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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

Form 10-K


(Mark One)

þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1933
		For the fiscal year ended December 31, 2007
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number 001-33917

Williams Pipeline Partners L.P.

(Exact name of Registrant as Specified in Its Charter)


Delaware		26-0834035
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

One Williams Center, Tulsa, Oklahoma (Address of Principal Executive Offices)		74172-0172 (Zip Code)

918-573-2000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered

Common Units		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

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 o No þ

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


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The registrant was formed on August 31, 2007, and completed its initial public offering on January 24, 2008. As a result, there was no aggregate market value of the registrant’s common units held by non-affiliates as of the last business day of the registrant’s most recently completed second quarter.

The registrant had 22,605,688 common units and 10,957,900 subordinated units outstanding as of February 27, 2008.

DOCUMENTS INCORPORATED BY REFERENCE
None

WILLIAMS PIPELINE PARTNERS L.P.

FORM 10-K

PART I


Items 1 and 2.	*Business and Properties*

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Pipeline Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of Northwest Pipeline GP, in which we own a 35% interest. When we refer to Northwest by name, we are referring exclusively to Northwest Pipeline GP and its consolidated affiliate, Northwest Pipeline Services LLC.

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other documents electronically with the U.S. Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934, as amended. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at http://www.sec.gov.

We make available free of charge on or through our Internet website at http://www.williamspipelinepartners.com, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charter of the audit committee of our general partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s secretary at Williams Pipeline Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

Our principal executive offices are located at One Williams Center, Tulsa, Oklahoma 74172. Our telephone number is 918-573-2000.

GENERAL

We are a growth-oriented limited partnership recently formed by The Williams Companies, Inc., or Williams, to own and operate natural gas transportation and storage assets. Our primary business objectives are to generate stable cash flows and, over time, to increase our quarterly cash distributions per unit. We own a 35% general partnership interest in Northwest Pipeline GP, or Northwest, which owns an approximate 3,900-mile, bi-directional, interstate natural gas pipeline system that extends from the San Juan Basin in New Mexico, through the Rocky Mountains and to the Northwestern United States. Northwest also has working natural gas storage capacity of approximately 12.6 billion cubic feet, or Bcf. We account for our 35% interest in Northwest as an equity investment, and, therefore, do not consolidate its financial results.

The 35% of Northwest owned by us was owned by Williams prior to the initial public offering (“IPO”) of our common units in January 2008. As of February 21, 2008, Williams indirectly owns an approximate 45.7% limited partnership interest in us and all of our 2% general partner interest.

Williams is an integrated energy company with 2007 revenues in excess of $10.5 billion that trades on the New York Stock Exchange under the symbol “WMB.” Williams operates in numerous aspects of the energy industry, including natural gas exploration and production, midstream services and interstate natural gas transportation. Williams has owned or operated interstate natural gas transportation and storage assets for more than 23 years.

RECENT EVENTS

On January 24, 2008, we completed our IPO of 16,250,000 common units representing limited partner interests in us at a price to the public of $20.00 per unit ($18.80 net of underwriters’ discount). Concurrent with the closing of the IPO, (i) the public, through the underwriters of the offering, contributed $325.0 million ($305.5 million net of the underwriters’ discount and structuring fees) to us in exchange for 16,250,000 common units, representing a 47.5% limited partner interest in us, (ii) we purchased from Northwest a 15.9% general partnership interest in Northwest, and (iii) a 19.1% interest in Northwest was contributed to us by Williams Pipeline GP LLC, our General Partner, in exchange for 6,350,668 common units, 10,957,900 subordinated units, 684,869 units representing a 2% general partner interests in us, and all of our incentive distribution rights. On February 15, 2008, the underwriters of the offering exercised their right to purchase an additional 1,650,000 common units from us to cover over-allotments. The underwriters purchased the common units pursuant to that option on February 21, 2008 at the IPO price of $18.80 per unit, net of underwriting discounts. 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 IPO, the Partnership redeemed 1,650,000 common units held by the General Partner.

FINANCIAL INFORMATION ABOUT SEGMENTS

See Part II, Item 8 — Financial Statements and Supplementary Data.

NARRATIVE DESCRIPTION OF BUSINESS

We are a growth-oriented Delaware limited partnership recently formed by Williams to own and operate natural gas transportation and storage assets. We own a 35% general partnership interest in Northwest. The remainder of the interest in Northwest is owned by Williams Gas Pipeline, a wholly owned subsidiary of Williams. As of February 21, 2008, Williams, through its subsidiary, Williams Pipeline GP LLC, owns a 2% general partner interest and a 45.7% limited partner interest in us.

Northwest is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending 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. Northwest provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, directly or indirectly through interconnections with other pipelines. Northwest’s principal business is regulated by the Federal Energy Regulatory Commission (FERC).

Northwest’s System

Northwest owns and operates 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. Northwest’s system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Its compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2007, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.4 Bcf*( of natural gas per day. Northwest also has approximately 12.6 Bcf of working natural gas storage capacity.

Northwest has 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. Northwest provides natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado,

(* 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.

New Mexico, California and Arizona either directly or indirectly through interconnections with other pipelines. Northwest is 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 Northwest provides competitively priced services in markets such as Reno, Nevada, Spokane, Washington and Medford, Oregon that are also served by other interstate natural gas pipelines.

Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies (or LDCs), municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. For the year ended December 31, 2007, Northwest’s two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Co., which accounted for approximately 20.0% and 11.5%, respectively, of its total operating revenues during that period. No other customer accounted for more than 10% of total operating revenues during that period.

Northwest’s Transportation and Storage Services

Northwest’s rates are subject to the rate-making policies of FERC. Northwest provides a significant portion of its transportation and storage services pursuant to long-term firm contracts that obligate its customers to pay it 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, Northwest also collects 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% of Northwest’s long-term firm contracts are at the maximum rate allowed under Northwest’s tariff, as distinguished from discounted rates. Northwest also derives a small portion of its revenues from short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related services.

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


	•	Jackson Prairie: Northwest owns a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of its distribution customers. As of December 31, 2007, Northwest’s 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, Northwest’s share of the best-efforts delivery capacity was 50 MMcf per day. As described below, Northwest is participating in an ongoing expansion of Jackson Prairie.

	•	Plymouth LNG: Northwest also owns and operates an LNG storage facility located near Plymouth, Washington, which provides standby service for its 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 Northwest’s major customers own the working natural gas stored at the LNG plant.

	•	Clay Basin Field: Northwest has a contract with a third party under which natural gas storage services are provided to it in an underground storage reservoir in the Clay Basin Field located in Daggett County, Utah. Northwest is 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.

Northwest’s 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 Northwest’s primary markets such as Seattle, Washington, Portland, Oregon and Boise, Idaho. Northwest’s 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 Northwest’s 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., Northwest’s 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 new 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 Northwest’s Capacity Replacement Project. Puget Sound Energy, Northwest’s 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.

Northwest is 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/d 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, 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, Northwest’s customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with Northwest’s 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 Northwest’s transmission system near Chehalis, Washington, is operated by Puget Sound Energy and is jointly owned by Northwest, Puget Sound Energy and Avista Corporation. A phased capacity expansion is currently underway and a deliverability expansion is planned for 2008.

As a one-third owner of Jackson Prairie, Northwest held an open season for a new incremental firm storage service based on its 104 MMcf per day share of the planned 2008 deliverability expansion and its 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.

Northwest’s one third share of the deliverability expansion is estimated to be $16 million. Northwest’s 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 Northwest’s customers and their need for peak day capacity, Northwest believes 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 its system.

Colorado Hub Connection Project

Northwest has proposed installing a new lateral to connect the White River Hub near Meeker, Colorado to Northwest’s 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. Northwest has 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. The Pan-Alberta capacity was originally contracted to transport natural gas supplies from the WCSB through Northwest’s 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 Northwest’s system.

The 98 MMcf per day of short-term firm capacity is currently contracted through at least November 2008 at maximum rates, but historically, Northwest deeply discounted its 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 Northwest elects 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 Northwest’s Pacific Northwest customers. Northwest has 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. The Northwest general partnership agreement provides that, if Northwest elects to proceed with the CHC Project, the associated capital expenditures required to construct the lateral would be funded by the affiliate of Williams holding the 65% general partnership interest in Northwest not owned by us. If the CHC Project proceeds, Northwest expects to seek approval to recover the CHC Project costs in a future rate case filed with the FERC.

Parachute Lateral Project

Northwest placed its Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, Northwest filed an application with the FERC to amend its certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of its 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 Northwest completed the transfer of the Parachute Lateral on December 31, 2007. Northwest 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, Northwest 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 Northwest charged $2.8 million of these assets to expense.

As contemplated in the application for amendment, Parachute has leased the facilities back to Northwest and has become a subsidiary of Williams Field Services. Northwest 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, Northwest will pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3% 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, Northwest 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 Northwest’s existing Vernal compressor station. The project would utilize capacity on the proposed lateral to be constructed as part of Northwest’s Colorado Hub Connection Project to access supplies in the Piceance Basin.

Seasonality

Although Northwest delivers more gas to its market areas in the winter heating season months of November through March, because a significant percentage of Northwest’s revenues are collected through reservation fees, its 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 result in mainline throughput.

Regulatory Matters

FERC Regulation

Northwest’s interstate pipeline system and storage facilities are subject to extensive regulation by FERC. FERC has jurisdiction with respect to virtually all aspects of its 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.

Northwest holds certificates of public convenience and necessity issued by FERC pursuant to Section 7 of the Natural Gas Act of 1938 (NGA) covering its facilities, activities and services. Northwest may not unduly discriminate in providing open access, available transportation and storage services to customers qualifying under Northwest’s 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 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, Northwest 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 Northwest’s pipeline in western Washington, which resulted in Corrective Action Orders from PHMSA. In response to these orders, and pursuant to FERC certificate authority, Northwest 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 Northwest’s 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, Northwest 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 Northwest’s 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 Northwest or by any other party to the settlement for any further rate increases or decreases prior to January 1, 2009 and Northwest is 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 Court. The D.C. Circuit Court, 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 Court 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 Northwest’s income tax allowance, it may be more difficult for Northwest to justify its rates in future proceedings. While we have established the Eligible Holder certification requirement, we can provide no assurance that such certification will be effective to establish that our unitholders, or our unitholders’ owners, are subject to United States federal income taxation on the income generated by us. If we are unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating Northwest’s cost of service in future rate cases, FERC could disallow a substantial portion of Northwest’s income tax allowance, and its maximum lawful rates could decrease from current levels.

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 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 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. Northwest cannot ensure that such policy developments would not adversely affect Northwest’s 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

Northwest is subject to regulation by the DOT’s Pipeline and Hazardous Materials Safety Administration, or 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. 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. Northwest’s natural gas pipeline has inspection and compliance programs designed to maintain compliance with federal and applicable state pipeline safety and pollution control requirements.

Northwest is 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. Northwest’s 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 Northwest’s operations, including:


	•	requiring the acquisition of permits to conduct regulated activities;

	•	restricting the manner in which Northwest 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 Northwest’s overall cost of business, including its capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect Northwest’s maintenance capital expenditures and net income, we believe that they do not affect Northwest’s competitive position in that the operations of Northwest’s 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 Northwest’s operations and financial position. In the event of future increases in costs, Northwest may be unable to pass on those increases to its customers. We believe that Northwest is in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements will not have a material adverse effect on Northwest.

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

Waste Management. Northwest’s 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 its operations, Northwest 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 its operations, Northwest 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.

Northwest currently owns or leases properties that for many years have been used for the transportation and compression of natural gas, and the storage of natural gas. Although Northwest 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 it 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 Northwest’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Northwest 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, Northwest evaluated many of its facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. Northwest identified PCB contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, Northwest 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 Northwest and the EPA in the late 1980’s and Northwest conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990’s. In 2005, the Washington Department of Ecology required Northwest to reevaluate its previous mercury clean-ups in Washington. Currently, Northwest is assessing the actions needed to bring the sites up to Washington’s current environmental standards. At December 31, 2007, Northwest had accrued liabilities totaling approximately $7.5 million for these costs, which are expected to be incurred over the period from now through 2012. Northwest believes these costs associated with compliance with these environmental laws and regulations are prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest’s 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.

Northwest 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, Northwest may be required to supplement or modify its 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 Northwest will not have a material adverse effect on its 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.

Northwest’s 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 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 Northwest’s operations and demand for its 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

Northwest’s 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, Northwest is not fully insured against all risks inherent in its business. See “Risk Factors” below.

Ownership of Property

Northwest owns its system in fee simple. However, a substantial portion of its system is constructed and maintained on and across properties owned by others pursuant to rights-of-way, easements, permits, licenses or consents. Northwest’s compressor stations, with associated facilities, are located in whole or in part upon lands owned by it and upon sites held under leases or permits issued or approved by public authorities. Land owned by others, but used by Northwest 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 Northwest. Various credit arrangements restrict the sale or disposal of a major portion of Northwest’s pipeline system. Northwest leases its corporate offices in Salt Lake City, Utah.

Williams owns its corporate offices in Tulsa, Oklahoma. We do not own or lease any properties of our own.

Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. All of our executive management personnel are employees of our general partner or another subsidiary of Williams and will devote the portion of their time to our business and affairs that is required to manage and conduct our operations. The officers of Williams Pipeline GP LLC will likely devote substantially less than a majority of their time to our business, although we expect the amount of time that they devote may increase or decrease in future periods as our business develops. These officers will manage the day-to-day affairs of our business and operations. Northwest is operated by an affiliate of Williams’ pursuant to an operating agreement and the employees who operate the Northwest assets are therefore not employees of ours.

Transactions with Affiliates

Northwest engages 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.”

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

We have no revenue or segment profit/loss attributable to international activities.

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT

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. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The reader should carefully consider the risk factors discussed below in addition to the other information in this annual report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units and the trading price of our common units could decline and unitholders could lose all or part of their investment.

Many of the factors that could adversely affect our business, results of operations and financial condition 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:


	•	We may not have sufficient cash from operations to enable us to pay the minimum distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

	•	The amount of cash we have available for distribution depends primarily on our cash flow, and not solely on profitability.

	•	We and Williams jointly control Northwest.

	•	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 and Northwest’s competitors.

	•	The 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 Northwest’s debt agreements.

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

	•	Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Williams, our general partner, and their respective affiliates have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.

	•	The credit and risk profile of our general partner, and its owner, Williams, could adversely affect our or Northwest’s credit ratings.

	•	Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

	•	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities.

	•	Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to 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 include those described in the following section.

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 Related to Our Business

We may not have sufficient cash from operations to enable us to pay the minimum quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash Northwest generates from its operations, which will fluctuate based on, among other things:


	•	the rates Northwest charges for its transportation and storage services and the volumes of natural gas its customers transport and store;

	•	the level of Northwest’s operating and maintenance expense and general and administrative costs and our incremental general and administrative costs;

	•	the overall demand for natural gas in markets that Northwest serves and the quantities of natural gas available for transport, especially from the Rocky Mountain region, the San Juan Basin and the WCSB supply basins;

	•	regulatory action affecting the demand for natural gas, the supply of natural gas, the rates Northwest can charge, how Northwest contracts for services, and Northwest’s existing contracts, operating costs and operating flexibility;

	•	the development of LNG import terminals could materially affect the market price of natural gas, which could indirectly affect the longer term supply and demand dynamics of natural gas in Northwest’s areas of operation;

	•	the costs of complying with the Pipeline Safety Improvement Act of 2002 and other governmental regulations; and

	•	potential competition from third parties who may build new pipelines in or near Northwest’s markets or supply basins.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:


	•	the amount of cash distributed by Northwest in respect of our 35% general partnership interest, which is our sole asset;

	•	the level of capital expenditures we and Northwest make, including expenditures to maintain Northwest’s facilities, to complete construction projects, and to make acquisitions;

	•	our and Northwest’s debt service requirements and other liabilities;

	•	fluctuations in our and Northwest’s working capital needs;

	•	our and Northwest’s ability to borrow funds and access capital markets;

	•	the creditworthiness and timeliness of payment from Northwest’s customers;

	•	restrictions on distributions contained in Williams’ credit agreement; and

	•	the amount of cash reserves established by Northwest and by our general partner.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

We and Williams jointly control Northwest. As a result, we cannot independently control the amount of cash we will receive from Northwest, and we may be required to contribute significant cash to fund Northwest’s operations.

