10-Q

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, 2007

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 GP

(Exact name of registrant as specified in its charter)

DELAWARE	26-1157701
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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)

Northwest Pipeline Corporation

(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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o           Accelerated filer o           Non-accelerated filer 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.

Not Applicable

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 GP

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION:
Item 1. Financial Statements -
Condensed Statements of Income, three and nine months ended September 30, 2007 and 2006		1
Condensed Balance Sheets as of September 30, 2007 and December 31, 2006		2
Condensed Statements of Cash Flows, nine months ended September 30, 2007 and 2006		4
Notes to Condensed Financial Statements		5
Item 2. Management’s Narrative Analysis of the Results of Operations		12
Item 4. Controls and Procedures		15
PART II. OTHER INFORMATION:
Item 1. Legal Proceedings		16
Item 1A. Risk Factors		16
Item 6. Exhibits		22
Certification of Principal Executive Officer
Certification of Principal Financial Officer
Certification of Principal Executive Officer and Principal Financial Officer

     Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements 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.

     All statements, other than statements of historical facts, included in this report, which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Business strategy;

• Cash flow from operations; and

• Power and natural gas prices and demand.

 i

     Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this document. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

• Availability of supplies ( including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;

• Inflation, interest rates, and general economic conditions;

• The strength and financial resources of our competitors;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations including proposed climate change legislation, environmental liabilities, litigation, and rate proceedings;

• Changes in the current geopolitical situation;

• Risks related to strategy and financing, including restrictions stemming from our debt agreements and our lack of investment grade credit ratings; and

• Risk associated with future weather conditions and acts of terrorism.

     Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

     In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

     Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 and Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007.

ii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENTS OF INCOME

(Thousands of Dollars)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
OPERATING REVENUES	$	106,364		$	81,088		$	312,062		$	240,641
OPERATING EXPENSES:
General and administrative		15,472			17,958			46,827			44,823
Operation and maintenance		17,328			15,352			48,172			45,686
Depreciation		20,378			18,004			59,783			53,188
Regulatory credits		(1,811	)		(1,080	)		(3,556	)		(3,696	)
Taxes, other than income taxes		3,943			3,113			10,423			12,027
Regulatory liability reversal (Note 1)		—			—			(16,562	)		—
Total operating expenses		55,310			53,347			145,087			152,028
Operating income		51,054			27,741			166,975			88,613
OTHER INCOME – net
Interest income –
Affiliated		1,026			998			1,663			2,945
Other		2,314			1,350			2,679			2,599
Allowance for equity funds used during construction		261			3,667			1,772			6,801
Miscellaneous other income (expense), net		468			(4,395	)		1,469			(705	)
Contract termination income (Note 3)		12,154			—			18,199			895
Total other income, net		16,223			1,620			25,782			12,535
INTEREST CHARGES:
Interest on long-term debt		11,491			12,377			35,595			31,566
Other interest		1,559			955			4,097			2,868
Allowance for borrowed funds used during construction		(168	)		(1,866	)		(1,102	)		(3,466	)
Total interest charges		12,882			11,466			38,590			30,968
INCOME BEFORE INCOME TAXES		54,395			17,895			154,167			70,180
PROVISION FOR INCOME TAXES		20,469			6,622			58,320			25,531
NET INCOME	$	33,926		$	11,273		$	95,847		$	44,649

See accompanying notes.

- 1 -

NORTHWEST PIPELINE CORPORATION

CONDENSED BALANCE SHEETS

(Thousand of Dollars)

	September 30,		December 31,
	2007		2006
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	121	$	1,489
Advance to affiliates		89,335		49,980
Accounts receivable -
Trade, less reserves of $7 for September 30, 2007 and $53 for December 31, 2006		40,429		32,230
Affiliated companies		1,522		591
Materials and supplies, less reserves of $454 for September 30, 2007 and $472 for December 31, 2006		10,154		10,013
Exchange gas due from others		4,964		10,556
Exchange gas offset		2,367		4,538
Deferred income taxes		2,139		4,066
Prepayments and other		8,080		7,945
Total current assets		159,111		121,408
PROPERTY, PLANT AND EQUIPMENT, at cost		2,764,572		2,669,056
Less – Accumulated depreciation		937,073		893,033
Total property, plant and equipment		1,827,499		1,776,023
OTHER ASSETS:
Deferred charges		39,353		32,093
Regulatory assets		53,424		47,829
Total other assets		92,777		79,922
Total assets	$	2,079,387	$	1,977,353

See accompanying notes.

