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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-K


þ		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2007


o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Transition Period from to

Commission File Number 1-7414

NORTHWEST PIPELINE GP

(Exact name of registrant as specified in its charter)


DELAWARE		26-1157701
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

295 Chipeta Way, Salt Lake City, Utah		84108
(Address of principal executive offices)		(Zip Code)

(801) 583-8800
(Registrant’s telephone number, including area code)

Securities Registered Pursuant to Section 12(b) of the Act:
None

Securities Registered Pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No þ

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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 Act). Yes o No þ

Documents Incorporated by Reference:
None

NORTHWEST PIPELINE GP

FORM 10-K

PART I

Item 1. BUSINESS

In this report, Northwest Pipeline GP and its consolidated affiliate, Northwest Pipeline Services LLC, (Northwest) are at times referred to in the first person as “we”, “us” or “our”.

GENERAL

On December 31, 2007, Northwest was owned 12.1 percent by Williams Pipeline Partners Holdings LLC and 87.9 percent by WGPC Holdings LLC, both indirect wholly-owned subsidiaries of The Williams Companies, Inc. (Williams). In January 2008, WGPC Holdings LLC distributed 7 percent of its general partnership interest in us to Williams Gas Pipeline Company, LLC (WGP). Williams Gas Pipeline contributed the 7 percent general partnership interest in us to Williams Pipeline Partners Holdings LLC.

RECENT EVENTS

On January 24, 2008, Williams Pipeline Partners L.P. (previously a wholly-owned subsidiary of 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. 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 23, 2008 from Williams Pipeline Partners L.P. for the partnership’s purchase of its 15.9 percent interest, and Northwest in turn contributed $300.9 million to Williams. After these transactions, Northwest is owned 35 percent by Williams Pipeline Partners L.P. and 65 percent by WGPC Holdings LLC. Through its ownership interests in each of our partners, Williams indirectly owns 81.7 percent of Northwest as of February 28, 2008.

We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through the states of Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. We provide natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Our principal business is the interstate transportation of natural gas which is regulated by the Federal Energy Regulatory Commission (FERC).

Prior to October 1, 2007, Northwest was a corporation, known as Northwest Pipeline Corporation, and was wholly-owned by WGP. Effective October 1, 2007, Northwest converted to a general partnership. Throughout this document, “Northwest” refers to Northwest Pipeline Corporation prior to October 1, 2007, and Northwest Pipeline GP thereafter.

PIPELINE SYSTEM, CUSTOMERS AND COMPETITION

Transportation and Storage

Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2007, we had long-term firm

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transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.4 Bcf* of natural gas per day.

We have access to multiple strategic natural gas supply basins, including basins in the Rocky Mountain region, the San Juan Basin and the Western Canadian Sedimentary Basin, or WCSB. We are the only interstate natural gas pipeline that currently provides service to certain key markets, including Seattle, Washington, Portland, Oregon and Boise, Idaho. In addition, we believe that we provide competitively priced services in markets such as Reno, Nevada, Spokane, Washington and Medford, Oregon that are also served by other interstate natural gas pipelines.

We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible and short-term firm transportation services. During 2007, we served a total of 132 transportation and storage customers. Our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Co., which accounted for approximately 20.0 percent and 11.5 percent, respectively, of our total operating revenues for the year ended December 31, 2007. No other customer accounted for more than 10 percent of our total operating revenues during that period.

Our rates are subject to the rate-making policies of FERC. We provide a significant portion of our transportation and storage services pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees, which are fees that are owed for reserving an agreed upon amount of pipeline or storage capacity regardless of the amount of pipeline or storage capacity actually utilized by a customer. When a customer utilizes the capacity it has reserved under a firm transportation contract, we also collect a volumetric fee based on the quantity of natural gas transported. These volumetric fees are typically a small percentage of the total fees received under a firm contract. Over 99 percent of our long-term firm contracts are at the maximum rate allowed under our tariff, as distinguished from discounted rates. We also derive a small portion of our revenues from short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related services. The high percentage of our revenue derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions.

We have approximately 12.6 Bcf of working natural gas storage capacity through the following three storage facilities. These natural gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to certain major customers.

	•		Jackson Prairie: We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of our distribution customers. As of December 31, 2007, our share of the firm seasonal storage service in this facility was approximately 7.3 Bcf of working natural gas storage capacity and up to 283 MMcf per day of peak day deliveries. Additionally, our share of the best-efforts delivery capacity was 50 MMcf per day. As described below, we are participating in an ongoing expansion of Jackson Prairie.

	•		Plymouth LNG: We also own and operate an LNG storage facility located near Plymouth, Washington, which provides standby service for our customers during extreme peaks in demand. The facility has a total LNG storage capacity equivalent to 2.3 Bcf of working natural gas, liquefaction capability of 12 MMcf per day and regasification capability of 300 MMcf per day. Certain of our major customers own the working natural gas stored at the LNG plant.

	•		Clay Basin Field: We have a contract with a third party under which natural gas storage services are provided to us in an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. We are authorized to utilize the Clay Basin Field at a seasonal storage level of 3.0 Bcf of working natural gas, with a firm delivery capability of 25 MMcf of natural gas per day.


*		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 one trillion British Thermal Units. The term Dth means one dekatherm, which is equal to one MMBtu. The term MDth means thousand dekatherms. The term MMDth means million dekatherms.

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Competition

We believe the topography of the Pacific Northwest makes construction of competing pipelines difficult and expensive and it forms a natural barrier to entry for potential competitor pipelines in our primary markets such as Seattle, Washington, Portland, Oregon and Boise, Idaho. Our pipeline is currently the sole source of interstate natural gas transportation in many of the markets we serve. However, there are a number of factors that could increase competition in our traditional market area. For example, customers may consider such factors as cost of service and rates, location, reliability, available capacity, flow characteristics, pipeline service offerings, supply abundance and diversity and storage access when analyzing competitive pipeline options.

Competition could arise from new ventures or expanded operations from existing competitors. For example, in late 2006, Northwest Natural Gas Co., our second largest customer, announced that it is partnering with TransCanada’s Gas Transmission Northwest, or GTN, to build the Palomar Gas Transmission project. This proposed project would consist of a greenfield pipeline from GTN’s system in central Oregon to Northwest Natural’s system in western Oregon. Palomar could also be used to transport natural gas from one of the proposed Columbia River LNG terminals back to GTN’s system. GTN also previously proposed a 235-mile lateral from its mainline system near Spokane, Washington to the Seattle/Tacoma corridor, or Washington Lateral, as an alternative to our Capacity Replacement Project. Puget Sound Energy, our largest customer, was the target customer for this lateral. While this pipeline project has not been built, incremental power generation loads requiring a pipeline expansion could cause GTN to reconsider the Washington Lateral project.

We are also experiencing increased competition for domestic supply with the completion of projects such as Kinder Morgan’s Rockies Express and Wyoming Interstate’s Kanda Lateral, which are designed to transport natural gas produced in the Piceance and Uinta Basins to Midwestern and Eastern markets. Additionally, Questar Pipeline and Enterprise Products Partners recently announced plans to construct the White River Hub Project, an approximate seven-mile pipeline to connect to several interstate pipelines in the Greasewood and Meeker, Colorado areas. The net effect of these projects could result in increased liquidity in Piceance Basin gas supplies and a significant narrowing of the price differential between the Rocky Mountains and Sumas natural gas supplies, further increasing overall Pacific Northwest natural gas prices.

Spectra Energy (Spectra) and El Paso Corporation (El Paso) have each independently proposed new pipeline projects that would begin at the Opal Hub in Wyoming and terminate in Malin, Oregon to create additional access to Rocky Mountain gas in western markets. Williams, in conjunction with GTN, has proposed an alternative project called the Sunstone Pipeline Project that would begin at the Opal Hub and terminate at Stanfield, Oregon. Sunstone would be constructed along our existing pipeline corridor to provide up to 1.2 Bcf per day of additional supply for our customers and customers on GTN’s system and could be used by GTN customers to deliver gas to Malin, Oregon.

Natural gas also competes with other forms of energy available to Northwest’s customers, including electricity, coal, fuel oils and other alternative energy sources.

In addition, the FERC’s continuing efforts to promote competition in the natural gas industry have increased the number of service options available to shippers in the secondary market. As a result, our customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with our pipeline services. Some customers see this as a benefit because it allows them to effectively reduce the cost of their capacity reservation fees.

CAPITAL PROJECTS

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.

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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 costs 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.

Colorado Hub Connection Project

We have proposed installing a new lateral to connect the White River Hub near Meeker, Colorado to our mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection, or CHC Project. It is estimated that the construction of the CHC Project would cost up to $53 million and could begin service as early as November 2009. We have proposed to combine the lateral with up to 298 MMcf per day of existing mainline capacity, including up to 98 MMcf per day of capacity from various receipt points for delivery to Ignacio, Colorado, that is currently sold on a short-term basis. In addition, the project could help facilitate re-contracting up to 200 MMcf per day from Stanfield, Oregon to Ignacio, Colorado that is currently held by Pan-Alberta Gas under a contract that terminates on October 31, 2012. The Pan-Alberta capacity was originally contracted to transport natural gas supplies from the WCSB through our system for delivery to California markets. After the associated California commitments were terminated, the producers underlying the Pan-Alberta contract directed their supplies to other markets and no longer utilized the capacity contracted on our system.

The 98 MMcf per day of short-term firm capacity is currently contracted through at least November 2008 at maximum rates, but historically, we have deeply discounted our rates for this capacity.

With respect to the Pan-Alberta commitments, the 200 MMcf per day of capacity generates approximately $27.7 million in annual capacity reservation revenues. Pan-Alberta has confirmed that it will terminate its contract in 2012 and is willing to relinquish up to 100 MMcf per day of its capacity early, if we elect to utilize this capacity in conjunction with the CHC Project.

In addition to providing greater opportunity for contract extensions for the existing short-term firm and Pan-Alberta capacity, the CHC Project would provide direct access to additional natural gas supplies at the White River Hub for our Pacific Northwest customers. We have entered into precedent agreements with minimum terms of ten years at maximum rates for most of the short-term firm and Pan-Alberta capacity that is available prior to 2012 and a portion of the capacity that is not available until 2012. The Colorado Hub Connection Project remains subject to certain conditions, including the necessary regulatory approvals. If we do not proceed with the CHC Project, or are otherwise unable to resell any portion of the Pan-Alberta the capacity, we will seek recovery of any shortfall in annual capacity reservation revenues from our remaining customers in a future rate proceeding. If the CHC Project proceeds, we expect to collect maximum rates for the new CHC capacity commitments and seek approval to recover the CHC Project costs in any future rate case filed with the FERC.

Parachute Lateral Project

We placed our Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, we filed an application with the FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (Parachute), which is owned by an affiliate of Williams. This application was approved by the FERC on November 15, 2007, and we completed the transfer of the Parachute Lateral on December 31,

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2007. We received cash proceeds of $79.8 million from Parachute equal to the net book value of the net assets transferred, and subsequently made a distribution to Williams in an equal amount. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. Prior to the transfer of the facilities, we reassessed the probability of recovering certain regulatory assets associated with the Parachute Lateral and concluded that with the change of ownership it was not probable that these assets would be recovered in future rates. In the fourth quarter 2007, $2.8 million of these assets were charged to expense.

As contemplated in the application for amendment, Parachute has leased the facilities back to us. We will continue to operate the facilities under the FERC certificate. When Williams Field Services completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate, and Parachute will assume full operational control and responsibility for the Parachute Lateral. Under the terms of the lease, we will pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral. Based upon the above, we do not anticipate any adverse impact to our future results of operations or financial position from these transactions.

Sundance Trail Expansion

In February 2008, we initiated an open season for the proposed Sundance Trail Expansion project seeking commitments from shippers for approximately 150,000 Dth per day of firm transportation service from the White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project, which is estimated to cost between $45 million and $55 million, would include construction of approximately 16 miles of 30-inch loop between the Green River, Wyoming and Muddy Creek, Wyoming compressor stations and the addition of horsepower at our existing Vernal compressor station. The project would utilize capacity on the proposed lateral to be constructed as part of our Colorado Hub Connection project to access supplies in the Piceance Basin.

Seasonality

Although we deliver more gas to our market areas in the winter heating season months of November through March, because a significant percentage of our revenues are collected through reservation fees, our revenues remain fairly stable from quarter to quarter. The table below sets forth seasonal revenues, expenses and throughput for each quarter and the total year ended December 31, 2007.


2007	Jan-Mar			Apr-Jun			Jul-Sep			Oct-Dec			Total
Revenues ($ in 000)	$	103,043		$	102,655		$	106,364		$	109,789		$	421,851
Revenue %		24.5	%		24.3	%		25.2	%		26.0	%		100	%
Operating Expenses ($ in 000)	$	53,726		$	38,199		$	56,384		$	62,813		$	211,122
Throughput (TBtu) (1)		200			160			177			220			757
Throughput %		26.4	%		21.1	%		23.4	%		29.1	%		100	%


(1)		Parachute Lateral volumes are excluded from throughput as these volumes flow under separate contracts that do not generally result in mainline throughput.

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OPERATING STATISTICS

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


	Year Ended December 31,
	2007		2006		2005
	(In trillion British Thermal Units)
Total Throughput (1)		757		676		673

Average Daily Transportation Volumes		2.1		1.9		1.8
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity		2.5		2.5		2.5
Average Daily Reserved Capacity Under Short-Term Firm Contracts (2)		.8		.9		.8


(1)		Parachute Lateral volumes of 55 TBtu in 2007 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.

REGULATORY MATTERS

FERC Regulation

Our interstate pipeline system and storage facilities are subject to extensive regulation by FERC. FERC has jurisdiction with respect to virtually all aspects of our business, including generally:

	•		transportation and storage of natural gas;

	•		rates and charges;

	•		terms of service including creditworthiness requirements;

	•		construction of new facilities;

	•		extension or abandonment of service and facilities;

	•		accounts and records;

	•		depreciation and amortization policies;

	•		relationships with marketing affiliates; and

	•		initiation and discontinuation of services.

We hold certificates of public convenience and necessity issued by FERC pursuant to Section 7 of the Natural Gas Act of 1938 (NGA) covering our facilities, activities and services. We may not unduly discriminate in providing open access, available transportation and storage services to customers qualifying under our tariff provisions. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of items for regulatory purposes. The books and records of interstate pipelines may be periodically audited by FERC.

FERC regulates the rates and charges for transportation and storage in interstate commerce. Interstate pipelines may not charge rates that have been determined not to be just and reasonable.

The maximum recourse rates that may be charged by interstate pipelines for their services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are level of plant investment and costs of providing service, allowed rate of return and volume throughput and contractual capacity

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commitments. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved tariff or established by reference to FERC’s regulations. Rate design and the allocation of costs also can impact a pipeline’s profitability. Interstate pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”

Interstate pipelines may also use “negotiated rates” which, in theory, could involve rates above or below the “recourse rate,” provided the affected customers are willing to agree to such rates. A prerequisite for having the right to agree to negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s maximum recourse rates.

