e10vq

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, 2006


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 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.


Class		Outstanding at November 6, 2006

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, 2006 and 2005		1

Condensed Balance Sheet as of September 30, 2006 and December 31, 2005		2

Condensed Statement of Cash Flows, nine months ended September 30, 2006 and 2005		4

Notes to Condensed Financial Statements		5

Item 2. Management’s Narrative Analysis of the Results of Operations		13

Item 4. Controls and Procedures		17

PART II. OTHER INFORMATION:

Item 1. Legal Proceedings		18

Item 1A. Risk Factors		18

Item 6. Exhibits		18
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification 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 2005 Annual Report on Form 10-K and 2006 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,
	2006			2005			2006			2005
OPERATING REVENUES	$	81,088		$	79,639		$	240,641		$	238,829


OPERATING EXPENSES:
General and administrative		17,935			11,019			44,771			34,831
Operation and maintenance		15,352			13,885			45,686			38,860
Depreciation		18,004			16,812			53,188			49,005
Regulatory credits		(1,080	)		(1,189	)		(3,696	)		(3,379	)
Taxes, other than income taxes		3,113			3,038			12,027			11,276


Total operating expenses		53,324			43,565			151,976			130,593


Operating income		27,764			36,074			88,665			108,236


OTHER INCOME – net		1,597			2,988			12,483			8,151


INTEREST CHARGES:
Interest on long-term debt		12,377			9,499			31,566			28,722
Other interest		955			842			2,868			2,557
Allowance for borrowed funds used during construction		(1,866	)		(537	)		(3,466	)		(1,195	)


Total interest charges		11,466			9,804			30,968			30,084


INCOME BEFORE INCOME TAXES		17,895			29,258			70,180			86,303

PROVISION FOR INCOME TAXES		6,622			11,006			25,531			32,545


NET INCOME	$	11,273		$	18,252		$	44,649		$	53,758


CASH DIVIDENDS ON COMMON STOCK	$	—		$	—		$	—		$	50,000

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED BALANCE SHEET
(Thousand of Dollars)
(Unaudited)


	September 30,		December 31,
	2006		2005
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	44,173	$	59,709
Advance to affiliates		49,980		50,000
Accounts receivable -
Trade, less reserves of $91 for September 30, 2006 and December 31, 2005		27,920		28,677
Affiliated companies		538		4,015
Income taxes due from affiliate		954		1,475
Materials and supplies, less reserves of $505 for September 30, 2006 and $263 for December 31, 2005		9,902		8,365
Exchange gas due from others		10,971		11,257
Exchange gas offset		4,407		9,386
Deferred income taxes		3,079		3,913
Prepayments and other		3,802		2,681


Total current assets		155,726		179,478


PROPERTY, PLANT AND EQUIPMENT, at cost		2,595,824		2,286,280
Less – Accumulated depreciation		971,168		957,385


Total property, plant and equipment		1,624,656		1,328,895


OTHER ASSETS:
Deferred charges		50,673		49,124
Regulatory assets		62,684		58,607


Total other assets		113,357		107,731


Total assets	$	1,893,739	$	1,616,104

See accompanying notes.

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


	September 30,		December 31,
	2006		2005
LIABILITIES AND STOCKHOLDER’S EQUITY

CURRENT LIABILITIES:
Accounts payable-
Trade	$	38,959	$	25,835
Affiliated companies		21,280		3,754
Accrued liabilities -
Taxes, other than income		11,130		8,511
Interest		12,136		7,013
Employee costs		7,888		8,731
Exchange gas due to others		15,378		20,643
Deferred contract termination income		6,045		6,045
Other		7,784		4,318
Current maturities of long-term debt		2,867		7,500


Total current liabilities		123,467		92,350


LONG-TERM DEBT LESS CURRENT MATURITIES		684,190		512,580


DEFERRED INCOME TAXES		261,271		236,548


DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		71,030		65,869


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		490,561		445,912
Accumulated other comprehensive income		375		—


Total common stockholder’s equity		753,781		708,757


Total liabilities and stockholder’s equity	$	1,893,739	$	1,616,104

See accompanying notes.