- 2 -

NORTHWEST PIPELINE CORPORATION
CONDENSED BALANCE SHEETS
(Thousands of Dollars)

	September 30,			December 31,
	2007			2006
	(Unaudited)
LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
Accounts payable-
Trade	$	36,057		$	55,403
Affiliated companies		7,900			13,701
Accrued liabilities -
Income taxes due to affiliate		16,465			3,090
Taxes, other than income taxes		11,490			6,779
Interest		16,528			7,038
Employee costs		7,630			10,759
Exchange gas due to others		7,331			15,094
Deferred contract termination income		—			6,045
Other		3,780			5,268
Current maturities of long-term debt		250,000			252,867
Total current liabilities		357,181			376,044
LONG-TERM DEBT LESS CURRENT MATURITIES		443,703			434,208
DEFERRED INCOME TAXES		277,843			255,469
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		90,875			98,595
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		327,844			327,844
Retained earnings		598,900			503,055
Accumulated other comprehensive income		(16,960	)		(17,863	)
Total common stockholder’s equity		909,785			813,037
Total liabilities and stockholder’s equity	$	2,079,387		$	1,977,353

See accompanying notes.

- 3 -

NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	Nine Months Ended
	September 30,
	2007			2006
OPERATING ACTIVITIES:
Net Income	$	95,847		$	44,649
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		59,783			53,188
Regulatory credits		(3,556	)		(3,696	)
Provision for deferred income taxes		23,758			25,331
Amortization of deferred charges and credit		7,705			2,204
Allowance for equity funds used during construction		(1,772	)		(6,801	)
Reserve for doubtful accounts		(46	)		—
Regulatory liability reversal		(16,562	)		—
Contract termination income		(6,045	)		—
Changes in:
Trade accounts receivable		(8,153	)		757
Affiliated receivables, including income taxes		(931	)		3,998
Exchange gas due from others		7,763			5,265
Materials and supplies		(141	)		(1,537	)
Other current assets		(135	)		(1,121	)
Deferred charges		(5,513	)		(1,385	)
Trade accounts payable		1,331			(4,903	)
Affiliated payables, including income taxes		7,574			17,526
Exchange gas due to others		(7,763	)		(5,265	)
Other accrued liabilities		11,258			10,366
Other deferred credits		2,130			3,657
Net cash provided by operating activities		166,532			142,233
FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		184,362			174,447
Retirement of long-term debt		(2,867	)		(7,500	)
Prepayments of long-term debt		(175,000	)		—
Debt issuance costs		(2,175	)		(2,310	)
Premium on early retirement of long-term debt		(7,111	)		—
Changes in cash overdrafts		(35,555	)		3,762
Net cash provided by (used in) financing activities		(38,346	)		168,399
INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(106,099	)		(313,728	)
Proceeds from sales		—			(31,212	)
Asset removal cost		2,697			—
Changes in accounts payable		13,203			15,404
Proceeds from contract termination payments (Note 3)		—			3,348
Advances to affiliates		(39,355	)		20
Net cash used in investing activities		(129,554	)		(326,168	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(1,368	)		(15,536	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,489			59,709
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	121		$	44,173

See accompanying notes.

- 4 -

NORTHWEST PIPELINE CORPORATION

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

     On September 30, 2007, Northwest Pipeline Corporation (Northwest) was owned 11.6 percent by Williams Pipeline Partners Holdings LLC and 88.4 percent by WGPC Holdings LLC, both indirect wholly-owned subsidiaries 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”.

     During third quarter 2007, Williams formed Williams Pipeline Partners L.P. (WMZ) to own and operate natural gas transportation and storage assets. On September 12, 2007, WMZ filed a registration statement on Form S-1 with the Securities Exchange Commission relating to a proposed underwritten initial public offering of common units representing limited partner interests. On October 29, 2007, WMZ filed an amendment to the registration statement. An affiliate of ours will serve as the general partner of WMZ. The initial asset of the new partnership will be a 25 percent interest in Northwest Pipeline GP (Northwest GP).

     On October 1, 2007, Northwest converted from a Delaware corporation to a general partnership, Northwest GP. Coincident with the conversion, the partners of Northwest GP entered into a partnership agreement. Northwest GP is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986) or enhances operations that generate such qualified income. The partners holding partnership interests in Northwest GP are WGPC Holdings, LLC and Williams Pipeline Partners Holdings LLC, both indirect, wholly-owned subsidiaries of Williams. Because of our conversion to a general partnership, we will no longer be subject to federal and state income taxes. As of October 1, 2007, approximately $275.7 million deferred income tax liabilities will be reversed.

Basis of Presentation

     Our 1983 acquisition by Williams has been accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price 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 $68.7 million, as of September 30, 2007, to us as current Federal Energy Regulatory Commission (FERC) policy does not permit us to recover these amounts through our rates and we are not otherwise required to do so. 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, 2007 and December 31, 2006, and results of operations for the three and nine month periods ended September 30, 2007 and 2006, and cash flows for the nine months ended September 30, 2007 and 2006. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2006 Annual Report on Form 10-K and 2007 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)

- 5 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

deferred and other income taxes; 6) depreciation; 7) pension and other post-employment benefits; and 8) asset retirement obligations.

