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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 September 30, 2005


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 by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 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 October 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 nine months ended September 30, 2005 and 2004		1

Condensed Balance Sheet as of September 30, 2005 and December 31, 2004		2

Condensed Statement of Cash Flows, nine months ended September 30, 2005 and 2004		4

Notes to Condensed Financial Statements		5

Item 2. Management’s Narrative Analysis of the Results of Operations		11

Item 4. Controls and Procedures		14

PART II. OTHER INFORMATION:

Item 1. Legal Proceedings		15

Item 6. Exhibits		15
Certification of Principal Executive Officer Pursuant to Section 302
Certification of Principal Financial Officer Pursuant to Section 302
Certification of Principal Executive and 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 and Second Quarter Reports on Form 10-Q.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENT OF INCOME

(Thousands of Dollars)
(Unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
OPERATING REVENUES	$	79,639		$	83,255		$	238,829		$	252,235


OPERATING EXPENSES:
General and administrative		13,999			14,867			41,722			45,052
Operation and maintenance		10,905			8,518			31,969			24,879
Depreciation		16,812			13,272			49,005			48,104
Regulatory credits		(1,189	)		(1,932	)		(3,379	)		(5,961	)
Taxes, other than income taxes		3,038			3,523			11,276			13,776
Impairment charges (adjustments)		—			(128	)		—			8,872


Total operating expenses		43,565			38,120			130,593			134,722


Operating income		36,074			45,135			108,236			117,513


OTHER INCOME – net		2,988			1,208			8,151			4,293


INTEREST CHARGES:
Interest on long-term debt		9,499			9,667			28,722			29,109
Other interest		842			899			2,557			2,589
Allowance for borrowed funds used during construction		(537	)		(97	)		(1,195	)		(275	)


Total interest charges		9,804			10,469			30,084			31,423


INCOME BEFORE INCOME TAXES		29,258			35,874			86,303			90,383

PROVISION FOR INCOME TAXES		11,006			13,858			32,545			34,337


NET INCOME	$	18,252		$	22,016		$	53,758		$	56,046


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)


	September 30,		December 31,
	2005		2004
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	92,610	$	53,393
Advance to affiliates		50,000		50,000
Accounts receivable -
Trade, less reserves of $91 for September 30, 2005 and $320 for December 31, 2004		27,452		30,486
Affiliated companies		117		1
Materials and supplies, less reserves of $369 for September 30, 2005 and $439 for December 31, 2004		8,442		8,601
Exchange gas due from others		10,983		16,011
Exchange gas offset		3,152		—
Deferred income taxes		5,628		4,173
Prepayments and other		1,458		855


Total current assets		199,842		163,520


PROPERTY, PLANT AND EQUIPMENT, at cost		2,230,355		2,273,333
Less – Accumulated depreciation		940,528		933,297


Total property, plant and equipment		1,289,827		1,340,036


OTHER ASSETS:
Deferred charges		48,872		50,019
Regulatory assets		40,453		36,361


Total other assets		89,325		86,380


Total assets	$	1,578,994	$	1,589,936

See accompanying notes.

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


	September 30,		December 31,
	2005		2004
LIABILITIES AND STOCKHOLDER’S EQUITY

CURRENT LIABILITIES
Accounts payable-
Trade	$	11,000	$	11,705
Affiliated companies		16,718		16,103
Accrued liabilities -
Income taxes due to affiliate		11,152		3,436
Taxes, other than income		14,569		11,599
Interest		8,880		7,294
Employee costs		6,362		8,277
Exchange gas due to others		14,135		13,939
Exchange gas offset		—		2,072
Deferred contract termination income		6,045		—
Other		3,689		2,367
Current maturities of long-term debt		7,500		7,500


Total current liabilities		100,050		84,292


LONG-TERM DEBT LESS CURRENT MATURITIES		512,576		520,062


DEFERRED INCOME TAXES		229,139		255,379


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		46,469		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		427,915		424,157


Total common stockholder’s equity		690,760		687,002


Total liabilities and stockholder’s equity	$	1,578,994	$	1,589,936

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENT OF CASH FLOWS

(Thousands of Dollars)
(Unaudited)