Our 35% general partnership interest in Northwest is our sole asset and therefore will generate substantially all of our cash available for distribution. As a result, our performance is substantially dependent on Northwest’s distributions to us. The ownership of Northwest is shared between us and Williams. Accordingly, we cannot independently control the amount of cash distributed to us, nor can we independently control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund. More specifically:


	•	we cannot independently control decisions with respect to the operation of Northwest, including decisions with respect to incurrence of expenses and distributions to us;

	•	Northwest may establish reserves for working capital and maintenance capital expenditures which would reduce cash otherwise available for distribution to us;

	•	Northwest may incur additional indebtedness, and the related principal and interest payments would reduce cash otherwise available for distribution to us;

	•	Northwest may require us to make additional capital contributions to fund working and maintenance capital expenditures, as well as to fund expansion capital expenditures, funding of which could reduce the amount of cash otherwise available for distribution to you.

Our lack of 100% control over the operation of Northwest may mean that we do not receive the amount of cash expected to be distributed to us. We may be required to make capital contributions to Northwest, and these contributions may be material. This lack of 100% control may materially and adversely affect our ability to distribute cash to you.

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

Northwest’s 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 Northwest’s 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 Northwest’s and our financial condition and results of operations. Accidents or other operating risks could further

result in loss of service available to Northwest’s customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of Northwest’s pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of Northwest’s 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 Northwest’s ability to meet contractual obligations and retain customers, with a resulting negative impact on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Compliance with the Pipeline Safety Improvement Act of 2002 may adversely impact Northwest’s cost of conducting its business.

Northwest has developed an Integrity Management Plan that it believes meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration, or PHMSA, final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The regulations require operators 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 their pipelines as necessary; and

	•	implement preventive and mitigating actions.

In meeting these integrity regulations, Northwest has identified high consequence areas and completed its baseline assessment plan. Currently, Northwest estimates 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 Northwest fail to comply with Department of Transportation regulations, it could be subject to penalties and fines. If the costs of complying with these integrity regulations are materially higher than its current expectations, Northwest’s business and its ability to make distributions to us could be adversely impacted. Any limitation on Northwest’s ability to make distributions to us could adversely affect our ability to make distributions to you because distributions from Northwest represent substantially all of the cash we expect to distribute to our unitholders.

Northwest’s current pipeline infrastructure is aging, which may adversely affect its business and our ability to make distributions to you.

Some portions of Northwest’s pipeline infrastructure are approximately 50 years old. The current age and condition of this pipeline infrastructure could result in a material adverse impact on Northwest’s business, financial condition and results of operations and on our ability to make distributions to you if the costs of maintaining its 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.

Northwest competes primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of Northwest’s competitors may have greater financial resources and access to greater supplies of natural gas than it does. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services Northwest provides to its customers. For example, the proposed Palomar Gas Transmission Project could result in an increase in competition in the Pacific Northwest. Moreover, Williams and its affiliates, including Williams Partners, are not limited in their ability to compete with Northwest or us. Further, natural gas also competes with other forms of energy available to Northwest’s 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 Northwest’s traditional customer base. As a result, Northwest could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If Northwest is unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, Northwest or its 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 Northwest’s system or, in cases where it does not have long-term fixed rate contracts, could force Northwest to lower its 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 Northwest’s 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. Northwest’s 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 Northwest’s competitors, including the Rocky Mountain pipeline projects recently proposed by Spectra and El Paso. All of these competitive pressures could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

Northwest’s 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 Northwest’s material contracts are terminable in 2008, upon expiration of the primary terms, Northwest may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

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


	•	the level of existing and new competition to deliver natural gas to Northwest’s markets;

	•	the growth in demand for natural gas in Northwest’s markets;

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

	•	whether Northwest’s business strategy continues to be successful;

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

	•	the effects of state regulation on customer contracting practices.

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

Northwest’s natural gas transportation and storage operations are subject to regulation by FERC, which could have an adverse impact on its ability to establish transportation and storage rates that would allow it to recover the full cost of operating its pipeline, including a reasonable return, and on our ability to make distributions to you.

Northwest’s interstate natural gas transportation and storage operations are subject to federal, state and local regulatory authorities. Specifically, its natural gas pipeline system and its 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 Northwest may offer to its customers;


	•	certification and construction of new facilities;

	•	acquisition, extension, disposition or abandonment of facilities;

	•	accounts and records;

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

	•	initiation and discontinuation of services; and

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

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

The rates, terms and conditions for Northwest’s interstate pipeline and storage services are set forth in its FERC-approved tariff. Pursuant to the terms of a prior rate settlement agreement, Northwest 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 Northwest must file a new rate case to become effective not later than January 1, 2013. Any successful complaint or protest against Northwest’s rates could have an adverse impact on Northwest’s revenues associated with providing transportation and storage services.

Northwest could be subject to penalties and fines if it fails to comply with FERC regulations.

Northwest’s transportation and storage operations are regulated by FERC. Should Northwest fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it 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 Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

The outcome of certain FERC proceedings regarding income tax allowances in rate calculations is uncertain and could affect Northwest’s ability to include an income tax allowance in its cost-of-service based rates, which would in turn impact our cash available for distribution.

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, or the D.C. Circuit Court. The D.C. Circuit Court, 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 Court denied rehearing of its decision.

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.

The outcome of future rate cases to set the rates Northwest can charge customers on its pipeline might result in rates that will not fully compensate Northwest for its ongoing expenses and provide an adequate return on the capital that Northwest has invested in its pipeline.

Northwest filed a rate case with FERC on June 30, 2006 to request changes to the rates Northwest charges. The new rates became effective January 1, 2007. On January 31, 2007, Northwest filed a stipulation and settlement agreement to resolve all outstanding issues in its rate case, which included a two-year moratorium that precludes filings by Northwest or by any other party to the settlement for any further rate increases or decreases prior to January 1, 2009 and a requirement for Northwest to file a new rate case to be effective not later than January 1, 2013. The settlement was approved by FERC on March 30, 2007 and is now final. There is a risk that the rates that FERC approved as part of the submitted settlement will ultimately prove to be inadequate to recover increases in operating costs, while sustaining an adequate return on capital investments. There is also the risk that higher rates will cause Northwest’s customers to look for alternative ways to transport their natural gas.

Any significant decrease in supplies of natural gas in Northwest’s areas of operation could adversely affect its business and operating results and reduce our cash available for distribution to unitholders.

Northwest’s 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 Northwest’s pipeline and storage assets. Production from existing wells and natural gas supply basins with access to Northwest’s 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 Northwest’s customers. For example, the Rockies Express Pipeline Project, which is expected to take natural gas from the Piceance Basin to Midwest and Eastern markets, will reduce the availability of Piceance Basin natural gas for Northwest. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, or throughput, on Northwest’s pipeline and cash flows associated with the transportation of natural gas, Northwest’s customers must continually obtain adequate supplies of natural gas.

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

For example, Northwest currently has a contract with Pan-Alberta Gas that was originally entered into to transport natural gas supplies from the WCSB through Northwest’s 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 Northwest. Northwest has proposed the Colorado Hub Connection Project in an attempt to re-contract the Pan-Alberta contract commitments, which terminate in 2012. However, if Northwest is not successful in re-contracting this capacity, or otherwise able to resell the capacity, it could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Significant prolonged changes in natural gas prices could affect supply and demand, cause a reduction in or termination of the long-term transportation and storage contracts or throughput on Northwest’s system, and adversely affect our cash available to make distributions to you.

Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in Northwest’s long-term transportation and storage contracts or throughput on Northwest’s 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 Northwest’s system. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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 Northwest’s 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 Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Northwest depends on certain key customers for a significant portion of its revenues. The loss of any of these key customers or the loss of any contracted volumes could result in a decline in cash available for us to make distributions to you.

Northwest relies on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2007, the two largest customers for Northwest were Puget Sound Energy and Northwest Natural Gas Co. These customers accounted for approximately 20.0% and 11.5%, respectively, of its operating revenues for the year ended December 31, 2007. The loss of even a portion of Northwest’s 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 Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

If third-party pipelines and other facilities interconnected to Northwest’s pipeline and facilities become unavailable to transport natural gas, Northwest’s revenues and our ability to make distributions to you could be adversely affected.

Northwest depends upon third-party pipelines and other facilities that provide delivery options to and from its pipeline and storage facilities. Because Northwest does not own these third-party pipelines or facilities, their continuing operation is not within its 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, Northwest’s ability to operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing its revenues. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on Northwest’s pipeline or stored at Northwest’s facilities could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Northwest’s debt agreements impose restrictions on it that may adversely affect its ability to operate its business.

Williams has a credit agreement to which Northwest is a party. This agreement contains covenants that limit, among other things, Northwest’s ability to create liens supporting indebtedness, sell assets, make certain distributions, and incur additional debt. In addition, the credit agreement and Northwest’s existing indentures contain other limitations such as, in the case of the credit agreement, financial covenants, with which it must comply. Any debt agreements that we or Northwest enter into in the future may contain similar covenants and limitations. Northwest’s and our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that Northwest’s and our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of its debt agreements, to remedy that default.

A failure to comply with the covenants in the credit agreement or in any existing or future debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding 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 other debt agreements. Such a cross-default or cross-acceleration could have a wider impact on Northwest’s or 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 it, Northwest or we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. Any event of default or acceleration at Northwest would materially and adversely affect our ability to make distributions to you because distributions from Northwest represent substantially all of the cash we expect to distribute to our unitholders.

Although Northwest’s debt instruments may contain limitations on additional indebtedness, Northwest’s general partnership agreement does not prohibit it from incurring indebtedness, which may affect our ability to make distributions to you.

As discussed in the immediately preceding risk factor, Northwest’s existing debt instruments contain restrictions on its ability to incur additional indebtedness. However, such restrictions do not prohibit incurrence

of indebtedness in all instances, and Northwest’s general partnership agreement does not prohibit it from incurring indebtedness. At December 31, 2007, Northwest had approximately $443.7 million in outstanding senior notes and $250 million outstanding under Williams’ credit agreement, none of which indebtedness is consolidated on our balance sheet. If permitted under Williams’ credit agreement and Northwest’s other indebtedness, Northwest could incur additional indebtedness. Northwest’s incurrence of significant additional indebtedness could inhibit its ability to make distributions to us. An inability by Northwest to make distributions to us would materially and adversely affect our ability to make distributions to you because distributions from Northwest represent substantially all of the cash we expect to distribute to our unitholders.

If we or Northwest do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.

A principal focus of our strategy is to continue to grow the cash distributions to our unitholders by expanding our business. Our ability to grow depends on our and Northwest’s ability to complete expansion projects and our and Northwest’s ability to make acquisitions that result in an increase in cash generated from operations per unit. We and Northwest may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:


	•	inability to identify attractive expansion projects or acquisition candidates or outbidding by competitors;

	•	inability to obtain necessary rights of way or government approvals;

	•	inability to integrate successfully the businesses built or acquired;

	•	inability to raise financing for such expansion projects or acquisitions on economically acceptable terms;

	•	mistaken assumptions about contract commitments, volumes, reserves, revenues and costs, including synergies and potential growth; or

	•	inability to secure adequate customer commitments to use the newly expanded or acquired facilities.

Acquisitions or expansion projects may reduce our cash from operations on a per unit basis.

If we or Northwest make acquisitions or complete expansion projects, these acquisitions or expansion projects may reduce our cash from operations on a per unit basis. Any acquisition or expansion project involves potential risks, including, among other things:


	•	decreases in liquidity as a result of using a significant portion of available cash or borrowing capacity to finance the project or acquisition;

	•	inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

	•	inability to receive cash flows from a newly built or acquired asset until it is operational;

	•	unforeseen difficulties operating in new producing basins or end-use markets; and

	•	customer losses at the acquired business.

If any expansion projects or acquisitions we or Northwest ultimately complete are not accretive to our cash available for distribution, our ability to make distributions to you may be reduced.

Northwest’s operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

Northwest’s 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.

These laws and regulations may impose numerous obligations that are applicable to Northwest’s operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from its pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the 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 Northwest’s 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 Northwest’s properties and facilities. Private parties, including the owners of properties through which Northwest’s pipeline passes and facilities where Northwest’s 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. Northwest may not be able to recover all or any of its remedial costs from insurance. 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 Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Northwest does not own all of the land on which its pipeline and facilities are located, which could disrupt its operations.

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

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

We and Northwest are not fully insured against all risks inherent to our businesses, including environmental accidents that might occur. In addition, neither we nor Northwest 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 $610.0 million per occurrence and in the aggregate annually and a deductible of $2.0 million per occurrence. This insurance covers Williams’ and its affiliates’, including our and Northwest’s, 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 $135.0 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 $25.0 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 or Northwest are not fully insured, it could adversely affect Northwest’s or our operations and financial condition. We or Northwest 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 or Northwest may elect to self insure a portion of our asset portfolio. We cannot assure you that we or Northwest will in the future be able to obtain the levels or types of insurance we or Northwest would otherwise have obtained prior to these market changes or that the insurance coverage we or Northwest 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 Northwest’s and our business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

Northwest’s assets and the assets of its customers and others may be targets of terrorist activities that could impact its business or cause significant harm to its operations, such as full or partial disruption to its 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 repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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.

We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition the Financial Accounting Standards Board, or FASB, the SEC, or FERC could enact new accounting standards or issue orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which could have an adverse effect on our business and would likely cause the market price of our common units to decline materially.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future or comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, beginning in 2008, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm annually to attest to, our internal control over financial reporting. Any failure to develop, implement or maintain effective internal controls, or any failure to improve our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls would subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and could cause the market price of our common units to decline materially.

Risks Inherent in an Investment in Us

Williams controls our general partner, which has sole responsibility for conducting our business and managing our operations. Williams, our general partner, and their respective affiliates have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of our unitholders.

