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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 1934
		For the fiscal year ended December 31, 2008
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		74172-0172
(Address of Principal Executive Offices)		(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 þ No o

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

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	Smaller reporting company o

Do not check if a smaller
reporting company)

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 aggregate market value of the registrant’s common units held by non-affiliates based on the closing sale price of such units as reported on the New York Stock Exchange, as of the last day of the registrant’s most recently completed second quarter was approximately $309,040,300. This figure excludes common units beneficially owned by the directors and executive officers of Williams Pipeline GP LLC, our general partner.

The registrant had 22,607,430 common units and 10,957,900 subordinated units outstanding as of February 23, 2009.

DOCUMENTS INCORPORATED BY REFERENCE

None

WILLIAMS PIPELINE PARTNERS L.P.

FORM 10-K

PART I


Item 1.	*Business*

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 percent 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, NE, 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 corporate 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 Delaware limited partnership formed on August 31, 2007 by The Williams Companies, Inc. (“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 percent general partnership interest in Northwest, which owns an approximately 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 12.8 billion cubic feet, or Bcf. We account for our 35 percent interest in Northwest as an equity investment, and, therefore, do not consolidate its financial results.

The 35 percent 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 23, 2009, Williams indirectly owns an approximate 45.7 percent limited partnership interest in us and all of our 2 percent general partner interest.

Williams is an integrated energy company with 2008 revenues in excess of $12.3 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 24 years.

2008 EVENTS

On January 24, 2008, we completed our IPO. Concurrent with the closing of the IPO, (i) the public, through the underwriters of the offering, purchased common units, representing a 47.5 percent limited partner interest in us, (ii) we purchased from Northwest a 15.9 percent general partnership interest in Northwest, and (iii) a 19.1 percent interest in Northwest was contributed to us by Williams Pipeline GP LLC, our General Partner, in exchange for a 2 percent general partner interests in us, and all of our incentive distribution rights. On February 21, 2008, the underwriters of the offering exercised their right to purchase additional common units from us to cover over-allotments which represented an additional 4.8 percent limited partner interest in us. 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 those common units from the General Partner.

FINANCIAL INFORMATION ABOUT SEGMENTS

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

NARRATIVE DESCRIPTION OF BUSINESS

We are a Delaware limited partnership formed on August 31, 2007 by Williams to own and operate natural gas transportation and storage assets. We own a 35 percent general partnership interest in Northwest. The remainder of the interest in Northwest is owned by Williams Gas Pipeline Company, LLC, a wholly owned subsidiary of Williams. As of February 23, 2009, Williams, through its subsidiary, Williams Pipeline GP LLC, owns a 2 percent general partner interest and a 45.7 percent limited partner interest in us.

Northwest’s System

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 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 principal business is the interstate transportation of natural gas, which is regulated by the Federal Energy Regulatory Commission (“FERC”).

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. As of December 31, 2008, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 Bcf* of natural gas per day. Northwest also has approximately 12.8 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 (“WCSB”). 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 Northwest provides competitively priced services in markets such as Reno, Nevada; Spokane, Washington and Medford, Oregon that are also serviced by other interstate natural gas pipelines.

* 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.

Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Northwest firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of its business. Additionally, Northwest offers interruptible and short-term firm transportation services. During 2008, Northwest served a total of 136 transportation and storage customers. Northwest’s largest customer was Puget Sound Energy, Inc., which accounted for approximately 20.7 percent of its total operating revenues for the year ended December 31, 2008. No other customer accounted for more than 10 percent of Northwest’s total operating revenues during that period.

Northwest’s 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 Liquified Natural Gas (“LNG”), directly or indirectly affect the demand for Northwest’s 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.

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. 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. The high percentage of Northwest’s revenue derived from capacity reservation fees helps mitigate the risk of revenue fluctuations caused by changing supply and demand conditions.

Northwest has approximately 12.8 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, 2008, Northwest’s share of the firm seasonal storage service in this facility was approximately 7.5 Bcf of working natural gas storage capacity and up to 383 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 Northwest contracts for natural gas storage services 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

Northwest believes 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 Natural”), Northwest’s second largest customer, announced that it is partnering with TransCanada’s Gas Transmission Northwest (“GTN”), to build the Palomar Gas Transmission project. This proposed project would consist of a Greenfield pipeline from GTN’s system in central Oregon to Northwest Natural’s system in western Oregon. Palomar could also be used to transport natural gas from one of the proposed Columbia River LNG terminals back to GTN’s system.