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NORTHWEST PIPELINE CORPORATION

CONDENSED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)


	Nine Months Ended
	September 30,
	2006			2005
OPERATING ACTIVITIES:
Net Income	$	44,649		$	53,758
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		53,188			49,005
Regulatory credits		(3,696	)		(3,379	)
Provision (benefit) for deferred income taxes		25,331			(27,695	)
Amortization of deferred charges and credit		2,204			1,830
Allowance for equity funds used during construction		(6,801	)		(2,245	)
Reserve for doubtful accounts		—			44
Changes in:
Trade accounts receivable		757			2,990
Affiliated receivables, including income taxes		3,998			(116	)
Exchange gas due from others		5,265			5,028
Materials and supplies		(1,537	)		159
Other current assets		(1,121	)		(3,755	)
Deferred charges		(1,385	)		(1,940	)
Trade accounts payable		8,933			(164	)
Affiliated payables, including income taxes		17,526			8,331
Exchange gas due to others		(5,265	)		(1,876	)
Other accrued liabilities		10,366			11,208
Other deferred credits		3,657			2,470


Net cash provided by operating activities		156,069			93,653


INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(313,728	)		(83,019	)
Asset removal cost, net of salvage		(31,212	)		(1,293	)
Changes in accounts payable		5,330			(541	)
Contract termination payment		3,348			87,917
Advances to affiliates		20			—


Net cash provided by (used in) investing activities		(336,242	)		3,064


FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		174,447			—
Principal payments on long-term debt		(7,500	)		(7,500	)
Debt issuance costs		(2,310	)		—
Dividends paid		—			(50,000	)


Net cash provided by (used in) financing activities		164,637			(57,500	)


NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(15,536	)		39,217

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		59,709			53,393


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	44,173		$	92,610

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 (Northwest) is a wholly-owned subsidiary of Williams Gas Pipeline Company LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).

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

Basis of Presentation

Our 1983 acquisition by Williams has been accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities, based on their estimated fair values at the time of the acquisition. Williams has not pushed down the purchase price allocation (amounts in excess of original cost) of $ 73.0 million, as of September 30, 2006, 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, 2006 and December 31, 2005, and results of operations for the three and nine month periods ended September 30, 2006 and 2005, and cash flows for the nine months ended September 30, 2006 and 2005. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2005 Annual Report on Form 10-K and 2006 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; 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 Developments

In June 2006, 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 clarifies the accounting for uncertainty in income taxes under FASB Statement No. 109, “Accounting for Income Taxes.” 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 at the largest amount of benefit 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

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

applying the Interpretation must be reported as an adjustment to the opening balance of retained earnings in the year of adoption. We will adopt the Interpretation beginning in 2007 and will adjust the January 1, 2007 opening balance of retained earnings. We will assess the impact of the Interpretation on our condensed financial statements. We do not anticipate that the adoption of this Interpretation will have any material impact on our financial position.

The FASB issued Statement of Financial Accounting Standards (SFAS) 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) in September 2006. The Statement requires an employer to recognize in its statement of financial position an asset for a defined benefit pension or other postretirement benefit plan’s overfunded status or a liability for a plan’s underfunded status. Entities will now recognize in the statement of financial position changes in the funded status of a defined benefit pension or other postretirement benefit plan in the year in which the changes occur. Those changes that arise during the year but are not recognized as a component of net periodic benefit cost would typically be reported in other comprehensive income. However, subject to clarification of regulatory accounting treatment, we may report such amounts as regulatory assets or liabilities. The Statement also requires measurement of a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year. The requirement to recognize the funded status of a defined benefit plan and the related disclosure requirements is effective as of the end of the fiscal year ending after December 15, 2006. The initial impact of this Statement on our financial statements will not be determined until the Williams sponsored plans’ benefit obligations and the fair value of the plans’ assets are measured as of December 31, 2006. Adoption of the Statement is not expected to impact our Statement of Income or funding requirements. Estimates based on January 1, 2006, data indicate that the decrease in our pension and other postretirement benefit assets and the increase in our pension and other postretirement benefit liabilities could potentially total approximately $40 million due to the adoption of this Statement. The actual adjustments ultimately recorded will depend on various factors including, but not limited to, regulatory accounting interpretations, changes in assumptions used to calculate the year-end benefit obligations, changes in the fair value of plan assets at year-end, and the impact of income taxes. The requirement to measure plan assets and benefit obligations as of the date of the employer’s fiscal year-end statement of financial position is effective for fiscal years ending after December 15, 2008, and will not impact our financial statements as the Williams sponsored plans’ obligations and assets are currently measured as of our fiscal year-end.