     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter.

Recent Accounting Standards

     Effective January 1, 2007, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured as the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

     FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We adopted FIN 48 beginning January 1, 2007, as required. The adoption of FIN 48 did not have a material effect on our financial position or results of operations.

     Our policy is to recognize interest and penalties related to unrecognized tax benefits as a component of income tax expense.

     As of January 1, 2007, the IRS examination of Williams’ consolidated U.S. income tax return for 2002 was in process. The Williams’ consolidated U.S. income tax return incorporates our tax information. During the first quarter of 2007, the IRS also commenced examination of Williams’ 2003 through 2005 consolidated U.S. income tax returns. IRS examinations for 1996 through 2001 have been completed but the years remain open while certain issues are under review with the Appeals Division of the IRS. The statute of limitations for most states expires one year after IRS audit settlement.

FERC Accounting and Reporting Guidance

     On March 29, 2007, the FERC issued “Commission Accounting and Reporting Guidance to Recognize the Funded Status of Defined Benefit Postretirement Plans.” The guidance is being provided to all jurisdictional entities to ensure proper and consistent implementation of Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158) for FERC financial reporting purposes beginning with the 2007 FERC Form 2 to be filed in 2008. We completed our evaluation and applied the FERC guidance during the second quarter of 2007. It had no effect on our financial statements.

Change in Accounting Estimate

     In the second quarter of 2007, we recorded $16.6 million in income for a change in accounting estimate related to a pension regulatory liability. We have historically recorded a regulatory asset or liability for the difference between pension expense as estimated under Statement of Financial Accounting Standards No. 87, “Employer’s Accounting for Pensions,” and the amount we funded as a contribution to our pension plans. As a result of recent information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and have concluded that it is not probable that it will be refundable or recoverable in future rates.

- 6 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

Reclassifications

     A regulatory asset has been recorded in connection with our asset retirement obligations, and is being recovered through the negative salvage component of depreciation included in our rates. The negative salvage component of accumulated depreciation has been previously classified as a non-current regulatory liability. Beginning in 2007, the regulatory asset has been offset against the regulatory liability and prior periods have been reclassified to conform to the current period presentation.

     Certain reclassifications have been made to the 2006 financial statements to conform to the 2007 presentation, including reflecting the change in bank overdrafts as financing activities and additional changes in capital related accounts payable as investing activities in the condensed statement of cash flows.

2. RATE AND REGULATORY MATTERS

General Rate Case (Docket No. RP06-416)

     On June 30, 2006, we filed a general rate case under Section 4 of the Natural Gas Act. On July 31, 2006, the FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement to resolve all outstanding issues in our pending rate case. On March 30, 2007, the FERC approved the submitted settlement. The settlement specified an annual cost of service of $404 million and increased our general system firm transportation rates from $0.30760 to $0.40984 per Dth, effective January 1, 2007. Refunds to customers were made during April 2007.

Parachute Lateral

     On August 24, 2007, we filed an application with the FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created subsidiary, Parachute Pipeline LLC (Parachute), while we retain the rights and obligations associated with operating the Parachute Lateral facilities under the amended FERC certificate. As contemplated in the application for amendment, Parachute will lease the facilities back to us. Under the terms of the lease, we will pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less three percent to cover costs related to the operation of the lateral. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. The Parachute Lateral facilities are anticipated to be contributed to Parachute prior to December 2007.

     Although the Parachute Lateral facilities were originally built to provide transportation for pipeline-quality natural gas being produced in the Parachute area, approval of the certificate amendment is the first step towards moving these facilities from our interstate pipeline system to the gathering and processing function of Williams Field Services Company, LLC (Williams Field Services), which is owned by Williams. When Williams Field Services completes its Willow Creek Processing Plant, it is contemplated that the lease (subject to further regulatory approval) will terminate, and Parachute, as a subsidiary of Williams Field Services, will assume full operational control and responsibility for the Parachute Lateral.

3. 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 had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was 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, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui

- 7 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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 remained pending against Williams, including us, and the other defendants, although the defendants had filed a number of motions to dismiss these claims on jurisdictional grounds. 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 us and certain of the other Williams defendants. On October 20, 2006, the District Court dismissed all claims against us. Mr. Grynberg filed a Notice of Appeal from the dismissals with the Tenth Circuit Court of Appeals effective November 17, 2006.

Environmental Matters

     We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, management believes that we are in substantial compliance with existing environmental requirements. We believe that, with respect to any additional expenditures required to meet applicable standards and regulations, the FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates.