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. El Paso Corporation has proposed a new pipeline project, called Ruby, which would begin at the Opal Hub in Wyoming and terminate in Malin, Oregon, near the California border, to create additional access to Rocky Mountain gas in western markets.

Natural gas also competes with other forms of energy available to Northwest’s customers, including electricity, coal, fuel oils and other alternative energy sources. A shift from natural gas to other forms of energy could cause a decrease in use of Northwest’s storage and transportation services.

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.

Northwest’s Customers

Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies (“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.

Capital Projects

The pipeline projects listed below are significant future pipeline projects for which Northwest has significant customer commitments.

Colorado Hub Connection Project

Northwest has proposed installing a new 27-mile, 24-inch diameter lateral to connect the Meeker/White River Hub near Meeker, Colorado to Northwest’s mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub Connection (“CHC Project”). It is estimated that the construction of the CHC Project will cost up to $60 million with service targeted to commence in November 2009. Northwest will combine the lateral capacity with 341 MDth per day of existing mainline capacity from various receipt points for delivery to Ignacio, Colorado, including approximately 98 MDth per day of capacity that was sold on a short-term basis. Approximately 243 MDth per day of this capacity was originally held by Pan-Alberta Gas under a contract that terminates on October 31, 2012.

In addition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub for Northwest’s on-system and off-system markets. Northwest has entered into precedent agreements with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. In September 2008, Northwest filed an application for FERC certification and is awaiting necessary regulatory approvals. If Northwest does not proceed with the CHC Project, Northwest will seek recovery of any shortfall in annual capacity reservation revenues from its remaining customers in a future rate proceeding. Northwest expects to collect maximum rates for the new CHC Project capacity commitments and seek approval to recover the CHC Project costs in any future rate case filed with 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 was placed in service on November 1, 2008.

As a one-third owner of Jackson Prairie, in early 2006, Northwest held an open season for a new firm storage service based on its 100 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 six-year period from 2007 through 2012.

As a result of the open season, four shippers have executed long-term service agreements for the full amount of incremental storage service offered at contract terms averaging 33 years. The firm service relating to storage capacity rights will be phased-in as the expanded working natural gas capacity is developed. Northwest’s one-third share of the deliverability expansion was placed in service on November 1, 2008 at a cost of approximately $16.0 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 that resulted in the execution of an agreement for 150 MDth per day of firm transportation service from the Meeker/White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project will include construction of approximately 16 miles of 30-inch loop between Northwest’s existing Green River and Muddy Creek compressor stations in Wyoming as well as an upgrade to Northwest’s existing Vernal compressor station, with service targeted

to commence in November 2010. The total project is estimated to cost up to $65 million, including the cost of replacing existing compression at the Vernal compressor station which will enhance the efficiency of Northwest’s system. The Sundance Trail Expansion will utilize available capacity on the CHC Project lateral and the existing Piceance lateral in conjunction with available and expended mainline capacity. The Sundance Trail Expansion remains subject to certain conditions, including receiving the necessary regulatory approvals. Northwest expects to collect its maximum system rates, and will seek approval to roll-in the Sundance Trail Expansion costs in any future rate case with FERC.

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 Northwest’s 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 gas marketing functions within Williams; 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. FERC may periodically audit the books and records of interstate pipelines.

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.

Pursuant to Northwest’s March 30, 2007 rate settlement, Northwest is required to file a new rate case to be effective no 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 December 26, 2007, FERC issued an order on rehearing affirming its prior ruling. FERC indicated that it will continue to review on a case-by-case basis whether a pipeline’s owners have an actual or potential income tax liability and may utilize a normalization approach to reduce a pipeline’s income tax allowance as appropriate. On January 25, 2008, shippers on the pipeline asked FERC to reconsider its income tax allowance policy, including whether such allowance should be permitted at all. On February 15, 2008, FERC responded that the shipper’s income tax allowance issues are complex and will be addressed at a later time.

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 Northwest is unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating its 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 guidance and to obtain public comment on FERC’s policies concerning return on equity determinations, on July 19, 2007, FERC issued a proposed policy statement. In the proposed policy statement, FERC proposed 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.