Williams owns and controls our general partner, and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and its affiliates, including Williams Partners’ general partner. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner and Williams Partners, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include the following situations:


	•	neither our partnership agreement nor any other agreement requires Williams to pursue a business strategy that favors us. Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to our interests;

	•	all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Partners’ general partner, and these persons will also owe fiduciary duties to those entities;

	•	our general partner is allowed to take into account the interests of parties other than us, such as Williams and its affiliates, in resolving conflicts of interest;

	•	Williams owns the remaining 65% general partnership interest in Northwest;

	•	Williams owns general partner units representing a 2% general partner interest, the incentive distribution rights and common and subordinated units representing an aggregate 45.7% limited partner interest in us, and if a vote of limited partners is required, Williams will be entitled to vote its units in accordance with its own interests, which may be contrary to our interests or your interests;

	•	the limited partner interests that Williams will own initially will permit it to effectively control any votes of our limited partners;

	•	Williams and its affiliates, including Williams Partners, are not limited in their ability to compete with Northwest or us. Neither Williams nor Williams Partners is obligated to offer business opportunities to Northwest or us or to offer, contribute, or sell additional assets or operations to Northwest or us;

	•	our general partner may make a determination to receive a quantity of our Class B common units and additional general partner units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders;

	•	all of the executive officers and certain of the directors of our general partner will devote significant time to the business of Williams and/or Williams Partners, and will be compensated by Williams for the services rendered to them;

	•	pursuant to our partnership agreement, our general partner has limited its liability and defined its fiduciary duties in ways that are protective of it as compared to liabilities and duties that would be imposed upon a general partner under Delaware law in the absence of such limitations and definition. Our partnership agreement also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under Delaware common law. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;


	•	our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

	•	our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders, including distributions on our subordinated units, and to our general partner in respect of the incentive distribution rights, as well as the ability of the subordinated units to convert to common units;

	•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

	•	in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

	•	our partnership agreement permits us to classify up to $25 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources the distribution of which would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

	•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf;

	•	our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

	•	our general partner may exercise its limited right to call and purchase all common units not owned by it and its affiliates if they own more than 75% of the common units;

	•	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

	•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The credit and risk profile of our general partner and its owner, Williams, could adversely affect our or Northwest’s credit ratings, which could increase our or Northwest’s borrowing costs or hinder our or Northwest’s ability to raise capital.

The credit and business risk profiles of our general partner and Williams may be factors considered in credit evaluations of us and Northwest. This is because Williams, through our general partner, controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. A decline in Williams’ credit rating, such as occurred in 2002, would adversely affect Northwest and us.

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner, Northwest or Williams, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of Williams and its affiliates because of their ownership interest in and control of us and the strong operational links between Williams, Northwest and us. If Williams’ debt levels adversely impact our or Northwest’s credit rating, it would increase our or its cost of borrowing or hinder our or its ability to raise financing in the capital markets, which would impair our or its ability to grow our or its business and make distributions.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. The limitation and definition of these duties is permitted by the Delaware law governing limited partnerships. In addition, our partnership agreement restricts the remedies available to holders of our limited partner units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights, the exercise of its reset rights with respect to our incentive distribution levels, and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

	•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner or the conflicts committee of its board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

In addition, the general partnership agreement of Northwest contains similar provisions that limit the duties of each partner to the other and to Northwest. To the maximum extent permitted by Delaware law, the Northwest general partnership agreement also provides that the members of the management committee only owe fiduciary duties to the partner that appointed them.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. The fiduciary duties of the general partners of Northwest are similarly restricted.

Affiliates of our general partner, including Williams and Williams Partners, are not limited in their ability to compete with Northwest or us. Williams is also not obligated to offer us the opportunity to acquire additional assets or businesses from it, which could limit our commercial activities or our ability to grow. In addition, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Partners’ general partner, and these persons will also owe fiduciary duties to those entities.

Neither our partnership agreement nor the omnibus agreement among us, Williams, and certain affiliates of Williams will prohibit affiliates of our general partner, including Williams, Williams Partners and their respective affiliates, from owning assets or engaging in businesses that compete directly or indirectly with Northwest or us. In addition, Williams, Williams Partners, and their respective affiliates may acquire, construct or dispose of additional natural gas transportation or storage assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Williams may also choose to offer assets to its other affiliates, including Williams Partners, instead of us. Furthermore, all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Partners’ general partner and will owe fiduciary duties to those entities as well as our unitholders and us.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Williams and not by the unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, if the unitholders become dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units, and your common units will be subject to redemption at a price that may be below the then-current market price.

We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If you do not meet the requirements to be an Eligible Holder, you will not be entitled to receive distributions or allocations of income and loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price and the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner may elect to cause us to issue Class B common units and additional general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of its board of directors or the holders of our common units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right to reset the minimum quarterly distribution and the initial target distribution levels upon which the incentive distributions payable to our general partner are based at higher levels based on our cash distribution for the two quarters prior to the exercise of the reset election. Following a reset election by our general partner, the new minimum quarterly distribution amount and target distribution levels will be higher than they were prior to the reset such that incentive distributions to our general partner will be reduced or eliminated until cash distributions per common unit following the reset increase. Our general partner may initially exercise its right to reset the minimum quarterly distribution and target distribution levels at a time when there are no subordinated

units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B common units and additional general partner units. The Class B common units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. Our general partner will be issued the number of Class B common units such that the aggregate cash distribution to be received by our general partner with respect to the newly issued Class B common units and any retained incentive distribution rights immediately following the reset is equivalent to the average of the cash distributions received by our general partner with respect to its incentive distribution rights for the two consecutive fiscal quarters prior to the reset. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such exercise. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B common units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new Class B common units to our general partner in connection with resetting the target distribution levels.

Cost reimbursements to our general partner and its affiliates for services provided to us, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to you.

We will reimburse our general partner and its affiliates, including Williams, for various general and administrative services they provide for our benefit, including costs for rendering administrative staff and support services to us, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Even if unitholders are dissatisfied, they cannot initially remove our general partner without its consent.

If you are dissatisfied with the performance of our general partner, you will initially have effectively no ability to remove our general partner. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. Our general partner owns 46.7% of our outstanding common and subordinated units. Accordingly, our unitholders will initially be unable to remove our general partner without its consent because our general partner will own sufficient units to be able to prevent its removal. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. In addition, under certain circumstances the successor general partner may be required to purchase the combined general partner interest and incentive distribution rights of the removed general partner, or alternatively, such interests will be converted into common units. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

Cause is narrowly defined in our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence, or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period.

We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.

We are a partnership holding company and our operating company owns our only significant asset, which is our 35% general partnership interest in Northwest. We have no significant assets other than our 100% ownership of our operating company, and its 35% general partnership interest in Northwest. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws, and other laws and regulations, including FERC policies.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the member or members of our general partner to transfer its or their members’ interests in our general partner to a third party. The new owner or owners of our general partner would then be in a position to replace the board of directors and officers of the general partner with their own choices and to control the decisions taken by the board of directors and officers of the general partner. This effectively permits a “change of control” of the partnership without your vote or consent. In addition, pursuant to the omnibus agreement with Williams, any new owner of the general partner would be required to change our name so that there would be no further reference to Williams.

Increases in interest rates may cause the market price of our common units to decline.

In recent years, the United States credit markets experienced 50-year record lows in interest rates. If the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation risk. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt to make acquisitions or for other purposes.

We may issue additional units without your approval, which would dilute your ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:


	•	each existing unitholder’s proportionate ownership interest in us will decrease;

	•	the amount of cash available for distribution on each unit may decrease;

	•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

	•	the ratio of taxable income to distributions may increase;


	•	the relative voting strength of each previously outstanding unit may be diminished; and

	•	the market price of the common units may decline.

Our general partner may sell units in the public or private markets, which sales could have an adverse impact on the trading price of the common units.

Our general partner holds an aggregate of 4,700,668 common units and 10,957,900 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of any of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 75% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934. Our general partner owns approximately 20.8% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our general partner will own approximately 46.7% of our outstanding common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:


	•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the market price of our common units and could have a material adverse effect on our business.

Our initial asset is a 35% general partnership interest in Northwest. If this general partnership interest were to be deemed an “investment security” within the meaning of the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Although general partner interests are typically not considered securities or “investment securities,” there is a risk that our general partnership interest in Northwest could be deemed an investment security. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events could have an adverse effect on our business and would cause the market price of our common units to decline materially.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result we would pay federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. As a result, treatment of us as an investment company would result in a material reduction in distributions to you, which would materially reduce the value of our common units.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by states and localities. If the IRS were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state or local tax purposes, the amount of cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35%, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses,

deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d). It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units. In addition, because of widespread state budget deficits and other reasons, at least one state (in which Northwest does not operate) has imposed entity-level taxation on partnerships and other states may be evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

We prorate our items of income, gain, loss and deduction between transferors and transferees of the units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

The tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if our common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, regardless of

whether such amount represents gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. In addition, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, because the costs of any contest with the IRS will reduce our cash available for distribution, the costs will be borne indirectly by our unitholders.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, and other retirement plans, and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss allocated to you. It also could affect the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholders’ taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If we are treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

You will likely be subject to state and local taxes and return filing requirements in states or localities where you do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business indirectly in Colorado, Idaho, New Mexico, Oregon, Utah, Washington and Wyoming. Each of these states, other than Washington and Wyoming, currently imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax or an entity level tax. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.


Item 1B.	*Unresolved Staff Comments*

None.


Item 3.	*Legal Proceedings*

The information called for by this item is provided in Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to the Consolidated Financial Statements — Note 3. Contingent Liabilities and Commitments — Legal Proceedings,” which information is incorporated into this Item 3 by reference.


Item 4.	*Submission of Matters to a Vote of Security Holders*

None.

PART II


Item 5.	*Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.*

Use of Proceeds

On January 17, 2008, we commenced the initial public offering of 16,250,000 of our common units at a price to the public of $20.00 per unit. The offering was made pursuant to the registration statement on Form S-1 (File No. 333-146015) we filed with the Securities Exchange Commission, which was declared effective on January 17, 2008. The managing underwriters included Lehman Brothers Inc., Citigroup Global Markets Inc., and Merrill Lynch, Pierce, Fenner & Smith, Incorporated. The sale of 16,250,000 common units was completed on January 24,

2008. On February 15, 2008, underwriters exercised their option to purchase an additional 1,650,000 common units, which sale was completed on February 24, 2008. The aggregate proceeds to WMZ from the offering were approximately $335.3 million reflecting gross proceeds of $358 million, net of underwriting discounts and structuring fees of approximately $22.8 million. During January 2008, the partnership used a portion of the proceeds to pay $300.9 million to purchase a 15.9% general partnership interest in Northwest. In February 2008, the partnership used approximately $31 million to redeem 1,650,000 common units held by the General Partner in accordance with the terms of the Contribution Conveyance and Assignment Agreement entered into by the partnership in connection with the closing of the initial public offering. The partnership intends to use the remaining proceeds to pay $3.4 million of expenses associated with the initial public offering and related formation transactions.

Market Information, Holders and Distributions

Our common units are listed on the New York Stock Exchange under the symbol “WMZ.” At the close of business on February 27, 2008, there were 22,605,688 common units outstanding, held by approximately 5 record holders and over 400 beneficial holders, including common units held in street name and by affiliates of Williams.

As of February 27, 2008, there were 10,957,900 subordinated units outstanding held by a subsidiary of Williams. The subordinated units are not publicly traded.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2008, we distribute all of our available cash to unitholders of record on the applicable record date Available cash, for any quarter, consists of all cash on hand at the end of that quarter:


	•	less the amount of cash reserves established by our general partner to:


	•	provide for the proper conduct of our business, including necessary maintenance capital expenditures;

	•	comply with applicable law, any of our debt instruments or other agreements; or

	•	provide funds for distribution to our unitholders and to our general partner for any one or more of the next four quarters;


	•	plus, all cash on hand on the date of determination resulting from cash received after the end of that quarter in respect of our ownership interest in Northwest and attributable to its operations during that quarter; and

	•	plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter. Working capital borrowings are generally borrowings that are made under a credit agreement or another arrangement, are used solely for working capital purposes or to pay distributions to unitholders and are intended to be repaid within twelve months.

Initially, our general partner will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus in excess of $0.2875 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on common or subordinated units that it owns.

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Upon the closing of our IPO, our general partner received an aggregate of 10,975,900 subordinated units. During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.2875 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash to pay the minimum quarterly distribution on the common units.

Except as described below the subordination period will extend until the first business day of any quarter beginning after December 31, 2010 that each of the following tests are met: (i) distributions of available cash from operating surplus on the outstanding common units, subordinated units and general partner units equaled or exceeded the sum of the minimum quarterly distributions for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date; (ii) the “adjusted operating surplus” (as defined in our partnership agreement) for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units and the related distributions on the general partner units during those periods on a fully diluted basis; and (iii) there are no arrearages in payment of the minimum quarterly distribution on the common units.

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day following the distribution of available cash to partners in respect of any quarter that each of the following tests are met: (i) distributions of available cash from operating surplus on the outstanding common units, subordinated units and general partner units equaled or exceeded $1.725 (150% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding such date; (ii) the “adjusted operating surplus” (as defined in our partnership agreement) for the four-quarter period immediately preceding that date equaled or exceeded $1.725 (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units and the related distributions on the general partner units during that period on a fully diluted basis; and (iii) there are no arrearages in payment of the minimum quarterly distribution on the common units.

If the unitholders remove the general partner without cause, the subordination period may also end before December 31, 2010.

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner: first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, in the manner described in our partnership agreement.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels. If for any quarter we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution, then our

partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:


	•	first, 98% to all common and subordinated unitholders, pro rata, and 2% to our general partner, until each common and subordinated unitholder receives a total of $0.330625 per unit for that quarter, or the first target distribution;

	•	second, 85% to all common and subordinated unitholders, pro rata, and 15% to our general partner, until each common and subordinated unitholder receives a total of $0.359375 per unit for that quarter, or the second target distribution;

	•	third, 75% to all common and subordinated unitholders, pro rata, and 25% to our general partner, until each common and subordinated unitholder receives a total of $0.431250 per unit for that quarter, or the third target distribution; and

	•	thereafter, 50% to all common and subordinated unitholders, pro rata, and 50% to our general partner.

Securities Authorized for Issuance Under Equity Compensation Plans

As of December 31, 2007, the partnership had no securities authorized for issuance under equity compensation plans. In connection with the IPO, the board of directors of the general partner adopted the Williams Pipeline GP LLC Long Term Incentive Plan, under which awards for 2,000,000 units may be granted.


Item 6.	*Selected Financial and Operating Data*

The following tables show (i) selected financial data of Williams Pipeline Partners Predecessor (which reflects a 35% ownership interest in Northwest) and (ii) selected financial and operating data of Northwest. The following financial data as of December 31, 2007 and 2006, and for the years ended December 31, 2007, 2006 and 2005 was derived from financial statements included herein. All other amounts have been prepared from financial statements not included herein. The information in this selected Financial and Operating Data should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information concerning significant trends in the financial condition and results of operations.

Williams Pipeline Partners Predecessor


	Year Ended December 31,
	2007		2006		2005		2004		2003
	(Thousands of dollars)

Income Statement Data:
Equity earnings from investment in Northwest	$	153,904	$	19,062	$	24,141	$	25,891	$	24,714
Net income		153,904		19,062		24,141		25,891		24,714
Balance Sheet Data (at period end):
Investment in Northwest		414,966		300,281		264,721		258,080		253,054
Total partners’ capital		414,966		300,281		264,721		258,080		253,054

Northwest (100%)


	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 Partners’ 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 Northwest is a wholly-owned subsidiary of Williams at December 31, 2007 and for all periods presented.


(A)		Through September 30, 2007, Northwest 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 Northwest’s assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following Northwest’s conversion to a general partnership on October 1, 2007, Northwest is no longer subject to income tax. On October 1, 2007, Northwest reversed to income deferred income tax liabilities of approximately $311.8 million and $10.2 million of deferred income tax assets to comprehensive income.