FERC Accounting Guidance On June 30, 2005, the FERC issued an order, “Accounting for Pipeline Assessment Cost,” to be applied prospectively beginning January 1, 2006. The Order requires companies to expense certain pipeline integrity-related assessment costs that we have historically capitalized. We anticipate expensing approximately $6 million to $8 million of costs in 2006 that would have been capitalized prior to the Order becoming effective. During the nine months ended September 30, 2006, the amount expensed for integrity-related assessment activities is approximately $1.8 million.

Reclassifications and Adjustments

For the three and nine month periods ended September 30, 2005, General and Administrative Expense was decreased and Operation and Maintenance Expense was increased by $3.0 million and $6.9 million, respectively, to allocate benefits that had previously been classified as General and Administrative Expense to Operation and Maintenance Expense to appropriately reflect these benefits as cost of operations. Certain other reclassifications have been made in the 2005 financial statements to conform to the current period presentation.

In the third quarter of 2006, we made an adjustment to correct an error resulting from an analysis of our regulatory assets. Property, plant and equipment includes the capitalization of equity funds used during construction (EAFUDC). The capitalization of EAFUDC creates a deferred tax difference and an associated regulatory asset. The regulatory asset was not properly reduced for certain retirements of property, plant and equipment made prior to 2000. The correction of the error resulted in a decrease to Income Before Income Taxes of $4.7 million and a decrease to net income of $3.0 million during the three and nine month periods ending September 30, 2006. Our management concluded that the effect of these corrections is not material to prior annual or interim periods subsequent to 2000, expected 2006 results, or trend of earnings.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

2. CONTINGENT LIABILITIES AND COMMITMENTS

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 seeking an increase in jurisdictional revenues of approximately $119 million. 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. Our rate case seeks a total cost of service of $441.4 million, which includes a request for an allowed rate of return on equity of 13.6 percent. We propose the use of a straight-fixed variable rate design. Significant costs that have contributed to the need to file this rate case include: construction of the Capacity Replacement Project (see “2003 Pipeline Breaks in Washington” below), an increase in reliability and integrity expenditures, and an increase in labor costs. Under the filing our current system-wide transportation rate of $0.30760 per Dth * would increase to $0.44468 per Dth.

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 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 March 2005, oral argument on these motions occurred. 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. On October 20, 2006, the District Court dismissed all claims against us.

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. 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.

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. Consistent with other natural gas transmission companies, 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


*		The term “MCF” means thousand cubic feet, “MMcf” means million cubic feet and “Bcf” means billion cubic feet. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. The term “MMBtu” means one million British Thermal Units and “TBtu” means on trillion British Thermal Units. The term Dth means one dekatherm; this is equal to one MMBtu. The term MDth means thousand dekatherms. The term MMDth means million dekatherms.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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, 2006, we have accrued liabilities totaling approximately $4.7 million for these costs which are expected to be incurred over the period from now through 2009. 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 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 $95 million and $120 million over the remaining assessment period of 2006 through 2012. As a result of the June 30, 2005, FERC order described in Note 1, a portion of this amount will be expensed. We implemented the FERC order effective January 1, 2006. 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

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 or results of operations.

2003 Pipeline Breaks in Washington

In 2003, we experienced two breaks in a segment of one of our natural gas pipelines in western Washington. In response to the first break, we received a Corrective Action Order (CAO) from the Office of Pipeline Safety (OPS). In December 2003, as a result of the second break, we received an Amended Corrective Action Order (ACAO). 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, 2006, approximately $43 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.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 MDth/day of capacity being relinquished and incorporated into the replacement project.

On November 29, 2004, we filed 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, 2006, the net book value of the assets to be abandoned was $84.0 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. As of November 1, 2006, construction is substantially complete. By December 2006, all of the facilities are expected to be in service, and the abandonment of the 26-inch pipeline is expected to be completed.

The rate case we filed on June 30, 2006 seeks to recover, among other things, the capitalized costs relating to the Capacity Replacement Project.

Asset Retirement Obligation

As disclosed in our 2005 Annual Report on Form 10-K, we recorded an asset retirement obligation (ARO) of approximately $15.4 million as of December 31, 2005. The ARO was recorded in accordance with FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” and FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143.” We are in the process of reassessing certain assumptions used in the calculation of the asset retirement obligations, and anticipate completing this assessment in the fourth quarter of 2006. Although our reassessment could result in a material adjustment to our ARO liability, we expect to record an offsetting adjustment to the related regulatory asset, since the retirement costs are expected to be recovered through our rates. An adjustment to our ARO would not have a material effect on our results of operations.

