UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

For the Quarterly Period Ended June 30, 2004

OR

For the Transition Period from                    to

Commission File Number 1-7414

NORTHWEST PIPELINE CORPORATION

295 Chipeta Way
Salt Lake City, Utah 84108

(801) 583-8800

No Change

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

The registrant meets the conditions set forth in General Instruction (H)(1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

NORTHWEST PIPELINE CORPORATION

TABLE OF CONTENTS

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 Form 10-K and 2004 First Quarter Report on Form 10-Q.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHWEST PIPELINE CORPORATION
CONDENSED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION
CONDENSED BALANCE SHEET
(Thousand of Dollars)
(Unaudited)

See accompanying notes.

4

NORTHWEST PIPELINE CORPORATION
CONDENSED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

5

NORTHWEST PIPELINE CORPORATION
CONDENSED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

     Northwest Pipeline Corporation (Pipeline) 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, Northwest Pipeline Corporation is at times referred to in the first person as “we”, “us” or “our”.

Basis of Presentation

     Our 1983 acquisition by Williams has been accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities, based on their estimated fair values at the time of the acquisition. Williams has not pushed down the purchase price allocation (amounts in excess of original cost) of $ 82.7 million, as of June 30, 2004, to us as current Federal Energy Regulatory Commission (“FERC”) policy does not permit us to recover through our rates amounts in excess of original cost. The accompanying financial statements reflect our original basis in our assets and liabilities.

     The condensed 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 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 June 30, 2004, and results of operations for the three and six month periods ended June 30, 2004 and 2003, and cash flows for the six month periods ended June 30, 2004 and 2003. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2003 Annual Report on Form 10-K and 2004 first quarter report on Form 10-Q.

     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 condensed financial statements and accompanying notes. Actual results could differ from those estimates.

Other

     Cash payments for interest were $13.6 million and $12.8 million, net of interest capitalized, in the six month periods ended June 30, 2004 and 2003, respectively.

     Cash payments of $3.3 million and $12.3 million were made to Williams for income taxes in the six month periods ended June 30, 2004 and 2003, respectively.

Reclassifications

     Certain reclassifications have been made in the 2003 financial statements to conform to the 2004 presentation.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

     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

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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 District Court for the District of Colorado. In October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui am 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 the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Our management, believes that we are in substantial compliance with existing environmental requirements. We believe that, with respect to any capital expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that, for the most part, such expenditures and a return thereon would be permitted to be recovered. As a result, we believe that compliance with applicable environmental requirements is not likely to have a material effect upon our earnings or financial position.

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 $75 million and $100 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. Our 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.

Other Matters

     Williams responded to a subpoena from the Commodities Futures Trading Commission and inquiries from the FERC related to natural gas storage inventory issues. Williams believes that these inquires are a part of an ongoing general industry-wide investigation. The inquires relate to the formal reporting of inventory levels, 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.

     In addition to the foregoing, various other proceedings are pending against us incidental to our operations.

Summary

     Litigation, arbitration, regulatory matters and environmental 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 net income of the period in which the ruling occurs. Our 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 or results of operations.

Other Commitments

     In December 2003, we received an Amended Corrective Action Order (“ACAO”) from the U.S. Department of Transportation’s Office of Pipeline Safety (“OPS”) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured. The decision to idle the pipeline has not had a significant impact on our ability to meet market demand to date. Primarily because of customer market profiles prior to the summer months, we have been able to meet firm service requirements through our parallel pipeline in the same corridor.

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     We have successfully hydrotested and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MMcf/day of the 360 MMcf/day of idled capacity and is anticipated to be adequate to meet most market conditions. The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Total estimated testing and remediation costs are between $40 million to $50 million, including approximately $9 million related to one segment of pipe that we recently determined not to return to service and is thus being expensed in the second quarter.

     As currently required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 MMcf/day of capacity being relinquished and incorporated into the replacement project. The total costs of the capacity replacement project are expected to be in the range of approximately $310 million to $360 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

3. DEBT AND FINANCING ARRANGEMENTS

Long-Term Debt

     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. At June 30, 2004, letters of credit totaling $181 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. Williams also has a commitment from its agent bank to expand its credit facility by an additional $275 million. Pipeline and Transcontinental Gas Pipe Line 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.

