UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2008

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

Large accelerated filer o  Accelerated filer o  Non-accelerated filer   þ
(Do not check if a smaller reporting company) Smaller reporting company o 

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

NORTHWEST PIPELINE GP

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION:
Item 1. Financial Statements -
Consolidated Statements of Income, three and six months ended June 30, 2008 and 2007		1
Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007		2
Consolidated Statements of Cash Flows, six months ended June 30, 2008 and 2007		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
Item 3. Quantitative and Qualitative Disclosures about Market Risk		18
Item 4. Controls and Procedures		19
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		20
Item 1A. Risk Factors		20
Item 6. Exhibits		20
Section 302 Certification
Section 302 Certification
Section 906 Certification

i

Forward Looking Statements

     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 or results of operations;

• rate case filing; and

• power and natural gas prices and demand.

     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;

• increasing maintenance and construction costs;

• changes in the current geopolitical situation;

• risks related to strategy and financing, including restrictions stemming from our debt agreements and future changes in our 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, 2007.

ii

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
				(Restated)						(Restated)
OPERATING REVENUES	$	106,450		$	102,655		$	213,855		$	205,698
OPERATING EXPENSES:
General and administrative		16,851			16,920			31,408			31,355
Operation and maintenance		18,949			15,454			36,405			30,844
Depreciation		21,392			21,066			43,052			41,553
Regulatory credits		(774	)		(975	)		(1,581	)		(1,745	)
Taxes, other than income taxes		3,356			2,296			8,729			6,480
Regulatory liability reversal (Note 1)		—			(16,562	)		—			(16,562	)
Total operating expenses		59,774			38,199			118,013			91,925
Operating income		46,676			64,456			95,842			113,773
OTHER INCOME – net:
Interest income –
Affiliated		260			449			569			637
Other		1			155			5			365
Allowance for equity funds used during Construction		239			583			266			1,511
Miscellaneous other (expense) income, net		(71	)		773			(101	)		1,001
Contract termination income		—			6,045			—			6,045
Total other income — net		429			8,005			739			9,559
INTEREST CHARGES:
Interest on long-term debt		10,158			11,768			20,107			24,104
Other interest		1,390			1,550			2,771			2,538
Allowance for borrowed funds used during Construction		(128	)		(375	)		(140	)		(934	)
Total interest charges		11,420			12,943			22,738			25,708
INCOME BEFORE INCOME TAXES		35,685			59,518			73,843			97,624
PROVISION FOR INCOME TAXES		—			22,131			—			36,880
NET INCOME	$	35,685		$	37,387		$	73,843		$	60,744

See accompanying notes.

1

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CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

	June 30,		December 31,
	2008		2007
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9	$	497
Advance to affiliates		59,072		39,072
Accounts receivable -
Trade, less reserves of $0 for June 30, 2008 and $7 for December 31, 2007		42,572		40,689
Affiliated companies		3,628		3,514
Materials and supplies, less reserves of $158 for June 30, 2008 and $181 for December 31, 2007		9,963		10,344
Exchange gas due from others		16,319		10,155
Exchange gas offset		1,217		6,593
Prepayments and other		6,717		6,928
Total current assets		139,497		117,792
PROPERTY, PLANT AND EQUIPMENT, at cost		2,717,745		2,706,691
Less – Accumulated depreciation		891,042		864,999
Total property, plant and equipment		1,826,703		1,841,692
OTHER ASSETS:
Deferred charges		45,397		44,915
Regulatory assets		52,408		52,072
Total other assets		97,805		96,987
Total assets	$	2,064,005	$	2,056,471

See accompanying notes.

2

NORTHWEST PIPELINE GP
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)

	June 30,			December 31,
	2008			2007
	(Unaudited)
LIABILITIES AND OWNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable-
Trade	$	21,091		$	32,055
Affiliated companies		13,855			13,056
Accrued liabilities -
Taxes, other than income taxes		11,022			7,935
Interest		5,053			4,517
Employee costs		8,033			12,106
Exchange gas due to others		17,536			16,748
Other		6,948			5,713
Total current liabilities		83,538			92,130
LONG-TERM DEBT		693,142			693,736
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		83,586			84,989
CONTINGENT LIABILITIES AND COMMITMENTS
OWNERS’ EQUITY:
Owners’ capital		977,022			977,022
Retained earnings		246,141			228,739
Accumulated other comprehensive loss		(19,424	)		(20,145	)
Total owners’ equity		1,203,739			1,185,616
Total liabilities and owners’ equity	$	2,064,005		$	2,056,471

See accompanying notes.