(B)		Northwest’s 1983 acquisition by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to Northwest’s assets and liabilities, based on their estimated fair values at the time of the acquisition. The purchase price allocation was not pushed down to Northwest, as FERC policy does not permit Northwest to recover these amounts through its rates and Northwest had not been required to reflect Williams’ purchase price allocations in its financial statements. Beginning December 31, 2007, Northwest has elected to include Williams’ purchase price allocations in its financial statements. Accordingly, Northwest’s 2006, 2005, 2004 and 2003 selected financial data has been restated to include the effects of Williams’ excess purchase price allocation. A reconciliation between Northwest’s previously reported amounts and their restated amounts follow:


	Year Ended December 31,
	2006			2005			2004			2003
	(Thousands of dollars)

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*

Overview

We are a growth-oriented Delaware limited partnership recently formed by Williams to own and operate natural gas transportation and storage assets. Effective January 24, 2008 we own a 35% general partnership interest in Northwest, a subsidiary of Williams that owns an approximate 3,900-mile, bi-directional, interstate natural gas pipeline system that extends from the San Juan Basin in New Mexico, through the Rocky Mountains and to the Northwestern United States. Northwest also has working natural gas storage capacity of approximately 12.6 Bcf. The remaining 65% general partnership interest in Northwest is owned by a subsidiary of Williams.

Our general partnership interest in Northwest is our only asset. As a result, we are dependent on Northwest for substantially all of our cash available for distribution and the management’s discussion and analysis of financial condition and results of operations contained herein is primarily focused on Northwest.

How We Evaluate Our Operations

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


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

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

	•	Northwest’s operating expenses; and

	•	our and Northwest’s estimated cash available for distribution.

Long-Term Firm Service

Northwest competes for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. To the extent Northwest’s customers believe that Northwest can offer these services at rates, terms and conditions, which are more attractive than those of its competition, they will be more inclined to purchase Northwest’s services. Firm transportation service requires Northwest 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 whether the capacity is actually used. Northwest’s ability to maintain or increase the amount of long-term firm service it provides is key to assuring a consistent revenue stream.

Short-Term Firm and Interruptible Service

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

Northwest’s Operating Expenses

Northwest’s operating expenses typically do not vary significantly based upon the amount of natural gas it transports. While expenses may not materially vary with throughput, the timing of Northwest’s spending during a year can be dictated by weather and customer demands. During the winter months, Northwest’s pipeline average throughput is higher. As a result, Northwest typically does 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. Northwest is also regulated by the federal government and certain state and local laws which can impact the activities it performs on its pipeline. Changes in these regulations or Northwest’s 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. Northwest has and other pipelines have incurred additional costs to meet these standards. Certain of Northwest’s markets are served by other interstate natural gas pipelines and Northwest needs to operate its system efficiently and reliably to effectively compete for transportation and storage services.

Our Cash Available for Distribution

We define our cash available for distribution as our net income, less equity earnings from investment in Northwest, plus a general and administrative expense credit and cash available for distribution from Northwest.

Northwest’s Cash Available for Distribution

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% 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.

Factors That Impact Northwest’s Business

The high percentage of Northwest’s 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. Northwest’s 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 its customers, competition and changes in regulatory requirements affecting its operations.

We believe the key factors that impact Northwest’s business are the supply of and demand for natural gas in the markets in which Northwest operates; Northwest’s 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 Northwest manages its operations and implements its long-term strategies.

Supply and Demand Dynamics

To effectively manage its business, Northwest monitors its 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-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, Northwest’s customers will face increasing competition from Mid-Continent and East Coast markets for Rocky Mountain natural gas supplies. As these supply dynamics shift, Northwest anticipates that it 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 Northwest’s customers’ overall demand for natural gas. As customer demand dynamics change, Northwest anticipates that it will create new services or capacity arrangements that meet their long-term requirements.

Customers

Northwest transports and stores 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. Northwest provides 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. Northwest’s customers use its 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. Northwest’s customer mix can vary over time and largely depends on the natural gas supply and demand dynamics in its markets.

Competition

Northwest’s 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 its 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, Northwest’s customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with Northwest’s 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 Northwest’s long-term firm contracts which could adversely affect its revenue over the long term. We believe the impact of the factors described in “— Customers” and “— Competition” above may also provide Northwest 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 Northwest’s system to maintain or possibly increase its transportation commitments and volumes.

Outlook

Northwest’s strategy to create value focuses on maximizing the contracted capacity on its pipeline by providing high quality, low cost natural gas transportation and storage services to its markets. Changes in commodity prices and volumes transported have little impact on revenues because the majority of its revenues are recovered through firm capacity reservation charges. Northwest grows its business primarily through expansion

projects that are designed to increase its access to natural gas supplies and to serve the demand growth in its markets.


	•	Colorado Hub Connection Project. Northwest has proposed installing a new lateral to connect the proposed White River Hub near Meeker, Colorado to Northwest’s 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 begin service as early as November 2009. Northwest has proposed combining 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 of capacity 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.

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 Northwest’s Pacific Northwest customers. Northwest has 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 CHC Project remains subject to certain conditions, including the necessary regulatory approvals. If Northwest does not proceed with the CHC Project, or is otherwise unable to resell any portion of the Pan-Alberta capacity, Northwest will seek recovery of any shortfall in annual capacity reservation revenues from its remaining customers in a future rate proceeding. If the CHC Project proceeds, Northwest expects 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.


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

As a one-third owner of Jackson Prairie, Northwest held an open season for new firm storage service based on its 104 MMcf per day share of the planned 2008 deliverability expansion and its 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. Northwest’s one third share of the deliverability expansion is estimated to be $16 million. Northwest’s estimated capital cost for the capacity expansion component of the new storage service is $6.1 million, primarily for base natural gas.


	•	Sundance Trail Expansion. In February 2008, Northwest 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 Northwest’s existing Vernal


		compressor station. The project would utilize capacity on the proposed lateral to be constructed as part of Northwest’s CHC Project to access supplies in the Piceance Basin.

Northwest’s Operations

Northwest owns and operates 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. Northwest’s system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Its compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2007, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.4 Bcf of natural gas per day. Northwest also has approximately 12.6 Bcf of working natural gas storage capacity through its one-third interest in the Jackson Prairie underground storage facility, its ownership of the Plymouth LNG storage facility and contract storage at Clay Basin.

Transportation Services. Northwest’s transportation services consist primarily of 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 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. Northwest generates a small portion of its revenues from short-term firm and interruptible transportation services.

Northwest is 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 its results of operations. Northwest depends on the availability of competitively priced natural gas supplies which its customers desire to ship through its system. Northwest delivers natural gas to a broad mix of customers including LDCs, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers.

Storage Services. Northwest’s natural gas storage services allow it to offer customers a high degree of flexibility in meeting their delivery requirements and enable Northwest 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. Northwest offers 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.

Critical Accounting Policies, Estimates, Judgments and Sensitivities

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

Regulatory Accounting

Northwest’s 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, Northwest’s estimated risk-adjusted total exposure, market circumstances and other risks. Northwest’s current rates were approved pursuant to a rate settlement. As a result, its current revenues are not subject to refund.

the manner in which independent third-party regulators establish rates. In applying SFAS No. 71, Northwest capitalizes 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 — Northwest Pipeline GP Notes to Consolidated Financial Statements — Note 1. Summary of Significant Accounting Policies — Property, Plant and Equipment and Note 10. Regulatory Assets and Liabilities.

Contingencies

Northwest records 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

Northwest’s environmental liabilities are based on Northwest management’s best estimate of the undiscounted future obligation for probable costs associated with environmental assessment and remediation of Northwest’s 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. Northwest’s 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, FERC and other governmental authorities on these matters. Northwest continues to conduct environmental assessments and is implementing a variety of remedial measures that may result in increases or decreases in the total estimated environmental costs.

Impairment of Long-Lived Assets

Northwest evaluates 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 Northwest’s management 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

Northwest’s consolidated affiliate participates in employee benefit plans sponsored by 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 Northwest may be subject to possible refunds upon final orders in pending rate proceedings with the FERC. Northwest records estimates of rate refund liabilities considering its and other third party regulatory proceedings, advice of counsel, as well as collection and other risks. At December 31, 2007, Northwest had no rate refund liabilities.

Northwest’s Results of Operations

In the following discussion of the results of Northwest, all amounts represent 100% of the operations of Northwest, in which we hold a 35% general partnership interest following the completion of our initial public offering on January 24, 2008.

Analysis of Financial Results

This analysis discusses financial results of Northwest’s 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 Northwest’s rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in Northwest’s transportation rates.


	Year Ended December 31,
	2007			2006			2005
				(Restated)(A)			(Restated)(A)
	(Thousands of dollars)

Income Statement Data:
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)		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 for income taxes		(254,667	)		31,206			38,679

Net income	$	439,726		$	54,462		$	68,974


(A)		Northwest’s 1983 acquisition by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to Northwest’s assets and liabilities, based on their estimated fair values at the time of the acquisition. The purchase price allocation was not pushed


		down to Northwest, as FERC policy does not permit Northwest to recover these amounts through its rates and Northwest had not been required to reflect Williams’ purchase price allocations in its financial statements. Beginning December 31, 2007, Northwest has elected to include Williams’ purchase price allocations in its financial statements. Accordingly, Northwest’s 2006 and 2005 income statement has been restated to include the effects of Williams’ excess purchase price allocation.

2007 vs. 2006

Operating revenues increased $97.6 million, or 30%, for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Higher rates resulting from Northwest’s 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.

Northwest’s transportation service accounted for 96% of its operating revenues for each of the years ended December 31, 2007 and 2006. Natural gas storage service accounted for 3% of operating revenues for each of the years ended December 31, 2007 and 2006.

Operating expenses decreased $1.1 million, or 1%, from 2006 to 2007. This decrease was due primarily to the June 2007 reversal of Northwest’s pension regulatory liability of $16.6 million and a reduction of its accrued ad valorem taxes of $1.0 million to reflect lower 2007 tax assessments on its 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 Northwest’s 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 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%, from 2006 to 2007, due to the reasons discussed above.

Other income increased $8.8 million, or 53%, from 2006 to 2007, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million of additional contract termination income and $2.3 million of 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 and 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%, 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 $175.0 million of 7% senior unsecured notes, due 2016, in June of 2006, and the issuance of $185.0 million of 5.95% senior unsecured notes, due 2017, in April of 2007, partially offset by the early retirement of $175.0 million of 8.125% 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 $250.0 million of 6.625% senior unsecured notes with $250.0 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 Northwest’s conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, Northwest recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8% compared to 36.4% in 2006. At the date of conversion, Northwest recognized income tax benefit of $311.8 million reflecting the removal of its net deferred tax liabilities.

2006 vs. 2005

Operating revenues increased $2.8 million, or 1%, 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.

Northwest’s transportation service accounted for 96% of its operating revenues and Northwest’s gas storage service accounted for 3% of its operating revenues for each of the years ended December 31, 2006 and 2005.

Operating expenses increased $27.9 million, or 15%, 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 Northwest’s pipeline integrity and environmental assessment efforts and a change in FERC’s accounting policies requiring Northwest 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 its 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.

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

Other income increased $6.0 million, or 57%, 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%, 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% 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%, 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. Northwest’s effective income tax rate was 36.5% in 2006 and 35.9% in 2005.

Capital Resources and Liquidity of Northwest

Northwest’s ability to finance operations, including funding capital expenditures and acquisitions, to meet its indebtedness obligations, to refinance its indebtedness or to meet collateral requirements will depend on its ability to generate cash in the future and to borrow funds. Northwest’s ability to generate cash is subject to a number of factors, some of which are beyond its control, including the impact of regulators on its 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 Northwest’s partners as required by its general partnership agreement. Available cash with respect to any quarter is generally defined for Northwest 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.

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

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

Northwest’s 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


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

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

	•	Northwest retired $175 million of 8.125% senior unsecured notes due 2010.

	•	Northwest retired $250 million of 6.625% senior unsecured notes due 2007.

	•	Northwest paid distributions of $109.8 million to Williams.

2006


	•	Northwest issued $175 million aggregate principal amount of 7% senior unsecured notes due 2016.

	•	Northwest received a capital contribution of $65 million from Williams.

2005


	•	Northwest paid dividends of $50 million to Williams.

Investing Activities

2007


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

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

	•	Northwest 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.

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

Working Capital

Working capital is the amount by which current assets exceed current liabilities. Northwest’s 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 Northwest’s transportation and storage arrangements have a direct impact on Northwest’s 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 Northwest’s ability to fund its requirements for liquidity and capital resources.

On December 31, 2007 Northwest made a distribution of $30 million to its partners as of that date (who are affiliates of Williams), representing cash in excess of working capital requirements. Prior to the closing of the transactions contemplated by this prospectus, Northwest will distribute any additional cash in excess of its working capital requirements to its pre-closing partners, who are affiliates of Williams.

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

Short-Term Liquidity

Northwest funds its 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.

Northwest invests cash through participation in Williams’ cash management program. At December 31, 2007 and 2006, the advances due to Northwest 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% at December 31, 2007. Beginning in 2008, the interest rates on these demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29% at December 31, 2007.

Credit Agreement

Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012. Northwest has 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% per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $28.0 million, none of which are associated with Northwest, have been issued by the participating institutions and $250.0 million revolving credit loans, all associated with Northwest, were outstanding at December 31, 2007. In December 2007, Northwest borrowed $250.0 million under this agreement to repay $250.0 million in 6.625% senior notes at maturity. Northwest did not access the agreement in 2006. The interest rate at December 31, 2007 was 5.68%

The credit agreement contains a number of restrictions on the business of the borrowers, including Northwest. 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. Northwest and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in the case of Northwest, 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 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

Northwest has an effective shelf registration statement on file with the SEC. As of December 31, 2007, $150 million of availability remained under this registration statement. Northwest 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 Northwest’s 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.

Northwest categorizes its 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 Northwest’s 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. Northwest anticipates 2008 capital expenditures will be between $100 million and $125 million.

Northwest’s 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. Northwest 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. Its new rates became effective January 1, 2007.

Contractual Obligations

The table below summarizes the maturity dates of Northwest’s 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)(4)		1.5		3.3		3.0		—		7.8

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


(1)		Does not include Northwest’s estimated contributions to the Williams’ sponsored pension and other postretirement benefit plans. Northwest 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 “Item 8. Financial Statements and


		Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements — Note 5. Employee Benefit Plans”). The decrease in the estimated contributions from 2006 and 2005 levels can be attributed to Northwest’s previous contributions to the other postretirement benefit plans. There were no minimum funding requirements to the tax-qualified pension plans in 2007, 2006 or 2005. Northwest anticipates 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, Northwest may elect to make contributions to increase the funded status of the plans.

(2)		Does not include estimated settlement of asset retirement obligations. See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements — Note 9. Asset Retirement Obligations.

(3)		Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements — Note 10. Regulatory Assets and Liabilities.

Off-Balance Sheet Arrangements

Neither we nor Northwest have any guarantees of off-balance sheet debt to third parties and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in Williams’ or Northwest’s credit ratings given by Moody’s Investors Service, Standard and Poor’s and Fitch Ratings.

Impact of Inflation

Northwest generally has 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 Northwest’s 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, Northwest believes it 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 its 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, Northwest is subject to extensive federal, state and local environmental laws and regulations which affect its operations related to the construction and operation of its pipeline facilities. Northwest considers 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, Northwest has been permitted recovery of environmental costs incurred, and it is Northwest’s intent to continue seeking recovery of such costs, as incurred, through rate filings.

Safety Matters

Pipeline Integrity Regulations

Northwest has developed an Integrity Management Plan that it believes 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, Northwest has identified high consequence areas and completed its baseline assessment plan. Northwest is on schedule to complete the required assessments within specified timeframes. Currently, Northwest

estimates 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. Northwest’s 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 its rates.

Legal Matters

Northwest is party to various legal actions arising in the normal course of business. Northwest’s management believes that the disposition of outstanding legal actions will not have a material adverse impact on its future financial condition.