On June 30, 2006, we filed a general rate case under Section 4 of the NGA. Significant costs that contributed to the need to file this rate case included: construction of the Capacity Replacement Project, an increase in reliability and integrity expenditures, and an increase in other operating costs. The Capacity Replacement Project stemmed from two breaks in 2003 in a segment of our pipeline in western Washington, which resulted in Corrective Action Orders from the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). In response to these orders, and pursuant to FERC certificate authority, we abandoned approximately 268 miles of existing 26-inch pipeline and replaced it with approximately 80 miles of 36-inch pipeline. The Capacity Replacement Project has been completed at an estimated cost of $325 million.

On July 31, 2006, FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement that resolved all outstanding issues in the rate case. On March 30, 2007, FERC approved the submitted settlement and it is now final. The settlement specified an annual cost of service of $404 million and increased our general system firm transportation rates from $0.30760 to $0.40984 per Dth, effective January 1, 2007. Refunds to customers were made during April 2007. Pursuant to the settlement, a rate moratorium precludes filings by us or by any other party to the settlement for any further rate increases or decreases prior to January 1, 2009 and we are required to file a new rate case to be effective not later than January 1, 2013.

FERC Policy Statement on Income Tax Allowances

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

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

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

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FERC Policy Statement on Proxy Groups and Return on Equity

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

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

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

Energy Policy Act of 2005

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or EP Act 2005. Among other matters, EP Act 2005 amends the NGA to add an antimanipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations prescribed by FERC and provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the antimanipulation provision of EP Act 2005, and subsequently denied rehearing of that order. The rule makes it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new antimanipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction. The EP Act 2005 also amends the NGA and the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The antimanipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.

Safety and Maintenance

We are subject to regulation by the DOT’s PHMSA, pursuant to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in high consequence areas.

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PHMSA regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. The PHMSA may assess fines and penalties for violations of these and other requirements imposed by its regulations.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but some are certified by DOT to assume responsibility for inspection and enforcement of federal natural gas pipeline safety regulations. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Our natural gas pipeline has inspection and compliance programs designed to maintain compliance with federal and applicable state pipeline safety and pollution control requirements.

We are subject to a number of federal laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and some comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the U.S. Environmental Protection Agency community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities, and citizens.

Environmental Regulation

General

Our natural gas transportation and storage operations are subject to extensive and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including:

	•		requiring the acquisition of permits to conduct regulated activities;

	•		restricting the manner in which we can release materials into the environment;

	•		imposing investigatory and remedial obligations to mitigate pollution from former or current operations;

	•		assessing administrative, civil and criminal penalties for failure to comply with applicable legal requirements; and

	•		in certain instances, enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to applicable laws and regulations.

As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected.

The general trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and, thus, any changes in environmental laws and regulations that result in more stringent and costly hazardous substance and waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. In the event of future increases in costs, we may be unable to pass on those increases to our customers. We believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements will not have a material adverse effect on us.

The following is a discussion of some of the environmental laws and regulations that are applicable to natural gas transportation and storage activities.

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Waste Management

Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act, also known as RCRA, and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous solid wastes, which includes certain wastes associated with the exploration and production of oil and natural gas. In the course of our operations, we may generate petroleum hydrocarbon wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous solid wastes. Similarly, the Toxic Substances Control Act, or TSCA, and analogous state laws impose requirements on the use, disposal and storage of various chemicals and chemical substances. In the course of our operations, we may use chemicals and chemical substances which are regulated by TSCA.

Site Remediation

The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owner or operator of a site where a hazardous substance release into the environment occurred, and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency, also known as the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

We currently own or lease properties that for many years have been used for the transportation and compression of natural gas, and the storage of natural gas. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

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 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 consent decrees between us and the 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 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 December 31, 2007, we had accrued liabilities totaling approximately $7.5 million for these costs, which are expected to be incurred over the period from now through 2012. We believe these costs associated with compliance with

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these environmental laws and regulations are prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Air Emissions

The Clean Air Act and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for and strict compliance with air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in the assessment of monetary penalties and the pursuit of potentially criminal enforcement actions, the issuance of injunctions, and the further imposition of conditions or restrictions on permitted operations.

We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, we may be required to supplement or modify our air emission control equipment and strategies due to changes in state implementation plans for controlling air emissions in regional non-attainment areas, or stricter regulatory requirements for sources of hazardous air pollutants. We believe that any such future requirements imposed on us will not have a material adverse effect on our operations.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into state waters as well as waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also regulates storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, and monitor and sample storm water runoff from their facilities. Under the Clean Water Act, federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Activities on Federal Lands

Natural gas transportation activities conducted on federal lands are subject to review and assessment under provisions of the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment, or a more detailed Environmental Impact Statement, that assesses the potential direct, indirect and cumulative impacts of a proposed project, which may be made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

Endangered Species

The Endangered Species Act restricts activities that may affect threatened and endangered species or their habitats. Some of Northwest’s natural gas pipeline is located in areas inhabited by threatened or endangered species. If Northwest’s activities adversely affect endangered species or their habitats, Northwest could incur additional costs or become subject to operating restrictions or bans in the affected area. Civil and criminal penalties can be imposed against any person violating the Endangered Species Act.

Global Warming and Climate Control

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states, including New Mexico, Oregon and

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Washington, have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where we conduct business could adversely affect our operations and demand for our services.

Anti-Terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but such costs could be substantial.

INSURANCE

Our insurance program includes general liability insurance, auto liability insurance, workers’ compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate. However, we are not fully insured against all risks inherent in our business. See “Risk Factors” below.

OWNERSHIP OF PROPERTY

We own our system in fee simple. However, a substantial portion of our system is constructed and maintained on and across properties owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Our compressor stations, with associated facilities, are located in whole or in part upon lands owned by us and upon sites held under leases or permits issued or approved by public authorities. Land owned by others, but used by us under rights-of-way, easements, permits, leases, licenses or consents includes land owned by private parties, federal, state and local governments, quasi-governmental agencies, or Native American tribes. The Plymouth LNG facility is located on lands owned in fee simple by us. Various credit arrangements restrict the sale or disposal of a major portion of our pipeline system. We lease our corporate offices in Salt Lake City, Utah.

EMPLOYEES

As of December 31, 2007, our consolidated affiliate, Northwest Pipeline Services LLC had 446 employees. Northwest Pipeline GP has no employees. Services are provided to Northwest Pipeline GP by Northwest Pipeline Services LLC, a variable interest entity.

TRANSACTIONS WITH AFFILIATES

We engage in transactions with Williams and other Williams’ subsidiaries. See “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements — 1. Summary of Significant Accounting Policies and 8. Transactions with Major Customers and Affiliates” and “Item 13. Certain Relationships and Related Transactions and Director Independence.”

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FORWARD LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT FOR
PURPOSES OF THE “SAFE HARBOR“PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Item 1A. RISK FACTORS

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; 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;

	•		changes in the current geopolitical situation;

	•		risks related to strategy and financing, including restrictions stemming from our debt agreements; 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-

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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. These factors are described in the following section.

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, operating results, and financial condition as well as adversely affect the value of an investment in our securities.

Risks Inherent to our Industry and Business

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

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

	•		uncontrolled releases of natural gas;

	•		fires and explosions;

	•		natural disasters;

	•		mechanical problems; and

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

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

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

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

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

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

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

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

Our primary exposure to market risk occurs at the time the primary terms of existing transportation and storage contracts expire and are subject to termination. Although none of our material contracts are terminable in 2008, upon expiration of the primary terms we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis.

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

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

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

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

	•		whether our business strategy continues to be successful;

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

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•

the effects of state regulation on customer contracting practices.

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

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

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

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

For example, we currently have a contract with Pan-Alberta Gas that was originally entered into to transport natural gas supplies from the Western Canadian Sedimentary Basin through our system for delivery to California markets. After the associated California commitments were terminated, the producers underlying the Pan-Alberta contract directed their supplies to other markets and no longer utilized the capacity commitments on our system. We have proposed the Colorado Hub Connection Project in an attempt to re-contract the Pan-Alberta contract commitments, which terminate in 2012. However, if our re-contracting or reselling of this capacity fails, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

Costs of environmental liabilities and complying with existing and future environmental regulations could exceed our current expectations.

Our natural gas transportation and storage operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. For a description of these laws and regulations, please see “Business — Regulatory Matters — Environmental Regulation.”

These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the

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environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the operation of natural gas transportation and storage facilities due to the handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to the operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the federal Resource Conservation and Recovery Act, or RCRA, and analogous state laws, in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of its remedial costs from insurance. Please read “Business — Regulatory Matters — Environmental Regulation” for more information. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly regulated substance and waste handling, storage, transport, disposal, or remedial requirements could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

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

We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2007, our two largest customers were Puget Sound Energy and Northwest Natural Gas Co. These customers accounted for approximately 20.0 percent and 11.5 percent, respectively, of our operating revenues for the year ended December 31, 2007. The loss of even a portion of our contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operation and cash flows.

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

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable due to repairs, damage to the facility, lack of capacity or any other reason, our ability to

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operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

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

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

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

Risks Related to Strategy and Financing

Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with

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these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.

Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

A downgrade of our current credit rating could impact our costs of doing business in certain ways and maintaining our current credit rating is within the control of independent third parties.

A downgrade of our credit rating might increase our cost of borrowing. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:

	•		economic downturns;

	•		deteriorating capital market conditions generally;

	•		declining market prices for natural gas, natural gas liquids and other commodities;

	•		terrorist attacks or threatened attacks on our facilities or those of other energy companies;

	•		the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital markets and the energy industry over the last few years, credit rating agencies continue to review the criteria for attaining investment grade ratings and make changes to those criteria from time to time. While we are currently rated investment grade by three of the major credit rating agencies, no assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

Williams can exercise substantial control over our distribution policy and our business and operations and may do so in a manner that is adverse to our interests.

Our general partners are both indirectly controlled by Williams. The majority interest in our business is owned by a subsidiary of Williams. As a result, Williams exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

	•		decisions on financings and our capital raising activities;

	•		mergers or other business combinations;

	•		acquisition or disposition of assets.

Our majority partner’s board of directors could decide to increase distributions or advances to our partners consistent with existing debt covenants. This could adversely affect our liquidity. Moreover, various Williams’ credit facilities include covenants restricting the ability of Williams’ entities, including us,

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to make advances to Williams and its other subsidiaries, which could make the terms on which we may be able to secure additional future financing less favorable.

The financial condition and liquidity of Williams affects our access to capital, our credit standing and our financial condition.

Substantially all of Williams’ operations are conducted through its subsidiaries. Williams’ cash flows are substantially derived from loans and dividends paid to it by its subsidiaries, including WGP, our majority partner, under which Williams’ interstate natural gas pipelines and gas pipeline joint venture investments are grouped. Williams’ cash flows are typically utilized to service debt and pay dividends on the common stock of Williams, with the balance, if any, reinvested in its subsidiaries as contributions to capital.

Our ratings and credit are impacted by Williams’ credit standing. If Williams were to experience a deterioration in its credit standing or financial difficulties, our access to credit and our ratings could be adversely affected.

Risks Related to Regulations that Affect our Industry

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

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

	•		perform ongoing assessments of pipeline integrity;

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

	•		improve data collection, integration and analysis;

	•		repair and remediate our pipeline as necessary; and

	•		implement preventative and mitigating actions.

In meeting these integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $175 million and $195 million over the remaining assessment period of 2008 through 2012. Should we fail to comply with Department of Transportation regulations, we could be subject to penalties and fines. If the costs of complying with these integrity regulations are materially higher than our current expectations, our business could be adversely impacted.

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

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

	•		rates, operating terms and conditions of service;

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

	•		certification and construction of new facilities;

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	•		acquisition, extension, disposition or abandonment of facilities;

	•		accounts and records;

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

	•		initiation and discontinuation of services; and

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

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation and storage services in interstate commerce. Natural gas companies may only charge rates that have been determined to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

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

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

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

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

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

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, the pipeline asked FERC to reconsider this ruling. On March 9, 2007, FERC granted rehearing for further consideration of its December 8, 2006 order. The rehearing is pending before the FERC.

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

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

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

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

The outcome of future rate cases to set the rates we can charge customers on our pipeline might result in rates that lower our return on the capital that we have invested in our pipeline.

There is a risk that rates set by the FERC will be lower than is necessary to provide us with an adequate return on the capital we have invested in our assets or might not be adequate to recover increases in operating costs. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.

Risks Related to Accounting Standards

Potential changes in accounting standards might cause us to revise our financial results and disclosures in the future, which might change the way analysts measure our business or financial performance.

Regulators and legislators continue to evaluate accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firm and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or

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practices in general with respect to public companies or the energy industry or in our operations specifically.

In addition, the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC) or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology.

Institutional knowledge residing with current employees nearing retirement eligibility might not be adequately preserved.

In our business, institutional knowledge resides with employees who have many years of service. As these employees reach retirement age, we may not be able to replace them with employees of comparable knowledge and experience. In addition, we may not be able to retain or recruit other qualified individuals and our efforts at knowledge transfer could be inadequate. If knowledge transfer, recruiting and retention efforts are inadequate, access to significant amounts of internal historical knowledge and expertise could become unavailable to us.

Failure of or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its outsourcing providers and to closely monitor their performance, a deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business.

Certain of our accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to us present similar risks of business operations located outside of the United States, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Risks Related to Weather, Other Natural Phenomena and Business Disruption

Our assets and operations can be affected by weather and other natural phenomena.

Our assets and operations can be adversely affected by earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations.

Acts of terrorism could have a material adverse effect on our financial condition, results of operations and cash flows.

Our assets and the assets of our customers and others may be targets of terrorist activities that could disrupt our business or cause significant harm to our operations, such as full or partial disruption to our ability to transport natural gas. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

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PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

On October 1, 2007, Northwest Pipeline Corporation converted from a Delaware corporation to a general partnership, Northwest Pipeline GP (Northwest GP). As of December 31, 2007, we were wholly-owned by Williams. As of February 28, 2008, we are owned 65 percent by Williams and 35 percent by Williams Pipeline Partners L.P., a publicly traded master limited partnership. Our partnership interest is not publicly traded. Through its partial ownership of Williams Pipeline Partners L.P., Williams directly and indirectly owns 81.7 percent of us.

We paid $109.8 million in cash distributions to our partners during 2007.

Item 6. SELECTED FINANCIAL DATA

The following financial data as of December 31, 2007 and 2006, and for the three years ended December 31, 2006, are an integral part of, and should be read in conjunction with, the audited consolidated financial statements and related notes included elsewhere herein. All other amounts have been prepared from our audited consolidated financial statements not included herein. Certain amounts below have been restated or reclassified. See Note 1 of Notes to Consolidated Financial Statements in Part II Item 8 for discussion of changes in 2007, 2006 and 2005. Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion & Analysis of Financial Condition and Results of Operations of this report.