3

NORTHWEST PIPELINE GP

CONDENSED STATEMENT OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	Six Months Ended
	June 30,
	2008			2007
				(Restated)
OPERATING ACTIVITIES:
Net Income	$	73,843		$	60,744
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		43,052			41,553
Regulatory credits		(1,581	)		(1,745	)
Provision for deferred income taxes		—			18,783
Amortization of deferred charges and credits		4,681			4,451
Allowance for equity funds used during construction		(266	)		(1,511	)
Reserve for doubtful accounts		(7	)		—
Regulatory liability reversal		—			(16,562	)
Contract termination income		—			(6,045	)
Changes in:
Trade accounts receivable		(1,876	)		(4,346	)
Affiliated receivables, including income taxes in 2007		(114	)		(904	)
Exchange gas due from others		(788	)		5,800
Materials and supplies		381			(267	)
Other current assets		211			(517	)
Deferred charges		(1,313	)		(5,140	)
Trade accounts payable		(76	)		(344	)
Affiliated payables, including income taxes in 2007		799			769
Exchange gas due to others		788			(5,800	)
Other accrued liabilities		786			(3,098	)
Other deferred credits		(2,152	)		3,931
Net cash provided by operating activities		116,368			89,752
FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		249,333			184,362
Retirement of long-term debt		(250,000	)		—
Prepayments of long-term debt		—			(175,000	)
Debt issuance costs		(2,115	)		(2,133	)
Premium on early retirement of long-term debt		—			(7,111	)
Proceeds from sale of partnership interest		300,900			—
Distributions paid		(357,342	)		—
Changes in cash overdrafts		(2,795	)		(37,543	)
Net cash used in financing activities		(62,019	)		(37,425	)
INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(28,577	)		(68,627	)
Proceeds from sales		1,833			832
Changes in accounts payable and accrued liabilities		(8,093	)		6,830
(Advances to) repayments from affiliates		(20,000	)		7,516
Net cash used in investing activities		(54,837	)		(53,449	)
NET DECREASE IN CASH AND CASH EQUIVALENTS		(488	)		(1,122	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		497			1,489
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	9		$	367

See accompanying notes.

4

NORTHWEST PIPELINE GP

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

     The accompanying interim consolidated 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 accompanying unaudited financial statements include all adjustments both normal recurring and others which, in the opinion of our management, are necessary to present fairly our financial position at June 30, 2008 and December 31, 2007, and results of operations for the three and six months ended June 30, 2008 and 2007, and cash flows for the six months ended June 30, 2008 and 2007. These consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in our 2007 Annual Report on Form 10-K.

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the 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) litigation-related contingencies; 2) environmental remediation obligations; 3) impairment assessments of long-lived assets; 4) depreciation; 5) pension and other post-employment benefits; and 6) asset retirement obligations.

Corporate Structure and Control

     On January 24, 2008, Williams Pipeline Partners L.P. (previously a wholly-owned subsidiary of The Williams Companies, Inc. (Williams)) completed its initial public offering of limited partnership units, the net proceeds of which were used to acquire a 15.9 percent interest in Northwest Pipeline GP (Northwest). Williams contributed 19.1 percent of its ownership in Northwest in return for limited and general partnership interests in Williams Pipeline Partners L.P. Northwest received net proceeds of $300.9 million on January 24, 2008 from Williams Pipeline Partners L.P. for the purchase of its 15.9 percent interest, and Northwest in turn made a distribution to Williams of $300.9 million. After these transactions, Northwest is owned 35 percent by Williams Pipeline Partners L.P. and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of Williams. Through its ownership interests in each of our partners, Williams indirectly owns 81.7 percent of Northwest as of June 30, 2008.

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

Basis of Presentation

     The accompanying consolidated financial statements include the accounts of Northwest and Northwest Pipeline Services LLC, a variable interest entity for which Northwest is the primary beneficiary.