Regulatory Proceedings

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

Liquidity and Capital Resources of Williams Pipeline Partners L.P.

Our principal sources of liquidity include cash distributed to us by Northwest and our working capital credit agreement with Williams as the lender. We expect to fund our operating expenses, debt service and cash distributions primarily with distributions from Northwest.

At January 24, 2008, we entered into a $20 million working capital credit agreement with Williams as the lender. The facility will be available exclusively to fund working capital borrowings. The initial maturity date of the facility will be the 365th day following the effective date of the agreement but may be extended for another 365-day period upon notice as provided in the agreement. Borrowings under the agreement will bear interest at the same rate as for borrowings under the Williams credit agreement described above in “— Liquidity and Capital Resources of Northwest — Credit Agreement.” We will pay a commitment fee to Williams on the unused portion of the credit agreement of 0.25% annually. We will be required to reduce all borrowings under our working capital credit agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the facility.

We expect to fund our expansion capital expenditures primarily through commercial borrowings or the sale of debt or equity securities.

We will invest cash through participation in Williams’ cash management program. The advances will be represented by one or more demand obligations. The interest rate on the demand notes will be based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 1.29% at December 31, 2007.


Item 7A.	*Qualitative and Quantitative Disclosures About Market Risk*

Interest Rate Risk

Our interest risk indirectly includes Northwest’s long-term debt. All of Northwest’s interest on long-term debt is fixed in nature, except the interest on Northwest’s revolver borrowing, 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

		695,000
Unamortized debt discount		1,264

Total long-term debt	$	693,736


(1)		Interest rate was 5.68% 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% per annum) based on the unused portion of the agreement. The applicable margin and commitment fee are based on Northwest’s senior unsecured long-term debt ratings.

Northwest’s 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 Northwest’s long-term debt was 6.3%. Northwest expects to have sensitivity to interest rate changes with respect to future debt facilities, its ability to prepay existing facilities and on the variability of cash flows for interest payments on the revolver borrowings.

Credit Risk

Northwest is, and therefore 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 and Northwest’s 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 Northwest to them generally under its parking and lending services and no-notice services. Northwest maintains credit policies intended to minimize credit risk and actively monitor these policies.

Market Risk

Northwest’s 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, Northwest’s contracts generally continue on a year to year basis, but are subject to termination by its customers. In the event of termination, Northwest may not be able to obtain replacement contracts at favorable rates or on a long-term basis.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Pipeline GP LLC

We have audited the accompanying balance sheets of Williams Pipeline Partners Predecessor (Predecessor) as of December 31, 2007 and 2006, and the related statements of income, owner’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of Williams Pipeline Partners L.P.’s management. Our responsibility is to express an opinion on these financial statements 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 Predecessor’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 Predecessor’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 financial position of Williams Pipeline Partners Predecessor at December 31, 2007 and 2006, and the results of its operations and cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

Ernst & Young LLP

Houston, Texas

February 26, 2008

WILLIAMS PIPELINE PARTNERS PREDECESSOR

STATEMENTS OF OWNER’S EQUITY AND COMPREHENSIVE INCOME


	Year Ended December 31,
	2007			2006			2005
	(Thousands of dollars)

Owner’s equity at beginning of period	$	300,281		$	264,721		$	258,080
In-kind capital contribution from parent		—			22,750			—
In-kind dividends		(38,420	)		—			(17,500	)
Net Income		153,904			19,062			24,141
Other comprehensive income Gain (loss) on cash flow hedges, net of reclassification adjustments		(22	)		126			—
Pension benefits:
Amortization of prior service cost		27			—			—
Amortization of net actuarial gain		670			—			—
Net actuarial gain arising during the period		2,293			—			—
Elimination of deferred income taxes		(3,767	)		—			—

Total comprehensive income		153,105			19,188			24,141
Adjustment to initially apply SFAS No. 158:
Pension benefits, net of tax:
Prior service cost		—			(107	)		—
Net actuarial loss		—			(6,271	)		—

Total owner’s equity at end of period	$	414,966		$	300,281		$	264,721

See notes to financial statements

WILLIAMS PIPELINE PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS


1.	Description of Business and Basis of Presentation

Williams Pipeline Partners Predecessor (Predecessor) is the predecessor entity to Williams Pipeline Partners L.P. (the Partnership), which was formed on August 31, 2007 and which owns the operations and assets of the Company, as further described below. The Predecessor is engaged in the transportation and storage of natural gas through pipeline systems that serve the western United States.

Effective January 24, 2008, the Partnership acquired a 35% ownership interest in Northwest Pipeline GP (Northwest), formerly Northwest Pipeline Corporation, in connection with the Partnership’s initial public offering (IPO) of common units. In this report, Northwest Pipeline GP and its consolidated affiliate, Northwest Pipeline Services LLC are referred to as Northwest.

The Predecessor’s sole asset is a 35% ownership interest in Northwest, for the periods presented in these financial statements. Northwest owns and operates an interstate pipeline system for the 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. The remaining 65% interest of Northwest is held indirectly by The Williams Companies, Inc. (Williams).

The financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the basis of the Predecessor’s historical 35% ownership of Northwest. Accordingly, the historical financial statements for the Predecessor, as the financial statement predecessor to the Partnership, reflect the inclusion of the 35% investment in Northwest using the equity method of accounting. These financial statements have been prepared from the books and records of Northwest and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during those periods.

The acquisition of Northwest in 1983 by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to Northwest’s assets and liabilities, based on their estimated fair values at the time of the acquisition. The purchase price allocation was not pushed down to Northwest. Beginning December 31, 2007, Northwest has elected to include the Williams’ purchase price allocations in their financial statements. Accordingly, Northwest’s 2006 and 2005 financial statements have been restated to include the effects of Williams’ excess purchase price allocation. The financial statements of the Predecessor reflect our 35% interest in Northwest, including the effects of purchase accounting, for all periods presented.


2.	Summary of Significant Accounting Policies

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.

Equity Method Investments. The Predecessor accounts for investments in 20% to 50% owned affiliates, and in less than 20% owned affiliates where the Predecessor has the ability to exercise significant influence, under the equity method.

Impairment of Investments. We evaluate our investments for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.

WILLIAMS PIPELINE PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)

Income Taxes. With the January 2008 initial public offering of the Partnership, our operations are treated as a partnership with each partner being separately taxed on its share of our taxable income. Therefore, we have excluded income taxes from these financial statements.


3.	Investment in Northwest

Investment in Northwest at December 31, 2007 and 2006 represents our 35% ownership interest in Northwest. The summarized financial position and results of operations for 100% of Northwest are presented below.


	2007			2006		2005
				(Restated)(B)		(Restated)(B)
	(Thousands of dollars)

Balance Sheet Data (at end of period):
Current assets	$	117,792		$	121,408
Noncurrent assets		1,938,679			1,927,916
Current liabilities		92,130			376,044
Noncurrent liabilities		778,725			815,335

Owner’s equity	$	1,185,616		$	857,945

Income Statement Data:
Operating revenues	$	421,851		$	324,250	$	321,457
Operating expenses		211,122			212,263		184,377

Operating income		210,729			111,987		137,080
Other income — net		25,437			16,597		10,597
Interest charges		51,107			42,916		40,024

Income before income taxes		185,059			85,668		107,653
Provision for income taxes		(254,667	)(A)		31,206		38,679

Net income	$	439,726		$	54,462	$	68,974


(A)		Through September 30, 2007, Northwest 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 Northwest’s assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following Northwest’s conversion to a general partnership on October 1, 2007, Northwest is no longer subject to income tax. On October 1, 2007, Northwest 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)		Northwest’s 1983 acquisition by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to Northwest’s assets and liabilities, based on their estimated fair values at the time of the acquisition. The purchase price allocation was not pushed down to Northwest, as FERC policy does not permit Northwest to recover these amounts through its rates and Northwest has not been required to reflect Williams’ purchase price allocations in its financial statements. Beginning December 31, 2007, Northwest has elected to include Williams’ purchase price allocations in its financial statements. Accordingly, Northwest’s 2006 and 2005 financial statements have been restated to include the effects of Williams’ excess purchase price allocation. A reconciliation between Northwest’s previously reported amounts and their recast follows:

WILLIAMS PIPELINE PARTNERS PREDECESSOR

NOTES TO FINANCIAL STATEMENTS — (Continued)


	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, plant 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, plant and equipment, net of income taxes		44,908

Equity, as restated	$	857,945


4.	Owner’s Equity and Comprehensive Income

In-kind capital contributions and dividends reflected in our Statements of Owner’s Equity and Comprehensive Income represent cash capital transactions that occurred between Northwest and Williams, and had the effect of increasing or decreasing the carrying value of our investment in Northwest.

In September 2006, the Financial Statements Accounting Board, or FASB, issued Statement of Financial Accounting Standards, or SFAS, No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158). This Statement requires sponsors of defined benefit pension and other postretirement benefit plans to recognize the funded status of their pension and other postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. On December 31, 2006, Northwest adopted the recognition and disclosure provisions of SFAS No. 158 related to its participation in Williams’ sponsored pension and other postretirement benefit plans. In accordance with SFAS No. 158, we recorded adjustments to accumulated other comprehensive loss, net of income taxes, to recognize our 35% share of Northwest’s funded status related to the Williams’ sponsored pension plans.

On October 1, 2007, Northwest converted from a Delaware corporation to a general partnership. Upon conversion to a general partnership, Northwest reversed all deferred tax assets and liabilities and will no longer be subject to income taxes. The impact to our financial statements was an increase to equity earnings from investment in Northwest of $109.1 million, and a decrease to other comprehensive income of $3.8 million.

We also record our 35% interest in any gain or loss on Northwest’s cash flow hedges as an increase or decrease to other comprehensive income.


5.	Deferred Costs

As of December 31, 2007, an affiliate of the Predecessor had incurred $1.7 million of offering and related formation expenses on behalf of the Predecessor. At December 31, 2007, the Predecessor recorded these costs to deferred assets and recorded a payable to the affiliate. These deferred costs will be reversed in 2008 and recorded as a reduction to owner’s equity when the transactions for the IPO are recorded.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Pipeline GP LLC

We have audited the accompanying balance sheet of Williams Pipeline Partners L.P. as of December 31, 2007. This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Oversight Accounting Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit 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 balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of Williams Pipeline Partners L.P. at December 31, 2007 in conformity with U.S. generally accepted accounting principles.

Ernst & Young LLP

Houston, Texas
February 26, 2008

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO BALANCE SHEET


1.	Nature of Operations

Williams Pipeline Partners L.P. (the Partnership) is a Delaware limited partnership formed on August 31, 2007 to own and operate natural gas transportation and storage assets, including a minority ownership interest in Northwest Pipeline GP, formerly Northwest Pipeline Corporation (Northwest).

On January 24, 2008, the Partnership completed its initial public offering (IPO) of 16,250,000 common units representing limited partner interest in the Partnership. Concurrent with the closing of the IPO, (i) the public through the underwriters of the offering contributed $305.5 million to the Partnership in exchange for 16,250,000 common units representing a 47.5% limited partner interest in us, (ii) the Partnership purchased from Northwest a 15.9% general partnership interest in Northwest, and (iii) a 19.1% interest in Northwest was contributed to the Partnership by Williams Pipeline GP LLC, our general partner, in exchange for 6,350,668 common units, 10,957,900 subordinated units, 684,869 units representing a 2% general partner interest in us, and all of the Partnership’s incentive distribution rights. On February 21, 2008 the underwriters of the offering purchased 1,650,000 common units from the Partnership pursuant to their right to purchase additional common units from us to cover over-allotments. Concurrently with the purchase of the additional shares by the underwriters, the Partnership redeemed 1,650,000 common units held by the Partnership’s general partner. After the closing of the IPO the Partnership owns a 35% general partnership interest in Northwest. The remainder of the interest in Northwest is owned by Williams Gas Pipeline, a wholly owned subsidiary of The Williams Companies, Inc (Williams). Williams, through its subsidiary, Williams Pipeline GP LLC, owns a 2% general partner interest and a 45.7% limited partner interest in the Partnership as of February 27, 2008. The Partnership intends to conduct its activities through a wholly owned operating company.

Williams Pipeline GP LLC, as general partner, contributed $20 and Williams Pipeline Services Company, an indirect wholly owned subsidiary of Williams, as the organizational limited partner, contributed $980, all in the form of notes receivable to the Partnership on August 31, 2007. The receivables from Williams Pipeline Services Company and Williams Pipeline GP LLC have been reflected as a deduction from partners’ equity on the accompanying balance sheet. There have been no other transactions involving the Partnership as of December 31, 2007, other than the incurrence of deferred costs described in Note 2.


2.	Deferred Costs

As of December 31, 2007, an affiliate of the Partnership had incurred $1.7 million of offering and related formation expenses on behalf of the Partnership. At December 31, 2007, the Partnership recorded these costs to deferred assets and recorded a payable to the affiliate. These deferred costs will be credited in 2008 and recorded as a reduction to partners’ equity when the transactions for the IPO are recorded.

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. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements 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.

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

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
	(Thousands of dollars)

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 DIVIDENDS	$	109,770		$	—		$	50,000

See notes to financial statements

NORTHWEST PIPELINE GP

CONSOLIDATED BALANCE SHEETS


	December 31,
	2007			2006
				(Restated)
	(Thousands of dollars)

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


LIABILITIES AND STOCKHOLDER’S 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 notes to financial statements

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
	(Thousands of dollars)

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, as restated		—			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, as restated		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 owners’ equity	$	1,185,616		$	857,945		$	756,346

See notes to financial statements

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2007			2006			2005
				(Restated)			(Restated)
	(Thousands of dollars)

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 payment		—			3,348			87,917
Proceeds from sale at 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 notes to financial statements

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 Pipeline Corporation (Northwest) was owned 11.6% by Williams Pipeline Partners Holdings LLC and 88.4% 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% interest in Northwest. Williams contributed 19.1% 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% interest, and Northwest in turn made a distribution to Williams of $300.9 million. After these transactions, Northwest is owned 35% by Williams Pipeline Partners L.P. and 65% by WGPC Holdings LLC. Through its ownership interests in each of our partners, Williams indirectly owns 81.7% 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 total exposure, market circumstances and

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:


	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.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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; 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%, 2.86% and 2.96% 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.

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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.

The composite rate used to capitalize AFUDC was approximately 9% for 2007 and approximately 10% 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% 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.

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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.

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 they 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.

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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.

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.

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

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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.

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.

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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)

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

Parachute Lateral 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, 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% to cover costs related to the operation of the lateral.


3.	CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui 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

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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.

Beginning in the mid-1980’s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl, or PCB, contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency 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

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.

Other Matters

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

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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.

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.

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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%. We are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, was approximately 36% at December 31, 2007.

Long-Term Debt

In June 2006, we issued $175 million aggregate principal amount of 7% 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% 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.

On April 5, 2007, we issued $185 million aggregate principal amount of 5.95% 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% 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% 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
7.00%, payable 2016		174,532		174,477
7.125%, payable 2025		84,797		84,785
8.125%, payable 2010		—		175,000
9.00%, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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% per annum) based on the unused portion of the agreement. The commitment fee is based on Williams’ senior unsecured long-term debt rating, while the applicable margin is based on the specific borrower’s senior unsecured long-term debt rating. 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% senior unsecured notes at maturity. We did not access the agreement in 2006. The interest rate on this debt was 5.68% 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%.

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

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.

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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
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% 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 subsidiaries that provide pension benefits for our 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 cost 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 liabilities included prior service costs of $3.2 million and net actuarial gains of $3.3 million related to other 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 market 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.