After receiving public comment on the proposed policy statement, on April 17, 2008, FERC issued a final policy statement which rejected the concept of capping distributions in favor of an adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly traded partnerships which are included in the proxy group.

On January 19, 2009, FERC applied the policy statement to a pipeline rate case and determined that the pipeline’s equity return should be 11.55 percent. It is difficult to know how instructive this case is for purposes of anticipating rates of return in future rate cases, because FERC determined the composition of the proxy group using data from 2004 when the case was filed.

The effect of the application of FERC’s policy to Northwest’s future rate proceedings is not certain, and Northwest cannot ensure that such application would not adversely affect Northwest’s ability to achieve a reasonable level of return on equity.

Energy Policy Act of 2005

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (“EP Act 2005”). Among other matters, EP Act 2005 amends the NGA to add an antimanipulation provision that 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,(i) to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) 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 United States Department of Transportation (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“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 (“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 (“EPA”) 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. 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 and that may have a material impact on Northwest’s business.

Waste Management. Northwest’s operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. 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 receive 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 (“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 that are regulated by TSCA.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) 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 was released into the environment 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 were released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes 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 that 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, compression and 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 (i) remove previously disposed wastes, including waste disposed of by prior owners or operators (ii) remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills or (iii) perform remedial closure operations to prevent future contamination.

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 (i) 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; (ii) application for and strict compliance with air permits containing various emissions and operational limitations; or (iii) 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 (“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 (“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, agencies prepare Environmental Assessments, or more detailed Environmental Impact Statements which assess the potential direct, indirect and cumulative impacts of a proposed project and 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.

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.

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 Part II, Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated 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
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995

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.

All statements, other than statements of historical facts, included in this report, that 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;

	•	financial condition and liquidity;

	•	business strategy;

	•	cash flow from operations or results of operations;


	•	the levels of cash distributions to unitholders;

	•	rate case filings; and

	•	natural gas and natural gas liquids 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 project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:


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

	•	inflation, interest rates, and general economic conditions (including the recent economic slowdown and the disruption of global credit markets and the impact of these events on Northwest’s customers and suppliers);

	•	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;

	•	Northwest’s costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

	•	increasing maintenance and construction costs;

	•	changes in the current geopolitical situation;

	•	Northwest’s exposure to the credit risks of its customers;

	•	risks relating to strategy and financing, including restrictions stemming from Northwest’s debt agreements, future changes in Northwest’s credit rating and the availability and cost of credit;

	•	risks association with future weather conditions;

	•	acts of terrorism; and

	•	additional risks described in our filings with the Securities and Exchange Commission.

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 following:

RISK FACTORS

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

Risks Inherent in Our Industry and Our Business

We may not have sufficient cash from operations to enable us to maintain current levels of cash distributions or 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 maintain current levels of cash distributions or 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 from quarter to quarter 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 expenses 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, which could materially affect the market price of natural gas, which could inturn indirectly affect the longer term supply and demand dynamics of natural gas in Northwest’s areas of operation; 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 percent 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 of, and timeliness of payment from, Northwest’s customers;


	•	restrictions contained in Williams’ and Northwest’s credit agreement and in Northwest’s indentures, including restrictions on distributions; and

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

We may not be able to grow or effectively manage our growth.

A principal focus of our strategy is to continue to grow by expanding our business. Our future growth will depend upon our ability to successfully identify, finance, acquire, integrate and operate projects and businesses. Failure to achieve any of these factors would adversely affect our ability to achieve anticipated growth in the level of cash flows or realize anticipated benefits.

We may acquire new facilities or Northwest may expand its existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into Northwest’s operations may result in unforeseen operating difficulties, may absorb significant management attention and may require financial resources that would otherwise be available for the ongoing development and expansion of our existing operations. Future acquisitions or construction projects may require substantial new capital and could result in the incurrence of indebtedness, additional liabilities and excessive costs that could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders. If we issue additional common units in connection with future acquisitions, unitholders’ interest in us will be diluted and distributions to unitholders may be reduced. Further, any limitations on our access to capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all.

Events in the global financial crisis have made equity and debt markets less accessible and created a shortage in the availability of credit, which could disrupt our financing plans and limit our ability to grow.

