UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

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 June 30, 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

(Exact name of registrant as specified in its charter)

DELAWARE	87-0269236
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

295 Chipeta Way
Salt Lake City, Utah 84108

(Address of principal executive offices and Zip Code)

(801) 583-8800

(Registrant’s telephone number, including area code)

No Change

(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 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.

Class	Outstanding at July 31, 2005
Common stock, $1 par value	1,000 shares

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

	Page
PART I. FINANCIAL INFORMATION:
Item 1. Financial Statements -
Condensed Statement of Income, three and six months ended June 30, 2005 and 2004		2
Condensed Balance Sheet as of June 30, 2005 and December 31, 2004		3
Condensed Statement of Cash Flows, six months ended June 30, 2005 and 2004		5
Notes to Condensed Financial Statements		6
Item 2. Management’s Narrative Analysis of the Results of Operations		11
Item 4. Controls and Procedures		13
PART II. OTHER INFORMATION		14
Item 1. Legal Proceedings		14
Item 6. Exhibits		14
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Principal Executive Officer & Principal Financial Officer Pursuant to Section 906

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 Annual Report on Form 10-K and 2005 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)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
OPERATING REVENUES	$	78,907		$	83,504		$	159,190		$	168,980
OPERATING EXPENSES:
General and administrative		15,573			14,865			29,171			30,185
Operation and maintenance		10,013			8,598			19,616			16,361
Depreciation		15,983			17,718			32,193			34,832
Regulatory credits		(1,171	)		(1,931	)		(2,190	)		(4,029	)
Taxes, other than income taxes		4,011			5,123			8,238			10,253
Impairment charges		—			9,000			—			9,000
Total operating expenses		44,409			53,373			87,028			96,602
Operating income		34,498			30,131			72,162			72,378
OTHER INCOME – net		3,083			1,159			5,163			3,085
INTEREST CHARGES:
Interest on long-term debt		9,612			9,780			19,223			19,442
Other interest		855			838			1,715			1,690
Allowance for borrowed funds used during construction		(438	)		(148	)		(658	)		(178	)
Total interest charges		10,029			10,470			20,280			20,954
INCOME BEFORE INCOME TAXES		27,552			20,820			57,045			54,509
PROVISION FOR INCOME TAXES		10,363			7,747			21,539			20,479
NET INCOME	$	17,189		$	13,073		$	35,506		$	34,030
CASH DIVIDENDS ON COMMON STOCK	$	—		$	—		$	50,000		$	60,000

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED BALANCE SHEET

(Thousand of Dollars)

(Unaudited)

	June 30,		December 31,
	2005		2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	106,256	$	53,393
Advance to affiliates		50,000		50,000
Accounts receivable -
Trade, less reserves of $47 for June 30, 2005 and $320 for December 31, 2004		26,240		30,486
Affiliated companies		113		1
Materials and supplies, less reserves of $387 for June 30, 2005 and $439 for December 31, 2004		8,534		8,601
Exchange gas due from others		7,658		16,011
Exchange gas offset		2,655		—
Deferred income taxes		6,522		4,173
Prepayments and other		1,353		855
Total current assets		209,331		163,520
PROPERTY, PLANT AND EQUIPMENT, at cost		2,187,876		2,273,333
Less — Accumulated depreciation		925,020		933,297
Total property, plant and equipment		1,262,856		1,340,036
OTHER ASSETS:
Deferred charges		48,989		50,019
Regulatory assets		39,129		36,361
Total other assets		88,118		86,380
Total assets	$	1,560,305	$	1,589,936

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)

	June 30,		December 31,
	2005		2004
LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES
Accounts payable-
Trade	$	11,847	$	11,705
Affiliated companies		21,527		16,103
Accrued liabilities -
Income taxes due to affiliate		5,989		3,436
Taxes, other than income		12,845		11,599
Interest		7,294		7,294
Employee costs		6,853		8,277
Exchange gas due to others		10,313		13,939
Exchange gas offset		—		2,072
Deferred contract termination income		6,045		—
Other		3,232		2,367
Current maturities of long-term debt		7,500		7,500
Total current liabilities		93,445		84,292
LONG-TERM DEBT LESS CURRENT MATURITIES		520,071		520,062
DEFERRED INCOME TAXES		230,633		255,379
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		43,648		43,201
CONTINGENT LIABILITIES AND COMMITMENTS
COMMON STOCKHOLDER’S EQUITY:
Common stock, par value $1 per share; authorized and outstanding, 1,000 shares		1		1
Additional paid-in capital		262,844		262,844
Retained earnings		409,663		424,157
Total common stockholder’s equity		672,508		687,002
Total liabilities and stockholder’s equity	$	1,560,305	$	1,589,936