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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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%(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 a corporation to a 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

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% 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 these demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83% 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% 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

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 $31.6 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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:


	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 postemployment 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)


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 capital 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.


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

We did not conduct any operations prior to December 31, 2007. The 35% interest in Northwest Pipeline GP that is our sole asset was acquired by us after December 31, 2007. We performed an evaluation of the effectiveness of the design and operation of Northwest Pipeline GP’s and our own disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d — 15(e) of the Securities Exchange Act) (Disclosure Controls) as of December 31, 2007. Our evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner. That evaluation included review of Northwest Pipeline GP management’s review and evaluation of the effectiveness of the design and operation of its disclosure controls and procedures. Based upon our evaluation, our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, concluded that these Disclosure Controls are effective at a reasonable assurance level.

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that Disclosure Controls or internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by the rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Control 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, the internal controls over financial reporting.


Item 9B.	*Other Information*

None.

members of the Williams board of directors, including Mr. Malcolm, among others, under the Employee Retirement Income Security Act of 1974, or ERISA, by participants in Williams’ 401(k) plan.

Donald R. Chappel is chief financial officer and a director of our general partner. Mr. Chappel has served as senior vice president and chief financial officer of Williams since April 2003. Prior to joining Williams, Mr. Chappel, from 2000 to April 2003, founded and served as chief executive officer of a real estate leasing and development business in Chicago, Illinois. Mr. Chappel has more than thirty years of business and financial management experience with major corporations and partnerships. From 1987 though February 2000, Mr. Chappel served in various financial, administrative and operational leadership positions for Waste Management, Inc., including twice serving as chief financial officer, during 1997 and 1998 and most recently during 1999 through February 2000. Mr. Chappel has served as chief financial officer and director of Williams Partners GP LLC, the general partner of Williams Partners L.P., since 2005.

Phillip D. Wright is chief operating officer and a director of our general partner. Mr. Wright has served as senior vice president of Williams’ gas pipeline operations since January 2005. From October 2002 to January 2005, Mr. Wright served as chief restructuring officer of Williams. From September 2001 to October 2002, Mr. Wright served as president and chief executive officer of Williams Energy Services. From 1996 to September 2001, he was senior vice president, enterprise development and planning for Williams’ energy services group. Mr. Wright, from 1989 to 1996 served in various capacities for Williams. Mr. Wright served as president, chief operating officer and director of the general partner of Williams Energy Partners L.P. from the initial public offering in February 2001 of Williams Energy Partners L.P., now known as Magellan Midstream Partners, L.P., to the sale of Williams’ interests therein in June 2003.

James J. Bender is the general counsel of our general partner. Mr. Bender has served as senior vice president and general counsel of Williams since December 2002. From June 2000 until joining Williams, Mr. Bender was senior vice president and general counsel with NRG Energy, Inc. Mr. Bender was vice president, general counsel and secretary of NRG Energy from June 1997 to June 2000. NRG Energy filed a voluntary bankruptcy petition during 2003 and its plan of reorganization was approved in December 2003. Mr. Bender has served as general counsel of Williams Partners GP LLC, the general partner of Williams Partners L.P., since 2005.

Rodney J. Sailor is treasurer and a director of our general partner. Mr. Sailor served as vice president and treasurer of Williams since July 2005. From 2001 to 2005, he served as assistant treasurer for Williams. From 1985 to 2001, Mr. Sailor served in various capacities for Williams.

Stephen C. Beasley is a director of our general partner. Mr. Beasley served on the El Paso Corporation Executive Committee as president of the El Paso Eastern Pipeline Group from 2003 through 2007. Within the El Paso Eastern Pipeline Group, Mr. Beasley also served as chairman and president of each of Tennessee Gas Pipeline Company and ANR Pipeline Company. He is currently retired.

Emmitt C. House is a director of our general partner. Since 2000, Mr. House has been associated with the law firm of Gonzalez, Saggio & Harlan and has been a partner since 2003. Prior to that Mr. House served as General Counsel for a retail energy marketer of natural gas and electricity. Mr. House has significant experience in the regulated natural gas pipeline industry.

Governance

Our general partner adopted governance guidelines that address, among other areas, director independence standards, policies on meeting attendance and preparation, executive sessions of non-management directors and communications with non-management directors.

Director Independence

Because we are a limited partnership, the New York Stock Exchange does not require our general partner’s board of directors to be composed of a majority of directors who meet the criteria for independence required by the New York Stock Exchange or to maintain nominating/corporate governance and compensation committees composed entirely of independent directors.

Our general partner’s board of directors annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with our general partner (either directly or indirectly or as a partner, shareholder or officer of an organization that has a relationship with our general partner). In order to make this determination, our general partner’s board of directors broadly considers all relevant facts and circumstances and applies categorical standards from our governance guidelines, which are set forth below and also available on our Internet website at www.williamspipelinepartners.com under the “Investor Relations” caption. Under those categorical standards, a director will not be considered to be independent if:


	•	the director, or an immediate family member of the director, has received during any twelve-month period within the last three years more than $100,000 per year in direct compensation from our general partner, us, and any parent or subsidiary in a consolidated group with such entities (collectively, the “Partnership Group”), other than board and committee fees and pension or other forms of deferred compensation for prior service (provided such compensation is not contingent in any way on continued service). Neither compensation received by a director for former service as an interim chairman or chief executive officer or other executive officer nor compensation received by an immediate family member for service as an employee of the Partnership Group will be considered in determining independence under this standard.

	•	the director is a current employee, or has an immediate family member who is a current executive officer, of another company that has made payments to, or received payments from, the Partnership Group for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1.0 million, or 2% of the other company’s consolidated gross annual revenues. Contributions to tax exempt organizations are not considered “payments” for purposes of this standard.

	•	the director is, or has been within the last three years, an employee of the Partnership Group, or an immediate family member is, or has been within the last three years, an executive officer, of the Partnership Group. Employment as an interim chairman or chief executive officer or other executive officer will not disqualify a director from being considered independent following that employment.

	•	(i) the director or an immediate family member is a current partner of a present or former internal or external auditor for the Partnership Group, (ii) the director is a current employee of such a firm, (iii) the director has an immediate family member who is a current employee of such a firm and participates in such firm’s audit, assurance or tax compliance (but not tax planning) practice or (iv) the director or an immediately family member was within the last three years (but is no longer) a partner or employee of such a firm and personally worked on an audit for the Partnership Group within that time.

	•	if the director or an immediate family member is, or has been within the last three years, employed as an executive officer of another company where any of the Partnership Group’s present executive officers at the same time serves or served on that company’s compensation committee.

	•	if the board of directors determines that a discretionary contribution made by any member of the Partnership Group to a non-profit organization with which a director, or a director’s spouse, has a relationship, impacts the director’s independence.

Our general partner’s board of directors has affirmatively determined that each of Messrs. Beasley and House is an “independent director” under the current listing standards of the New York Stock Exchange and our categorical director independence standards. In doing so, the board of directors determined that each of these individuals met the “bright line” independence standards of the New York Stock Exchange. In addition, the board of directors considered relationships with our general partner, either directly or indirectly. The purpose of this review was to determine whether any such relationships or transactions were inconsistent with a determination that the director is independent. Because Messrs. Chappel, Malcolm, Wright and Sailor are employees, officers and/or directors of Williams, they are not independent under these standards.

Messrs. Beasley and House do not serve as an executive officer of any non-profit organization to which the Partnership Group made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2% of such organization’s consolidated gross revenues. Further, in accordance with our categorical director independence standards, there were no discretionary contributions made by any member of

the Partnership Group to a non-profit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.

In addition, our general partner’s board of directors determined that each of Messrs. Beasley and House, who constitute the members of the audit committee of the board of directors, meet the heightened independence requirements of the New York Stock Exchange for audit committee members.

Meeting Attendance and Preparation

Members of the board of directors are expected to attend at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing written materials distributed in advance.

Executive Sessions of Non-Management Directors

The general partner’s non-management board members will periodically meet outside the presence of our general partners’ executive officers. When appointed the chairman of the audit committee will serve as the presiding director for executive sessions of the non-management board members.

Communications with Directors

Interested parties wishing to communicate with our general partner’s non-management directors or the presiding director may contact our general partner’s corporate secretary or the presiding director. The contact information is published on the investor relations page of our website at www.williamspipelinepartners.com.

The current contact information is as follows:
Williams Pipeline Partners L.P.
c/o Williams Pipeline GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Corporate Secretary

Williams Pipeline Partners L.P.
c/o Williams Pipeline GP LLC
One Williams Center, Suite 4700
Tulsa, Oklahoma 74172
Attn: Presiding Director

E-mail: brian.shore@williams.com

Board Committees

The board of directors of our general partner has a separately-designated standing audit committee and a conflicts committee.

Audit Committee

Our general partner’s board of directors has determined that Messrs. Beasley and House, who constitute all of the members of the audit committee, meet the heightened independence requirements of the New York Stock Exchange for audit committee members and that all members are financially literate as defined by the rules of the New York Stock Exchange. Neither Mr. Beasley nor Mr. House qualify as an audit committee “financial expert” as defined by the rules of the SEC. Our third independent director, who will be appointed no later than January 29, 2009, will qualify as an audit committee “financial expert.” The audit committee is governed by a written charter adopted by the board of directors. For further information about the audit committee, please read the “Report of the Audit Committee” below.

Conflicts Committee

The conflicts committee of our general partner’s board of directors reviews specific matters that the board believes may involve conflicts of interest. The conflicts committee determines if resolution of the conflict is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience requirements established by the New York Stock Exchange and the Sarbanes-Oxley Act of 2002 and other federal securities laws. Any matters approved by the conflicts committee will be conclusively deemed fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe to us or our unitholders. Messrs. Beasley and House are the current members of the conflicts committee.

Code of Business Conduct and Ethics

Our general partner has adopted a code of business conduct and ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the code of business conduct and ethics on behalf of our general partner’s chief executive officer, chief financial officer, controller and persons performing similar functions on our Internet website at www.williamspipelinepartners.com under the “Investor Relations” caption, promptly following the date of any such amendment or waiver.

Internet Access to Governance Documents

Our general partner’s code of business conduct and ethics, governance guidelines and the charter for the audit committee are available on our Internet website at www.williamspipelinepartners.com under the “Investor Relations” caption. We will provide, free of charge, a copy of our code of business conduct and ethics or any of our other governance documents listed above upon written request to our general partner’s secretary at Williams Pipeline Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s officers and directors, and persons who own more than 10% of a registered class of our equity securities to file with the SEC and the New York Stock Exchange reports of ownership of our securities and changes in reported ownership. Officers and directors of our general partner and greater than 10% common unitholders are required to by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2007 our general partner’s officers, directors and greater than 10% common unitholders filed all reports they were required to file under Section 16(a).

Transfer Agent and Registrar

Computershare Trust Company, N.A. serves as registrar and transfer agent for our common units. Contact information for Computershare is as follows:

Computershare Trust Company, N.A.
P.O. Box 43069
Providence, Rhode Island 02940-3069
Phone: (781) 575-2879 or toll-free, (877) 498-8861
Hearing impaired: (800) 952-9245
Internet: www.computershare.com/investor

Send overnight mail to:

Computershare
250 Royall St.
Canton, Massachusetts 02021

CEO/CFO Certifications

We submitted the certification of Steven J. Malcolm, our general partner’s chairman of the board and chief executive officer, to the New York Stock Exchange pursuant to NYSE Section 303A.12(a) on January 16, 2008. In addition, the certificates of our chief executive officer and chief financial officer as required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2 to this annual report.

REPORT OF THE AUDIT COMMITTEE

The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The audit committee operates under a written charter approved by the board. The charter, among other things, provides that the audit committee has authority to appoint, retain and oversee the independent auditor. In this context, the audit committee:


	•	reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

	•	reviewed with Ernst & Young LLP, the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of Williams Pipeline Partners L.P.’s accounting principles and such other matters as are required to be discussed with the audit committee under generally accepted auditing standards;

	•	received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the audit committee by Ernst & Young LLP;

	•	discussed with Ernst & Young LLP its independence from management and Williams Pipeline Partners L.P. and considered the compatibility of the provision of nonaudit services by the independent auditors with the auditors’ independence;

	•	discussed with Ernst & Young LLP the matters required to be discussed by statement on auditing standards No. 61 (communications with audit committees);

	•	based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2007, for filing with the SEC; and

	•	approved the selection and appointment of Ernst & Young LLP to serve as Williams Pipeline Partners L.P.’s independent auditors.

This report has been furnished by the members of the audit committee of the board of directors:


	•	Stephen C. Beasley

	•	Emmitt C. House

February 28, 2008

The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by Williams Pipeline Partners L.P. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.

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Item 11.	*Executive Compensation*

Compensation Discussion and Analysis

We and our general partner were formed in August 2007. We are managed by the executive officers of our general partner who are also executive officers of Williams. Neither we nor our general partner have a compensation committee. The executive officers of our general partner are compensated directly by Williams. All decisions as to the compensation of the executive officers of our general partner who are involved in our management are made by the compensation committee of Williams. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner and we make no decisions relating to such compensation. A full discussion of the policies and programs of the compensation committee of Williams is set forth in the proxy statement for Williams’ 2007 annual meeting of stockholders which is available on the SEC’s website at www.sec.gov and on Williams’ website at www.williams.com under the heading “Investors — SEC Filings.” The secretary of our general partner will also provide a copy to you free of charge upon request. We reimburse our general partner for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Party Transactions” for more information regarding this arrangement.

Executive Compensation

Our general partner was formed on August 31, 2007. Our general partner did not accrue any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2007 fiscal year. Our executive officers are also executive officers of Williams or one of its pipeline subsidiaries. The compensation of the executive officers of our general partner will be set by Williams. The officers and employees of our general partner may participate in employee benefit plans and arrangements sponsored by Williams. Our general partner has not entered into any employment agreements with any of its officers. Further information regarding such compensation by 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.”

Employment Agreements

The executive officers of our general partner are also executive officers of Williams. These executive officers do not have employment agreements in their capacity as officers of our general partner.

Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s board of directors is not required to maintain, and does not maintain, a compensation committee. Steven J. Malcolm, our general partner’s chief executive officer and chairman of the board of directors serves as the chairman of the board and chief executive officer of Williams. Donald R. Chappel, Phillip D. Wright and Rodney J. Sailor, who are directors of our general partner, are also executive officers of Williams. However, all compensation decisions with respect to each of these persons are made by Williams and none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.

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Board Report on Compensation

Neither we nor our general partner has a compensation committee. The board of directors of our general partner 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.

The Board of Directors of Williams Partners GP LLC:
Stephen C. Beasley, Donald R. Chappel,
Emmitt C. House, Steven J. Malcolm
Rodney Sailor, Phillip D. Wright

Compensation of Directors

Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Messrs. Beasley and House, as non-employee directors will receive an annual compensation package consisting of the following: (a) $50,000 cash retainer; (b) restricted units representing our limited partnership interests valued at $25,000 in the aggregate; and (c) $5,000 cash for service on the conflicts or audit committees of the board of directors. The annual compensation package is paid to each non-employee director based on their service on the board of directors for the period beginning upon the closing of our initial public offering and ending on each anniversary of the closing of our initial public offering. In addition to the annual compensation package, each non-employee director received a one-time grant of restricted units valued at $25,000 on the date of first election to the board of directors. Restricted units awarded to non-employee directors under the annual compensation package or upon first election to the board of directors are granted under the Williams Pipeline GP LLC Long-Term Incentive Plan and vest 180 days after the date of grant. Cash distributions are to be paid on these restricted units. Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse non-employee directors for the costs of education programs relevant to their duties as board members.