     Beginning in the mid-1980’s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (PCB) contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency in the late 1980’s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990’s. In 2005, the Washington Department of Ecology required us to reevaluate our previous mercury clean-ups in Washington. Currently, we are assessing the actions needed to bring the sites up to Washington’s current environmental standards. At September 30, 2007, we have accrued liabilities totaling approximately $6.9 million for these costs which are expected to be incurred through 2011. We consider these costs associated with compliance with these environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

     Pipeline Integrity Regulations We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration final rule that was issued 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 remediation will be between $195 million and $215 million over the remaining assessment period of 2007 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.

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 was contractually owed by Duke according to the terms of the facilities reimbursement agreement and our tariff.  Duke initially 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 invoiced Duke for an additional $30 million, representing the additional income taxes related to the termination of the contract.  Duke disputed this additional amount. We recorded a reserve against the full $30 million invoiced and deferred recognition of the $6 million received from Duke related to income taxes.

- 8 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

     On June 16, 2005, we filed a Petition for a Declaratory Order with the FERC requesting that it rule on our interpretation of our tariff to aid in resolving the dispute with Duke.  On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order (2006 Order) addressing a possible equitable solution but not directly addressing the tariff interpretation issues that we had presented. On November 3, 2006, we filed a request for rehearing of the FERC’s 2006 Order seeking a FERC determination of our tariff language concerning mid-term contractual buyouts and further clarification of the underlying principles of a possible equitable solution.  On June 15, 2007, the Federal Energy Regulatory Commission issued its Order on Rehearing in response to our request for rehearing, reaffirming its 2006 Order, but providing specific clarifications as to how the Duke buyout amount should be calculated with respect to related taxes.

     As a result of the Order on Rehearing, $6 million of previously deferred income was recognized in June 2007. Based upon terms of the Order, we also sought an additional $14.5 million (including interest of $2.3 million) from Duke. On September 24, 2007, Northwest received final payment from Duke in the amount of $14.5 million, which represents full payment (with interest) to Northwest of the amount that was recently invoiced to Duke. This final payment was recorded as other income in September 2007.

Other Matters

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

Summary

     Litigation, arbitration, regulatory matters, environmental matters, and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements, will not have a material adverse effect upon our future financial position.

4. DEBT AND FINANCING ARRANGEMENTS

Revolving Credit and Letter of Credit Facilities

     Under Williams’ $1.5 billion unsecured revolving credit facility, letters of credit totaling $28.0 million, none of which were issued on our behalf, have been issued by the participating institutions and no revolving credit loans were outstanding under the facility at September 30, 2007.

     On May 9, 2007, Williams amended its $1.5 billion unsecured credit facility, extending the maturity date from May 1, 2009 to May 1, 2012. Applicable borrowing rates and commitment fees for investment grade credit ratings were also modified.

Long-Term Debt

     Current maturities

     The current maturities of long-term debt at September 30, 2007 are associated with $250 million of 6.625 percent notes that mature on December 1, 2007. We plan to refinance this debt.

     Issuances and retirements

     On April 4, 2007, we retired $175 million of 8.125 percent senior unsecured notes due 2010. We paid premiums of approximately $7.1 million in conjunction with the early debt retirement. These premiums are considered recoverable through rates and are therefore deferred as a component of deferred charges on our condensed balance sheet, amortizing over the life of the original debt.

- 9 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

     On April 5, 2007, we issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017 to certain institutional investors in a private debt placement.

     Registration payment arrangements

     Under the terms of our $185 million 5.95 percent senior unsecured notes mentioned above, we were obligated to file a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act of 1933, as amended, within 180 days from closing and use commercially reasonable efforts to cause the registration statement to be declared effective within 270 days after closing. We initiated an exchange offer on July 26, 2007, which expired on August 23, 2007. We received full participation in the exchange offer.

5. TRANSACTIONS WITH AFFILIATES

     Included in our operating revenues for the nine months ending September 30, 2007 and 2006 are amounts received from affiliates for transportation and exchange transactions of $7.8 million and $1.8 million, respectively. The rates charged to provide services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

     Also included in our operating revenues for the nine months ending September 30, 2006 are amounts received for processed liquids associated with mainline gas of $0.3 million, which are received by us merely as a conduit to pass the revenues through to our customers who own the gas. For the nine months ending September 30, 2007, amounts received for processed liquids were not material.