     Our 1983 acquisition by Williams was 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. Because we had significant outstanding public debt and preferred stock at the time of our acquisition by Williams, under the provisions of Staff Accounting Bulletin No. 54, “Push Down Basis of Accounting Required in Certain Limited Circumstances,” we were not required to, and elected not to, push down the purchase price allocation in our financial statements. Beginning December 31, 2007, we elected to include Williams’ purchase price allocations in our financial statements. Accordingly, our June 30, 2007 financial statements have been restated to include the effects of Williams’ excess purchase price allocation. A reconciliation between our original basis in our assets and liabilities and our consolidated financial statements for the three and six months ended June 30, 2007 is as follows:

5

NORTHWEST PIPELINE GP
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

	Three Months			Six Months
	Ended			Ended
	June 30, 2007			June 30, 2007
	(Thousands of Dollars)
Income Statement
Net income, as previously reported	$	37,941		$	61,921
Depreciation of purchase price allocation to Property and equipment, net of income taxes		(554	)		(1,177	)
Net income, as restated	$	37,387		$	60,744

     Management believes this change in accounting is preferable as the push down of fair value purchase price allocations to the financial statements of an acquired entity is encouraged by Securities and Exchange Commission Staff Accounting Bulletin No. 54, and the fact that our financial statements are now included in the Form 10-K of Williams Pipeline Partners L.P., whose equity investment in us is reported based on Williams’ historical basis in us, including such purchase accounting adjustments.

Recent Accounting Standards

     In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2008, we adopted SFAS 157. We had no assets or liabilities measured at fair value on a recurring basis. Therefore, the initial adoption of SFAS 157 had no impact on our Consolidated Financial Statements. Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. Application will be prospective when nonrecurring fair value measurements are required. We will assess the impact on our Consolidated Financial Statements of applying these requirements to nonrecurring fair value measurements for nonfinancial assets and nonfinancial liabilities.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133” (SFAS 161). SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS 161 amends and expands the disclosure requirements of Statement 133 with enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments, gains and losses on derivative instruments and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and nonhedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will assess the application of this Statement on our disclosures in our Consolidated Financial Statements.

6

NORTHWEST PIPELINE GP
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

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 had 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 additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.

2. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

     In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg 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 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. In October 2006, the District Court dismissed all claims against us and in November 2006, Mr. Grynberg filed his notice of appeal with the Tenth Circuit Court of Appeals.

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, our management believes that it is in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, Federal Energy Regulatory Commission (FERC) would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

     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, or 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 natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (EPA) 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 re-evaluate 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 June 30, 2008, we have accrued liabilities totaling approximately $7.2 million for these costs which are expected to be incurred through 2012. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. We consider these costs associated with compliance with environmental laws and

7

NORTHWEST PIPELINE GP
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

     In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard for ground-level ozone.  Within three years, the EPA will designate new eight-hour ozone non-attainment areas.  Designation of new eight-hour ozone non-attainment areas will result in additional federal and state regulatory actions that may impact our operations.  As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations.  Management considers costs associated with compliance with the environmental laws and regulations described above 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 we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (DOT PHMSA) 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 high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $175 million and $195 million over the remaining assessment period of 2008 through 2012. The cost estimates have been revised to reflect refinements in the scope of required remediation and for increases in assessment and remediation costs. Our 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 on our future financial position.

Cash Distributions to Partners

     On or before the end of the calendar month following each quarter, available cash is distributed to our partners as required by our general partnership agreement. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves as established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.

     In January 2008, we distributed $8.8 million to Williams representing available cash prior to Williams Pipeline Partners L.P.’s acquisition of its interest in us. In April 2008, we declared and paid equity distributions of $47.6 million to our partners. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. In July 2008, we declared and paid equity distributions of $31.0 million to our partners.

8

NORTHWEST PIPELINE GP
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

3. DEBT AND FINANCING ARRANGEMENTS

Debt Covenants

     Our debt indentures contain restrictions on our ability to incur secured debt beyond certain levels.

Line of Credit Arrangements

     We are a borrower under Williams’ $1.5 billion unsecured revolving credit facility. Letters of credit totaling $28.0 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of June 30, 2008. Our ratio of debt to capitalization must be no greater than 55 percent under this agreement. We are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, was approximately 36.1 percent at June 30, 2008.

Long-Term Debt

     Issuances and retirements

     On May 22, 2008, we issued $250.0 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a private debt placement. These proceeds were used to repay our December 2007 $250.0 million loan under Williams’ $1.5 billion unsecured revolving credit facility.