3. DEBT AND FINANCING ARRANGEMENTS

Issuance of Long-Term Debt

In June 2006, we issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. We intend to use the proceeds for general corporate purposes, including the funding of capital expenditures.

In October 2006, we completed the exchange of the 7 percent senior unsecured notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

Revolving Credit and Letter of Credit Facilities

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt, and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the facility to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. Williams is required to pay a commitment fee (currently .25 percent annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $46 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at September 30, 2006.

4. STOCK-BASED COMPENSATION

Plan Information

The Williams Companies, Inc. 2002 Incentive Plan (Plan) was approved by stockholders on May 16, 2002, and amended and restated on May 15, 2003, and January 23, 2004. The Plan provides for Williams common-stock-based awards to both employees and nonmanagement directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees. We are also billed for our proportionate share of both WGP’s and Williams’ stock-based compensation expense through various allocation processes.

Accounting for Stock-Based Compensation

Prior to January 1, 2006, we accounted for the Plan under the recognition and measurement provisions of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations, as permitted by FASB Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Compensation cost for stock options was not recognized in our Condensed Statement of Income for the nine months ending September 30, 2005, as all Williams stock options granted under the Plan had an exercise price equal to the market value of the underlying Williams common stock on the date of the grant. Prior to January 1, 2006, compensation cost was recognized for deferred share awards. Effective January 1, 2006, we adopted the fair value recognition provisions of FASB Statement No. 123(R), “Share-Based Payment” (SFAS No. 123(R)), using the modified-prospective method. Under this method, compensation cost recognized in the first nine months of 2006 includes: (1) compensation cost for all Williams share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (2) compensation cost for most Williams share-based payments granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS No. 123(R). The performance targets for certain performance based deferred shares have not been established, and therefore, expense is not currently recognized. Results for prior periods have not been restated.

Total stock-based compensation expense, included in administrative and general expenses, for the three and nine months ending September 30, 2006 was $0.2 million and $0.7 million, respectively, excluding amounts allocated from WGP and Williams.

5. TRANSACTIONS WITH AFFILIATES

Included in our operating revenues for the nine months ending September 30, 2006 and 2005 are amounts received from affiliates for transportation and exchange transactions of $1.8 million and $1.2 million, respectively. The rates charged to provide services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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 offset by an other expense to pass the revenues through to our customers who own the gas.

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, 2006 and 2005 are $13.3 million and $10.6 million, respectively, for such corporate expenses charged by Williams and other affiliated companies. Management considers the cost of these services to be reasonable.

6. 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.

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 July 15, 2005, Duke filed a motion to intervene and provided comments supporting its position concerning the issues in dispute.

On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order, providing clarification on issues relating to Duke’s obligation to reimburse us for future tax expenses. We are reviewing the Order and filed a request for rehearing on November 3, 2006. Based upon the order, as written, we do not anticipate any adverse impact to our results of operations or financial position.

7. COMPREHENSIVE INCOME

Comprehensive income is as follows:

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NORTHWEST PIPELINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2006			2005		2006			2005
	(Thousands of Dollars)					(Thousands of Dollars)
Net income	$	11,273		$	18,252	$	44,649		$	53,758
Other comprehensive income:
Gain on cash flow hedges		—			—		619			—
Reclassification cash flow hedge gain into earnings		(15	)		—		(18	)		—

Other comprehensive income before taxes		(15	)		—		601			—
Income tax provision on other comprehensive income		5			—		(226	)		—

Other comprehensive income		(10	)		—		375			—

Comprehensive income	$	11,263		$	18,252	$	45,024		$	53,758

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. The gain will be amortized to reduce interest expense over the life of the related debt.

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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 2005 Annual Report on Form 10-K and with the condensed financial statements and notes thereto in Item 2 of our 2006 first and second quarter reports on Form 10-Q and within this report.

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 seeking an increase in jurisdictional revenues of approximately $119 million. 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. Our rate case seeks a total cost of service of $441.4 million, which includes a request for an allowed rate of return on equity of 13.6 percent. We propose the use of a straight-fixed variable rate design. Significant costs that have contributed to the need to file this rate case include: construction of the Capacity Replacement Project (see “2003 Pipeline Breaks in Washington” below), an increase in reliability and integrity expenditures, and an increase in labor costs. Under the filing our current system-wide transportation rate of $0.30760 per Dth * would increase to $0.44468 per Dth.

Termination of the Grays Harbor Transportation Agreement

2003 Pipeline Breaks in Washington

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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 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.