     Williams has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for the nine months ending September 30, 2007 and 2006 are $13.4 million and $13.3 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

6. COMPREHENSIVE INCOME

     Comprehensive income is as follows:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Thousands of Dollars)						(Thousands of Dollars)
Net income	$	33,926		$	11,273		$	95,847		$	44,649
Gain on cash flow hedges		—			—			—			387
Reclassification of cash flow hedge gain into earnings, net of tax		(10	)		(10	)		(29	)		(12	)
Pension benefits, net of tax
Amortization of prior service cost		12			—			36			—
Amortization of net actuarial loss		299			—			896			—
Total comprehensive income	$	34,227		$	11,263		$	96,750		$	45,024

- 10 -

NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

     The gain on cash flow hedges for the nine months ending September 30, 2006 represents a realized gain on forward starting interest rate swaps that we entered into prior to our issuance of fixed rate, long-term debt in the second quarter 2006. The swaps, which were settled near the date of the debt issuance, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate debt.

- 11 -

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

GENERAL

     The following discussion 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 2006 Annual Report on Form 10-K and with the condensed financial statements and notes thereto contained in Item 2 of our 2007 first and second quarter reports on Form 10-Q and within this report.

Recent Events

     During third quarter 2007, Williams formed Williams Pipeline Partners L.P. (WMZ) to own and operate natural gas transportation and storage assets. On September 12, 2007, WMZ filed a registration statement on Form S-1 with the Securities Exchange Commission relating to a proposed underwritten initial public offering of common units representing limited partner interests. On October 29, 2007, WMZ filed an amendment to the registration statement. An affiliate of ours will serve as the general partner of WMZ. The initial asset of the new partnership will be a 25 percent interest in Northwest Pipeline GP.

     On October 1, 2007, in conjunction with the new master limited partnership, Northwest converted from a Delaware corporation to a general partnership. Coincident with the conversion, the partners of Northwest GP entered into a partnership agreement. Northwest GP is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986 ) or enhances operations that generate such qualified income. The partners holding partnership interests in Northwest GP are WGPC Holdings, LLC and Williams Pipeline Partners Holdings LLC, both indirect, wholly-owned subsidiaries of Williams. Because of our conversion to a general partnership, we will no longer be subject to federal and state income taxes. As of October 1, 2007, approximately $275.7 million deferred income tax liabilities will be reversed.

General Rate Case (Docket No. RP06-416)

     On June 30, 2006, we filed a general rate case under Section 4 of the Natural Gas Act. On July 31, 2006, the FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement to resolve all outstanding issues in our pending rate case. On March 30, 2007, the FERC approved the submitted settlement. The settlement specified an annual cost of service of $404 million and increased our general system firm transportation rates from $0.30760 to $0.40984 per Dth, effective January 1, 2007. Refunds to customers were made during April 2007.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the nine-month periods ended September 30, 2007 and 2006. 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.

     Our operating revenues increased $71.4 million, or 30 percent. Higher rates resulting from our rate case are the primary source of this increase. In addition, the Parachute lateral, placed into service in May 2007, contributed $3.9 million to our revenues. (See Capital Expenditures below.)

     Our transportation service accounted for 96 percent and our gas storage service accounted for 3 percent of our operating revenues for each of the nine-month periods ended September 30, 2007 and 2006.

- 12 -

     Operating expenses decreased $6.9 million, or 5 percent. This decrease is due primarily to the June 2007 reversal of our pension regulatory liability of $16.6 million as described in Note 1 of the Notes to Condensed Financial Statements and $1.6 million reduction in taxes other than income taxes reflecting lower than expected 2007 tax assessments on our property. These decreases were partially offset by a $6.6 million increase in depreciation related to new property additions, a $2.6 million increase in labor due primarily to annual salary increases, a $1.4 million increase in group insurance expense due primarily to rising medical costs and a $1.3 million increase in lease expense due to the correction of an error in accounting for our headquarters building lease in the fourth quarter of 2006.

     Other income increased $13.2 million, or 106 percent, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million additional contract termination income and $2.3 million additional interest related to the termination of the Grays Harbor transportation agreement as discussed in Note 3 of the Notes to Condensed Financial Statements. These increases were offset by a $5.0 million decrease in the allowance for equity funds used during construction resulting from the lower capital expenditures in 2007, a $1.3 million decrease in interest income from affiliates resulting from note repayments from Williams, and a $2.3 million decrease in other interest income resulting from lower short-term investments.

     Interest charges increased $7.6 million, or 25 percent, due primarily to the issuance of $175 million 7 percent debt due 2016 in June of 2006 and the issuance of $185 million 5.95 percent debt due 2017 in April of 2007, partially offset by the early retirement of the $175 million 8.125 percent debt due 2010 in April of 2007. A $2.4 million decrease in the allowance for borrowed funds used during construction related to the lower capital expenditures in 2007 and a $1.2 million increase in other interest also contributed to this increase.

     The provision for income taxes increased $32.8 million, or 128 percent, due primarily to higher pre-tax income in 2007 as compared to 2006. Our effective tax rate was 37.8 percent and 36.4 percent in 2007 and 2006, respectively.