	Year Ended December 31,
	2007			2006		2005		2004		2003
				(Restated) (B)		(Restated) (B)		(Restated) (B)		(Restated) (B)
						(Thousands of Dollars)
Income Statement Data:
Operating revenues	$	421,851		$	324,250	$	321,457	$	338,532	$	323,353
Net income		439,726	(A)		54,462		68,974		73,974		70,612
Balance Sheet Data (at period end):
Total assets		2,056,471			2,049,324		1,692,371		1,670,499		1,615,563
Long-term debt, including current maturities		693,736			687,075		520,080		527,562		535,042
Total owner’s equity		1,185,616			857,945		756,346		737,372		723,010


Note:		Earnings and distributions/dividends per partnership unit/common share are not presented because we are a wholly-owned subsidiary of Williams at December 31, 2007 and for all periods presented.


(A)		Through September 30, 2007, we used the liability method of accounting for income taxes which required, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. On October 1, 2007, we reversed to income deferred income tax liabilities of approximately $311.8 million and $10.2 million of deferred income tax assets to other comprehensive income.

(B)		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. The purchase price allocation was not pushed down to us, as FERC policy does not permit us to recover these amounts through our rates and we have not been required to reflect Williams’ purchase price allocations in our financial statements. Beginning December 31, 2007, we have elected to include Williams’ purchase price allocations in our financial statements. Accordingly, our 2003, 2004, 2005 and 2006 selected financial data has been restated to include the effects of Williams’ excess purchase price

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allocation. A reconciliation between our original basis in our assets and liabilities and the selected financial data above follows:


	Year Ended December 31,
	2006			2005			2004			2003
Income Statement:
Net income, as previously reported	$	57,143		$	71,755		$	76,655		$	73,294
Depreciation of purchase price allocation to property, plant and equipment, net of income taxes		(2,681	)		(2,781	)		(2,681	)		(2,682	)

Net income, as restated	$	54,462		$	68,974		$	73,974		$	70,612

Balance Sheet:
Equity, as previously reported	$	813,037		$	708,757		$	687,002		$	669,959
Allocation of purchase price to property, plant and equipment, net of taxes		44,908			47,589			50,370			53,051

Equity, as restated	$	857,945		$	756,346		$	737,372		$	723,010


Item 7.		MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

Unless indicated otherwise, the following discussion of critical accounting policies and estimates, discussion and analysis of results of operations, and financial condition and liquidity should be read in conjunction with the financial statements and notes thereto included within Part II — Item 8 of this document.

HOW WE EVALUATE OUR OPERATIONS

We evaluate our business on the basis of a few key measures:

•		the level of capacity reserved under our long-term firm transportation and storage contracts;

•		the level of revenues provided by our short-term firm and interruptible transportation and storage services;

•		our operating expenses; and

•		our cash available for distribution.

Long-Term Firm Service

We compete for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. To the extent our customers believe that we can offer these services at rates, terms and conditions, which are more attractive than those of our competition, they will be more inclined to purchase our services. Firm transportation service requires us to reserve pipeline capacity for a customer at certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” charge based on the amount of capacity being reserved regardless of whether the capacity is used, plus a volumetric fee and an in-kind fuel reimbursement based on the volume of natural gas transported. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, and generally pay a capacity reservation charge based on the amount of capacity being reserved. Capacity reservation revenues derived from long-term firm service contracts generally remain constant over the term of the contracts, subject to adjustment in rate proceedings with FERC, because the revenues are primarily based upon the capacity reserved and not

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whether the capacity is actually used. Our ability to maintain or increase the amount of long-term firm service we provide is key to assuring a consistent revenue stream.

Short-Term Firm and Interruptible Service

A small portion of our revenues are generated by short-term firm and interruptible services under which customers pay fees for transportation, storage or other related services. Of our revenues for the twelve months ended December 31, 2007, approximately 4.7 percent were derived from short-term firm and interruptible services.

Operating Expenses

Our operating expenses typically do not vary significantly based upon the amount of natural gas we transport. While expenses may not materially vary with throughput, the timing of our spending during a year can be dictated by weather and customer demands. During the winter months, our pipeline average throughput is higher. As a result, we typically do not perform compressor or pipeline maintenance until off peak periods, which generally results in higher costs in the second and third quarters compared to the other two quarters. We are also regulated by the federal government and certain state and local laws which can impact the activities we perform on our pipeline. Changes in these regulations or our assessment of the condition of inspected facilities can increase costs. As an example, the Pipeline Safety Improvement Act of 2002 set new standards for pipelines in assessing the safety and reliability of their pipeline infrastructure. We have and other pipelines have incurred additional costs to meet these standards. Certain of our markets are served by other interstate natural gas pipelines and we need to operate our system efficiently and reliably to effectively compete for transportation and storage services.

Cash Available for Distribution

Under our general partnership agreement, on or before the end of the calendar month following each quarter, our management committee is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. 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 established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.

FACTORS THAT IMPACT OUR BUSINESS

The high percentage of our revenues derived from capacity reservation fees on long-term, contractual arrangements helps mitigate the risk of revenue fluctuations due to near-term changes in natural gas supply and demand conditions and price volatility. Our business can, however, be negatively affected by sustained downturns or sluggishness in the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by our customers, competition and changes in regulatory requirements affecting our operations.

We believe the key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate; our customers and their requirements; and government regulation of natural gas pipelines. These key factors, discussed in more detail below, play an important role in how we manage our operations and implement our long-term strategies.

Supply and Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in natural gas supply and demand. Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as imported LNG, directly or indirectly affect the demand for our services from both producers and consumers. For example, western U.S. production levels are growing rapidly, but a large portion of the new production of natural gas from the Rocky Mountain region will be delivered to markets in the mid-

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continent and eastern U.S. through projects like the Rockies Express Pipeline. Canadian production levels, on the other hand, are in a flat to downward trend and exports to U.S. markets are declining. As a result, our customers will face increasing competition from Mid-Continent and East Coast markets for Rocky Mountain natural gas supplies. As these supply dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to customers willing to contract for transportation on a long-term firm basis. Changes in demographics, the amount of electricity generation, prevailing weather conditions and shifts in residential and commercial usage affect our customers’ overall demand for natural gas. As customer demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet their long-term requirements.

Customers

We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, or LDCs, direct industrial users, electric power generators and natural gas marketers and producers. We provide natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Our customers use our transportation and storage services for a variety of reasons. Natural gas distribution companies and electric generation companies typically require a secure and reliable supply of natural gas over a prolonged period of time to meet the needs of their customers and frequently enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Producers of natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Natural gas marketers use storage and transportation services to capitalize on price differentials over time or between markets. Our customer mix can vary over time and largely depends on the natural gas supply and demand dynamics in our markets.

Competition

Our pipeline is currently the sole source of interstate natural gas transportation in many of the markets it serves. However, there are a number of factors that could increase competition in our traditional market area. For example, customers may consider such factors as cost of service and rates, location, reliability, available capacity, flow characteristics, pipeline service offerings, supply abundance and diversity and storage access when analyzing competitive pipeline options. Competition could arise from new ventures or expanded operations from existing competitors. Some of these competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, FERC’s continuing efforts to promote competition in the natural gas industry have increased the number of service options available to shippers in the secondary market. As a result, our customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with our pipeline services. Some customers see this as a benefit because it allows them to effectively reduce the cost of their capacity reservation fees. However, the high percentage of our revenues derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions in the near term.

Regulation

Regulation of natural gas transportation by FERC and other federal and state regulatory agencies, including the Department of Transportation, has a significant impact on our business. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas.

We believe the collective impact of the trends and uncertainties described above may result in an increasingly competitive natural gas transportation market. This could result in a reduction in the overall average life of our long-term firm contracts which could adversely affect our revenue over the long term. We believe the impact of the factors described in “— Customers” and "— Competition” above may also provide us with growth opportunities. These factors may also result in a need for increased capital expenditures to take advantage of opportunities to bring additional supplies of natural gas into our system to maintain or possibly increase our transportation commitments and volumes.

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OPERATIONS

We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2007, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.4 Bcf of natural gas per day. We also have approximately 12.6 Bcf of working natural gas storage capacity through our one-third interest in the Jackson Prairie underground storage facility, our ownership of the Plymouth LNG storage facility and contract storage at Clay Basin.

Transportation Services

Our transportation services consist primarily of a) firm transportation under long-term contracts, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points on the system, plus a volumetric fee and an in-kind fuel reimbursement based on the volume transported; and b) interruptible transportation, whereby the customer pays to transport natural gas when capacity is available and used. Firm transportation capacity reservation revenues typically do not vary over the term of the contract, subject to adjustment in rate proceedings with FERC, because the revenues are primarily based upon the capacity reserved, and not upon the capacity actually used. We generate a small portion of our revenues from short-term firm and interruptible transportation services.

We are not generally in the business of buying and selling natural gas, but changes in the price of natural gas can affect the overall supply and demand for natural gas, which in turn can affect our results of operations. We depend on the availability of competitively priced natural gas supplies which our customers desire to ship through our system. We deliver natural gas for a broad mix of customers including LDCs, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers.

Storage Services

Our natural gas storage services allow us to offer customers a high degree of flexibility in meeting their delivery requirements and enable us to balance daily receipts and deliveries. For example, LDCs use traditional storage services by injecting natural gas into storage in the summer months when natural gas prices are typically lower and then withdrawing the natural gas during the winter months in order to reduce their exposure to the potential volatility of winter natural gas prices. We offer firm storage service, in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage service, where the customer receives and pays for capacity only when it is available and used.

RECENT EVENTS

On October 1, 2007, Northwest Pipeline Corporation converted from a Delaware corporation to a general partnership, Northwest Pipeline GP. Coincident with the conversion, the partners of Northwest GP entered into a partnership agreement. Northwest is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986) or enhances operations that generate such qualified income. Because of our conversion to a general partnership, we will no longer be subject to federal and state income taxes. As of October 1, 2007, approximately $311.8 million of net deferred income tax liabilities were reversed to income and $10.2 million of deferred income tax assets to other comprehensive income.

On January 24, 2008, Williams Pipeline Partners L.P. (previously a wholly-owned subsidiary of Williams) completed its initial public offering of limited partnership units. In January 2008, we received net

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proceeds of $300.9 million from Williams Pipeline Partners L.P. for the purchase of a 15.9 percent interest in us. Williams also contributed a 19.1 percent interest in us to Williams Pipeline Partners L.P. for a 52.5 percent partnership interest, including a continuation of its 2 percent general partnership interest. We distributed the proceeds to Williams as a reimbursement of capital expenditures incurred prior to our conversion to a partnership for federal income tax purposes. On February 15, 2008, the underwriters of the offering exercised their right to purchase an additional 1,650,000 common units from Williams to cover over-allotments. The underwriters purchased the shares pursuant to that option on February 21, 2008 at the initial public offering price of $18.80 per unit, which includes the underwriting discount. Concurrently with the exercise of the option and in accordance with the terms of the Contribution, Conveyance and Assumption Agreement entered into in connection with the closing of the initial public offering, Williams Pipeline Partners L.P. then redeemed 1,650,000 common units held by its general partner. Including its 2 percent general partnership interest, as of February 28, 2008, Williams holds a 47.7 percent partnership interest in Williams Pipeline Partners L.P.

On June 30, 2006, we filed a general rate case under Section 4 of the Natural Gas Act. On July 31, 2006, the FERC issued an Order accepting our filing and suspended the effective date of the new rates for five months, to become effective January 1, 2007, subject to refund. On January 31, 2007, we filed a stipulation and settlement agreement to resolve all outstanding issues in our pending rate case. On March 30, 2007, the FERC approved the submitted settlement. The settlement specified an annual cost of service of $404 million and increased our general system firm transportation rates from $0.30760 to $0.40984 per Dth, effective January 1, 2007. Refunds to customers were made during April 2007. Pursuant to the settlement, a rate moratorium precludes filings by us or by any other party to the settlement for any further rate increases or decreases prior to January 1, 2009, and we are required to file a new rate case to be effective no later than January 1, 2013.

In September 2007, we received final payment from Duke Energy Trading and Marketing, LLC (Duke) in the amount of $14.5 million, which represents full payment in resolution of the Grays Harbor contract termination dispute. (See “Item 8. Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements — 3. Contingent Liabilities and Commitments - Termination of the Grays Harbor Transportation Agreement.)

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

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

On December 1, 2007, we retired $250 million of 6.625 percent senior unsecured notes upon maturity with $250 million borrowings under the Williams revolving credit agreement.

On December 31, 2007, the Parachute Lateral facilities, originally placed into service in May 2007, were sold to an affiliate for $79.8 million. The facilities are being leased back to us and we will continue to operate the facilities. Under the terms of the lease, we will 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.

We paid $109.8 million in cash distributions to our partners during 2007.

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

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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 lateral to connect the White River Hub near Meeker, Colorado to our mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection, or CHC Project. It is estimated that the construction of the CHC Project would cost up to $53 million and could begin service as early as November 2009. We have proposed to combine the lateral with up to 298 MMcf per day of existing mainline capacity, including up to 98 MMcf per day of capacity from various receipt points for delivery to Ignacio, Colorado, that is currently sold on a short-term basis. In addition, the project could help facilitate re-contracting up to an additional 200 MMcf per day from Stanfield, Oregon to Ignacio, Colorado that is currently held by Pan-Alberta Gas under a contract that terminates on October 31, 2012. Pan-Alberta has confirmed that it will terminate its contract in 2012 and is willing to relinquish up to 100 MMcf per day of its capacity early, if we elect to utilize this capacity in conjunction with the CHC Project.

Jackson Prairie Underground Expansion

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 costs 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

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miles of 30-inch loop between the Green River, Wyoming and Muddy Creek, Wyoming compressor stations and the addition of horsepower at our existing Vernal compressor station. The project would utilize capacity on the proposed lateral to be constructed as part of our Colorado Hub Connection project to access supplies in the Piceance Basin.

CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS AND SENSITIVITIES

The accounting policies discussed below are considered by our management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment.

Regulatory Accounting

Our natural gas pipeline operations are regulated by the FERC. FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. From time to time, certain revenues collected may be subject to possible refunds upon final FERC orders. Accordingly, estimates of rate refund reserves are recorded considering third-party regulatory proceedings, advice of counsel, our estimated risk-adjusted total exposure, market circumstances and other risks. Our current rates were approved pursuant to a rate settlement. As a result, our current revenues are not subject to refund.

SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” requires rate-regulated public utilities that apply this standard to account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying SFAS No. 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. (See Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements - Note 1. Summary of Significant Accounting Policies — Property, Plant and Equipment and Note 10. Regulatory Assets and Liabilities.)

Contingencies

We record liabilities for estimated loss contingencies when a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon management’s assumptions and estimates regarding the probable outcomes of the matters. Should the outcomes differ from the assumptions and estimates, revisions to the liabilities for contingent losses would be required.

Environmental Liabilities

Our environmental liabilities are based on management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of our operating sites. These estimates are based on evaluations and discussions with counsel and independent consultants, and the current facts and circumstances related to these environmental matters. Our accrued environmental liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, the FERC and other governmental authorities on these matters. We continue to conduct environmental assessments and are implementing a variety of remedial measures that may result in increases or decreases in the total estimated environmental costs.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such

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a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

Pension and Postretirement Obligations

We participate in employee benefit plans with Williams and its subsidiaries that include pension and other postretirement benefits. Pension and other postretirement benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.