Because the Partnership did not have any non-management directors in 2007, non-management directors did not receive any compensation in 2007.

Long-Term Incentive Plan

Our general partner adopted the Williams Pipeline GP LLC Long-Term Incentive Plan for employees, consultants and directors of our general partner and employees and consultants of its affiliates who perform services for our general partner or its affiliates. The long-term incentive plan consists of four components: restricted units, phantom units, unit options and unit appreciation rights. The long-term incentive plan permits the grant of awards covering an aggregate of 2,000,000 units.

Our general partner’s board of directors in its discretion may initiate, terminate, suspend or discontinue the long-term incentive plan at any time with respect to any award that has not yet been granted. Our general partner’s board of directors also has the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to unitholder approval as required by the exchange upon which the common units are listed at that time. However, no change in any outstanding grant may be made that would materially impair the rights of the participant without the consent of the participant.

Restricted Units and Phantom Units

A restricted unit issued under the long term incentive plan will be a common unit subject to forfeiture prior to the vesting of the award. A phantom unit will be a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner, cash equivalent to the value of a common unit. Our general partner may determine to make grants under the plan of restricted units and phantom units to employees, consultants and directors containing such terms as the general partner shall determine. Our general partner will determine the period over which restricted units and phantom units granted to employees,

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consultants and directors will vest. The general partner may base its determination upon the achievement of specified financial objectives. In addition, the restricted units and phantom units will vest upon a change of control of us, our general partner or Williams, unless provided otherwise by our general partner.

If a grantee’s employment, service relationship or membership on the board of directors terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, our general partner provides otherwise. Common units to be delivered in connection with the grant of restricted units or upon the vesting of phantom units may be common units acquired by our general partner on the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. Thus, the cost of the restricted units and delivery of common units upon the vesting of phantom units will be borne by us. If we issue new common units in connection with the grant of restricted units or upon vesting of the phantom units, the total number of common units outstanding will increase. Our general partner, in its discretion, may grant tandem distribution rights with respect to restricted units and tandem distribution equivalent rights with respect to phantom units.

Unit Options and Unit Appreciation Rights

The long-term incentive plan will permit the grant of options covering common units and the grant of unit appreciation rights. A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. Such excess may be paid in common units, cash, or a combination thereof, as determined by our general partner in its discretion. Our general partner will be able to make grants of unit options and unit appreciation rights under the plan to employees, consultants and directors containing such terms as the general partner shall determine. Unit options and unit appreciation rights may not have an exercise price that is less than the fair market value of the common units on the date of grant. In general, unit options and unit appreciation rights granted will become exercisable over a period determined by our general partner. In addition, the unit options and unit appreciation rights will become exercisable upon a change in control of us, our general partner or Williams, unless provided otherwise by our general partner. Our general partner, in its discretion may grant tandem distribution equivalent rights with respect to unit options and unit appreciation rights.

Upon exercise of a unit option (or a unit appreciation right settled in common units), our general partner will acquire common units on the open market or directly from us or any other person or use common units already owned by our general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring these common units and the proceeds received from a participant at the time of exercise. Thus, the cost of the unit options (or a unit appreciation right settled in common units) will be borne by us. If we issue new common units upon exercise of the unit options (or a unit appreciation right settled in common units), the total number of common units outstanding will increase, and our general partner will pay us the proceeds it receives from an optionee upon exercise of a unit option. The availability of unit options and unit appreciation rights is intended to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of us. Our general partner and its affiliates will be reimbursed for expenses incurred on our behalf, including the compensation of employees of an affiliate of our general partner that perform services on our behalf. These expenses include all expenses necessary or appropriate to the conduct of the business of, and allocable to, us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner for compensation or expenses incurred on our behalf, except that pursuant to the omnibus agreement, Williams will provide a partial credit for general and administrative expenses that we incur for a period of five years following our initial public offering. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

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Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*

The following table sets forth the beneficial ownership of our units held by:


	•	each person known by us to be a beneficial owner of more than 5% of the then outstanding units;

	•	each of the directors of our general partner;

	•	each of the named executive officers of our general partner; and

	•	all directors and executive officers of our general partner as a group.

The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Percentage of beneficial ownership after the transaction is based on 33,558,568 limited partner units outstanding. The address for the beneficial owners listed below is One Williams Center, Tulsa, Oklahoma 74172-0172.

Percentage of

Common

Subordinated

Total

Units

Units to be

Beneficially

Name of Beneficial Owner

Owned

The Williams Companies(1)

4,700,668

20.9

10,957,900

100

45.7

Steven J. Malcolm

10,000

—

Donald R. Chappel

10,000

—

James J. Bender

8,000

—

Phillip D. Wright

10,100

—

Rodney J. Sailor

500

—

Stephen C. Beasley

17,500

—

Emmitt C. House

2,500

—

All executive officers and directors as a group

58,600

—


*		Less than 1%.

(1)		The Williams Companies, Inc.’s common stock is listed on the NYSE under the symbol “WMB.” The Williams Companies, Inc. files information with or furnishes information to the SEC pursuant to the information requirements of the Securities Exchange Act of 1934.

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The following table sets forth, as of February 25, 2008, the number of shares of common stock of Williams owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.

Shares of

Shares

Percentage of

Common

Underlying

Total Shares

Stock

Options

of Common

Owned

Exercisable

Stock

Directly or

Within

Beneficially

Name of Beneficial Owner

Indirectly(1)

60 Days(2)

Owned

Owned(3)

Steven J. Malcolm

919,212

1,717,198

2,636,410

Donald R. Chappel

258,285

374,097

632,382

James J. Bender

122,693

95,781

218,474

Phillip D. Wright

257,576

422,799

680,375

Rodney J. Sailor

33,707

43,155

76,862

Stephen C. Beasley

Emmitt C. House

120

All directors and executive officers as a group

1,591,593

2,653,030

4,244,623


*		Less than 1%

(1)		Includes shares held under the terms of incentive and investment plans as follows: Mr. Malcolm, 45,736 shares in The Williams Companies Investment Plus Plan, 468,092 restricted stock units and 405,384 beneficially owned shares; Mr. Chappel, 186,642 restricted stock units and 71,643 beneficially owned shares; Mr. Bender, 2,800 shares owned by children, 122,693 restricted stock units and 28,490 beneficially owned shares; Mr. Wright, 15,109 shares in The Williams Companies Investment Plus Plan, 128,414 restricted stock units and 114,053 beneficially owned shares; Mr. Sailor, 10,120 shares in The Williams Companies Investment Plus Plan, 22,933 restricted stock units and 654 beneficially owned shares; and Mr. House owns 120 shares in a third party-managed Individual Retirement Account. Restricted stock units do not provide the holder with voting or investment power.

(2)		The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 25, 2008. Shares subject to options cannot be voted.

(3)		Based on 585,088,929 shares outstanding as of February 25, 2008.

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Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information concerning common units that were potentially subject to issuance under the Williams Pipeline Partners GP LLC Long-Term Incentive Plan as of December 31, 2007. Please read “Executive Compensation — Long Term Incentive Plan” for a description of the material features of the plan, including the awards that may be granted under the plan.

Number of Securities

Remaining Available

Number of Securities

Weighted-Average

for Future Issuance

to be Issued Upon

Exercise Price of

Under Equity

Exercise of Outstanding

Outstanding

Compensation Plan

Options, Warrants

(Excluding Securities

Plan category

and Rights (a)

and Rights (b)

Reflected in Column(a)) (c)

Equity compensation plans approved by security holders

Equity compensation plans not approved by security holders

2,000,000

Total

2,000,000


Item 13.	*Certain Relationships and Related Transactions*

Through its ownership of our general partner, Williams owns 4,700,668 common units and 10,957,900 subordinated units representing an aggregate 45.7% limited partner interest in us. In addition, our general partner owns 684,869 general partner units, representing a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments made by us to our general partner and its affiliates in connection with our formation, ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.


Formation Stage
The contribution by our general partner of the asset to us		• 19.1% ownership interest in Northwest
The consideration received by our general partner for the contribution of the asset to us		• 6,350,668 common units
		• 10,957,900 subordinated units
		• 684,869 general partner units representing a 2% general partner interest and the incentive distribution rights

The interest in Northwest purchased by us using proceeds of our initial public offering		15.9% ownership interest in Northwest
The consideration paid by us for purchase of an interest in Northwest using proceeds from our initial public offering		$300.9 million.
Funds received by our general partner as consideration for the redemption of 1,650,000 common units upon exercise by the underwriters in the initial public offering of their option to purchase additional common units to cover over-allotments		$31.0 million.

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Operational Stage
Distributions of available cash to our general partner		We will generally make cash distributions 98% to unitholders, including our general partner as the holder of 4,700,668 common units and all of the subordinated units, and the remaining 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level.
Payments to our general partner and its affiliates		Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition, we will reimburse our general partner and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for our benefit. For further information regarding the administrative fee, please read “-- Omnibus Agreement -- Reimbursement of Operating and General and Administrative Expense.”
Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement -- Withdrawal or Removal of Our General Partner.”

Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements Governing the Transactions

We and other parties entered into agreements with respect to our formation and the application of the proceeds of our initial public offering. These agreements are not the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, were not effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. Because these agreements relate to formation agreements that, by their nature, would not occur in a third-party situation, it is not possible to determine what the differences would be in the terms of these transactions when compared to the terms of transactions with an unaffiliated, third party. We believe the terms of these agreements with related parties to be comparable to the terms of agreements used in similarly structured transactions. All of the transaction expenses incurred in connection with our formation transactions, including the expenses associated with vesting assets in our subsidiaries, were paid from the proceeds of our initial public offering.

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Omnibus Agreement

Upon the closing of our initial public offering, we entered into an omnibus agreement with Williams and certain of its affiliates that governs our relationship with them regarding the following matters:


	•	reimbursement of certain operating and general and administrative expenses;

	•	indemnification for certain environmental contingencies, tax contingencies, and right-of-way defects; and

	•	a license for the use of certain intellectual property.

Reimbursement of Operating and General and Administrative Expense

Williams will provide us with a partial credit for general and administrative expenses incurred on our behalf through 2011. In 2008, the amount of the general and administrative expense credit will be $2.0 million and it will decrease by $0.5 million for each subsequent year. As a result, after 2011, we will no longer receive any credit and will be required to reimburse Williams for all of the general and administrative expenses incurred on our behalf.

Indemnification

Under the omnibus agreement, Williams will indemnify us for three years after the closing of our initial public offering against certain potential environmental claims, toxic tort losses and expenses associated with the business conducted by Northwest or the operation of its assets and occurring before the closing date of our initial public offering and for which Northwest has not created and publicly disclosed a reserve for such losses. The maximum liability of Williams for this indemnification obligation will not exceed $9 million and Williams will not have any obligation under this indemnification until our aggregate losses exceed $0.25 million. Williams will have no indemnification obligations with respect to environmental or toxic tort claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of our initial public offering. We have agreed to indemnify Williams against environmental liabilities related to the post-closing operation of our assets to the extent Williams is not required to indemnify us.

Additionally, Williams will indemnify us for losses arising out of the failure of Northwest to own valid and indefeasible easement rights, leasehold and/or fee ownership interests in land on which its assets are located; our failure to be the owner of a valid and indefeasible ownership of a 35% general partnership interest in Northwest; our failure to obtain any consent or governmental permit necessary to allow the transfer of a 35% general partnership interest in Northwest, Northwest’s failure to obtain any consent or governmental permit necessary to allow any of Northwest’s assets to cross the roads, waterways, railroads, and other areas where such assets are located, such that Northwest’s operations are substantially affected; income tax liabilities attributable to the ownership or operation of Northwest’s assets pre-closing, including any such income tax liability of Williams and its affiliates that may result from our formation transactions; and the assets, liabilities, business or operations associated with the Parachute Lateral.

In no event will Williams be obligated to indemnify us for any claims, losses or expenses or income taxes referred to in either of the two immediately preceding paragraphs to the extent we recover any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party or in the tariffs paid by the customers of our affected pipeline system. In addition, in no event will the amount required to be indemnified to us in respect of any such claims, losses or expenses or income taxes in respect of Northwest exceed 35% of the gross amount of such claims, losses, expenses or income taxes, as the case may be.

Intellectual Property License

Williams and its affiliates granted a license to us for the use of certain marks, including our logo, for as long as Williams controls our general partner, at no charge.

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Amendments

The omnibus agreement may not be amended without the prior approval of the conflicts committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of our common units.

Competition

Neither Williams nor any of its affiliates, including Williams Partners, will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. Williams and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets.

Contracts with Affiliates

Northwest General Partnership Agreement

General. In connection with the closing of our initial public offering, Williams contributed to us a 19.1% general partnership interest in Northwest and we purchased a 15.9% general partnership interest in Northwest. As a result, we indirectly own a 35% general partnership interest in Northwest, and a Williams subsidiary owns a 65% general partnership interest in Northwest. A general partnership agreement governs the ownership and management of Northwest.

Northwest is a Delaware general partnership, one partner of which is a wholly owned subsidiary of Williams owning a 65% general partnership interest and the other partner of which is a wholly owned subsidiary of ours owning a 35% general partnership interest. The purposes of Northwest are 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 the Code) or enhances operations that generate such qualified income.

Under the partnership agreement, any affiliate of either partner may engage in other business opportunities, including those that compete with Northwest’s business, free from any obligation to offer such opportunities to the other partner or Northwest.

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 us. 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;

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	•	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;

	•	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% 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

110

of Williams holding the 65% general partnership interest in Northwest not owned by us. See “Business — Capital Projects — Colorado Hub Connection Project.”

Working Capital Agreement

Upon the closing of our initial public offering, we entered into a $20 million working capital credit agreement with Williams as the lender. The facility is available exclusively to fund working capital borrowings. The initial maturity date of the facility will be the 365th day following the effective date of the agreement but may be extended for another 365-day period upon notice as provided in the agreement. Borrowings under the agreement will bear interest at the same rate as would be available for borrowings under the Williams revolving credit facility.

We are required to reduce all borrowings under our working capital credit facility to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the facility.

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. 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% at December 31, 2007.

Northwest’s Related Party Agreements and Related Transactions

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% 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.

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% at December 31, 2007.

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.

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.

Review, Approval or Ratification of Transactions with Related Persons

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Williams and Williams Partners on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage us in a manner beneficial to us and our unitholders. Our partnership agreement contains provisions that specifically define our general partner’s duties to the unitholders. Our partnership agreement also specifically defines the remedies

111

available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Revised Uniform Limited Partnership Act, which we refer to as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the duties (including fiduciary duties) otherwise owed by a general partner to limited partners and the partnership.

Whenever a conflict arises in the operation of the partnership between our general partner or its affiliates, on the one hand, and us or any limited partner, on the other, including a transaction with an affiliate, our general partner will resolve that conflict. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of our general partner. Our general partner is not obligated to submit the resolution to an independent third party for evaluation or approval.

Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of a conflict is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

If our general partner does not seek approval from the conflicts committee and our general partner’s board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically mandated in our partnership agreement, our general partner or the conflicts committee of our general partner’s board of directors may consider any factors it determines in good faith when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

In addition, our code of business conduct and ethics requires that all employees, including employees of affiliates of Williams who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the appearance of interfering, with their responsibilities to us and our unitholders. Conflicts of interest that cannot be avoided must be disclosed to a supervisor who is then responsible for establishing and monitoring procedures to ensure that we are not disadvantaged.

Director Independence

Please read “— Directors, Executive Officers and Corporate Governance — Governance — Director Independence” above for information about the independence of our general partner’s board of directors and its committees, which information is incorporated herein by reference in its entirety.

