Second Quarter Reports on Form 10-Q. The following describes new capital projects proposed by us.

     Central New Jersey Expansion Project The Central New Jersey Expansion Project will involve an expansion of our existing natural gas transmission system in Zone 6 from the Station 210 pooling point to locations along our Trenton-Woodbury Line. The project will create 105,000 dekatherms per day (dt/d) of new firm transportation capacity, which has been fully subscribed by one shipper for a twenty-year primary term. The project facilities will include approximately 3.5 miles of pipeline loop at an estimated capital cost of $13 million. We filed an application for FERC approval of the project on August 11, 2004. The target in-service date for the project is November 1, 2005.

     Leidy to Long Island Expansion Project We held an “open season” from June 14, 2004 to July 13, 2004 to receive requests for new firm transportation capacity to be made available from the Leidy Hub in Clinton County, Pennsylvania to certain Zone 6 delivery points under our proposed Leidy to Long Island Expansion Project. As a result of the open season, the expansion has been designed to create 100,000 dt/d of firm transportation capacity, for which one shipper has submitted a binding commitment for a twenty-year primary term. The current design of the project facilities includes pipeline looping and compression facilities and pipeline and compressor upgrades at an estimated capital cost of approximately $143 million. The final design of the project facilities is subject to the outcome of our “reverse open season” solicitation of permanent capacity release offers. We expect that nearly three-quarters of the project expenditures will occur in 2007. We plan to file for FERC approval of the project in the third quarter of 2005. The target in-service date for the project is November 1, 2007.

Other Capital Requirements and Contingencies

     Our capital requirements and contingencies are discussed in our 2003 Annual Report on Form 10-K. Other than as described in Note 2 of the Notes to Condensed Consolidated Financial Statements and the Capital Expenditures discussion in Item 2 of this report, there have been no new developments from those described in our 2003 Annual Report on Form 10-K and 2004 First and Second Quarter Reports on Form 10-Q with regard to other capital requirements and contingencies.

Conclusion

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

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ITEM 4. Controls and Procedures.

     An evaluation of the effectiveness of the design and operation of our 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 our management, including our Senior Vice President and Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.

     Our management, including our Senior Vice President and Vice President and Treasurer, does not expect that our Disclosure Controls or our internal controls over financial reporting (Internal Controls) will prevent all errors 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. 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. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.

     Effective July 1, 2004, Williams entered into an outsourcing agreement with IBM which will improve Williams’ ability to adjust support operations as business conditions dictate while maintaining a high quality of service. The services being rendered by IBM include certain aspects of Williams’ accounting, human resources and information technology activities. The more significant of these include payroll, accounts payable, property, general ledger and related accounting, benefits, compensation, infrastructure and applications. As a result of the outsourcing substantially all of Williams’ employees in the outsourced functions were initially hired by IBM and continued performing the same functions during the third quarter. Contractually, IBM is required to develop and implement internal controls and has agreed to work with Williams to implement compliance measures to satisfy the Sarbanes-Oxley Act of 2002. IBM has agreed to make minimal changes to processes and systems through year end 2004.

     Notwithstanding the above, management concludes that its current controls are effective at a reasonable assurance level. In addition, there has been no material change, other than the outsourcing described above, in our Internal Controls that occurred during the registrant’s third fiscal quarter.

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PART II — OTHER INFORMATION

ITEMS 1. LEGAL PROCEEDINGS.

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

ITEM 6. 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

–	1	Letter of Credit Commitment Increase Agreement dated August 4, 2004, by and among The Williams Companies, Inc., Citicorp USA in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent, the Banks and Issuing Banks party thereto and Citibank, N.A. and Bank of America, N.A. (filed as Exhibit 10.1 to The Williams Companies, Inc. Form 10-Q for the quarter ended September 30, 2004 Commission File Number 1-4174).
–	2	Revolving Credit Commitment Increase Agreement dated August 4, 2004, by and among the Williams Companies, Inc., Citicorp USA, Inc. in its capacity as Agent under the Credit Agreement dated as of May 3, 2004 among the Borrower, Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, the Agent, the Collateral Agent and the Banks and Issuing Banks party thereto, the Issuing Banks and Citicorp USA, Inc. (filed as Exhibit 10.2 to The Williams Companies, Inc. Form 10-Q for the quarter ended September 30, 2004 Commission File Number 1-4174).

(31)

Section 302 Certifications

–	1	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
–	2	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32)

Section 906 Certification

1

Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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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