4. 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. 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 SFAS No. 123, “Accounting for Stock-Based Compensation”.

     Pro forma amounts for 2004 include compensation expense from Williams awards made in 2004, 2003, 2002 and 2001. Also included in the 2004 pro forma expense is $42,421 and $84,841 of incremental expense for the three and six months ended June 30, 2004, respectively, associated with the stock option exchange program discussed below. Pro forma amounts for 2003 include compensation expense from Williams awards made in 2003, 2002, and 2001.

     Since compensation expense from 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

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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.

5. IMPAIRMENT CHARGES

     In the second quarter of 2004, we wrote off $9.0 million of previously capitalized costs incurred on an idled segment of our system that will not return to service due to the pipeline breaks in 2003 discussed in Note 2 above.

     In June 2003, we wrote off software development costs of $25.5 million associated with a service delivery system. Subsequent to the implementation of this system at Transcontinental Gas Pipe Line Corporation in the second quarter of 2003 and a determination of the unique and additional programming requirements that would be needed to complete the system for us, management determined that the system would not be implemented. In August 2003, we wrote off an additional $0.1 million of software development costs for the remaining component of the service delivery system.

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

GENERAL

     The following discussion and analysis of results of operations, financial condition and liquidity should be read in conjunction with the financial statements, notes and management’s narrative analysis of the results of operations contained in Items 7 and 8 of our 2003 Annual Report on Form 10-K and with the condensed financial statements and notes thereto and Item 2 contained in our 2004 first quarter report on Form 10-Q and within this report.

2003 PIPELINE BREAK NEAR AUBURN, WASHINGTON

     In December 2003, we received an Amended Corrective Action Order (“ACAO”) from the U.S. Department of Transportation’s Office of Pipeline Safety (“OPS”) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured. The decision to idle the pipeline has not had a significant impact on our ability to meet market demand to date. Primarily because of customer market profiles prior to the summer months, we have been able to meet firm service requirements through our parallel pipeline in the same corridor.

     We have successfully hydrotested and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MMcf/day of the 360 MMcf/day of idled capacity and is anticipated to be adequate to meet most market conditions. The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Total estimated testing and remediation costs are between $40 million to $50 million, including approximately $9 million related to one segment of pipe that we recently determined not to return to service and is thus being expensed in the second quarter.

     As currently required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 MMcf/day of capacity being relinquished and incorporated into the replacement project. The total costs of the capacity replacement project are expected to be in the range of approximately $310 million to $360 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

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REGULATORY MATTERS

     Order Nos. 2004 and 2004-A (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 which should narrow its scope. Transmission providers must comply with the new standards of conduct by September 1, 2004. We filed and posted a plan and schedule for implementing the requirements of Order No. 2004 on February 9, 2004, and currently are reviewing these new standards (as modified by Order No. 2004-A), preparing to adopt new compliance measures and evaluating the impact of increased costs to us.

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 include 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 initially expected to generate proceeds of approximately $800 million in 2004. In the first quarter of 2004, Williams completed an asset sale for proceeds of approximately $304 million. In July 2004, Williams completed the sale of additional assets for approximately $536 million. In addition to these transactions, Williams currently expects to generate additional proceeds from the sale of assets of approximately $50 million to $100 million.

     RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the six-month periods ended June 30, 2004 and 2003. Variances due to changes in price and volume have little impact on revenues, because under Pipeline’s rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in its transportation rates.

Six Months Ended June 30, 2004 versus Six Months Ended June 30, 2003

     Operating revenues increased $7.9 million, or 5 percent, due primarily to increased transportation revenues of $19.6 million from the incremental Evergreen project placed in service in late 2003, offset by lower short term firm and interruptible transportation revenues of $5.8 million primarily due to a decrease in basin price differentials, lower revenue of $2.8 million related to reduced equity AFUDC resulting from the decreased capital construction program in 2004, and lower transportation volumes leading to $0.6 million lower commodity revenues.