Revenue Recognition

Revenues from the transportation of gas are recognized in the period the service is provided based on contractual terms and the related transported volumes. As a result of the ratemaking process, certain revenues collected by us may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel, as well as collection and other risks. At December 31, 2007, we had no rate refund liabilities.

RESULTS OF OPERATIONS

ANALYSIS OF FINANCIAL RESULTS

This analysis discusses financial results of our operations for the years 2007, 2006 and 2005. Variances due to 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.

Years Ended December 31, 2006 and 2007

Operating revenues increased $97.6 million, or 30 percent, for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Higher rates resulting from our rate case, which became effective January 1, 2007, were the primary reason for this increase. In addition, the Parachute Lateral, placed into service in May 2007, contributed $6.6 million to revenues.

Our transportation service accounted for 96 percent of our operating revenues for each of the years ended December 31, 2007 and 2006. Natural gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2007 and 2006.

Operating expenses decreased $1.1 million, or 1 percent, from 2006 to 2007. This decrease was due primarily to the June 2007 reversal of our pension regulatory liability of $16.6 million and a reduction of accrued ad valorem taxes of $1.0 million to reflect lower 2007 tax assessments on our property. The pension regulatory liability was reversed based upon management’s assessment that the refundability of this obligation in future rates is no longer probable. These decreases were partially offset by a $6.3 million increase in lease expense due to a change in accounting for our headquarters building lease in the fourth quarter of 2006, a $3.7 million increase in depreciation related to new property additions, a $1.5 million write-off of a regulatory asset associated with the Parachute Lateral, a $4.2 million increase in labor costs

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due to annual salary increases and an increase in the number of employees, and a $1.3 million increase in group insurance expense due primarily to rising medical costs.

Operating income increased $98.7 million, or 88 percent, from 2006 to 2007, due to the reasons discussed above.

Other income increased $8.8 million, or 53 percent, from 2006 to 2007, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million additional contract termination income and $2.3 million additional interest related to the termination of the Grays Harbor transportation agreement. These increases were partially offset by a $5.6 million decrease in the allowance for equity funds used during construction (EAFUDC) resulting from lower capital expenditures in 2007, the $1.3 million write-off of a regulatory asset associated with the Parachute Lateral, a $3.1 million decrease in other interest income resulting from a reduced amount of short-term investments, and a $0.9 million decrease in interest income from affiliates resulting from note repayments from Williams.

Interest charges increased $8.2 million, or 19 percent, from 2006 to 2007, due to a $3.3 million decrease in the allowance for borrowed funds used during construction related to the lower capital expenditures in 2007, the issuance of $175 million of 7 percent senior unsecured notes, due 2016, in June of 2006, and the issuance of $185 million of 5.95 percent senior unsecured notes, due 2017, in April of 2007, partially offset by the early retirement of $175 million of 8.125 percent senior unsecured notes, due 2010, in April of 2007. A $1.8 million increase in other interest resulting from higher amortization of loss on reacquired debt related to the early debt retirement and the refinancing of $250 million of 6.625 percent senior unsecured notes with $250 million of revolver debt in December of 2007 also contributed to this increase.

The provision for income taxes decreased $285.9 million from 2006 to 2007, due to our conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, we recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8 percent compared to 36.4 percent in 2006. At the date of conversion, we recognized income tax benefit of $311.8 million reflecting the removal of our net deferred tax liabilities.

Years Ended December 31, 2005 and 2006

Operating revenues increased $2.8 million, or 1 percent, for the year ended December 31, 2006 as compared to the year ended December 31, 2005. Higher revenues due to short-term firm transportation services of $1.4 million and interruptible park and loan storage services of $1.3 million were the primary sources of this increase. Revenues from short-term firm transportation increased as a result of customers taking advantage of price differentials between producing basins. Interruptible park and loan storage services increased primarily as a result of customers taking advantage of the difference in the cost of gas between summer and winter forecasts.

Our transportation service accounted for 96 percent of our operating revenues and our gas storage service accounted for 3 percent of our operating revenues for each of the years ended December 31, 2006 and 2005.

Operating expenses increased $27.9 million, or 15 percent, from 2005 to 2006. This increase was due primarily to a $9.7 million increase in consulting, contract, engineering, maintenance and other outside services resulting in part from our pipeline integrity and environmental assessment efforts and a change in FERC’s accounting policies requiring us to expense (rather than capitalize) certain pipeline integrity assessment costs beginning in 2006; an $8.9 million increase in depreciation, including a $6.0 million increase resulting from property additions and a $2.9 million increase related to the 2006 correction of an error related to the accounting for our building lease expense and depreciation of leasehold improvements; and a $5.5 million increase in outside administrative costs related primarily to information technology services associated with system enhancements. Also contributing to this increase were higher labor expenses of $3.9 million due to annual salary increases and an increase in the number of employees, higher materials, supplies, vehicle and other expenses of $3.9 million, and higher insurance costs of $1.6 million related primarily to pipeline operations. These increases were partially offset by lower rent expense of $6.2 million related to the change of the accounting for Northwest’s headquarters building lease discussed above.

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Operating income decreased $25.1 million, or 18 percent, from 2005 to 2006, due to the reasons discussed above.

Other income increased $6.0 million, or 57 percent, from 2005 to 2006, primarily due to a $10.8 million increase in the EAFUDC resulting from the significantly higher capital expenditures in 2006 related to the Capacity Replacement Project, partially offset by an adjustment of $4.7 million in 2006 associated with the correction of an error related to the recognition of EAFUDC.

Interest charges increased $2.9 million, or 7 percent, from 2005 to 2006. This increase was the result of higher interest on long-term debt of $5.5 million due to the 7.00 percent senior notes issued in June 2006 due in 2016, offset by a $3.0 million increase in the debt AFUDC related to property additions in 2006.

The provision for income taxes decreased $7.4 million, or 18 percent, due primarily to lower pre-tax income in 2006 as compared to 2005 and a $1.8 million tax benefit adjustment in 2005 as a result of additional analysis of our tax basis and book basis assets and liabilities. Our effective income tax rate was 36.5 percent in 2006 and 35.9 percent in 2005.

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, beginning after the end of the first quarter 2008, available cash will be 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 established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.

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


	Years Ended December 31,
	2007			2006			2005
	(Thousands of Dollars)
Net cash provided (used) by:
Operating activities	$	205,357		$	159,807		$	97,636
Financing activities		(142,523	)		266,919			(57,072	)
Investing activities		(63,826	)		(484,946	)		(34,248	)

Increase (decrease) in cash and cash equivalents	$	(992	)	$	(58,220	)	$	6,316

Operating Activities

Our net cash provided by operating activities in 2007 increased from 2006 due primarily to the increase in our operating results, including the receipt of contract termination proceeds of $14.5 million, and from changes in working capital.

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Our net cash provided by operating activities in 2006 increased from 2005 due largely to lower income tax payments and from other changes in working capital.

Financing Activities

2007

	•		We issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017.

	•		We borrowed $250 million under the Williams’ revolving credit agreement.

	•		We retired $175 million of 8.125 percent senior unsecured notes due 2010.

	•		We retired $250 million of 6.625 percent senior unsecured notes due 2007.

	•		We paid distributions of $109.8 million to Williams.

2006

•

We issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016.

•

We received a capital contribution of $65 million from Williams.

2005

•

We paid dividends of $50 million to Williams.

Investing Activities

2007

	•		Capital expenditures totaled $157.2 million primarily related to normal maintenance and compliance.

	•		We received $79.8 million of proceeds from the sale of the Parachute Lateral to an affiliate.

	•		We received $10.9 million repayment of advances made to Williams.

2006

•

Capital expenditures totaled $473.6 million primarily related to the capacity replacement project.

2005

	•		Capital expenditures totaled $137.2 million primarily related to normal maintenance and compliance.

	•		We received an $87.9 million contract termination payment, representing reimbursement of the net book value of the related assets.

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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.

On December 31, 2007, we made a distribution of $30 million to our partners as of that date (who are affiliates of Williams), representing cash in excess of working capital requirements.

On December 31, 2007, we received $79.8 million in proceeds for the sale of our investment in Parachute Lateral net assets to an affiliate and on the same date made a distribution of $79.8 million to our partners.

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 made to Williams.

We invest cash through participation in Williams’ cash management program. At December 31, 2007 and 2006, the advances due to us by Williams totaled approximately $39.1 million and $50.0 million, respectively. The advances are represented by one or more demand obligations. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29 percent at December 31, 2007.

Credit Agreement

Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012. We have access to $400 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 million, none of which are associated with us, have been issued by the participating institutions, and $250.0 million revolving credit loans, all associated with us, were outstanding at December 31, 2007. In December 2007, we borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. We did not access the agreement in 2006. The interest rate at December 31, 2007 was 5.68 percent.

The credit agreement contains a number of restrictions on the business of the borrowers, including us. These restrictions include restrictions on the borrowers’ and their subsidiaries’ ability to: (i) grant liens securing indebtedness; (ii) merge, consolidate, or sell, lease or otherwise transfer assets; (iii) incur indebtedness; and (iv) engage in transactions with related parties. We and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in our case, and 0.65 to 1, in the case of Williams. The credit agreement also contains affirmative covenants and events of default. If any borrower breaches financial or certain other covenants or if an event of default occurs, the lenders may cause the acceleration of the borrower’s indebtedness and may terminate lending to all borrowers under the credit agreement. Additionally, if: (a) a borrower were to generally not pay its debts as such debts come due or admit in writing its inability to pay its debts generally; (b) a borrower were to make a general assignment for the benefit of its creditors; or (c) proceedings relating to the bankruptcy or receivership of any borrower were to remain unstayed or undismissed for

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60 days, then all lending under the credit agreement would terminate and all indebtedness outstanding under the credit agreement would be accelerated.

Long-Term Financing

We have an effective shelf registration statement on file with the SEC. As of December 31, 2007, $150 million of availability remained under this registration statement. We can raise capital through private debt offerings as well as offerings registered pursuant to offering-specific registration statements. Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets. We believe any additional financing arrangements, if required, can be obtained from the capital markets on terms that are commensurate with our then current credit ratings.

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 categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We anticipate 2008 capital expenditures will be between $100 million and $125 million.

Our expenditures for property, plant and equipment additions were $157.2 million, $473.6 million and $137.2 million for 2007, 2006 and 2005, respectively. The increase in expenditures during 2006 was primarily due to the Capacity Replacement Project, which was completed in late 2006. We filed a rate case on June 30, 2006 to recover the cost of property, plant and equipment placed into service as of December 31, 2006. Our new rates became effective January 1, 2007.

CREDIT RATINGS

During November 2007, rating agencies raised the credit ratings on our senior unsecured long-term debt as shown below. The rise in the Moody’s Investor Services and Standard and Poor’s credit ratings moves us to investment grade ratings from all three agencies.


	Moody’s Investors Service		Ba1 to Baa2
	Standard and Poor’s		BB- to BBB-
	Fitch Ratings		BBB- to BBB

At December 31, 2007, 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 & 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 & 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

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financial commitments. Standard & 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 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

Contractual Obligations

The table below summarizes the maturity dates of our more significant contractual obligations and commitments as of December 31, 2007 (in millions of dollars).


	2008		2009-2010		2011-2012		Thereafter		Total
Long-term debt, including current portion:
Principal	$	—	$	—	$	250.0	$	445.0	$	695.0
Interest		42.1		83.9		76.4		171.2		373.6
Operating leases		6.4		6.3		—		—		12.7
Purchase Obligations:
Natural gas purchase, storage, transportation and construction		28.7		5.2		4.1		—		38.0
Other		0.1		0.5		0.2		—		0.8
Other long-term liabilities, including current portion (1)(2) (3)		1.5		3.3		3.0		—		7.8

Total	$	78.8	$	99.2	$	333.7	$	616.2	$	1,127.9


(1)		Does not include estimated contributions to the pension and other postretirement benefit plans. We made contributions to the pension and other postretirement benefit plans of $3.2 million in 2007, $5.7 million in 2006 and $6.1 million in 2005. (See Note 5 of the Notes to Financial Statements). The decrease in the estimated contributions from 2006 and 2005 levels can be attributed to previous contributions to the other postretirement benefit plan. There were no minimum funding requirements to the tax-qualified pension plans in 2007, 2006 or 2005. We anticipate that future contributions to the pension plan will not vary significantly from recent historical contributions, assuming actual results do not differ significantly from estimates with respect to discount rates, returns on plan assets, retirement rates, mortality and other significant assumptions, and assuming no further changes in current and prospective legislation and regulations. Based upon these anticipated levels of future contributions, we do not expect to trigger any minimum funding requirements in the future; however, we may elect to make contributions to increase the funded status of the plans.

(2)		Does not include estimated settlement of asset retirement obligations. (See Note 9 of the Notes to Consolidated Financial Statements).

(3)		Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. (See Note 10 of the Notes to Consolidated Financial Statements.)

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

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levels of declines in Williams’ or our credit ratings given by Moody’s Investors Service, Standard and Poor’s and Fitch Ratings (rating agencies).

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 3 of the Notes to Consolidated Financial Statements included in Item 8 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. 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.

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 impact on our future financial condition.

Regulatory Proceedings

Reference is made to “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements — 3. Contingent Liabilities and Commitments” for information about regulatory and business developments which cause operating and financial uncertainties.

CONCLUSION

Although no assurances can be given, we currently believe that the aggregate of cash flows from operating activities, supplemented, when necessary, advances or capital contributions from Williams and borrowings under the Credit Agreement will provide us with sufficient liquidity to meet our capital

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requirements. When necessary, we also expect to access public and private markets on terms commensurate with our current credit ratings to finance our capital requirements.

Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Our interest rate risk exposure is limited to our long-term debt. All of our interest on long-term debt is fixed in nature, except the interest on our revolver borrowings, as shown on the following table (in thousands of dollars):


	December 31, 2007
Renewable borrowings under the Williams revolving credit agreement (1)	$	250,000

Fixed rates on long-term debt:
5.95% senior unsecured notes due 2017		185,000
7.00% senior unsecured notes due 2016		175,000
7.125% senior unsecured notes due 2025		85,000

		445,000

Unamortized debt discount		1,264


Total long-term debt	$	693,736


(1)		Interest rate was 5.68 percent at December 31, 2007. 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 and commitment fee are based on our senior unsecured long-term debt ratings.

Our total long-term debt at December 31, 2007 had a carrying value of $693.7 million and a fair market value of $710.9 million. As of December 31, 2007, the weighted-average interest rate on our long-term debt was 6.3 percent. We expect to have sensitivity to interest rate changes with respect to future debt facilities, our ability to prepay existing facilities and on the variability of cash flows for interest payments on the revolver borrowings.