In 2008 public equity markets experienced significant declines and global credit markets have experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Under current market conditions, it is unclear whether we could issue additional equity or debt securities or, even if we were able, whether we could do so at prices and pursuant to terms that would be acceptable to us. Continuing volatility or additional disruptions in the global financial marketplace, including the bankruptcy or restructuring of certain financial institutions, could make equity and debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future.

As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance growth projects. We distribute all of our available cash to our unitholders on a quarterly basis. We typically rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund acquisitions or expansion capital expenditures. Any limitations on our access to external capital, including limitations caused by illiquidity in the capital markets, may impair our ability to complete future acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a competitive disadvantage as compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under current economic conditions.

The continuation of recent economic conditions, including disruptions in the global credit markets, could adversely affect our results of operations.

The slowdown in the economy and the significant disruptions and volatility in global credit markets have the potential to negatively impact our business in many ways. Included among these potential negative impacts are reduced demand and lower prices for Northwest’s products and services, increased difficulty in collecting amounts owed to Northwest by its customers and a reduction in Northwest’s credit ratings (either due to tighter rating standards or the negative impacts described above), which could result in reducing Northwest’s and our access to credit markets, raising the cost of such access or requiring Williams, Northwest or us to provide collateral to third parties.

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 percent general partnership interest in Northwest is our sole asset and therefore Northwest generates 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 percent 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 percent 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:


	•	fires, blowouts, cratering and explosions;

	•	uncontrolled releases of natural gas;

	•	pollution and other environmental risks;

	•	natural disasters;

	•	aging pipeline infrastructure and mechanical problems;

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

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

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. In accordance with customary industry

practice, Northwest maintains insurance against some, but not all, of these risks and losses, and only at levels they believe to be appropriate. 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, particularly if the event is not fully covered by insurance. 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.

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. 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 could have 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, or increase the demand for, 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. 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 terms of existing transportation and storage contracts expire and are subject to termination. Although none of Northwest’s material contracts are terminable in 2009, upon expiration of the 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 interstate transportation and storage services and related assets are subject to regulation by FERC. The federal regulation extends to such matters as:


	•	transportation and sale for resale of natural gas in interstate commerce;

	•	rates, operating terms and conditions of service, including initiation and discontinuation of services;

	•	the types of services Northwest may offer to its customers, including initiation and discontinuation of services;

	•	certification and construction of new facilities;

	•	acquisition, extension, disposition or abandonment of facilities;

	•	accounts and records;

	•	depreciation and amortization policies;

	•	relationships with marketing functions within Williams involved in certain aspects of the natural gas business; 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 interstate providers of natural gas pipeline transportation and storage services and such providers may only charge rates that have been determined to be just and reasonable by FERC. In addition, FERC prohibits providers from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

Regulatory actions in these areas can affect Northwest’s business in many ways, including decreasing tariff rates and revenues, deceasing volumes in Northwest’s pipelines, increasing Northwest’s costs and otherwise altering the profitability of Northwest’s business.

The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and “marketing function employees” as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting their gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from marketing function employees and by restricting the information that transmission providers may provide to gas marketing employees. The inefficiencies created by the restrictions on the sharing of employees and information may increase our costs, and the restrictions on the sharing of information may have an adverse impact on our senior management’s ability to effectively obtain important information about our business. Violators of these rules are subject to potentially substantial civil penalty assessments.

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 Northwest’s most recent 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 future rate cases to set the rates Northwest can charge customers on its pipeline might result in rates that lower Northwest’s return on the capital that Northwest has invested in its pipeline.

There is a risk that the rates set by FERC will be inadequate to recover increases in operating costs or to sustain 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.

Legal and regulatory proceedings and investigations relating to the energy industry and capital markets have adversely affected our business and may continue to do so.

Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings in which Northwest or its affiliates are named as defendants. Both the shippers on Northwest’s pipeline and regulators have rights to challenge the rates Northwest charges under certain circumstances. Any successful challenge could materially affect Northwest’s results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Northwest might see adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, Northwest cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against Northwest, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of Northwest’s business and revenues and net income or increase Northwest’s operating costs in other ways. Current legal proceedings or other matters against Northwest including environmental matters, disputes over gas measurement and royalty payments, suits, regulatory appeals and similar matters might result in adverse decisions against Northwest. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

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. The development of the additional natural gas reserves requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to Northwest. Low prices for natural gas, regulatory limitations or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transmission and import and export of natural gas supplies, adversely impacting Northwest’s ability to fill the capacities of its gathering, transmission and processing facilities.