     Pipeline’s transportation service accounted for 97 percent and 94 percent of operating revenues for the six-month periods ended June 30, 2004 and 2003, respectively. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the six-month periods ended June 30, 2004 and 2003, respectively.

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     Operating costs and expenses decreased $2.7 million, or 3 percent, due primarily to the 2003 write-off of capitalized software development costs of $25.5 million associated with a service delivery system and the 2004 Regulatory Credit of $4.0 million related primarily to the Evergreen expansion project. This was mostly offset by a $9.0 million write-off of previously capitalized costs incurred on an idled segment of our system that will not return to service, a $2.8 million increase in pension expense due to the absence of a favorable adjustment made to pension expense in 2003 and a $1.4 million increase in labor costs resulting from a lower amount of capitalized labor in 2004. In addition, general corporate overhead increased $4.2 million due to increased management services billed to us by Williams. The higher management services are due primarily to increased third-party cost associated with the implementation of the Sarbanes-Oxley Act of 2002 and with efforts at Williams to evaluate and implement certain cost reduction strategies through internal initiatives and outsourcing of certain services. Depreciation expense increased by $3.2 million and Other Taxes increased by $2.5 million due to the increase in property resulting from the recent Evergreen and Rockies construction projects placed in service during the fourth quarter of 2003.

     Operating income increased $10.6 million, or 17 percent, due to the higher operating revenues and lower operating costs discussed above.

     Interest on long-term debt increased $1.9 million due to the March 4, 2003, $175 million private debt offering of 8.125 percent senior notes due 2010. Allowance for borrowed funds used during construction decreased $1.6 million due to the decrease in construction resulting from the completion of large projects in the fourth quarter of 2003.

     The following table summarizes volumes and capacity for the periods indicated:

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 June 30, 2004, $150 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 currently restricted by certain covenants associated with Williams’ $800 million 8.625% senior unsecured notes that were issued in 2003. 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. At June 30, 2004, letters of credit totaling $181 million, none of which are associated with Pipeline, have been issued by the participating institutions under this facility and no revolving credit loans were outstanding. Williams also has a commitment from its agent bank to expand its credit facility by an additional $275 million. Pipeline and Transcontinental Gas Pipe Line Corporation, a subsidiary of WGP, have access to $400 million each under the facility. The new facility is secured by certain Williams’

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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 borrowers senior unsecured long-term debt ratings.

     As a participant in Williams’ cash management program, we have advances to and from Williams. At June 30, 2004, the advances due to us by Williams totaled $50.0 million. The advances are represented by demand notes. 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 flowed through our parent company, WGP.

CREDIT RATINGS

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

CAPITALIZED EXPENDITURES

     We anticipate 2004 capital expenditures will total approximately $120.7 million, of which approximately $104.1 million will be for maintenance capital expenditures, the restoration of the pipeline break as discussed above and other non-expansion related items. Through June 30, 2004, we have expended $45.2 million for capital additions.

OTHER

Regulatory and Legal Proceedings

     Reference is made to Note 2 of the Notes to Condensed Financial Statements for information about regulatory, judicial and business developments, which cause operating and financial uncertainties.

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.

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, subject to the limitations noted below, these Disclosure Controls are effective.

     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

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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.

     Notwithstanding the above, management believes that its current controls are effective. In addition, there has been no material change in our Internal Controls that occurred during the registrant’s second fiscal quarter.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

     See discussion in Note 2 of the Notes to Condensed 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

–      1

U.S. $1,000,000,000 Credit Agreement dated as of May 3, 2004, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, as Borrowers, Citicorp USA, Inc., as Administrative Agent and Collateral Agent, Citibank, NA. And Bank of America, N.A., as Issuing Banks, the banks named therein as Banks, Bank of America, N.A. as Syndication Agent, JPMorgan Chase Bank, The Bank of Nova Scotia, The Royal Bank of Scotland plc as Co-Documentation Agents, Citigroup Global Markets Inc. and Banc of America Securities LLC as Joint Lead Arrangers and Co-Book Runners. (filed as Exhibit 10.4 to The Williams Companies, Inc. Form 10-Q for the quarterly period ended March 31, 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.

	(b)		Reports on Form 8-K.
			None.

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SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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