     Registration payment arrangements

     Under the terms of our $250.0 million 6.05 percent senior unsecured notes mentioned above, we are obligated to file an exchange offer registration statement offering to exchange the notes for a new issue of substantially identical notes (except they will not be subject to transfer restrictions) to be registered under the Securities Act of 1933, as amended, within 180 days after closing. We are obligated to use commercially reasonable efforts to cause such registration statement to be declared effective within 270 days after closing and to consummate the exchange offer within 30 business days after such effective date. We may also be required to provide a shelf registration statement to cover resales of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of the default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter up to a maximum amount for all such defaults of 0.5 percent annually.

5. TRANSACTIONS WITH AFFILIATES

     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At June 30, 2008 and December 31, 2007, the advances due to us by Williams totaled approximately $59.1 million and $39.1 million, respectively. The advances are represented by demand notes.

     Williams’ corporate overhead expenses allocated to us were $5.1 million and $9.3 million for the three and six months ended June 30, 2008, respectively, and $4.8 million and $9.5 million for the three and six months ended June 30, 2007, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, information technology, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $4.4 million and $8.3 million for the three and six months ended June 30, 2008, respectively, and $4.0 million and $7.9 million for the three and six months ended June 30, 2007, respectively. These expenses are included in general and administrative expense on the accompanying consolidated statement of income.

     During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $3.5

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NORTHWEST PIPELINE GP
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)

million and $7.5 million for the three and six months ended June 30, 2008, respectively, and $2.6 million and $3.8 million for the three and six months ended June 30, 2007, respectively.

     As of January 1, 2008, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we pay monthly rent equal to the revenues collected from transportation services on the lateral less 3 percent to cover costs related to the operation of the lateral. This lease expense, totaling $2.5 million and $5.0 million for the three and six months ended June 30, 2008, respectively, is included in operation and maintenance expense on the accompanying consolidated statement of income.

     We have entered into various other transactions with certain related parties, the amounts of which were not significant. These transactions and the above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.

6. COMPREHENSIVE INCOME

     Comprehensive income is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
				(Restated)						(Restated)
	(Thousands of Dollars)
Net income	$	35,685		$	37,387		$	73,843		$	60,744
Reclassification of cash flow hedge gain into earnings, net of tax in 2007		(15	)		(10	)		(31	)		(19	)
Pension benefits, net of tax in 2007
Amortization of prior service cost		20			12			40			24
Amortization of net actuarial loss		500			290			712			597
Total comprehensive income	$	36,190		$	37,679		$	74,564		$	61,346

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OUTLOOK

     Our strategy to create value focuses on maximizing the contracted capacity on our pipeline by providing high quality, low cost natural gas transportation and storage services to our markets. Changes in commodity prices and volumes transported have little impact on revenues because the majority of our revenues are recovered through firm capacity reservation charges. We grow our business primarily through expansion projects that are designed to increase our access to natural gas supplies and to serve the demand growth in our markets.

Colorado Hub Connection Project

     We have proposed installing a new 28-mile, 24-inch diameter lateral to connect the Meeker/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 CHC Project will cost up to $60 million with service targeted to commence in November 2009. We will combine the lateral capacity with 341 million cubic feet (MMcf) per day of existing mainline capacity from various receipt points for delivery to Ignacio, Colorado, including approximately 98 MMcf per day of capacity that is currently sold on a short-term basis. Approximately 243 MMcf per day of this capacity was originally held by Pan-Alberta Gas under a contract that terminates on October 31, 2012.

     In addition to providing greater opportunity for contract extensions for the existing short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub for our on-system and off system markets. We have entered into precedent agreements with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. The CHC Project remains subject to the necessary regulatory approvals. If we do not proceed with the CHC Project, we will seek recovery of any shortfall in annual capacity reservation revenues from our remaining customers in a future rate proceeding. We expect to collect maximum rates for the new CHC Project capacity commitments and seek approval to recover the CHC Project costs in any future rate case filed with the FERC.

Jackson Prairie Underground Expansion

     The Jackson Prairie Storage Project, connected to our transmission system near Chehalis, Washington, is operated by Puget Sound Energy and is jointly owned by Puget Sound Energy, Avista Corporation and us. A phased capacity expansion is currently underway and a deliverability expansion is planned for 2008.