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 pipelines to serve other markets could reduce the amount of natural gas supply for Northwest’s customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on Northwest’s pipeline and cash flows associated with the transportation of natural gas, Northwest’s customers must compete with others to obtain adequate supplies of natural gas.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas transported and stored on 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.

Decreases in demand for natural gas could adversely affect Northwest’s business.

Demand for Northwest’s transportation services depends on the ability and willingness of shippers with access to Northwest’s facilities to satisfy their demand by deliveries through Northwest’s system. Any decrease in this demand could adversely affect Northwest’s business. Demand for natural gas is also affected by weather, future industrial and economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, or technological advances in fuel economy and energy generation devices, all of which are matters beyond our and Northwest’s control. Additionally, in some cases, new LNG import facilities built near Northwest’s markets could result in less demand for Northwest’s transmission facilities.

Significant prolonged changes in natural gas prices could affect supply and demand, cause a termination of Northwest’s transportation and storage contracts or a reduction in 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 new sources of natural gas production or LNG import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for Northwest’s services.

New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future natural gas supplies in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed natural gas prices could increase and 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, 2008, Northwest’s largest customer was Puget Sound Energy, Inc. This customer accounted for approximately 20.7 percent of Northwest’s operating revenues for the year ended December 31, 2008. The loss of even a portion of Northwest’s contracted volumes, as a result of competition, creditworthiness, inability to negotiate contract 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, unless Northwest is able to acquire comparable volumes from other sources.

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, increased credit requirements or rates charged by such pipelines or facilities 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. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants. 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 is exposed to the credit risks of its customers.

Northwest is exposed to the credit risk of its customers in the ordinary course of its business. Generally Northwest’s customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, Northwest cannot predict to what extent its business would be impacted by deteriorating conditions in the economy, including declines in Northwest’s customers’ creditworthiness. While Northwest monitors these situations carefully and attempts to take appropriate measures to protect itself, it is possible that Northwest may have to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect Northwest’s operating results for the period in which they occur, and, if significant, could have a material adverse effect on its operating results and financial condition.

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 restrict or 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 under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of 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, 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.

Northwest’s ability to repay, extend or refinance its existing debt obligations and to obtain future credit will depend primarily on its operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our or its control. Northwest’s ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If Northwest is unable to meet its debt service obligations or obtain future credit on favorable terms, if at all, Northwest could be forced to restructure or refinance its indebtedness, seek additional equity capital or sell assets. Northwest may be unable to obtain financing or sell assets on satisfactory terms, or at all.

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, 2008, Northwest had no loans outstanding under its credit agreement, and approximately $693.2 million in outstanding senior notes which are not consolidated on our balance sheet. If permitted under Northwest’s credit agreement and its 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.

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 them to significant costs and liabilities and could exceed current expectations.

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, 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 the federal Resource Conservation and Recovery Act, 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 may be subject to legislative and regulatory responses to climate change with which compliance may be costly.

Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and similar federal legislation has been introduced in both houses of Congress. Northwest’s pipeline may be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If Northwest is unable to recover all costs related to complying with climate change regulatory requirements imposed on them, it could have a material adverse effect on Northwest’s results of operations and on our ability to make distributions to you. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact Northwest’s costs of and access to capital.

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. As such, we are subject to the possibility of increased costs to retain necessary land use. Northwest obtains, in certain circumstances, 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 with limited terms. Northwest does not have the right of eminent domain over land owned by Native American tribes. Northwest’s loss of any of these rights, through its inability to renew right of way 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.

Northwest’s costs and funding obligations for defined benefit pension plans and costs for other postretirement benefit plans, in which it participates, are affected by factors beyond its control.

Northwest is a participating employer in defined benefit pension plans covering substantially all of its U.S. employees and other postretirement benefit plans covering certain eligible participants. The timing and amount of Northwest’s funding allocation requirements under the defined benefit pension plans in which it participates depends upon a number of factors Williams controls, including changes to pension plan benefits as well as factors outside of its control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase Northwest’s funding allocations requirements could have a significant adverse effect on its financial condition. The amount of expenses recorded for the defined benefit pension plans and other postretirement benefit plans, in which Northwest participates, is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact Northwest’s future results of operations.