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	Six Months Ended
	June 30,
	2005			2004
OPERATING ACTIVITIES:
Net Income	$	35,506		$	34,030
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		32,193			34,832
Regulatory credits		(2,190	)		(4,029	)
Provision for deferred income taxes		(27,095	)		14,097
Impairment charges		—			9,000
Amortization of deferred charges and credit		11			2,526
Allowance for equity funds used during construction		(1,232	)		(319	)
Reserve for doubtful accounts		9			—
Changes in:
Accounts receivable and exchange gas due from others		12,478			6,922
Materials and supplies		67			952
Other current assets		(3,153	)		(1,035	)
Deferred charges		(1,140	)		(5,724	)
Accounts payable, income taxes due to affiliate and exchange gas due to others		619			(6,896	)
Other accrued liabilities		10,485			6,364
Other deferred credits		1,218			7,268
Net cash provided by operating activities		57,776			97,988
INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(41,553	)		(45,238	)
Proceeds from sales		—			1,487
Asset removal cost		(526	)		—
Changes in accounts payable		(751	)		408
Contract termination payment		87,917			—
Advances to affiliates		—			36,356
Net cash provided by (used in) investing activities		45,087			(6,987	)
FINANCING ACTIVITIES:
Dividends paid		(50,000	)		(60,000	)
Net cash used in financing activities		(50,000	)		(60,000	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		52,863			31,001
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		53,393			653
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	106,256		$	31,654

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 $ 78.4 million, as of June 30, 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 June 30, 2005 and December 31, 2004, and results of operations for the three and six month periods ended June 30, 2005 and 2004, and cash flows for the six months ended June 30, 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 and 2005 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. 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 Developments

     In December 2004, the Financial Accounting Standards Board (FASB) issued revised Statement of Financial 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 revised 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.

     The revised Statement allows either a modified prospective application or a modified retrospective application for adoption. We will use a modified prospective application for adoption and thus will apply the statement to new awards and to awards modified, repurchased, or cancelled after January 1, 2006. Also, for unvested stock awards outstanding as of January 1, 2006, compensation costs for the portion of these awards for which the requisite service has not been rendered will be recognized as the requisite service is rendered after January 1, 2006. Compensation costs for these awards will be based on fair value at the original grant date as estimated for the pro forma disclosures under SFAS No. 123, as amended by SFAS No. 148,

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“Accounting for Stock-Based Compensation — Transition and Disclosure – an amendment of SFAS No. 123.” Additionally, a modified retrospective application requires restating periods prior to January 1, 2006, on a basis consistent with the pro forma disclosures required by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148. Since we plan to use a modified prospective application, we will not restate prior periods.

     In March 2005, the FASB issued Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations-an interpretation of FASB Statement No. 143.” The Interpretation 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. This 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.

     In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of Accounting Research Bulletin (ARB) No. 43, Chapter 4,” which will be applied prospectively for inventory costs incurred in fiscal years beginning after June 15, 2005. The Statement amends ARB No. 43, Chapter 4, “Inventory Pricing” to clarify the accounting for abnormal amounts of certain costs and the allocation of overhead costs. We are assessing the impact of this Statement on our financial statements and believe the effect will not be material.

     In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets, an amendment of Accounting Principles Board (APB) Opinion No. 29,” which is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005, and will be applied prospectively. The Statement amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” The guidance in APB Opinion No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged but includes certain exceptions to that principle. SFAS No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. We will apply SFAS No. 153 as required.

     In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections — a Replacement of APB Opinion No. 20 and FASB Statement No. 3,” which is effective for reporting a change in accounting principle for fiscal years beginning after December 15, 2005. The Statement changes the reporting of a change in accounting principle to require retrospective application to prior periods’ financial statements, except for explicit transition provisions provided for in new accounting pronouncements or existing accounting pronouncements, including those in the transition phase when SFAS No. 154 becomes effective. We will apply SFAS No. 154 as required.

     FERC Accounting Guidance On June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Cost,” to be effective January 1, 2006.The order requires companies to expense certain assessment costs that we have historically capitalized. We are assessing the financial impact of the order and anticipate receiving updates throughout the remainder of 2005. The Interstate Natural Gas Association of America, an industry trade association, has filed for rehearing of this order.

Reclassifications

     Certain reclassifications have been made in the 2004 financial statements to conform to the 2005 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 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. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against certain of the Williams defendants, including us. The District Court began the process of considering whether to affirm or reject the special master’s recommendations in June 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. On June 15, 2005, the FERC approved a settlement between Williams and the FERC staff resolving that investigation, pursuant to which an affiliated pipeline paid a civil penalty and made refunds to its firm storage customers. As a result, this had no effect upon our financial position or results of operations.

     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 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

8

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 June 30, 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.

     On May 31, 2005, the FERC issued an order making a preliminary determination, subject to completion of environmental review, that the benefits of our Capacity Replacement Project will outweigh any potential adverse impacts and that it is required by the public convenience and necessity in view of the OPS CAO. A Final Environmental Impact Statement was issued in late July 2005. We anticipate receiving a final certificate order in the Fall of 2005, which will allow early construction on the critical river crossings this year with station and pipeline construction occurring next year to allow new facilities to be placed in service no later than December 2006.