Credit Risk

We are exposed to credit risk. Credit risk relates to the risk of loss resulting from the nonperformance by a customer of its contractual obligations. Our exposure generally relates to receivables and unbilled revenue for services provided, as well as volumes owed by customers for imbalances of natural gas lent by us to them generally under our parking and lending services and no-notice services. We maintain credit policies intended to minimize credit risk and actively monitor these policies.

Market Risk

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

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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) and for the assessment of the effectiveness of internal control over financial reporting. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of Northwest Pipeline GP’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of our internal control over financial reporting. Based on our assessment we believe that, as of December 31, 2007, Northwest Pipeline GP’s internal control over financial reporting is effective based on those criteria.

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of Northwest Pipeline GP

We have audited the accompanying consolidated balance sheets of Northwest Pipeline GP as of December 31, 2007 and 2006 and the related consolidated statements of income, comprehensive income, owners’ equity, and cash flows for each of the three years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Northwest Pipeline GP at December 31, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As described in Note 1 to the consolidated financial statements, in 2007 the Partnership changed its method of accounting for purchase price allocations.

ERNST & YOUNG LLP

Houston, Texas
February 26, 2008

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NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
OPERATING REVENUES	$	421,851		$	324,250		$	321,457


OPERATING EXPENSES:
General and administrative		65,772			56,463			49,749
Operation and maintenance		66,847			65,763			53,330
Depreciation		84,731			79,488			70,629
Regulatory credits		(3,663	)		(4,469	)		(4,446	)
Taxes, other than income taxes		13,997			15,018			15,115
Regulatory liability reversal		(16,562	)		—			—


Total operating expenses		211,122			212,263			184,377


Operating income		210,729			111,987			137,080


OTHER INCOME – net:
Interest income –
Affiliated		2,983			3,920			3,801
Other		2,681			3,423			2,820
Allowance for equity funds used during construction		2,091			8,947			2,872
Miscellaneous other income (expense), net		(517	)		307			1,104
Contract termination income		18,199			—			—


Total other income — net		25,437			16,597			10,597


INTEREST CHARGES:
Interest on long-term debt		46,828			43,649			38,164
Other interest		5,585			3,824			3,389
Allowance for borrowed funds used during construction		(1,306	)		(4,557	)		(1,529	)


Total interest charges		51,107			42,916			40,024


INCOME BEFORE INCOME TAXES		185,059			85,668			107,653

PROVISION (BENEFIT) FOR INCOME TAXES (Note 6)		(254,667	)		31,206			38,679


NET INCOME	$	439,726		$	54,462		$	68,974


CASH DISTRIBUTIONS/DIVIDENDS	$	109,770		$	—		$	50,000

See accompanying notes.

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NORTHWEST PIPELINE GP

CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)


	December 31,
	2007			2006
				(Restated)
LIABILITIES AND OWNERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable –
Trade	$	32,055		$	55,403
Affiliated companies		13,056			13,701
Accrued liabilities –
Income taxes due to affiliate		—			3,090
Taxes, other than income taxes		7,935			6,779
Interest		4,517			7,038
Employee costs		12,106			10,759
Exchange gas due to others		16,748			15,094
Deferred contract termination income		—			6,045
Other		5,713			5,268
Current maturities of long-term debt (Note 4)		—			252,867


Total current liabilities		92,130			376,044


LONG-TERM DEBT, LESS CURRENT MATURITIES		693,736			434,208

DEFERRED INCOME TAXES (Note 6)		—			282,532

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		84,989			98,595

CONTINGENT LIABILITIES AND COMMITMENTS

OWNERS’ EQUITY:
Common stock, par value $1 per share; authorized and outstanding, 1,000 shares in 2006		—			1
Additional paid-in capital		—			977,021
Partners’ capital		977,022			—
Retained earnings (deficit)		228,739			(101,214	)
Accumulated other comprehensive loss		(20,145	)		(17,863	)


Total owners’ equity		1,185,616			857,945


Total liabilities and owners’ equity	$	2,056,471		$	2,049,324

See accompanying notes.

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NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF OWNER’S EQUITY
(Thousands of Dollars, Except Per Share Amounts)


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
Common stock, par value $1 per share, authorized, 1,000 shares
Balance at beginning of period, outstanding, 1,000 shares	$	1		$	1		$	1
Conversion to GP		(1	)		—			—

Balance at end of period		—			1			1


Additional paid-in capital -
Balance at beginning of period, as previously stated		—			—			262,844
Cumulative effect of purchase accounting		—			—			649,177

Balance at beginning of period, as restated		977,021			912,021			912,021
Capital contribution from parent		—			65,000			—
Conversion to GP		(977,021	)		—			—


Balance at end of period		—			977,021			912,021


Partners’ capital -
Balance at beginning of period		—			—			—
Conversion to GP		977,022			—			—


Balance at end of period		977,022			—			—


Retained earnings (deficit) -
Balance at beginning of period, as previously stated		—			—			424,157
Cumulative effect of purchase accounting		—			—			(598,807	)

Balance at beginning of period, as restated		(101,214	)		(155,676	)		(174,650	)
Net income		439,726			54,462			68,974
Cash distributions		(109,770	)		—			—
Cash dividends		—			—			(50,000	)
Other		(3	)		—			—

Balance at end of period		228,739			(101,214	)		(155,676	)


Accumulated other comprehensive loss –
Balance at beginning of period		(17,863	)		—			—
Cash flow hedges:
Gain, net of tax of ($233) for 2006		—			386			—
Reclassification of gain into earnings, net of tax of $13 for 2006		(62	)		(21	)		—
Pension benefits:
Adjustment to initially apply SFAS No. 158:
Prior service cost, net of tax of $186 for 2006		—			(308	)		—
Net actuarial loss, net of tax of $10,797 for 2006		—			(17,920	)		—
Net actuarial gain		8,466			—			—
Prior service cost		77			—			—
Elimination of deferred income taxes		(10,763	)		—			—

Balance at end of period		(20,145	)		(17,863	)		—


Total owner’s equity	$	1,185,616		$	857,945		$	756,346

See accompanying notes.

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NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
OPERATING ACTIVITIES:
Net Income	$	439,726		$	54,462		$	68,974
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		84,731			79,488			70,629
Regulatory credits		(3,663	)		(4,469	)		(4,446	)
Provision (benefit) for deferred income taxes		(289,229	)		27,916			(20,086	)
Amortization of deferred charges and credits		9,783			2,484			4,053
Allowance for equity funds used during construction		(2,091	)		(8,947	)		(2,872	)
Reserve for doubtful accounts		(46	)		(38	)		44
Regulatory liability reversal		(16,562	)		—			—
Contract termination income		(6,045	)		—			—
Changes in:
Trade accounts receivable		(8,413	)		(3,515	)		1,639
Affiliated receivables, including income taxes.		(2,923	)		4,899			(5,489	)
Exchange gas due from others		(1,654	)		5,549			(4,632	)
Materials and supplies		(331	)		(1,912	)		236
Other current assets		1,017			(5,264	)		(800	)
Deferred charges		(9,769	)		(1,610	)		(6,992	)
Trade accounts payable		4,653			(2,011	)		(1,568	)
Affiliated payables, including income taxes		(5,259	)		13,037			(15,785	)
Exchange gas due to others		1,654			(5,549	)		4,632
Other accrued liabilities		2,105			1,192			6,440
Other deferred credits		7,673			4,095			3,659

Net cash provided by operating activities		205,357			159,807			97,636

FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		434,362			174,447			—
Retirement of long-term debt		(252,867	)		(7,500	)		(7,500	)
Prepayment of long-term debt		(175,000	)		—			—
Debt issuance costs		(2,059	)		(2,375	)		—
Premium on early retirement of long-term debt		(7,111	)		—			—
Capital contribution from parent		—			65,000			—
Distributions paid		(109,770	)		—			—
Dividends paid		—			—			(50,000	)
Changes in cash overdrafts		(30,078	)		37,347			428

Net cash provided by (used in) financing activities		(142,523	)		266,919			(57,072	)

INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures		(157,163	)		(473,566	)		(137,232	)
Proceeds from sales		2,257			—			—
Asset removal cost		—			(9,733	)		(1,568	)
Changes in accounts payable and accrued liabilities		402			(5,015	)		16,635
Proceeds from contract termination payments		—			3,348			87,917
Proceeds from sale of Parachute facilities		79,770			—			—
Repayments from affiliates		10,908			20			—

Net cash used in investing activities		(63,826	)		(484,946	)		(34,248	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(992	)		(58,220	)		6,316
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,489			59,709			53,393

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	497		$	1,489		$	59,709

See accompanying notes.

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

On October 1, 2007, Northwest Pipeline Corporation converted from a Delaware corporation to a general partnership, Northwest Pipeline GP. Northwest Pipeline Corporation, prior to October 1, 2007, and Northwest Pipeline GP, subsequent to September 30, 2007, are herein after referred to as “Northwest”. Coincident with the conversion, the partners of Northwest GP entered into a partnership agreement. Northwest is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986) or enhances operations that generate such qualified income. Because of our conversion to a general partnership, we will no longer be subject to federal and state income taxes. On October 1, 2007, we reversed to income deferred income tax liabilities of approximately $311.8 million and $10.2 million of deferred income tax assets to other comprehensive income.

On December 31, 2007, Northwest was owned 11.6 percent by Williams Pipeline Partners Holdings LLC and 88.4 percent by WGPC Holdings LLC, both indirect wholly-owned subsidiaries of The Williams Companies, Inc. (Williams).

On January 24, 2008, Williams Pipeline Partners L.P. (previously a wholly-owned subsidiary of 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. 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 23, 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. Through its ownership interests in each of our partners, Williams indirectly owns 81.7 percent of Northwest as of February 26, 2008.

Concurrent with the conversion to a general partnership, Northwest Pipeline Corporation ceased to be an employer. Employees previously employed by Northwest Pipeline Corporation became employees of Northwest Pipeline Services LLC, a consolidated affiliate. Northwest Pipeline GP and Northwest Pipeline Services LLC entered into an agreement whereby the employees of Northwest Pipeline Services LLC provide services to Northwest Pipeline GP. Northwest Pipeline GP will reimburse Northwest Pipeline Services LLC for the costs of the employees including compensation and employee benefit plan costs and all related administrative costs.

In this report, Northwest Pipeline GP and its consolidated affiliate are at times referred to in the first person as “we”, “us” or “our”.

Nature of Operations

We own and operate an interstate pipeline system for the mainline transmission of natural gas. This system extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington.

Regulatory Accounting

Our natural gas pipeline operations are regulated by the Federal Energy Regulatory Commission (FERC). FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. From time to time, certain revenues collected may be subject to possible refunds upon final FERC orders. Accordingly, estimates of rate refund reserves are recorded considering third-party regulatory proceedings, advice of counsel, our estimated risk-adjusted

-51-

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

total exposure, market circumstances and other risks. Our current rates were approved pursuant to a rate settlement. As a result, our current revenues are not subject to refund.

SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” requires rate-regulated public utilities that apply this standard to account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying SFAS No. 71, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. At December 31, 2007 and 2006, we had approximately $54.3 million and $49.3 million, respectively, of regulatory assets primarily related to equity funds used during construction, levelized incremental depreciation, environmental costs and other post-employment benefits, and approximately $17.8 million and $32.6 million, respectively, of regulatory liabilities related to postretirement benefits and asset retirement obligations included on the accompanying Balance Sheet.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Northwest and Northwest Services Company, 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. The purchase price allocation was not pushed down to us, as FERC policy does not permit us to recover these amounts through our rates and we have not been required to reflect Williams’ purchase price allocations in our financial statements. Beginning December 31, 2007, we have elected to include Williams’ purchase price allocations in our financial statements. Accordingly, our 2005 and 2006 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 follows:


	Year Ended December 31,
	2006			2005

	(Thousands of Dollars)
Income Statement
Net income, as previously reported	$	57,143		$	71,755
Depreciation of purchase price allocation to property and equipment, net of income taxes		(2,681	)		(2,781	)

Net income, as restated	$	54,462		$	68,974

Balance Sheet
Equity, as previously reported	$	813,037
Allocation of purchase price to property and equipment, net of taxes		44,908

Equity, as restated	$	857,945

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 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 The Williams Companies, Inc’s historical basis in us, including such purchase accounting adjustments.

Use of Estimates

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;

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

5) pension and other post-employment benefits; and 6) asset retirement obligations.

Property, Plant and Equipment

Property, plant and equipment (plant), consisting principally of natural gas transmission facilities, is recorded at original cost. We account for repair and maintenance costs under the guidance of FERC regulations. The FERC identifies installation, construction and replacement costs that are to be capitalized and included in our asset base for recovery in rates. Routine maintenance, repairs and renewal costs are charged to income as incurred. Gains or losses from the ordinary sale or retirement of plant are charged or credited to accumulated depreciation.

Depreciation is provided by the straight-line method by class of assets for property, plant and equipment. The annual weighted average composite depreciation rate recorded for transmission and storage plant was 2.76 percent, 2.86 percent and 2.96 percent for 2007, 2006 and 2005, respectively, including an allowance for negative salvage.

The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project created a revenue stream that will remain constant over the related 25-year and 15-year customer contract terms. The related levelized depreciation is lower than book depreciation in the early years and higher than book depreciation in the later years of the contract terms. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. FERC has approved the accounting for the differences between book depreciation and the Evergreen Expansion Project’s levelized depreciation as a regulatory asset with the offsetting credit recorded to a regulatory credit on the accompanying Income Statement.

We recorded regulatory credits totaling $3.7 million in 2007, $4.5 million in 2006, and $4.4 million in 2005 in the accompanying Statements of Income. These credits relate primarily to the levelized depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related regulatory assets of $25.8 million at December 31, 2007, and $22.1 million at December 31, 2006. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset with the offset to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates beginning January 1, 2007, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2007 and 2006 were $21.8 million and $15.5 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($21.8 million and $18.2 million at December 31, 2007 and 2006, respectively) was reclassified to a noncurrent regulatory liability and has been netted against the amount of the ARO regulatory asset expected to be collected in rates. Prior periods have been reclassified to conform to the current period presentation.

Allowance for Borrowed and Equity Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in process of construction and is included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. FERC has prescribed a formula to be used in computing separate allowances for debt and equity AFUDC. The cost of debt portion of AFUDC is recorded as a reduction in interest expense. The equity funds portion of AFUDC is included in Other Income – net.

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The composite rate used to capitalize AFUDC was approximately 9 percent for 2007 and approximately 10 percent for 2006 and 2005. Equity AFUDC of $2.1 million, $8.9 million and $2.9 million for 2007, 2006 and 2005, respectively, is reflected in Other Income — net.

Regulatory Allowance for Equity Funds Used During Construction

Prior to our conversion to a general partnership on October 1, 2007, we have recorded a regulatory asset in connection with deferred income taxes associated with equity AFUDC. Since we are no longer subject to income tax following the conversion, we will not record any further additions to the regulatory asset associated with equity AFUDC. The pre-conversion unamortized balance of this regulatory asset will continue to be amortized consistent with the amount being recovered in rates.

Advances to Affiliates

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. The advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectibility is reasonably assured. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29 percent at December 31, 2007.