112


Item 14.	*Principal Accountant Fees and Services*

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


	Year Ended December 31,
	2007		2006
	(Thousands of dollars)

Audit Fees	$	695	$	—
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	695	$	—

Fees for audit services in 2007 include fees associated with the annual audit, the audit and reviews of reports included in our registration statement on Form S-1, and services provided in connection with other filings with the SEC.

The audit committee has established a policy regarding pre-approval of all audit and non-audit services provided by Ernst & Young LLP. On an ongoing basis, our general partner’s management presents specific projects and categories of service to our general partner’s audit committee for which advance approval is requested. The audit committee reviews those requests and advises management if the audit committee approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of the general partner reports to the audit committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The audit committee may also delegate the ability to pre-approve permissible services, excluding services related to our internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported at a subsequent audit committee meeting. The audit committee’s pre-approval policy with respect to audit and non-audit services is provided as an exhibit to this report.

113

PART IV


Item 15.	*Exhibits and Financial Statement Schedules*

(a) 1 and 2. Williams Pipeline Partners L.P. financials

Covered by reports of independent auditors:


	Page

Williams Pipeline Partners Predecessor
Statements of Income for the years ended December 31, 2007, 2006, and 2005		58
Balance Sheets as of December 31, 2007 and 2006		59
Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005		60
Statements of Owners’ Equity and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005		61
Notes to Financial Statements		62
Williams Pipeline Partners L.P.
Balance Sheet as of December 31, 2007		66
Notes to Balance Sheet		67
Northwest Pipeline GP
Consolidated Statements of Income for the years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		69
Consolidated Balance Sheets as of December 31, 2007 and 2006 (restated)		70
Consolidated Statements of Owners’ Equity for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		71
Consolidated Statements of Comprehensive Income for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		72
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		73
Notes to Consolidated Financial Statements		74

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and(b). The exhibits listed below are furnished or filed as part of this annual report:

The exhibits listed below are filed as part of this annual report:


Exhibit
Number			Description

	3	.1	Certificate of Limited Partnership of Williams Pipeline Partners L.P. (filed on September 12, 2007 as Exhibit 3.1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	3	.2	First Amended and Restated Agreement of Limited Partnership of Williams Pipeline Partners L.P., dated January 24, 2008 (filed on January 30, 2008 as Exhibit 3.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	3	.3	Certificate of Formation of Williams Pipeline GP LLC (filed on September 12, 2007 as Exhibit 3.3 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	3	.4	First Amended and Restated Limited Liability Company Agreement of Williams Pipeline GP LLC, dated January 24, 2008 (filed on January 30, 2008 as Exhibit 3.2 to Williams Pipeline Partners L.P. Form 8-K (File No. 001-33917) and incorporated herein by reference).

114


Exhibit
Number			Description

	4	.1	Senior Indenture, dated August 1, 1992, between Northwest Pipeline and Continental Bank, N.A., relating to Northwest Pipeline’s 9% Debentures, due 2022 (filed on July 2, 1992 as Exhibit 4.1 to Northwest Pipeline’s Registration Statement on Form S-3 (File No. 33-49150) and incorporated herein by reference).
	4	.2	Form of Senior Indenture, dated November 30, 1995, between Northwest Pipeline and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Registration Statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
	4	.3	Indenture dated June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A. (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	4	.4	Indenture, dated April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 6, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.1	Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, by and 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 (filed on January 30, 2008 as Exhibit 10.2 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.2	Omnibus Agreement, dated January 24, 2008, among Williams Gas Pipeline Company, LLC, Williams Pipeline GP LLC, Williams Pipeline Operating LLC, Williams Pipeline Partners Holdings LLC and The Williams Companies, Inc. (filed on January 30, 2008 as Exhibit 10.3 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.3	General Partnership Agreement of Northwest Pipeline GP, dated October 1, 2007, between WGPC Holdings LLC and Williams Pipeline Partners Holdings LLC (filed on October 2, 2007 as Exhibit 3.2 to Northwest Pipeline GP’s Current Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.4	Form of Operating Agreement, dated July 1, 1991, between Northwest Pipeline and Williams Field Services Company (filed on March 26, 1992 as Exhibit 10(c)(9) to Northwest Pipeline’s Report on Form 10-K (File No. 001-07414) and incorporated herein by reference).
	10	.5	Long Term Incentive Plan (filed on October 29, 2007 as Exhibit 10.5 to Amendment No. 1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	10	.6	Form of Transfer Agreement, dated July 1, 1991, between Northwest Pipeline and Gas Processing (filed on March 26, 1992 as Exhibit 10(c)(8) to Northwest Pipeline’s Report on Form 10-K (File No. 001-07414) and incorporated herein by reference).
	10	.7	Working Capital Loan Agreement (filed on October 29, 2007 as Exhibit 10.7 to Amendment No. 1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	10	.8	Credit Agreement, dated 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 (filed on May 1, 2006 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
	10	.9	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 (filed on May 15, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

115


Exhibit
Number			Description

	10	.10	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 (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
	10	.11	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 (filed on April 6, 2007 as Exhibit 10.1 to Northwest Pipeline’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.12	Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.13	First Amended and Restated General Partnership Agreement of Northwest Pipeline GP, dated January 24, 2008 (filed on January 30, 2008 as Exhibit 10.4 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	21	.1*	List of subsidiaries of Williams Pipeline Partners L.P. (filed on January 7, 2008 as Exhibit 21.1 to Amendment No. 3 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	24*		Power of Attorney together with certified resolution.
	31	.1*	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
	31	.2*	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
	32*		Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer
	99	.1*	Williams Pipeline GP LLC Financial Statements


*		Filed herewith

116

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.

Williams Pipeline Partners L.P.

(Registrant)


	By:	Williams Pipeline GP LLC,

Its general partner


	By:	/s/ Brian K. Shore

Brian K. Shore

Attorney-in-Fact

Date: February 29, 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 and in the capacities and on the dates indicated.


Signature	Title	Date


/s/ Steven J. Malcolm* Steven J. Malcolm	Chief Executive Officer and Chairman of the Board (Principal Executive Officer)	February 29, 2008

/s/ Donald R. Chappel* Donald R. Chappel	Chief Financial Officer and Director (Principal Financial Officer)	February 29, 2008

/s/ Ted T. Timmermans* Ted T. Timmermans	(Principal Accounting Officer)	February 29, 2008

/s/ Phillip D. Wright* Phillip D. Wright	Chief Operating Officer and Director	February 29, 2008

/s/ Rodney J. Sailor* Rodney J. Sailor	Treasurer and Director	February 29, 2008

/s/ Stephen C. Beasley* Stephen C. Beasley	Director	February 29, 2008

/s/ Emmitt C. House* Emmitt C. House	Director	February 29, 2008

* By: /s/ Brian K. Shore Brian K. Shore Attorney-in-Fact

117

INDEX TO EXHIBITS


Exhibit
Number			Description

	3	.1	Certificate of Limited Partnership of Williams Pipeline Partners L.P. (filed on September 12, 2007 as Exhibit 3.1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	3	.2	First Amended and Restated Agreement of Limited Partnership of Williams Pipeline Partners L.P., dated January 24, 2008 (filed on January 30, 2008 as Exhibit 3.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	3	.3	Certificate of Formation of Williams Pipeline GP LLC (filed on September 12, 2007 as Exhibit 3.3 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	3	.4	First Amended and Restated Limited Liability Company Agreement of Williams Pipeline GP LLC, dated January 24, 2008 (filed on January 30, 2008 as Exhibit 3.2 to Williams Pipeline Partners L.P. Form 8-K (File No. 001-33917) and incorporated herein by reference).
	4	.1	Senior Indenture, dated August 1, 1992, between Northwest Pipeline and Continental Bank, N.A., relating to Northwest Pipeline’s 9% Debentures, due 2022 (filed on July 2, 1992 as Exhibit 4.1 to Northwest Pipeline’s Registration Statement on Form S-3 (File No. 33-49150) and incorporated herein by reference).
	4	.2	Form of Senior Indenture, dated November 30, 1995, between Northwest Pipeline and Chemical Bank, relating to Northwest Pipeline’s 7.125% Debentures, due 2025 (filed on September 14, 1995 as Exhibit 4.1 to Northwest Pipeline’s Registration Statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
	4	.3	Indenture dated June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A. (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline GP’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	4	.4	Indenture, dated April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 6, 2007 as Exhibit 4.1 to Northwest Pipeline GP’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.1	Contribution, Conveyance and Assumption Agreement, dated January 24, 2008, by and 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 (filed on January 30, 2008 as Exhibit 10.2 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.2	Omnibus Agreement, dated January 24, 2008, among Williams Gas Pipeline Company, LLC, Williams Pipeline GP LLC, Williams Pipeline Operating LLC, Williams Pipeline Partners Holdings LLC and The Williams Companies, Inc. (filed on January 30, 2008 as Exhibit 10.3 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.3	General Partnership Agreement of Northwest Pipeline GP, dated October 1, 2007, between WGPC Holdings LLC and Williams Pipeline Partners Holdings LLC (filed on October 2, 2007 as Exhibit 3.2 to Northwest Pipeline GP’s Current Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.4	Form of Operating Agreement, dated July 1, 1991, between Northwest Pipeline and Williams Field Services Company (filed on March 26, 1992 as Exhibit 10(c)(9) to Northwest Pipeline’s Report on Form 10-K (File No. 001-07414) and incorporated herein by reference).
	10	.5	Long Term Incentive Plan (filed on October 29, 2007 as Exhibit 10.5 to Amendment No. 1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	10	.6	Form of Transfer Agreement, dated July 1, 1991, between Northwest Pipeline and Gas Processing (filed on March 26, 1992 as Exhibit 10(c)(8) to Northwest Pipeline’s Report on Form 10-K (File No. 001-07414) and incorporated herein by reference).

118


Exhibit
Number			Description

	10	.7	Working Capital Loan Agreement (filed on October 29, 2007 as Exhibit 10.7 to Amendment No. 1 to Williams Pipeline Partners L.P.’s Registration Statement on Form S-1 (File No. 333-146015) and incorporated herein by reference).
	10	.8	Credit Agreement, dated 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 (filed on May 1, 2006 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
	10	.9	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 (filed on May 15, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
	10	.10	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 (filed on November 28, 2007 as Exhibit 10.1 to The Williams Companies, Inc.’s Report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
	10	.11	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 (filed on April 6, 2007 as Exhibit 10.1 to Northwest Pipeline’s Report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
	10	.12	Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	10	.13	First Amended and Restated General Partnership Agreement of Northwest Pipeline GP, dated January 24, 2008 (filed on January 30, 2008 as Exhibit 10.4 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917) and incorporated herein by reference).
	21	.1*	List of subsidiaries of Williams Pipeline Partners L.P.
	24*		Power of Attorney together with certified resolution.
	31	.1*	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
	31	.2*	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
	32*		Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer
	99	.1*	Williams Pipeline GP LLC Financial Statements


*		Filed herewith

119


Heading		Page

PART I
Item 1 and 2.	Business and Properties		1
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		36
Item 3.	Legal Proceedings		36
Item 4.	Submission of Matters to a Vote of Security Holders		36

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters		36
Item 6.	Selected Financial and Operating Data		39
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 7A.	Qualitative and Quantitative Disclosures about Market Risk		55
Item 8.	Financial Statements and Supplementary Data		56
Item 9.	Changes in and Disagreements with Accountants on Accounting		94
Item 9A.	Controls and Procedures		94
Item 9B.	Other Information		94

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		95
Item 11.	Executive Compensation		101
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		104
Item 13.	Certain Relationships and Related Transactions		106
Item 14.	Principal Accountant Fees and Services		113

PART IV
Item 15.	Exhibits and Financial Statement Schedules		114
Subsidiaries
Power of Attorney
Rule 13a-14(a)/15d-14(a) Certification of CEO
Rule 13a-14(a)/15d-14(a) Certification of CFO
Section 1350 Certifications of CEO and CFO
Financial Statements


Item 8.	*Financial Statements and Supplementary Data*


	Page

Williams Pipeline Partners Predecessor
Financial Statements
Report of Independent Registered Public Accounting Firm		57
Statements of Income for the years ended December 31, 2007, 2006, and 2005		58
Balance Sheets as of December 31, 2007 and 2006		59
Statements of Cash Flows for the years ended December 31, 2007, 2006 and 2005		60
Statements of Owners’ Equity and Comprehensive Income for the years ended December 31, 2007, 2006 and 2005		61
Notes to Financial Statements		62
Williams Pipeline Partners L.P.
Report of Independent Registered Public Accounting Firm		65
Balance Sheet as of December 31, 2007		66
Notes to Balance Sheet		67
Northwest Pipeline GP
Report of Independent Registered Public Accounting Firm		68
Consolidated Statements of Income for the years Ended December 31, 2007, 2006 (restated) and 2005 (restated)		69
Consolidated Balance Sheets as of December 31, 2007 and 2006 (restated)		70
Consolidated Statements of Owners’ Equity for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		71
Consolidated Statements of Comprehensive Income for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		72
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2006 (restated) and 2005 (restated)		73
Notes to Consolidated Financial Statements		74


ASSETS
Deferred costs	$	1,689,110

Total assets	$	1,689,110

LIABILITIES AND PARTNERS’ EQUITY
Accounts payable — affiliate	$	1,689,110

Partners’ Equity
Limited partner’s equity		980
General partner’s equity		20
Less receivables from partners		(1,000	)

Total partners’ equity		—

Total liabilities and partners’ equity	$	1,689,110


Item 10.	*Directors, Executive Officers and Corporate Governance*


Name	Age		Position with Williams Pipeline GP LLC

Steven J. Malcolm		59	Chairman of the Board and Chief Executive Officer
Donald R. Chappel		56	Chief Financial Officer and Director
Phillip D. Wright		52	Chief Operating Officer and Director
James J. Bender		51	General Counsel
Rodney J. Sailor		49	Treasurer and Director
Stephen C. Beasley		56	Director
Emmitt C. House		58	Director


Entity	Jurisdiction	Relationship
Williams Pipeline Operating LLC	Delaware	100% — owned by Williams Pipeline Partners L.P.
Williams Pipeline Partners Holdings LLC	Delaware	100% — owned by Williams Pipeline Operating LLC
Northwest Pipeline GP	Delaware	35% — owned by Williams Pipeline Partners
		Holdings LLC


/s/ Steven J. Malcolm		/s/ Donald R. Chappel

Steven J. Malcolm		Donald R. Chappel
Chairman of the Board President and Chief Executive Officer (Principal Executive Officer)		Chief Financial Officer and Director (Principal Financial Officer)


/s/ Phillip D. Wright		/s/ Rodney J. Sailor

Phillip D. Wright		Rodney J. Sailor
Chief Operating Officer and Director		Treasurer and Director

/s/ Stephen C. Beasley		/s/ Emmitt C. House

Stephen C. Beasley		Emmitt C. House
Director		Director

	a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



	/s/ Steven J. Malcolm
	Steven J. Malcolm
	Chief Executive Officer of Williams Pipeline GP LLC, general partner of Williams Pipeline Partners L.P. (Principal Executive Officer)



	/s/ Donald R. Chappel
	Donald R. Chappel
	Chief Financial Officer of Williams Pipeline GP LLC, general partner of Williams Pipeline Partners L.P. (Principal Financial Officer)


/s/ Steven J. Malcolm
Steven J. Malcolm
Chief Executive Officer
February 29, 2008

/s/ Donald R. Chappel

Donald R. Chappel
Chief Financial Officer
February 29, 2008