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 $531 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at June 30, 2005. During May 2005, we, together with Williams and Transcontinental Gas Pipe Line Corporation (Transco), an affiliate, amended and restated this agreement resulting in certain changes, including the following:

• added Williams Partners L.P. as a borrower for up to $75 million;

• provided Williams guarantee for the obligations of Williams Partners L.P.;

• released certain Williams’ midstream assets held as collateral and replaced them with the common stock of Transco; and

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• reduced commitment fees and margins.

4. STOCK-BASED COMPENSATION

     Employee stock-based awards are accounted for under 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”. We currently calculate fair value using the Black-Scholes pricing model.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
	(Thousand of Dollars)
Net income, as reported	$	17,189	$	13,073	$	35,506	$	34,030
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		54		152		145		308
Pro forma net income	$	17,135	$	12,921	$	35,361	$	33,722

     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 and Northwest’s tariff. 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. While the final income tax amount has not been agreed upon by Duke and us, 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.

     On June 16, 2005, we filed a Petition for a Declaratory Order at the FERC requesting that FERC rule on our interpretation of Northwest’s tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed its motion to intervene and provided comments supporting its position concerning the issues in dispute. We anticipate that FERC will rule on Northwest’s petition sometime in 2005.

6. 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.

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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 and Item 2 contained our 2005 first quarter report on Form 10-Q and within this report.

Termination of the Grays Harbor Transportation Agreement

     Effective January 2005, 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 and Northwest’s tariff. 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. While the final income tax amount has not been agreed upon by Duke and us, 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.

     On June 16, 2005, we filed a Petition for a Declaratory Order at the FERC requesting that FERC rule on our interpretation of Northwest’s tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed its motion to intervene and provided comments supporting its position concerning the issues in dispute. We anticipate that FERC will rule on Northwest’s petition sometime in 2005.

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 June 30, 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

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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.

     On May 31, 2005, the FERC issued an order making a preliminary determination, subject to completion of environmental review, that the benefits of our Capacity Replacement Project will outweigh any potential adverse impacts and that it is required by the public convenience and necessity in view of the OPS CAO. A Final Environmental Impact Statement was issued in late July 2005. We anticipate receiving a final certificate order in the Fall of 2005, which will allow early construction on the critical river crossings this year with station and pipeline construction occurring next year to allow new facilities to be placed in service no later than December 2006.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the six-month periods ended June 30, 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.

Six Months Ended June 30, 2005 versus Six Months Ended June 30, 2004

     Operating revenues decreased $9.8 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 six-month periods ended June 30, 2005 and 2004, respectively. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the six-month periods ended June 30, 2005 and 2004, respectively.

     Operating costs and expenses decreased $9.6 million, or 10 percent, due primarily to the 2004 write-off of $9.0 million of previously capitalized costs incurred on an idled segment of our system that will not return to service, a $2.6 million decrease in depreciation expense primarily due to the book retirement of the Grays Harbor Lateral, and a $1.6 million favorable adjustment to ad valorem taxes reflecting recent updates to state tax rates, partially offset by $1.8 million in higher charges related to the rental of facilities and a $1.4 million expense for amounts paid to a third party to modify a pipeline assessment tool for use in our 26-inch pipelines.

     Operating income decreased $0.2 million due to the reasons discussed above.

     Other income increased $2.1 million primarily due to interest income on higher levels of short term investments.

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

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	Six Months Ended June 30,
	2005		2004
Total Throughput (TBtu)		327		330
Average Daily Transportation Volumes (TBtu)		1.8		1.8
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity (TBtu)		2.5		2.5
Average Daily Reserved Capacity Under Short- Term Firm Contracts (TBtu) (1)		0.8		0.5

(1) Includes additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis.

CAPITAL EXPENDITURES

     Our capital expenditures for the six months ended June 30, 2005 were $41.6 million, compared to $45.2 million for the six months ended June 30, 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.

ITEM 4. Controls and Procedures

     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 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.

     On May 1, 2005, we completed the first of a series of system implementations which are part of a Williams’ initiative to move to common enterprise accounting systems. The implementations primarily relate to the replacement of our primary accounting system used to process, accumulate and summarize accounting information including capital projects, property and depreciation and amortization records. Our management believes that there was no negative impact on our internal controls.

     Other than as described above, there has been no material change that occurred during the second 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.

(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	Amended and Restated Credit Agreement dated as of May 20, 2005 among The Williams Companies, Inc., Williams Partner L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and the Banks, Citibank, N.A. and Bank of America, N.A. (each, an “Issuing Bank”), and Citicorp USA, INC. as administrative agent. (filed as Exhibit 1.1 to Form 8-K filed May 26, 2005).
	(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 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: August 4, 2005