     As a one-third owner of Jackson Prairie, we held an open season for a new firm storage service based on our 104 MMcf per day share of the planned 2008 deliverability expansion and our approximately 1.2 Bcf share of the working natural gas storage capacity expansion to be developed over approximately a four-year period from 2007 through 2010.

     As a result of the open season, four shippers executed binding precedent agreements for the full amount of incremental storage service offered at contract terms averaging 33 years. The precedent agreements obligate the shippers to execute long-term service agreements for the proposed new incremental firm storage service, with the firm service rights to be phased-in as the expanded working natural gas capacity and deliverability are developed. Our one third share of the deliverability expansion cost is estimated to be $16 million. Our estimated capital cost for the capacity expansion component of the new storage service is $6.1 million, primarily for base natural gas.

     Due to the profile of our customers and their need for peak-day capacity, we believe that expanding storage at Jackson Prairie is the most cost effective way to serve the weather-sensitive residential and commercial peak-day load growth on our system.

Sundance Trail Expansion

     In February 2008, we initiated an open season for the proposed Sundance Trail Expansion project that resulted in the execution of an agreement for 150 MMcf per day of firm transportation service from the Meeker/White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project, which is estimated to cost $53 million, will include construction of approximately 16 miles of 30-inch loop between our existing

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Green River and Muddy Creek compressor stations in Wyoming and the addition of horsepower at our existing Vernal compressor station with service targeted to commence in November 2010. The Sundance Trail Expansion will utilize available capacity on the CHC lateral and the existing Piceance lateral in conjunction with available and expanded mainline capacity. The Sundance Trail Expansion remains subject to certain conditions, including receiving the necessary regulatory approvals. We expect to collect our maximum system rates, and will seek approval to roll-in the Sundance Trail Expansion costs in any future rate case filed with the FERC.

GENERAL

     Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto included within Item 8 of our 2007 Annual Report on Form 10-K and with the consolidated financial statements and notes thereto contained within this document.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

     This analysis discusses financial results of our operations for the three and six-month periods ended June 30, 2008 and 2007. Changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007

     Our operating revenues increased $3.8 million, or 4 percent. This increase is attributed to a $1.3 million increase from the Parachute Lateral, placed into service in May 2007, with the balance of the increase primarily attributed to higher short-term firm transportation volumes.

     Our transportation service accounted for 96 percent of our operating revenues for each of the three-month periods ended June 30, 2008 and 2007. Additionally, gas storage service accounted for 3 percent of operating revenues for each of the three-month periods ended June 30, 2008 and 2007.

     Operating expenses increased $21.6 million, or 56 percent. This increase 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 Consolidated Financial Statements, the new Parachute Lateral lease of $2.5 million and higher expenses of $1.0 million for contracted services attributed primarily to pipeline maintenance.

     Other income decreased $7.6 million, or 95 percent, primarily due to the June 2007 recognition of $6.0 million of previously deferred income related to the termination of the Grays Harbor transportation agreement.

     Interest charges decreased $1.5 million, or 12 percent, due primarily to the December 2007 refinancing of $250.0 million of 6.625 percent senior unsecured notes with $250.0 million revolver debt at lower interest rates and the May 2008 refinancing of the $250.0 million revolver debt with the issuance of $250.0 million of 6.05 percent senior unsecured notes due in 2018.

     The provision for income taxes decreased $22.1 million due to our conversion to a non-taxable general partnership on October 1, 2007.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

     Our operating revenues increased $8.2 million, or 4 percent. This increase is attributed to a $3.9 million increase from the Parachute Lateral, placed into service in May 2007, with the balance of the increase primarily attributed to higher short-term firm transportation volumes.

     Our transportation service accounted for 97 percent of our operating revenues for each of the six-month periods ended June 30, 2008 and 2007. Additionally, gas storage service accounted for 2 percent of operating revenues for each of the six-month periods ended June 30, 2008 and 2007.

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     Operating expenses increased $26.1 million, or 28 percent. This increase 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, the new Parachute Lateral lease of $5.0 million and higher depreciation expense of $1.5 million resulting from property additions. Higher use taxes of $1.1 million attributed primarily to the 2007 reversal of $0.8 million of accrued use taxes resulting from the settlement of prior year audits and the Jackson Prairie Expansion and higher ad valorem taxes of $1.1 million resulting from property additions also contributed to the increase.