Operating Statistics

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

	Nine Months Ended
	September 30,
	2007		2006
Total Throughput (TBtu)		536		479
Average Daily Transportation Volumes (TBtu)		2.0		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		0.9

(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.

METHOD OF FINANCING

     On April 4, 2007, we retired $175 million of 8.125 percent senior unsecured notes due 2010. We paid premiums of approximately $7.1 million in conjunction with the early debt retirement. These premiums are considered recoverable through rates and are therefore deferred as a component of deferred charges on our condensed balance sheet, amortizing over the life of the original debt.

     On April 5, 2007, we issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017 to certain institutional investors in a private debt placement. In August 2007, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

- 13 -

CAPITAL EXPENDITURES

     Our capital expenditures for the nine months ended September 30, 2007 were $106.1 million, compared to $313.7 million for the nine months ended September 30, 2006. The decrease is due to the completion of our Capacity Replacement Project in fourth quarter 2006. We currently estimate our 2007 capital expenditures will be between $145 million and $165 million. These expenditures include maintenance capital expenditures, including expenditures required for the Pipeline Safety Improvement Act of 2002, and the Parachute Lateral project. The following describes the Parachute Lateral project and a new project proposed by us.

Parachute Lateral Project

     In January 2006, we filed an application with the FERC to construct a 38-mile lateral (Parachute Lateral) that would provide additional transportation capacity from the Parachute area to the Greasewood area in northwest Colorado. In August 2006, the FERC granted us the requested certificate and we commenced construction of the facilities. The Parachute Lateral provides new capacity of 450 MDth/day through a 30-inch diameter line and is estimated to cost $86 million. The lateral was placed into service in May 2007.

     On August 24, 2007, we filed an application with the FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created subsidiary, Parachute Pipeline LLC (Parachute), while we retain the rights and obligations associated with operating the Parachute Lateral facilities under the amended FERC certificate. As contemplated in the application for amendment, Parachute will lease the facilities back to us. Under the terms of the lease, we will pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. The Parachute Lateral facilities are anticipated to be contributed to Parachute prior to December 2007.

     Although the Parachute Lateral facilities were originally built to provide transportation for pipeline-quality natural gas being produced in the Parachute area, approval of the certificate amendment is the first step towards moving these facilities from our interstate pipeline system to the gathering and processing function of Williams Field Services Company, LLC (Williams Field Services), which is owned by Williams. When Williams Field Services completes its Willow Creek Processing Plant, it is contemplated that the lease (subject to further regulatory approval) will terminate, and Parachute, as a subsidiary of Williams Field Services, will assume full operational control and responsibility for the Parachute Lateral.

Colorado Hub Connection Project

     We have proposed constructing a new lateral to connect the White River Hub near Meeker, Colorado to our mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection, or CHC Project. It is estimated that the construction of the lateral would cost up to $53 million and could begin service as early as November 2009.

- 14 -

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 15d-15(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 have concluded that our Disclosure Controls were 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.

Third Quarter 2007 Changes in Internal Control over Financial Reporting

     There have been no changes during the third quarter of 2007 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

- 15 -

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 1A. RISK FACTORS.

Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2006 and Part II, Item 1A. Risk Factors in our 2007 First and Second Quarter Reports on Form 10-Q include certain risk factors that could materially affect our business, financial condition or future results. Those Risk Factors have not materially changed except as set forth below:

Risks Inherent to our Industry and Business

Our natural gas transportation and storage activities involve numerous risks that might result in accidents and other operating risks and hazards.

     Our operations are subject to all the risks and hazards typically associated with the transportation and storage of natural gas. These operating risks include, but are not limited to:

• uncontrolled releases of natural gas;

• fires and explosions;

• natural disasters;

• mechanical problems; and

• damage inadvertently caused by third party activity, such as operation of construction equipment.

     These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.

Our current pipeline infrastructure is aging, which may adversely affect our business.

     Some portions of our pipeline infrastructure are approximately 50 years old. The current age and condition of this pipeline infrastructure could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining our facilities exceed current expectations.

Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial impact on us.

- 16 -

     We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. For example, the proposed Palomar Gas Transmission Project could result in an increase in competition in the Pacific Northwest. Moreover, Williams and its other affiliates, including Williams Partners, are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.

     The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates or on a long-term basis.

     Our primary exposure to market risk occurs at the time the primary terms of existing transportation and storage contracts expire and are subject to termination. Upon expiration of the primary terms, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

     The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

• the level of existing and new competition to deliver natural gas to our markets;

• the growth in demand for natural gas in our markets;

• whether the market will continue to support long-term firm contracts;

• whether our business strategy continues to be successful;

• the level of competition for natural gas supplies in the production basins serving us; and

• the effects of state regulation on customer contracting practices.

     Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

- 17 -

     Our business is dependent on the continued availability of natural gas production and reserves. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. For example, the Rockies Express Pipeline Project, which is expected to take natural gas from the Piceance Basin to Midwest and Eastern markets, will reduce the availability of Piceance Basin natural gas for us. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, or throughput, on our pipeline and cash flows associated with the transportation of natural gas, our customers must continually obtain adequate supplies of natural gas.

     If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas transported and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations.

     For example, we currently have a contract with Pan Alberta Gas that was originally entered into to transport natural gas supplies from the Western Canadian Sedimentary Basin through our system for delivery to California markets. After the associated California commitments were terminated, the producers underlying the Pan Alberta contract directed their supplies to other markets and no longer utilized the capacity commitments on our system. We have proposed the Colorado Hub Connection Project in an attempt to re-contract the Pan Alberta contract commitments, which terminate in 2012. However, if we are not successful in re-contracting this capacity, or otherwise able to resell the capacity, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Significant prolonged changes in natural gas prices could affect supply and demand and cause a reduction in or termination of the long-term transportation and storage contracts or throughput on our system.

     Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in our long-term transportation and storage contracts or throughput on our system. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracts or throughput on our system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The failure of liquid natural gas (LNG) import terminals to be successfully developed in the United States could increase natural gas prices and reduce the demand for our services.

     Imported LNG is expected to become an increasingly significant component of future U.S. natural gas supply. Much of the increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade, particularly in the Gulf Coast region. If LNG facilities are not successfully developed in the Gulf Coast region and elsewhere, the demand for natural gas from the Rocky Mountain region is likely to increase along with the price for natural gas from that region. An increase in the price of natural gas from the Rockies would likely result in a narrowing of the price differential between the Rockies and Sumas, Canada supplies, increasing overall natural gas prices in the Pacific Northwest. Such an increase in natural gas prices could cause consumers of natural gas to turn to alternative energy sources, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in our business.

     We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2006, our two largest customers were Puget Sound Energy and Northwest Natural Gas Co. These customers accounted for approximately 19.9 percent and 10.9

- 18 -

percent, respectively, of our operating revenues for the year ended December 31, 2006. The loss of even a portion of our contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operation and cash flows.

If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport natural gas, our revenues could be adversely affected.

     We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.

     We do not own all of the land on which our pipeline and facilities have been constructed and are therefore subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain, in certain instances, the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We do not have the right of eminent domain over land owned by Native American tribes. If we were to be unsuccessful in renegotiating rights-of-way, we may have to relocate our facilities. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

     We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance in the type and amount to cover all possible risks of loss. Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the aggregate annually and a deductible of $2 million per occurrence. This insurance covers Williams’ and its affiliates’, including our, legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and natural gas liquids operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Williams and its affiliates.

     Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $25 million per occurrence for physical damage to assets and resulting business interruption caused by terrorist acts committed by a U.S. person or interest. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina and Rita have impacted the availability of certain types of coverage at reasonable rates, and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully

- 19 -

covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Related to Regulations that Affect our Industry

Compliance with the Pipeline Safety Improvement Act of 2002 may adversely impact our cost of conducting business.

     We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The regulations require us to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate our pipeline as necessary; and

• implement preventative and mitigating actions.

     In meeting these integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $195 million and $215 million over the remaining assessment period of 2007 through 2012. Should we fail to comply with Department of Transportation regulations, we could be subject to penalties and fines. If the costs of complying with these integrity regulations are materially higher than our current expectations, our business could be adversely impacted.

Our natural gas transportation and storage operations are subject to regulation by FERC, which could have an adverse impact on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipeline, including a reasonable return.

     Our interstate natural gas transportation and storage operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas pipeline system and our storage facilities and related assets are subject to regulation by FERC. The federal regulation extends to such matters as:

• rates, operating terms and conditions of service;

• the types of services we may offer to our customers;

• certification and construction of new facilities;

• acquisition, extension, disposition or abandonment of facilities;

• accounts and records;

• relationships with affiliated companies involved in certain aspects of the natural gas business;

• initiation and discontinuation of services; and

• market manipulation in connection with interstate sales, purchases or transportation of natural gas.

- 20 -

     Under the Natural Gas Act (NGA), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation and storage services in interstate commerce. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

     The rates, terms and conditions for our interstate pipeline and storage services are set forth in our FERC-approved tariff. Pursuant to the terms of a prior rate settlement agreement, we and the other parties to the settlement are precluded from filing for any further increases or decreases in existing rates prior to January 1, 2009 and we must file a new rate case to become effective not later than January 1, 2013. Any successful complaint or protest against our rates could have an adverse impact on our revenues associated with providing transportation and storage services.