	Nine Months Ended
	September 30,
	2005			2004
OPERATING ACTIVITIES:
Net Income	$	53,758		$	56,046
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		49,005			48,104
Regulatory credits		(3,379	)		(5,961	)
Provision (benefit) for deferred income taxes		(27,695	)		24,518
Impairment charges		—			8,872
Amortization of deferred charges and credit		1,830			2,482
Allowance for equity funds used during construction		(2,245	)		(485	)
Reserve for doubtful accounts		44			—
Changes in:
Accounts receivable and exchange gas due from others		7,902			5,507
Materials and supplies		159			948
Other current assets		(3,755	)		(1,556	)
Deferred charges		(1,940	)		(7,926	)
Accounts payable, income taxes due to affiliate and exchange gas due to others		(1,425	)		(5,771	)
Other accrued liabilities		18,924			8,575
Other deferred credits		2,470			8,845


Net cash provided by operating activities		93,653			142,198


INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(83,019	)		(71,841	)
Proceeds from sales		—			2,470
Asset removal cost		(1,293	)		—
Changes in accounts payable		(541	)		881
Contract termination payment		87,917			—
Advances to affiliates		—			36,356


Net cash provided by (used in) investing activities		3,064			(32,134	)


FINANCING ACTIVITIES:
Principal payments on long-term debt		(7,500	)		(7,500	)
Dividends paid		(50,000	)		(60,000	)


Net cash used in financing activities		(57,500	)		(67,500	)


NET INCREASE IN CASH AND CASH EQUIVALENTS		39,217			42,564

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		53,393			653


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	92,610		$	43,217

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 $ 77.3 million, as of September 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 September 30, 2005 and December 31, 2004, and results of operations for the three and nine month periods ended September 30, 2005 and 2004, and cash flows for the nine months ended September 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 and Second Quarter Reports 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 November 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

expected to change significantly as a result of the exchange. We will apply SFAS No. 153 as required.

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 December 2004, the FASB issued revised 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 that 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, “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 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 anticipate expensing between $7 million and $10 million in 2006 that previously would have been capitalized. In September 2005, the FERC denied the Interstate Natural Gas Association of America’s filing for rehearing of this order.

Reclassifications

Certain reclassifications have been made in the 2005 prior interim period and 2004 financial statements to conform to the current period presentation.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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. 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 is in the process of considering whether to affirm or reject the special master’s recommendations and has scheduled oral argument for December 9, 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.

In the early 1990’s, we embarked upon a voluntary clean-up program at sites where we had previously used mercury meters throughout our areas of operations. In 2005, the Washington Department of Ecology required us to reevaluate our previous clean-ups in Washington prior to issuing permits required for the capacity replacement project. Currently, we are in the process of assessing the levels of potential contamination and performing remediation to bring the sites up to the current environmental standards. Subject to approval of our proposed work plans with the State of Washington, we estimate that the costs incident to these most recent voluntary assessments and clean-ups will be in the $4 million to $6 million range.

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 $95 million and $120 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

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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 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 in 2006. Through September 30, 2005, approximately $42 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 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. A hearing on the proposed OPS civil penalty occurred on December 15, 2004, in Denver, Colorado and a decision is pending.

As required by OPS, we plan to replace all capacity associated with the segment affected by the ACAO 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.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

and an additional 10,760 net horsepower of compression at two existing compressor stations. The original cost of the abandoned assets and any cost of removal, net of salvage, will be charged to Accumulated Depreciation. At September 30, 2005, the net book value of the assets to be abandoned was $83.2 million. The estimated total cost of the proposed Capacity Replacement Project included in the filing is approximately $333 million, net of a $3.3 million contribution-in-aid-of-construction from a shipper that agreed to relinquish 13 MDth/d of capacity. A favorable preliminary determination was issued in May 2005 and we received and accepted the final FERC certificate in September 2005. We plan to begin construction of certain critical river crossings in late 2005. The main construction of pipeline and compression will begin in early 2006 with an anticipated in-service date of November 1, 2006.

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 $713 million, none of which are associated with us, have been issued and no revolving credit loans were outstanding at September 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. under this agreement;

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

	•		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.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
			(Thousand of Dollars)
Net income, as reported	$	18,252	$	22,016	$	53,758	$	56,046
Add: Stock-based employee compensation included in the Condensed Statement of Income, net of related tax effects		19		45		48		45
Deduct: Stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		101		308		275		616

Pro forma net income	$	18,170	$	21,753	$	53,531	$	55,475

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. Accordingly, 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 with the FERC requesting that the 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 the FERC will rule on Northwest’s petition by the end of 2005.