Accounts Receivable and Allowance for Doubtful Receivables

Accounts receivable are stated at the historical carrying amount net of allowance for doubtful accounts. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. As a result, receivables determined to be uncollectible are reserved or written off in the period of such determination.

Materials and Supplies Inventory

All inventories are stated at lower of cost or market. We determine the cost of the inventories using the average cost method.

We perform an annual review of materials and supplies inventories, including an analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline.

Impairment of Long-Lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. When such a determination has been made, management’s estimate of undiscounted future cash flows attributable to the assets is compared to the carrying value of the assets to determine whether an impairment has occurred. If an impairment of the carrying value has occurred, the amount of the impairment recognized in the financial statements is determined by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

Judgments and assumptions are inherent in management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the financial statements.

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Income Taxes

Williams and its wholly-owned subsidiaries file a consolidated federal income tax return. It is Williams’ policy to charge or credit its taxable subsidiaries with an amount equivalent to their federal income tax expense or benefit computed as if each subsidiary had filed a separate return.

Through September 30, 2007, we used the liability method of accounting for income taxes which required, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. (See Note 6.)

Deferred Charges

We amortize deferred charges over varying periods consistent with the FERC approved accounting treatment and recovery for such deferred items. Unamortized debt expense, debt discount and losses on reacquired long-term debt are amortized by the bonds outstanding method over the related debt repayment periods.

Cash and Cash Equivalents

Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid investments with an original maturity of three months or less.

Exchange Gas Imbalances

In the course of providing transportation services to our customers, we may receive or deliver different quantities of gas from shippers than the quantities delivered or received on behalf of those shippers. These transactions result in imbalances, which are typically settled through the receipt or delivery of gas in the future. Customer imbalances to be repaid or recovered in-kind are recorded as exchange gas due from others or due to others in the accompanying balance sheets. The exchange gas offset represents the gas balance in our system representing the difference between the exchange gas due to us from customers and the exchange gas that we owe to customers. These imbalances are valued at the average of the spot market rates at the Canadian border and the Rocky Mountain market as published in “Inside FERC’s Gas Market Report.” Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions.

Revenue Recognition

Environmental Matters

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. If capitalized, such amounts are amortized to expense consistent with the recovery of such costs in our rates. We believe that, with respect to any 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. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Payments

Cash payments for interest were $49.7 million, $43.5 million and $38.7 million in 2007, 2006 and 2005, respectively.

Recent Accounting Standards

Effective January 1, 2007, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The Interpretation prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted FIN 48 beginning January 1, 2007, as required. The adoption of FIN 48 did not have a material effect on our financial position or results of operations.

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

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

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 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 No. 157 is effective for fiscal years beginning after November 15, 2007. In December 2007, the FASB issued proposed FASB Staff Position (FSP) No. FAS 157-b deferring the effective date of SFAS No. 157 to fiscal years beginning after November 15,2008 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). SFAS No. 157 requires two distinct transition approaches; (i) cumulative-effect adjustment to beginning retained earnings for certain financial instrument transactions and (ii) prospectively as of the date of adoption through earnings or other comprehensive income, as applicable. On January 1, 2008, we adopted SFAS No. 157 applying a prospective transition for our assets and liabilities that are measured at fair value on a recurring basis with no material impact to our Consolidated Financial Statements. SFAS No. 157 expands disclosures about assets and liabilities measured at fair value on a recurring basis effective beginning with the first quarter 2008 reporting.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 establishes a fair value option permitting entities to elect to measure eligible financial instruments and certain other items at fair value. Unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The fair value option may be applied on an instrument-by-instrument basis, is irrevocable and is applied only to the entire instrument. SFAS No. 159 is effective as of the beginning of the first fiscal year beginning after November 15, 2007, and should not be applied retrospectively to fiscal years beginning prior to the effective date. On the adoption date, an entity may elect the fair value option for eligible items existing at that date and the adjustment for the initial remeasurement of those items to fair value should be reported as a cumulative effect adjustment to the opening balance of retained earnings. Subsequent to January 1, 2008, the fair value option can only be elected when a financial instrument or certain other item is entered into. On January 1, 2008, we did not elect the fair value option for any existing eligible financial instruments or certain other items.

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FERC Accounting and Reporting Guidance

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

Change in Accounting Estimate

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

Reclassifications and Adjustments

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). Prior to our conversion to a partnership, the capitalization of EAFUDC created a deferred tax liability 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 miscellaneous other income of $4.7 million and a decrease to net income of $3.0 million during 2006.

In the fourth quarter of 2006, we made adjustments to correct errors related to the accounting for our headquarters building lease expense and depreciation of leasehold improvements. The correction of the errors resulted in a decrease to general and administrative expense of $6.2 million, an increase to depreciation expense of $2.9 million and an increase to Net Income of $2.1 million during 2006.

Certain reclassifications have been made to the 2006 and 2005 financial statements to conform to the 2007 presentation, including reflecting the change in bank overdrafts as financing activities and additional changes in capital related accounts payable as investing activities in the condensed statement of cash flows.

2. RATE AND REGULATORY MATTERS

General Rate Case (Docket No. RP06-416)

Parachute Lateral Project

We placed our Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, we filed an application with the

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FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (Parachute), which is owned by an affiliate of Williams. This application was approved by the FERC on November 15, 2007, and we completed the transfer of the Parachute Lateral on December 31, 2007. We received cash proceeds of $79.8 million from Parachute equal to the net book value of the net assets transferred, and subsequently made a distribution to Williams in an equal amount. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. Prior to the transfer of the facilities, we reassessed the probability of recovering certain regulatory assets associated with the Parachute Lateral and concluded that with the change of ownership it was not probable that these assets would be recovered in future rates. In the fourth quarter 2007, $2.8 million of these assets were charged to expense.

3. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants had filed a number of motions to dismiss these claims on jurisdictional grounds. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against us and certain of the other Williams defendants. On October 20, 2006, the District Court dismissed all claims against us. Mr. Grynberg filed a Notice of Appeal from the dismissals with the Tenth Circuit Court of Appeals effective November 17, 2006 and briefing is underway.

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, 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.

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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 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 December 31, 2007, we have accrued liabilities totaling approximately $7.5 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 regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

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.

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $16.4 million at December 31, 2007.

Termination of the Grays Harbor Transportation Agreement

Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to the Grays Harbor Lateral. We invoiced Duke the amount we believe was contractually owed by Duke according to the terms of the facilities reimbursement agreement and our tariff. Duke initially paid us approximately $88 million for the remaining net book value of the lateral facilities and approximately $6 million towards the related income taxes. We invoiced Duke for an additional $30 million, representing the additional income taxes related to the termination of the contract. Duke disputed this additional amount. We recorded a reserve against the full $30 million invoiced and deferred recognition of the $6 million received from Duke related to income taxes.

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

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

Cash Distributions to Partners

On or before the end of the calendar month following each quarter, beginning after the end of the first quarter 2008, available cash will be 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.

4. DEBT, FINANCING ARRANGEMENTS AND LEASES

Debt Covenants

Our debt indentures contain provisions for the acceleration of repayment or the reset of interest rates under certain conditions. Our debt indentures also contain restrictions, which, under certain circumstances, limit the issuance of additional debt and restrict the disposal of a major portion of our natural gas pipeline system. Our ratio of debt to capitalization must be no greater than 55 percent. We are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, was approximately 36 percent at December 31, 2007.

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

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

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On December 1, 2007, we retired $250 million of 6.625 percent senior unsecured notes due 2007 with $250 million borrowings under the Williams revolving credit agreement. The interest rate on our revolving credit borrowings was 5.68 percent at December 31, 2007.

We entered into certain forward starting interest rate swaps 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 settlement resulted in a gain that is being amortized to reduce interest expense over the life of the related debt.

Long-term debt consists of the following:


	December 31,
	2007		2006
	(Thousands of Dollars)
5.95%, payable 2017	$	184,407	$	—
6.625%, payable 2007		—		250,000
7%, payable 2016		174,532		174,477
7.125%, payable 2025		84,797		84,785
8.125%, payable 2010		—		175,000
9%, payable 2004 through 2007		—		2,813
Revolving credit debt, payable 2012		250,000		—

Total long-term debt		693,736		687,075
Less current maturities		—		252,867


Total long-term debt, less current maturities	$	693,736	$	434,208

As of December 31, 2007, cumulative sinking fund requirements and other maturities of long-term debt (at face value) for each of the next five years are as follows:


	(Thousands of
	Dollars)
2008	$	—
2009		—
2010		—
2011		—
2012		250,000
Thereafter		445,000

Total	$	695,000

Line-of-Credit Arrangements

Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012. We have access to $400 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 commitment fee is based on Williams’ senior unsecured long-term debt ratings. Letters of credit totaling approximately $28 million, none of which are associated with us, have been issued by the participating institutions and $250.0 million revolving credit loans, all associated with us, were outstanding at December 31, 2007. In December 2007, we borrowed

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$250.0 million under this agreement to repay $250.0 million in 6.625 percent senior unsecured notes at maturity. We did not access the agreement in 2006. The interest rate on this debt was 5.68 percent at December 31, 2007. Significant financial covenants under the credit agreement include the following:

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent.

	•		Our ratio of debt to capitalization and that of another participating subsidiary of Williams must be no greater than 55 percent.

Leases

Our leasing arrangements include mostly premise and equipment leases that are classified as operating leases.

The major operating lease is a leveraged lease, which became effective during 1982 for our headquarters building. The agreement has an initial term of approximately 27 years, with options for consecutive renewal terms of approximately 9 years and 10 years. One year prior to the expiration of the initial term of the lease, we are required to give notice to the lessor of our intent to exercise our option to renew the term of the lease. The major component of the lease payment is set through the initial and first renewal terms of the lease. Various purchase options exist under the building lease, including options involving adverse regulatory developments.

We sublease portions of our headquarters building to third parties under agreements with varying terms. Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:


	(Thousands
	of Dollars)
2008	$	6,376
2009		6,312


	$	12,688

Less: noncancelable subleases		6,336


Total	$	6,352

Operating lease rental expense, net of sublease revenues, amounted to $4.9 million, ($1.2) million, and $5.3 million for 2007, 2006 and 2005, respectively. (See Note 1 – Reclassifications and Adjustments.)

On December 31, 2007, in connection with the sale of Parachute to an affiliate of Williams, Parachute leased the facilities back to us. We will continue to operate the facilities under the FERC certificate. When Williams Field Services completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate. Under the terms of the lease, we will pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral. This operating lease is not included in the future minimum annual rental payments shown above due to the contingent nature of the Parachute lease payments.

5. EMPLOYEE BENEFIT PLANS

Pension plans

We participate in noncontributory defined benefit pension plans sponsored by Williams and its

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subsidiaries that provide pension benefits for eligible participant employees. Cash contributions related to our participation in the plans totaled $3.1 million in 2007, $3.3 million in 2006 and $3.7 million in 2005. We expensed $4.0 million in 2007, $3.5 million in 2006 and $3.6 million in 2005. For the tax-qualified pension plans, we have historically recorded a regulatory asset or liability for the difference between pension expense as estimated under Statement of Financial Accounting Standards No. 87, “Employer’s Accounting for Pensions,” and the amount we funded as a contribution to the pension plans. The amount of pension benefit costs deferred as a regulatory liability at December 31, 2006 was $16.6 million. In the second quarter of 2007, we recorded $16.6 million in income for a change in accounting estimate related to this pension regulatory liability. As a result of information obtained in the second quarter of 2007, 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.

Accumulated other comprehensive loss at December 31, 2007 and 2006, include the following:


	Pension Benefits
	2007			2006
	(Thousands of Dollars)
Amounts not yet recognized in net periodic benefit expense:
Prior service cost	$	(417	)	$	(494	)
Net actuarial losses		(20,251	)		(28,717	)

Net actuarial losses of $847 thousand and prior services costs of $79 thousand related to the pension plans that are included in accumulated other comprehensive loss at December 31, 2007, are expected to be amortized in net periodic benefit expense in 2008.

Postretirement benefits other than pensions

We participate in a plan sponsored by Williams and its subsidiaries that provides certain retiree health care and life insurance benefits for our eligible participants that were hired prior to January 1, 1992. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $0.1 million in 2007 and $2.4 million in each of the years 2006 and 2005. We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to a regulatory asset or liability and any unrecovered amounts will be collected through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2007 and 2006 are $17.8 million and $13.4 million, respectively. No expense was recorded in 2007. We expensed $2.3 million in 2005 and 2006.

At December 31, 2007, regulatory liabilities include prior service costs of $2.6 million and net actuarial gains of $6.4 million related to other postretirement benefit plans. These amounts have not yet been recognized in net periodic other postretirement benefit expense. At December 31, 2006, regulatory

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liabilities included prior service costs of $3.2 million and net actuarial gains of $3.3 million related to postretirement benefit plans.

Defined contribution plan

Employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $2.0 million in 2007, $1.8 million in 2006 and $1.5 million in 2005.

Stock-Based Compensation

Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (the “Plan”) was approved by stockholders on May 17, 2007. The Plan provides for Williams common-stock-based awards to both employees and non-management 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 based on the fair value of such awards. 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 Statement of Income for 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 beginning in 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 years ended December 31, 2007 and 2006 was $0.7 million and $0.9 million, respectively, excluding amounts allocated from WGP and Williams.

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6. INCOME TAXES

Significant components of the deferred tax liabilities and assets are as follows:


	December 31,
	2007 (1)		2006
			(Restated)
	(Thousands of Dollars)
Property, plant and equipment	$	—	$	296,339
Regulatory assets		—		15,800
Loss on reacquired debt		—		3,962
Other – net		—		5,808


Deferred tax liabilities		—		321,909


Accrued liabilities		—		29,225
Accrued benefits		—		14,218


Deferred tax assets		—		43,443


Net deferred tax liabilities	$	—	$	278,466


Reflected as:
Deferred income taxes – current asset	$	—	$	4,066
Deferred income taxes – noncurrent liability		—		282,532


	$	—	$	278,466


(1)		Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax.

The provision (benefit) for income taxes includes:


	Year Ended December 31,
	2007			2006		2005
				(Restated)		(Restated)
	(Thousands of Dollars)
Current:
Federal	$	30,888		$	2,940	$	52,292
State		3,674			350		6,473


		34,562			3,290		58,765


Deferred:
Federal		(258,459	)		24,945		(17,727	)
State		(30,770	)		2,971		(2,359	)


		(289,229	)		27,916		(20,086	)


Total provision (benefit)	$	(254,667	)	$	31,206	$	38,679

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A reconciliation of the statutory Federal income tax rate to the provision (benefit) for income taxes is as follows:


	Year Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
	(Thousands of Dollars)
Provision at statutory Federal income tax rate of 35 percent (1)	$	52,831		$	29,984		$	37,679
Increase (decrease) in tax provision resulting from - State income taxes net of Federal tax benefit		3,948			2,159			2,674
Book/tax basis reconciliation adjustment		—			(723	)		(1,742	)
Other – net		330			(214	)		68


Provision for income taxes prior to conversion from a corporation to a partnership	$	57,109		$	31,206		$	38,679


Effective tax rate prior to conversion from a corporation to a partnership		37.83	%		36.43	%		35.93	%


Provision for income taxes prior to conversion from a corporation to a partnership	$	57,109		$	31,206		$	38,679
Conversion from corporation to partnership		(311,776	)		—			—


Total provision (benefit) for income taxes	$	(254,667	)	$	31,206		$	38,679


(1)		Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. The provision for income taxes shown herein for 2007 reflects the provision through September 30, 2007. Subsequent to the conversion to a general partnership on October 1, 2007, all deferred income taxes were eliminated and we no longer provide for income taxes.