We could be subject to penalties and fines if we fail to comply with FERC regulations.

     Our transportation and storage operations are regulated by FERC. Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. Any material penalties or fines imposed by FERC could have a material adverse impact on our business, financial condition, results of operations and cash flows.

The outcome of certain FERC proceedings regarding income tax allowances in rate calculations is uncertain and could affect our ability to include an income tax allowance in our cost-of-service based rates.

     In May 2005, FERC issued a statement of general policy, permitting a pipeline to include in cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. In June 2005 FERC applied its new policy and granted a partnership owning an oil pipeline an income tax allowance when establishing rates. That decision, applying the new policy to the particular oil pipeline, was appealed to the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit). The D.C. Circuit, by order issued May 29, 2007, denied the appeal and upheld FERC’s new tax allowance policy as applied in the decision involving the oil pipeline on all points subject to the appeal. On August 20, 2007, the D.C. Circuit denied rehearing of its decision.

     On December 8, 2006, FERC issued an order in an interstate oil pipeline proceeding addressing its income tax allowance policy, noting that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this creates an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling. On March 9, 2007, FERC granted rehearing for further consideration of its December 8, 2006 order.

     The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. If FERC were to disallow a substantial portion of our income tax allowance, it may be more difficult for us to justify our rates in future proceedings. If we are unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating our cost of service in future rate cases, FERC could disallow a substantial portion of our income tax allowance, and our maximum lawful rates could decrease from current levels.

- 21 -

The outcome of certain FERC proceedings involving FERC policy statements is uncertain and could affect the level of return on equity that Northwest may be able to achieve in any future rate proceeding.

     In an effort to provide some guidance and to obtain further public comment on FERC’s policies concerning return on equity determinations, on July 19, 2007, FERC issued its Proposed Proxy Policy Statement, “Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity.” In the Proposed Proxy Policy Statement, FERC proposes to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings and that evidence be provided in the form of multiyear analysis of past earnings demonstrating a publicly traded partnership’s ability to provide stable earnings over time.

     In a decision issued shortly after FERC issued its Proposed Proxy Policy Statement, the D.C. Circuit vacated FERC’s orders in proceedings involving High Island Offshore System and Petal Gas Storage. The Court determined that FERC had failed to adequately reflect risks of interstate pipeline operations both in populating the proxy group (from which a range of equity returns was determined) with entities the record indicated had lower risk, while excluding publicly traded partnerships primarily engaged in interstate pipeline operations, and in the placement of the pipeline under review in each proceeding within that range of equity returns. Although the Court accepted for the sake of argument FERC’s rationale for excluding publicly traded partnerships from the proxy group (i.e., publicly traded partnership distributions may exceed earnings) it observed this proposition was “not self-evident.”

     The ultimate outcome of these proceedings is not certain and may result in new policies being established at FERC that would not allow the full use of publicly traded partnership distributions to unitholders in any proxy group comparisons used to determine return on equity in future rate proceedings. We cannot ensure that such policy developments would not adversely affect our ability to achieve a reasonable level of return on equity in any future rate proceeding.

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.

(2	)	Plan of acquisition, reorganization, arrangement, liquidation or succession:
		-	1	Certificate of Conversion (Exhibit 2.1 to Form 8-K, filed October 2, 2007)
(3	)	Articles of incorporation and by-laws:
		-	1	Statement of Partnership (Exhibit 3.1 to Form 8-K, filed October 2, 2007)
		-	2	Partnership Agreement (Exhibit 3.2 to Form 8-K, filed October 2, 2007)
(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.

- 22 -

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 GP
Registrant
By:	/s/ R. Rand Clark
	R. Rand Clark
	Controller (Duly Authorized Officer and Chief Accounting Officer)

Date: November 5, 2007

EX-31.1

Exhibit 31.1

SECTION 302 CERTIFICATION

I, Phillip D. Wright, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Northwest Pipeline GP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2007

By:	/s/ Phillip D. Wright
	Phillip D. Wright
	Senior Vice President (Principal Executive Officer)

EX-31.2

Exhibit 31.2

SECTION 302 CERTIFICATION

I, Richard D. Rodekohr, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Northwest Pipeline GP;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the period covered by the report that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 5, 2007

By:	/s/ Richard D. Rodekohr
	Richard D. Rodekohr
	Vice President and Treasurer (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the Quarterly Report of Northwest Pipeline GP (the “Company”) on Form 10-Q for the period ending September 30, 2007 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

     (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

     (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Phillip D. Wright  

Phillip D. Wright 
Senior Vice President
November 5, 2007

/s/ Richard D. Rodekohr  

Richard D. Rodekohr 
Vice President and Treasurer
November 5, 2007

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.