6. IMPAIRMENT CHARGES

In the second quarter of 2004, we wrote off $8.9 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 and second quarter reports on Form 10-Q and within this report.

Termination of the Grays Harbor Transportation Agreement

2003 Pipeline Breaks in Washington

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On November 29, 2004, we filed an application with the FERC for certificate authorization to construct and operate the “Capacity Replacement Project”. This project entails the abandonment of approximately 268 miles of the existing 26-inch pipeline, and the construction of approximately 80 miles of new 36-inch pipeline and an additional 10,760 net horsepower of compression at two existing compressor stations. The original cost of the abandoned assets and any cost of removal, net of salvage, will be charged to Accumulated Depreciation. At September 30, 2005, the net book value of the assets to be abandoned was $83.2 million. The estimated total cost of the proposed Capacity Replacement Project included in the filing is approximately $333 million, net of a $3.3 million contribution-in-aid-of-construction from a shipper that agreed to relinquish 13 MDth/d of capacity. A favorable preliminary determination was issued in May 2005 and we received and accepted the final FERC certificate in September 2005. We plan to begin construction of certain critical river crossings in late 2005. The main construction of pipeline and compression will begin in early 2006 with an anticipated in-service date of November 1, 2006.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

This analysis discusses financial results of our operations for the nine-month periods ended September 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.

Nine Months Ended September 30, 2005 versus Nine Months Ended September 30, 2004

Operating revenues decreased $13.4 million, or 5 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 nine-month periods ended September 30, 2005 and 2004, respectively. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the nine-month periods ended September 30, 2005 and 2004, respectively.

Operating expenses decreased $4.1 million, or 3 percent, due primarily to the 2004 write-off of $8.9 million of previously capitalized costs incurred on an idled segment of our system that will not return to service, and $2.7 million in favorable adjustments to ad valorem taxes reflecting negotiated assessment reductions. These decreases were partially offset by $2.7 million in higher charges related to the rental of facilities, $2.6 million lower net regulatory credits associated primarily with the incremental Evergreen facilities (reference is made to the Property, Plant and Equipment policy in Note 1 of the 2004 Form 10-K Notes to Financial Statements for information about regulatory assets and regulatory credits) and a $1.5 million expense for amounts paid to a third party to modify a pipeline assessment tool for use in our 26-inch pipelines. Depreciation expense increased $0.9 million due primarily to a $5.4 million adjustment made in 2004 to correct an error related to the over depreciation of certain in-house developed system software and other general plant assets. This increase was mostly offset by lower depreciation in 2005 resulting from the retirement of the Grays Harbor Lateral.

Operating income decreased $9.3 million due to the reasons discussed above.

Other income increased $3.9 million primarily due to a $1.8 million increase in the allowance for equity funds used during construction resulting from the rising capital expenditures in 2005 and an increase of $1.1 million in interest income on higher levels of short term investments.

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


	Nine Months Ended
	September 30,
	2005		2004
Total Throughput (TBtu)		480		474

Average Daily Transportation Volumes (TBtu)		1.8		1.7
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		0.6


(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 nine months ended September 30, 2005 were $83.0 million, compared to $71.8 million for the nine months ended September 30, 2004. We currently estimate our 2005 capital expenditures will be between $130 million and $145 million. Our capital expenditures estimate for 2005 is discussed in our 2004 Annual Report on Form 10-K. The following describes a new capital project proposed by us.

Parachute Lateral Project On October 28, 2005, we announced an open season for an addition to our system that would provide additional natural gas transportation capacity for oncoming supply in the Parachute, Colorado area. As currently proposed, the Parachute Lateral Project would include approximately 38 miles of 30-inch diameter pipeline between Parachute and the Greasewood Hub at a cost of approximately $62 million. This design would provide approximately 575,000 dekatherms per day of transportation capacity. Based on the level of commitments, we will determine the final design, costs and rates for the expansion project. We expect to file a formal application with the FERC in January 2006. Subject to the necessary approvals, it is anticipated that construction would begin during the third quarter of 2006 and that service would be available in January 2007.

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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 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.

There has been no material change that occurred during the third 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.

(31)

Section 302 Certifications

(32)

Section 906 Certification


		-		a		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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		NORTHWEST PIPELINE CORPORATION

		Registrant

	By:	/s/ Jeffrey P. Heinrichs

		Jeffrey P. Heinrichs
		Controller
		(Duly Authorized Officer and
		Chief Accounting Officer)

Date: November 4, 2005

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.

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.