     Other income decreased $8.8 million, or 92 percent, primarily due to the June 2007 recognition of $6.0 million of previously deferred income related to the termination of the Grays Harbor transportation agreement and a $2.4 million decrease in the allowance for equity funds used during construction resulting from the lower capital expenditures in 2008.

     Interest charges decreased $3.0 million, or 12 percent, due primarily to the April 2007 early retirement of $175.0 million of 8.125 percent senior unsecured notes, due 2010, and the December 2007 refinancing of $250.0 million of 6.625 percent senior unsecured notes with $250.0 million revolver debt at lower interest rates and the May 2008 refinancing of the $250.0 million revolver debt with the issuance of $250.0 million of 6.05 percent senior unsecured notes, due 2018. This decrease was partially offset by the April 2007 issuance of $185.0 million of 5.95 percent senior unsecured notes, due 2017, and a $0.8 million decrease in the allowance for borrowed funds used during construction resulting from lower capital expenditures in 2008.

     The provision for income taxes decreased $36.9 million due to our conversion to a non-taxable general partnership on October 1, 2007.

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

	Three Months				Six Months
	Ended June30,				Ended June 30,
	2008		2007		2008		2007
	(In Trillion British Thermal Units)
Total Throughput (1)		171		160		391		360
Average Daily Transportation Volumes		1.9		1.8		2.1		2.0
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity		2.5		2.5		2.5		2.5
Average Daily Reserved Capacity Under Short- Term Firm Contracts (2)		0.7		0.8		0.7		0.8

(1)	Parachute Lateral volumes are excluded from total throughput as these volumes flow under separate contracts that do not result in mainline throughput.
(2)	Includes additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis.

CAPITAL RESOURCES AND LIQUIDITY

     Our ability to finance operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness, or to meet collateral requirements, will depend on our ability to generate cash in the future and to borrow funds. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including the impact of regulators on our ability to establish transportation and storage rates.

     On or before the end of the calendar month following each quarter, available cash is distributed to our partners as required by our general partnership agreement. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the

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management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.

     In January 2008, we distributed $8.8 million to Williams representing available cash prior to Williams Pipeline Partners L.P.’s acquisition of its interest in us. In April 2008, we declared and paid equity distributions of $47.6 million to our partners. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. In July 2008, we declared and paid equity distributions of $31.0 million to our partners.

     Expansion capital expenditures will be funded by third-party debt or contributions from our partners with the exception of the CHC Project which will be funded by capital contributions from Williams.

SOURCES (USES) OF CASH

	Six Months Ended June 30,
	2008			2007
				(Restated)
	(Thousands of Dollars)
Net cash provided (used) by:
Operating activities	$	116,368		$	89,752
Financing activities		(62,019	)		(37,425	)
Investing activities		(54,837	)		(53,449	)
Decrease in cash and cash Equivalents	$	(488	)	$	(1,122	)

Operating Activities

     Our net cash provided by operating activities for the six months ended June 30, 2008 increased $26.6 million from the same period in 2007. This increase is primarily attributed to a decrease in income taxes payable due to our conversion to a partnership in 2007, partially offset by an increase in cash provided by other working capital sources.

Financing Activities

     Cash used in financing activities for the six months ended June 30, 2008 increased $24.6 million from the same period in 2007 due to current year distributions to partners. Also included in financing activities are the proceeds of $300.9 million from the sale of a 15.9 percent partnership interest in us to Williams Pipeline Partners L.P., offset by distributions of $357.3 million to Williams. Financing activities also included the refinancing of the $250.0 million revolver debt with the issuance of $250.0 million unsecured senior notes in May 2008.

Investing Activities

     Cash used in investing activities for the six months ended June 30, 2008 increased $1.4 million from the same period in 2007 due to increased advances to affiliates, partially offset by lower capital expenditures.

METHOD OF FINANCING

Working Capital

     Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

     Changes in the terms of our transportation and storage arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

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Short-Term Liquidity

     We fund our working capital and capital requirements with cash flows from operating activities, and, if required, borrowings under the Williams credit agreement (described below) and return of advances previously made to Williams.

