UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2005

OR

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

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 þ      No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes o       No þ

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 2004 Form 10-K.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHWEST PIPELINE CORPORATION

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

See accompanying notes.

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

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

See accompanying notes

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1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

     Northwest Pipeline Corporation (Northwest) 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 $79.5 million, as of March 31, 2005, to us as current Federal Energy Regulatory Commission (FERC) policy does not permit us to recover amounts in excess of original cost through our rates. 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 March 31, 2005, and results of operations for the three months ended March 31, 2005 and 2004, and cash flows for the three months ended March 31, 2005 and 2004. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2004 Annual Report on Form 10-K.

     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. 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 long-lived assets; 5) deferred and other income taxes; 6) depreciation; and 7) pension and other post-employment benefits.

Recent Accounting Pronouncements

     In December 2004, the Financial Accounting Standards Board (FASB) issued revised Statement of Accounting Standards (SFAS) No. 123, “Share-Based Payment”. The Statement requires that compensation costs for all share-based awards to employees be recognized in the financial statements at fair value. The Statement, as issued by the FASB, was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, on April 15, 2005, the Securities and Exchange Commission (SEC) adopted a new rule, which amends the compliance dates for SFAS No. 123. The rule allows implementation of the Statement at the beginning of the next fiscal year that begins after June 15, 2005. We intend to adopt the revised Statement as of January 1, 2006.

     In March 2005, the FASB issued Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations—an interpretation of FASB Statement No. 143.” The statement clarifies that the term conditional asset retirement obligation, as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The effective date of this Interpretation is no later than the end of the fiscal year ending after December 15, 2005. We are assessing the impact of this Interpretation on our financial statements and believe the effect will not be material.

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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 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 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, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. Oral argument on these motions occurred on March 17 and 18, 2005, and we expect a decision in the second quarter of 2005.

Environmental Matters

     We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. 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 We have developed an Integrity Management Plan that meets the United States Department of Transportation Office of Pipeline Safety (OPS) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the Integrity Regulations, we have identified the high consequence areas, 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 remaining assessment period of 2005 through 2012. 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, including Northwest, 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. We own and operate natural gas storage facilities. On August 30, 2004, the CFTC announced that it had concluded its investigation. The FERC inquiries related to the sharing of non-public data concerning inventory levels and the potential uses of such data in natural gas trading. The FERC investigation is continuing and Williams is engaged in discussions with FERC staff that are likely to result in an ultimate disposition of this matter through a settlement that would include some amount of penalty and refund, the financial effect of which ultimately will be borne by an affiliate.

     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 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

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of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

Other Commitments

2003 Pipeline Breaks in Washington

     In December 2003, we received an Amended Corrective Action Order (ACAO) from 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.

     By June 2004 we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

     The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Through March 31, 2005, approximately $41 million has been spent on testing and remediation costs, including approximately $8.9 million related to one segment of pipe that we determined not to return to service and was therefore written off in the second quarter of 2004.

     On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original Corrective Action Order (CAO). This penalty was accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to ensure that a similar situation would not occur in the future. We requested a hearing on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS will issue its decision in the near future.

     As 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 MDth/day of capacity being relinquished and incorporated into the replacement project. On November 29, 2004, we filed with the FERC a certificate of application for the “Capacity Replacement Project”, including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 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

Revolving Credit and Letter of Credit Facilities

     Under Williams’ $1.275 billion secured revolving credit facility, letters of credit totaling $455 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at March 31, 2005.

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 option equals the market price of the underlying stock on the date of grant. The following table illustrates the effect on our net

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income if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”.

     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 not be representative of future years’ amounts.

5. CONTRACT TERMINATION

Termination of the Grays Harbor Transportation Agreement

     Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to the Grays Harbor Lateral. We invoiced Duke the amount we believe is contractually owed by Duke according to the terms of the facilities reimbursement agreement. Duke has paid us approximately $88 million for the remaining net book value of the lateral facilities and approximately $6 million towards the related income taxes. We have invoiced Duke for an additional $30 million, representing the additional income taxes related to the termination of the contract. This amount has not been paid to date by Duke, and the income effects from the agreement termination have therefore been deferred pending the resolution of this matter. As of May 2, 2005, the final income tax amount has not been agreed upon by Duke and us. However, based upon the payment already received, we do not anticipate any adverse impact to our results of operations or financial position in 2005. The monthly revenues from the Grays Harbor transportation agreement with Duke were approximately $1.6 million.

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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 2004 Annual Report on Form 10-K and with the condensed financial statements and notes thereto contained within this report.

Termination of the Grays Harbor Transportation Agreement

     Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to the Grays Harbor Lateral. We invoiced Duke the amount we believe is contractually owed by Duke according to the terms of the facilities reimbursement agreement. Duke has paid us approximately $88 million for the remaining net book value of the lateral facilities and approximately $6 million towards the related income taxes. We have invoiced Duke for an additional $30 million, representing the additional income taxes related to the termination of the contract. This amount has not been paid to date by Duke, and the income effects from the agreement termination have therefore been deferred pending the resolution of this matter. As of May 2, 2005, the final income tax amount has not been agreed upon by Duke and us. However, based upon the payment already received, we do not anticipate any adverse impact to our results of operations or financial position in 2005. The monthly revenues from the Grays Harbor transportation agreement with Duke were approximately $1.6 million.

2003 Pipeline Breaks in Washington

     In December 2003, we received an Amended Corrective Action Order (ACAO) from 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.

     By June 2004 we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 MDth/day of the 360 MDth/day of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

     The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Through March 31, 2005, approximately $41 million has been spent on testing and remediation costs, including approximately $8.9 million related to one segment of pipe that we determined not to return to service and was therefore written off in the second quarter of 2004.

     On October 4, 2004 we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original CAO. This penalty was accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to ensure that a similar situation would not occur in the future. We requested a hearing on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS will issue its decision in the near future.

     As 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 MDth/day of capacity being relinquished and incorporated into the replacement project. On November 29, 2004, we filed with the FERC a certificate of application for the “Capacity Replacement Project”, including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We

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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.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the three-month periods ended March 31, 2005 and 2004. Variances due to changes in price and volume have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

Three Months Ended March 31, 2005 vs. Three Months Ended March 31, 2004

     Operating revenues decreased $5.2 million, or 6 percent, due primarily to the termination of the Grays Harbor Agreement as described above.

     Northwest’s transportation service accounted for 96 percent and 97 percent of operating revenues for the three-month periods ended March 31, 2005 and 2004, respectively. Additionally, gas storage service accounted for 3 percent and 2 percent of operating revenues for the three-month periods ended March 31, 2005 and 2004 respectively.

     Operating income decreased $4.6 million, or 11 percent, due primarily to the lower operating revenues.

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

CAPITAL EXPENDITURES

     Our capital expenditures for the three months ended March 31, 2005 were $12.0 million, compared to $11.2 million for the three months ended March 31, 2004. We currently estimate our 2005 capital expenditures will be between $135 million and $160 million. Our capital expenditures estimate for 2005 is discussed in our 2004 Annual Report on Form 10-K.

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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.

     There has been no material change that occurred during the first fiscal quarter in our Internal Controls over financial reporting.

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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.

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.

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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.

	NORTHWEST PIPELINE CORPORATION
	Registrant

	By:	/s/ Jeffrey P. Heinrichs
		Jeffrey P. Heinrichs
		Controller (Duly Authorized Officer and Chief Accounting Officer)

Date: May 5, 2005

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