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, 2006, the net book value of the assets to be abandoned was $84.0 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. As of November 1, 2006, construction is substantially complete. By December 2006, all facilities are expected to be in service, and the abandonment of the 26-inch pipeline is expected to be completed.

The rate case we filed on June 30, 2006 seeks to recover, among other things, the capitalized costs relating to the Capacity Replacement Project.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

This analysis discusses financial results of our operations for the nine-month periods ended September 30, 2006 and 2005. 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 $1.8 million, or 1 percent. Higher levels of park and loan services, a form of interruptible storage service, are the primary source, generating $1.3 million of this increase.

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, 2006 and 2005.

Operating expenses increased $21.4 million, or 16 percent. This increase is due primarily to a $5.7 million increase in consulting, contract, engineering, maintenance and other outside services primarily as a result of our pipeline integrity and environmental assessment efforts, a $4.7 million increase in outside administrative costs related primarily to outsourced information technology services, and a $4.2 million increase in depreciation resulting from property additions. Also contributing to this increase were higher labor expenses of $3.0 million and higher materials and supplies expenses of $1.8 million related primarily to pipeline operations.

Other income increased $4.3 million, or 53 percent, primarily due to a $9.3 million increase in the allowance for equity funds used during construction resulting from the significantly higher capital expenditures in 2006, partially offset by the adjustment of an error of $4.7 million as described in Note 1.

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Interest charges increased $0.9 million, or 3 percent. This increase is the result of higher interest on long-term debt of $2.8 million from the new debt issued in June 2006, mostly offset by the increase in the allowance for borrowed funds used during construction related to the higher property additions in 2006.

The provision for income taxes decreased $7.0 million, or 22 percent, due primarily to lower pre-tax income in 2006 as compared to 2005.

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


	Nine Months Ended
	September 30,
	2006		2005
Total Throughput (TBtu)		479		480

Average Daily Transportation Volumes (TBtu)		1.8		1.8
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity (TBtu)		2.5		2.5
Average Daily Reserved Capacity Under Short-Term Firm Contracts (TBtu) (1)		0.9		0.8


(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

In October 2006, we completed the exchange of the 7 percent senior unsecured notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

In May 2006, Williams obtained an unsecured, three-year, $1.5 billion revolving credit facility, replacing our $1.275 billion secured credit facility. The new unsecured facility contains similar terms and covenants as the secured facility, but contains additional restrictions on asset sales, certain subsidiary debt, and sale-leaseback transactions. The facility is guaranteed by WGP, and Williams guarantees obligations of Williams Partners L.P. for up to $75 million. We have access to $400 million under the facility to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate plus an applicable margin. Williams is required to pay a commitment fee (currently .25 percent annually) based on the unused portion of the facility. The margins and commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $46 million, none of which are associated with us, have been issued by the participating institutions and no revolving credit loans were outstanding at September 30, 2006.

CAPITAL EXPENDITURES

Our capital expenditures for the nine months ended September 30, 2006 were $313.7 million, compared to $83.0 million for the nine months ended September 30, 2005. We currently estimate our 2006 capital expenditures will be between $435 million and $475 million. Our capital expenditures estimate for 2006 is discussed in our 2005 Annual Report on Form 10-K.

Parachute Lateral Project

In January 2006, we filed an application with the FERC to construct a 38-mile lateral that would provide additional transportation capacity in northwest Colorado. The planned lateral would increase capacity by 450 MDth/day through a 30-inch diameter line and is estimated to cost $64 million. We anticipate beginning service

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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 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 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 have been no changes during third quarter 2006 that have materially affected, or are reasonably likely to materially affect, 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 1A. RISK FACTORS.

There are no material changes to the Risk Factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2005.

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.


(3) Articles of incorporation and by-laws:

-	1	Restated Certificate of Incorporation, as amended (Exhibit 3.1 to Registration Statement on Form S-4, No. 333-136854, filed August 23, 2006)

-	2	Amended and Restated By-Laws (Exhibit 3.2 to Registration Statement on Form S-4, No. 333-136854, filed August 23, 2006)

(31) Section 302 Certifications:

-	1	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

-	2	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32) Section 906 Certification:

	- 1	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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				NORTHWEST PIPELINE CORPORATION
				Registrant

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

	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

	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

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	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.


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


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


/s/ Phillip D. Wright
Phillip D. Wright
Senior Vice President
November 6, 2006

/s/ Richard D. Rodekohr
Richard D. Rodekohr
Vice President and Treasurer
November 6, 2006