     We invest cash through participation in Williams’ cash management program. At June 30, 2008, the advances due to us by Williams totaled approximately $59.1 million. The advances are represented by one or more demand obligations. The interest rate on these demand notes is based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.37 percent at June 30, 2008.

Credit Agreement

     Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012. We have access to $400.0 million under the agreement 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 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $28.0 million, none of which are associated with us, have been issued by the participating institutions. No revolving credit loans were outstanding as of June 30, 2008.

CAPITAL REQUIREMENTS

     The transmission and storage business can be capital intensive, requiring significant investment to maintain and upgrade existing facilities and construct new facilities.

     We anticipate 2008 capital expenditures will be between $100 million and $125 million. Our expenditures for property, plant and equipment additions were $28.6 million and $68.6 million for the six months ended June 30, 2008 and 2007, respectively.

CREDIT RATINGS

     During the second quarter of 2008, the credit ratings on our senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below.

Moody’s Investors Service	Baa2
Standard and Poor’s	BBB-
Fitch Ratings	BBB

     At June 30, 2008, the evaluation of our credit rating is “stable outlook” from all three agencies.

     With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” ranking at the lower end of the category.

     With respect to Standard and Poor’s, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” indicates that the security has significant speculative characteristics. A “BB” rating indicates that Standard and Poor’s believes the issuer has the capacity to meet its financial commitment on the obligation, but adverse business conditions could lead to insufficient ability to meet financial commitments. Standard and Poor’s may modify its ratings with a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

     With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial

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alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

OTHER

Off-Balance Sheet Arrangements

     We have no guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or our credit ratings.

Impact of Inflation

     We have generally experienced increased costs in recent years due to the effect of inflation on the cost of labor, benefits, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies costs can directly affect income through increased operating and maintenance costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of the costs related to our property, plant and equipment and materials and supplies is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, we believe we may be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. However, cost-based regulation along with competition and other market factors limit our ability to price services or products to ensure recovery of inflation’s effect on costs.

Environmental Matters

     As discussed in Note 2 of the Notes to Consolidated Financial Statements included in Part 1, Item 1 herein, we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.

Safety Matters

     Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the DOT PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. We have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $175 million and $195 million over the remaining assessment period of 2008 through 2012. The cost estimates have been revised to reflect refinements in the scope of required remediation and for increases in assessment and remediation costs. Our 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.

Legal Matters

     We are party to various legal actions arising in the normal course of business. Our management believes that the disposition of outstanding legal actions will not have a material adverse effect on our future financial condition.

Regulatory Proceedings

     Reference is made to Note 2 of the Notes to Consolidated Financial Statements, included in Part 1, Item 1 herein, for information about regulatory and business developments which cause operating and financial uncertainties.

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CONCLUSION

     Although no assurances can be given, we currently believe that the aggregate of cash flows from operating activities, supplemented, when necessary, by advances or capital contributions from our partners and from borrowings under the credit agreement, will provide us with sufficient liquidity to meet our capital requirements. When necessary, we also expect to access public and private markets on terms commensurate with our credit ratings to finance our capital requirements.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

     For quantitative and qualitative disclosures about market risk, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” of our annual report on Form 10-K for the year ended December 31, 2007.  Our exposures to market risk have not changed materially since December 31, 2007.

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Item 4. Controls and Procedures

Evaluation of Disclosure 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 our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls are effective at a reasonable assurance level.

     Our management, including our Senior Vice President and our 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.

Changes in Internal Controls over Financial Reporting

     There have been no changes during the second quarter of 2008 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 2007 Annual Report on Form 10-K and Part II, Item 1A. Risk Factors in our 2008 First Quarter Report on Form 10-Q.

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.

(4	)	Instruments defining the rights of security holders, including indentures:
		-	1	Indenture, dated as of May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A. (Exhibit 4.1 to Form 8-K filed May 23, 2008)
(10	)	Material contracts
		-	1	Registration Rights Agreement, dated as of May 22, 2008, among Northwest Pipeline GP and Banc of America Securities LLC, BNP Paribas Securities Corp. and Greenwich Capital Markets, Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto. (Exhibit 10.1 to Form 8-K filed May 23, 2008)
(31	)	Section 302 Certifications
		-	1	Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
		-	2	Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32	)	Section 906 Certification
		-	1	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

Date: August 7, 2008

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