Prior to our conversion to a general partnership, we provided for income taxes using the asset and liability method as required by SFAS 109, “Accounting for Income Taxes,” through September 30, 2007. During 2006 and 2005, respectively, as a result of additional analysis of our tax basis and book basis assets and liabilities, we recorded a $0.7 million and a $1.8 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet. Management concluded that the effect of these corrections is not material to prior annual or interim periods, to 2006 and 2005 results, or to the trend of earnings.

As described in Note 1, we have restated 2006 and 2005 to reflect Williams’ purchase price allocations in our financial statements.

Net cash payments (received from) made to Williams for income taxes were $37.7 million, ($1.3) million and $63.7 million in 2007, 2006 and 2005, respectively.

7. FINANCIAL INSTRUMENTS

Disclosures About the Fair Value of Financial Instruments

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

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Cash, cash equivalents and advances to affiliate — The carrying amounts of these items approximates their fair value.

Long-term debt — The fair value of our publicly traded long-term debt is valued using year-end traded market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. The carrying amount and estimated fair value of our long term debt, including current maturities, were $693.7 million and $710.9 million, respectively, at December 31, 2007, and $687.1 million and $703.8 million, respectively, at December 31, 2006.

8. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

During the periods presented, more than 10 percent of our operating revenues were generated from each of the following customers:


	Year Ended December 31,
	2007		2006		2005
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	85,059	$	64,428	$	56,480
Northwest Natural Gas Co.		48,648		35,242		35,420

Our major customers are located in the Pacific Northwest. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are regularly evaluated and historical collection losses have been minimal.

Related Party Transactions

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, 2007 and 2006, the advances due to us by Williams totaled approximately $39.1 million and $50.0 million, respectively. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29 percent at December 31, 2007. We received interest income from advances to Williams of $3.0 million, $3.9 million, and $3.8 million during 2007, 2006 and 2005, respectively. Such interest income is included in Other Income – net on the accompanying Statement of Income.

Williams’ corporate overhead expenses allocated to us were $19.6 million, $18.7 million and $19.0 million for 2007, 2006 and 2005, 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, data processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $16.6 million, $16.6 million and $10.7 million for 2007, 2006 and 2005, respectively. These expenses are included in General and Administrative Expense on the accompanying Statement of Income.

During the periods presented, our revenues include transportation and exchange transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $11.8 million, $3.4 million and $2.4 million for 2007, 2006 and 2005, respectively. The increase from 2006 to 2007 is primarily due to capacity reservation revenues of $6.7 million related to the Parachute Lateral facility which was placed into service in May 2007.

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

9. ASSET RETIREMENT OBLIGATIONS

On December 31, 2005, we adopted the Financial Accounting Standards Board (FASB) Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations – an Interpretation of FASB Statement No. 143.” We adopted the Interpretation on December 31, 2005. In accordance with the Interpretation, we estimated future retirement obligations for certain assets previously considered to have an indeterminate life. As a result, we recorded an asset retirement obligation (ARO) of $15.4 million and a net increase in Property, Plant and Equipment of $0.9 million. We also recorded a $14.5 million regulatory asset for retirement costs expected to be recovered through our rates.

During 2006, we obtained additional information impacting our estimation of our ARO. Factors affected by the additional information included estimated settlement dates, estimated settlement costs and inflation rates. We adjusted the ARO related to certain assets because the additional information results in improved and the best available estimates regarding the ARO costs, lives, and inflation rates. As a result, we recorded an increase in Property, Plant and Equipment of $30.2 million and a corresponding increase in the ARO liability.

During 2007, we adjusted the ARO liability and Property, Plant and Equipment for a change in the inflation and discount rates.

During 2007 and 2006, our overall asset retirement obligation changed as follows (in thousands):


	2007			2006
Beginning balance	$	48,020		$	15,372
Accretion		3,673			965
New obligations		1,912			1,451
Obligations transferred to an affiliate		(1,996	)		—
Changes in estimates of existing obligations		(1,186	)		30,232

Ending Balance	$	50,423		$	48,020

The accrued obligations relate to our gas storage and transmission facilities. At the end of the useful life of our facilities, we are legally obligated to remove certain transmission facilities including underground pipelines, major river spans, compressor stations and meter station facilities. These obligations also include restoration of the property sites after removal of the facilities from above and below the ground.

10. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of SFAS No. 71 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and other. Regulatory liabilities are included in deferred credits and other noncurrent liabilities. These balances are presented on our balance sheet on a gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2007 and 2006:

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2007		2006
	(Thousands of Dollars)
Current regulatory assets — environmental costs	$	2,200	$	1,500


Non-current regulatory assets
Environmental costs		4,841		3,200
Grossed-up deferred taxes on equity funds used during construction		20,122		21,252
Levelized incremental depreciation		25,780		22,118
Other post-employment benefits		1,329		1,259


Total non-current regulatory assets		52,072		47,829


Total regulatory assets	$	54,272	$	49,329


Non-current regulatory liabilities
Asset retirement obligations, net		10		2,677
Pension plans (1)		—		16,562
Postretirement benefits		17,806		13,354


Total regulatory liabilities	$	17,816	$	32,593


(1)		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. See Note 5.

11. ACCUMULATED OTHER COMPREHENSIVE LOSS

Accumulated other comprehensive loss includes the following as of December 31, 2007 and 2006:


	2007			2006
	(Thousands of Dollars)
Cash flow hedges	$	523		$	585
Pension benefits		(20,668	)		(29,211	)

Accumulated other comprehensive loss before taxes		(20,145	)		(28,626	)
Deferred income taxes		—			10,763

Total accumulated other comprehensive loss	$	(20,145	)	$	(17,863	)

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NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12. QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of unaudited quarterly financial data for 2007 and 2006:


	Quarter of 2007
	First		Second		Third		Fourth
	(Restated)		(Restated)		(Restated)
	(Thousands of Dollars)
Operating revenues	$	103,043	$	102,655	$	106,364	$	109,789
Operating income		49,317		64,456		49,980		46,976
Net income		23,357		37,387		33,092		345,890

Second quarter 2007 results reflect an increase of $16.6 million in operating income and $10.3 million in net income due to the reversal of a pension regulatory liability, and an increase in net income of $3.8 million due to the recognition of deferred income related to the termination of the Grays Harbor transportation agreement. Third quarter 2007 net income includes a net increase of $9.0 million due to additional income related to the termination of the Grays Harbor transportation agreement. Fourth quarter net income includes an increase of $311.8 million due to the reversal of deferred income taxes resulting from our conversion to a non-taxable general partnership. The first, second and third quarters of 2007 have been restated to reflect the inclusion of Williams’ purchase price allocation.


	Quarter of 2006
	First		Second		Third		Fourth
	(Restated)		(Restated)		(Restated)		(Restated)
	(Thousands of Dollars)
Operating revenues	$	79,638	$	79,915	$	81,088	$	83,609
Operating income		29,872		28,881		26,690		26,544
Net income		15,257		16,781		10,632		11,792

Third quarter 2006 net income includes a decrease of $3.0 million for EAFUDC related to retirements of property, plant, and equipment. Fourth quarter 2006 includes a net increase in operating income of $3.3 million and a net increase in net income of $2.1 million related to error corrections for building lease expense and for depreciation of leasehold improvements. (See Note 1 – Reclassifications and Adjustments.) Each quarter of 2006 has been restated to reflect the inclusion of Williams’ purchase price allocation.

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Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

Item 9A. 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 and procedures were 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 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 make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

Changes in Internal Controls over Financial Reporting

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

Management’s Report on Internal Control over Financial Reporting

See “Management’s Report on Internal Control over Financial Reporting” set forth above in Item 8, “Financial Statements and Supplementary Data.”

Item 9B.

None.

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PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Management Committee Members and Executive Officers

Our Amended and Restated General Partnership Agreement provides that we will be managed by the two general partners. Each partner has designated a representative to serve as a member of the management committee. Our executive officers are elected by the management committee and hold office until relieved of such office by action of the management committee.

The following table sets forth certain information with respect to our executive officers and members of the management committee.


Name	Age		Position
Phillip D. Wright		52	Senior Vice President and Management Committee Member
Donald R. Chappel		56	Management Committee Member
Steven J. Malcolm		59	Chief Executive Officer
Richard D. Rodekohr		49	Vice President and Treasurer
Allison G. Bridges		48	Vice President
Randall L. Barnard		49	Vice President
Lawrence G. Hjalmarson		53	Vice President
Randall R. Conklin		51	Vice President and General Counsel
Frank J. Ferazzi		51	Vice President

Business Experience

Mr. Wright has served as a member of our management committee since October 1, 2007. He served as a director of Northwest Pipeline Corporation from January 3, 2005 to September 30, 2007. Since January 3, 2005, he has also served as Senior Vice President of the Company. He has also held various management positions with The Williams Companies, Inc. since November 21, 2002. Mr. Wright is also a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P.

Mr. Chappel has served as a member of our management committee since October 1, 2007. Since 2002, Mr. Chappel has served as Senior Vice President and Chief Financial Officer of The Williams Companies, Inc. Mr. Chappel is a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P. Mr. Chappel is also the director of Williams Partners GP LLC, the general partner of Williams Partners L.P.

Mr. Malcolm has served as our Chief Executive Officer since October 1, 2007. He served as a director of Northwest Pipeline Corporation from May 16, 2002 to September 30, 2007. Since May 16, 2002, Mr. Malcolm has served as President, Chief Executive Officer and Chairman of the Board of The Williams Companies, Inc. Mr. Malcolm is a director of Williams Pipeline GP LLC, the general partner of Williams Pipeline Partners L.P., a director of Williams Partners GP LLC, the general partner of Williams Partners L.P., and a director of Bank of Oklahoma, N.A.

Mr. Rodekohr has served as our Vice President and Treasurer since October 1, 2007. Mr. Rodekohr served as Vice President and Treasurer of Northwest Pipeline Corporation from November 15, 2002 to September 30, 2007.

Ms. Bridges has served as our Vice President since October 1, 2007. Ms. Bridges served as a director of Northwest Pipeline Corporation from December 1, 2002 to September 30, 2007 and as a Vice President from August 14, 2000 to September 30, 2007.

Mr. Barnard has served as our Vice President since October 1, 2007. Mr. Barnard served as a director of Northwest Pipeline Corporation from April 1, 2002 to September 30, 2007 and Vice President from April 1, 2003 to September 30, 2007.

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Mr. Hjalmarson has served as our Vice President since October 1, 2007. Mr. Hjalmarson served as Vice President of Northwest Pipeline Corporation from April 30, 2007 to September 30, 2007 and has held various management positions with Williams since 1982.

Mr. Conklin has served as our Vice President since October 1, 2007. Mr. Conklin served as Vice President and General Counsel of Northwest Pipeline Corporation from April 1, 2003 to September 30, 2007 and as Senior Vice President and General Counsel from April 1, 2002 to March 31, 2003.

Mr. Ferazzi has served as our Vice President since October 1, 2007. Mr. Ferazzi served as a Vice President of Northwest Pipeline Corporation from April 1, 2002 until September 30, 2007.

Section 16(a) Beneficial Ownership Reporting Compliance

We do not have publicly traded equity securities. Therefore compliance with Section 16(a) of the Securities Exchange Act of 1934 is not required.

Code of Ethics

As an indirect subsidiary of The Williams Companies, Inc., we have not adopted a separate Code of Ethics. We follow the Code of Business Conduct adopted by Williams.

Corporate Governance

We do not have a separate Audit Committee, Nominating and Governance Committee, or Compensation Committee from Williams.

Item 11. EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are managed by the employees of Williams and each of our executive officers are employees of Williams. Each of our executive officers is compensated directly by Williams rather than by us. All decisions as to the compensation of our executive officers are made by Williams. Therefore, we do not have any policies or programs relating to compensation of our executive officers and do not make any decisions relating to such compensation. A full discussion of the policies and programs of Williams will be set forth in the proxy statement for Williams’ 2008 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading “Investors — SEC Filings.” Williams charges us an allocated amount for the services of Williams’ employees who dedicate time to our affairs.

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Executive Compensation

The summary compensation table includes amounts allocated to Northwest by Williams for services provided by our executive officers.

2007 Summary Compensation Table


													Change in
													Pension
													Value and
													Nonqualified
											Non-Equity		Deferred
							Stock		Option		Incentive Plan		Compensation			All Other
Name	Year		Salary		Bonus		Awards		Awards		Compensation		Earnings			Compensation		Total
Phillip D. Wright Senior Vice President		2007	$	92,681	$	—	$	408,204	$	66,898	$	129,929	$	13,203		$	1,902	$	712,817
(Principal Executive Officer)		2006		98,253		—		198,649		57,690		138,718		31,480			2,045		526,835
Richard D, Rodekohr		2007		44,358		—		100,495		22,953		36,913		(121	)		2,966		207,564
Vice President and Treasurer		2006		44,959		—		49,113		24,130		37,572		11,183			3,035		169,992
(Principal Financial Officer)
Allison G. Bridges		2007		231,565		—		414,500		94,472		193,867		1,804			13,680		949,888
Vice President		2006		220,250		—		214,121		100,127		188,896		54,318			13,535		791,247
Randall L. Barnard		2007		72,584		—		142,715		33,037		76,975		3,091			3,644		332,046
Vice President		2006		50,805		—		69,122		32,998		55,295		14,136			2,656		225,012
Lawrence G. Hjalmarson		2007		68,301		—		16,427		22,957		51,332		1,345			5,009		165,371
Vice President		2006		159,450		—		5,753		46,843		86,974		39,549			13,200		351,769

Compensation Committee Interlocks and Insider Participation

We do not maintain a compensation committee. Our executive officers during 2007 were employees of Williams and compensation decisions with respect to those individuals were determined by Williams.

Compensation of Directors

The members of the management committee are employees of Williams and receive no compensation for service on the Company’s management committee.

Compensation Committee Report

We do not have a compensation committee. The management committee has reviewed and discussed the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.

Management Committee:
Donald R. Chappel
Phillip D. Wright

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Certain Beneficial Owners and Management

We do not have publicly traded equity securities.

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The following table sets forth the beneficial ownership of our general partnership interest as of February 20, 2008:


Name of Beneficial Owner		Percent of General Partnership Interest
WGPC Holdings LLC, a subsidiary of Williams		65%
Williams Pipeline Partners Holdings LLC, a subsidiary of Williams Pipeline Partners L.P.		35%

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Our two general partners are subsidiaries of Williams. WGPC Holdings LLC owns 65 percent of our partnership interest. Williams Pipeline Partners Holdings LLC owns the remaining 35 percent of our general partnership interest.

Governance

Although management of Northwest is vested in its partners, the partners of Northwest have agreed to delegate management of the partnership to a management committee. Decisions or actions taken by the management committee of Northwest bind Northwest. The management committee is composed of two representatives, with one representative being designated by Williams and one representative being designated by Williams Pipeline Partners L.P. Each representative has full authority to act on behalf of the partner that designated such representative with respect to matters pertaining to that partnership. Each representative is an agent of the partner that designated that person and does not owe any duty (fiduciary or otherwise) to Northwest, any other partner or any other representative.

The management committee of Northwest meets no less often than quarterly, with the time and location of, and the agenda for, such meetings to be as the management committee determines. Special meetings of the management committee may be called at such times as a partner or management committee representative determines to be appropriate. Each member of the management committee is entitled to a vote equal to the percentage interest in Northwest of the respective partner represented. Except as noted below, the vote of a majority of the percentage interests represented at a meeting properly called and held constitutes the action of the management committee. Any action of the management committee may be taken by unanimous written consent.

The following actions require the unanimous approval of the management committee:

	•		the liquidation, dissolution or winding up of Northwest or making any bankruptcy filing;

	•		the issuance, incurrence, assumption or guarantee of any indebtedness or the pledge of any of Northwest’s assets;

	•		filing or resolving a Section 4 general rate case proceeding under the Natural Gas Act or any other proceeding or controversy at FERC or an appeal of a FERC order, the outcome of which would cause (A) Northwest to have reduced revenue of, or pay penalties, refunds or interest in excess of, $50 million, or (B) Northwest to agree to any criminal penalty;

	•		any amendment of the Northwest partnership agreement;

	•		any distributions to Northwest’s partners, other than the distributions of available cash to be made at least quarterly as described below;

	•		the admission of any person as a partner (other than a permitted transferee of a partner) or the issuance of any partnership interests or other equity interests of Northwest or any withdrawal by any partner from the partnership;

	•		the transfer, redemption, repurchase or other acquisition of interests in Northwest;

	•		the disposition of substantially all of the assets of Northwest or any portion of such assets with a value exceeding $20 million;

	•		any merger or consolidation of Northwest with another person or any conversion or reorganization of Northwest;

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	•		entering into any activity or business that may generate income that may not be “qualifying income” under Section 7704 of the Internal Revenue Code;

	•		the approval of Northwest’s budget;

	•		the approval of a transfer by a partner of its interest in Northwest; and

	•		any amendment to the administrative services agreement to which Northwest is a party.

Quarterly Cash Distributions

Under the Northwest general partnership agreement, on or before the end of the calendar month following each quarter, the management committee of Northwest is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. 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 established by the management committee as necessary or appropriate for the conduct of Northwest’s business and to comply with any applicable law or agreement.

Capital Calls to the Partners

Except as described below with regard to the Colorado Hub Connection Project, the Northwest general partnership agreement allows the management committee to require the partners to make additional capital contributions in accordance with their percentage interests. The management committee may issue capital calls to fund working and maintenance capital expenditures, as well as to fund expansion capital expenditures.

Restrictions on Transfer of Interests in Northwest

Each of the partners is allowed to transfer its general partnership interest in Northwest to an affiliate that is a wholly owned subsidiary of Williams or us, respectively. Otherwise, each Northwest partner has a “right of first offer” that requires a partner to offer the general partnership interest to the other partner prior to selling the interest to a third party. If the partner declines the right of first offer, the partner wishing to sell its interest has 120 days to sell the interest to a third party, provided that the sale is for at least equal value as offered to the other partner and other terms are not materially more favorable to the third party than the terms offered to the other partner.

Profit and Loss Allocations

In general, all items of income, gain, loss and deduction will be allocated to the partners in accordance with their percentage interests.

Agreement with Regard to Colorado Hub Connection Project

The Northwest general partnership agreement provides that the capital expenditures related to the Colorado Hub Connection Project will be funded by the affiliate of Williams holding the 65 percent general partnership interest in Northwest not owned by Williams Pipeline Partners L.P.

Williams’ Cash Management Program

We will invest cash through participation in Williams’ cash management program. The advances will be represented by one or more demand obligations. As a participant in Williams’ cash management program, Northwest makes advances to and receives advances from Williams. At December 31, 2007, the advances due to Northwest by Williams totaled approximately $39.1 million. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter which was 7.83 percent at December 31, 2007. Northwest received interest income from advances to Williams of $3.0 million, $3.9 million and $3.8 million during 2007, 2006 and 2005, respectively.

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Beginning in 2008, the interest rate on these demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29 percent at December 31, 2007.

Other Related Party Transactions

Williams’ corporate overhead expenses allocated to Northwest were $19.6 million, $18.7 million and $19.0 million for 2007, 2006 and 2005, respectively. Such expenses have been allocated to Northwest 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 provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to Northwest on a direct charge basis, which totaled $16.6 million, $16.6 million and $10.7 million for 2007, 2006 and 2005, respectively.

Northwest also has transportation and exchange transactions and agreements relating to the rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $11.8 million, $3.4 million and $2.4 million for 2007, 2006 and 2005, respectively.

Northwest has also entered into an administrative services agreement with Northwest Pipeline Services LLC, a wholly-owned subsidiary of Williams, to provide services that Northwest determines may be reasonable and necessary to operate its business, including employees, accounting, information technology, company development, operations, administration, insurance, risk management, tax, audit, finance, land, marketing, legal, and engineering, which services may be expanded, modified or reduced from time to time as agreed upon by the parties. Northwest Pipeline Services LLC is a variable interest entity for which Northwest is the primary beneficiary, and accordingly, is consolidated in the financial statements of Northwest.

From time to time Northwest has 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.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees for professional services provided by our independent auditors in each of the last two fiscal years in each of the following categories are:


	2007		2006
	(Thousands of Dollars)
Audit Fees	$	1,124	$	851
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	1,124	$	851

Fees for audit services include fees associated with the annual audit, the reviews for our quarterly reports on Form 10-Q, the reviews for other SEC filings and accounting consultations.

As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The Williams audit committee policies and procedures for pre-approving audit and non-audit services will be filed with the Williams Proxy Statement to be filed with the SEC on or before April 15, 2008.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Index


	Page
	Reference
	to 2007
	Form 10-K
Management’s Report on Internal Control over Financial Reporting		43

Report of Independent Registered Public Accounting Firm		44

Consolidated Statements of Income for the Years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		45

Consolidated Balance Sheets at December 31, 2007 and 2006 (restated)		46

Consolidated Statements of Owners’ Equity for the Years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		48

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		49

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		50

Notes to Consolidated Financial Statements		51

(a) 2. Financial Statement Schedules

NORTHWEST PIPELINE CORPORATION
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)


			Charged to
	Beginning		Costs and						Ending
Description	Balance		Expenses			Deductions			Balances
Year ended December 31, 2007:
Reserve for doubtful receivables	$	53	$	(46	)	$	0		$	7
Reserve for obsolescence of materials and supplies		472		104			(395	)		181
Year ended December 31, 2006:
Reserve for doubtful receivables		91		(38	)		0			53
Reserve for obsolescence of materials and supplies		263		306			(97	)		472
Year ended December 31, 2005:
Reserve for doubtful receivables		320		44			(273	)		91
Reserve for obsolescence of materials and supplies		439		0			(176	)		263

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All other schedules have been omitted because they are not required to be filed.

(a) 3 and b. Exhibits:

(2)

Plan of acquisition, reorganization, arrangement, liquidation or succession:

	*	(a) Merger Agreement, dated as of September 20, 1983, between Williams and Northwest Energy Company (Energy) (Exhibit 18 to Energy schedule 14D-9 (Amendment No. 3) dated September 22, 1983).

	*	(b) The Plan of Merger, dated as of November 7, 1983, between Energy and a subsidiary of Williams (Exhibit 2(b) to Northwest report on Form 10-K, No. 1-7414, filed March 22, 1984).

	*	(c) Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007).

(3)

Articles of incorporation and by-laws:

	*	(a) Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007).

	*	(b) Amended and Restated General Partnership Agreement of Northwest Pipeline GP (Exhibit 3.1 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008).

(4)

Instruments defining the rights of security holders, including indentures:

	*	(a) Senior Indenture, dated as of August 1, 1992, between Northwest and Continental Bank, N.A., relating to Pipeline’s 9% Debentures, due 2022 (Exhibit 4.1 to Registration Statement on Form S-3, No. 33-49150, filed July 2, 1992).

	*	(b) Senior Indenture, dated as of November 30, 1995 between Northwest and Chemical Bank, relating to Pipeline’s 7.125% Debentures, due 2025 (Exhibit 4.1 to Registration Statement on Form S-3, No. 33-62639, filed September 14, 1995).

	*	(c) Senior Indenture, dated as of December 8, 1997 between Northwest and The Chase Manhattan Bank, relating to Pipeline’s 6.625% Debentures, due 2007 (Exhibit 4.1 to Registration Statement on Form S-3, No. 333-35101, filed September 8, 1997).

	*	(d) Indenture, dated March 4, 2003, between Northwest and JP Morgan Chase Bank, as Trustee (filed as Exhibit 4.1 to The Williams Companies, Inc. Form 10-Q for the quarter ended March 31, 2003, Commission File Number 1-4174).

	*	(e) Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A. (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed June 23, 2006).

	*	(f) Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (Exhibit 4.1 to Northwest report on Form 8-K, No. 1-7414, filed April 6, 2007).

(10)

Material contracts:


(a)	*(1)	Form of Transfer Agreement, dated July 1, 1991, between Northwest and Gas Processing (Exhibit 10(c)(8) to Pipeline Report on Form 10-K, No. 1-7414, filed March 26, 1992).

	*(2)	Form of Operating Agreement, dated July 1, 1991, between Northwest and Williams Field Services Company (Exhibit 10(c)(9) to Pipeline Report on Form 10-K, No. 1-7414, filed March 26, 1992).

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

		*(4)		Credit Agreement, dated as of May 1, 2006, among The Williams Companies, Inc., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, and Williams Partners L.P., as Borrowers, and Citibank, N.A., as Administrative Agent (Exhibit 10.1 to The Williams Companies, Inc. Form 8-K filed May 1, 2006 Commission File Number 1-4174).

		*(5)		Registration Rights Agreement, dated as of June 22, 2006, among Northwest Pipeline Corporation and J.P. Morgan Securities Inc. and Calyon Securities (USA) Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto. (Exhibit 10.1 to Form 8-K filed June 23, 2006).

		*(6)		Amendment Agreement, dated May 9, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline Corporation, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (Exhibit 10.1 to The Williams Companies, Inc. report on Form 8-K filed May 15, 2007, Commission File Number 1-4174).

		*(7)		Amendment Agreement dated November 21, 2007, among The Williams Companies, Inc., Williams Partners L.P., Northwest Pipeline GP, Transcontinental Gas Pipe Line Corporation, certain banks, financial institutions and other institutional lenders and Citibank, N.A., as administrative agent (Exhibit 10.1 to the Williams Companies, Inc., Form 8-K, filed November 28, 2007, Commission File Number 1-4174).

		*(8)		Administrative Services Agreement, dated January 24, 2008, between Northwest Pipeline GP and Northwest Pipeline Services, LLC (Exhibit 10.1 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008).

		*(9)		Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, among Williams Pipeline Partners L.P., Williams Pipeline Operating LLC, WPP Merger LLC, Williams Pipeline Partners Holdings LLC, Northwest Pipeline GP, Williams Pipeline GP LLC, Williams Gas Pipeline Company, LLC, WGPC Holdings LLC and Williams Pipeline Services Company (Exhibit 10.2 to Northwest report on Form 8-K, No. 1-7414, filed January 30, 2008).

		*(10)		Registration Rights Agreement, dated as of April 5, 2007, among Northwest Pipeline Corporation and Greenwich Capital Markets, Inc. and Banc of America Securities LLC, acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (Exhibit 10.1 to Northwest report on Form 8-K, No. 1-7414, filed April 6, 2007).

(12)		Statement of Ratio of Earnings to Fixed Charges

(18)		Letter Re: Change in Accounting Principles

(23)		Consent of Independent Registered Public Accounting Firm

(24)		Power of Attorney with Certified Resolution

(31)		Section 302 Certifications

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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

Date: February 28, 2008

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.


Signature		Title

/s/ Steven J. Malcolm*		Chief Executive Officer
Steven J. Malcolm

/s/ Donald R. Chappel*		Management Committee Member
Donald R. Chappel

/s/ Phillip D. Wright*		Senior Vice President and Management Committee Member
Phillip D. Wright

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

/s/ R. Rand Clark		Controller (Principal Accounting Officer)
R. Rand Clark

/s/ Allison G. Bridges*		Vice President
Allison G. Bridges

* By /s/ R. Rand Clark
R. Rand Clark
Attorney-in-fact

Date: February 28, 2008

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	December 31,
	2007		2006
			(Restated)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	497	$	1,489
Advances to affiliates		39,072		49,980
Accounts receivable –
Trade, less reserves of $7 for 2007 and $53 for 2006		40,689		32,230
Affiliated companies		3,514		591
Materials and supplies, less reserves of $181 for 2007 and $472 for 2006		10,344		10,013
Exchange gas due from others		10,155		10,556
Exchange gas offset (Note 1)		6,593		4,538
Deferred income taxes		—		4,066
Prepayments and other		6,928		7,945


Total current assets		117,792		121,408


PROPERTY, PLANT AND EQUIPMENT, at cost		2,706,691		2,654,717
Less – Accumulated depreciation		864,999		806,723


Total property, plant and equipment		1,841,692		1,847,994


OTHER ASSETS:
Deferred charges		44,915		32,093
Regulatory assets		52,072		47,829


Total other assets		96,987		79,922


Total assets	$	2,056,471	$	2,049,324


Heading	Page
PART I

Item 1. BUSINESS		1

Item 1A. RISK FACTORS		13

Item 1B. UNRESOLVED STAFF COMMENTS		24

Item 2. PROPERTIES		24

Item 3. LEGAL PROCEEDINGS		24

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		24

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCK-HOLDER MATTERS		25

Item 6. SELECTED FINANCIAL DATA		25

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		26

Item 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK		41

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		42

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		71

Item 9A. CONTROLS AND PROCEDURES		71

Item 9B. OTHER INFORMATION		71

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT		72

Item 11. EXECUTIVE COMPENSATION		73

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		74

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		75

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES		77

PART IV

Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES		78

Computation of Ratio of Earnings to Fixed Charges
Letter Re: Change in Accounting Principles
Consent of Independent Registered Public Accounting Firm
Power of Attorney with Certified Resolution
Section 302 Certification of Principal Executive Officer
Section 302 Certification of Principal Financial Officer
Section 906 Certification of Principal Executive Officer and Principal Financial Officer

	(a)		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.

	(b)		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.


*		Exhibits so marked have heretofore been filed with the Securities and Exchange Commission as part of the filing indicated and are incorporated herein by reference.