We and Northwest do not insure against all potential losses and could be seriously harmed by unexpected liabilities or by the inability of the insurers we do use to satisfy our claims.

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 $300 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, Rita, Gustav and Ike 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.

In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any potential claims. As a result, we could be exposed to greater losses than anticipated and replacement insurance may have to be obtained, at a greater cost, if available.

Execution of Northwest’s capital projects subjects them to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.

A significant portion of Northwest’s growth is accomplished through the construction of new transportation and storage facilities, as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:


	•	the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms;

	•	the availability of skilled labor, equipment, and materials to complete expansion projects;

	•	potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;

	•	impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms;

	•	the ability to construct projects within estimated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor or other factors beyond our control, that may be material; and

	•	the ability to access capital markets to fund construction projects.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve expected investment return, which could adversely affect Northwest’s results of operations, financial position or cash flows and our ability to make distributions to you.

Northwest’s assets and operations can be affected by weather and other natural phenomena.

Northwest’s assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions including extreme temperatures, making it more difficult for Northwest to realize the historic rates of return associated with these assets and operations and adversely affecting our ability to make distributions to you. Insurance may be inadequate, and in some instances, Northwest may be unable to obtain insurance on commercially reasonable terms, if at all. A significant disruption in operations or a significant liability for which Northwest was not fully insured could have a material adverse effect on its business, results of operations and financial condition, and on our ability to make distributions to you.

In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. Northwest’s customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

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 disrupt 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 environmental repercussions that could result in a significant decrease in revenues or

significant reconstruction or remediation costs, which could have a material adverse effect on Northwest’s financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

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

Failure of or disruptions to Northwest’s outsourcing relationships might negatively impact its ability to conduct its business.

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

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

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

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms and retirement plan practices. 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 (FASB), the SEC or the FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

Risks 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, among others, the following factors:


	•	neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us;

	•	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 percent general partnership interest in Northwest;

	•	Williams owns common and subordinated units representing an aggregate 45.7 percent 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;

	•	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;

	•	our general partner determines the amount and timing of our cash reserves, asset purchases and sales, borrowings and issuances of additional partnership securities, 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 with respect to its 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 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 required 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 percent of the common units;

	•	our general partner controls the enforcement of obligations owed to us by it 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, its voting rights with respect to the units it owns, its registration rights, 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, its affiliates and their officers and directors will not be liable for monetary damages to us or 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; 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 L.P. (“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 percent) 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. Our general partner determines the amount of these distributions 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 two-thirds 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 percent of our outstanding common and subordinated units. Accordingly, our unitholders cannot remove

our general partner without its consent because our general partner owns 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.

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 percent general partnership interest in Northwest. We have no significant assets other than our 100 percent ownership of our operating company, and its 35 percent 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.

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.

Common units held by our general partner eligible for future sale may adversely affect the price of our common units.

Our general partner holds an aggregate of 4,700,668 common units and 10,957,900 subordinated units. Our general partner may from time to time, sell all or a portion of its common units or subordinated units. Sales of

substantial amounts of its common units or subordinated units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

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 percent 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 percent 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 percent of our outstanding common units.

Our partnership agreement restricts the voting rights of unitholders owning 20 percent 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 percent 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 percent 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 Internal Revenue Service (“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 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 percent, 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.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any jurisdiction were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced. The 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.

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) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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.

We prorate our items of income, gain, loss and deduction between transferors and transferees of the common 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 common 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 applicable 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 and our general partner.

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 our counsel’s conclusions or from the federal income tax 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, the costs of any contest with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our general partner, and thus will be borne indirectly by our unitholders and our general partner.

Tax-exempt entities and non-U.S. 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 (known as IRAs), and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to the unit holders who are organizations that are exempt from federal income tax, including IRAs and other retirement plans, may be taxable to them as “unrelated business taxable income”. 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 have adopted 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 current valuation methods, 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 valuation 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 being 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 percent or more of our capital and profits interests within any 12-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 percent or more of the total interests in our capital and profits within a 12-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 would be required to 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, such as 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 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. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. It is your responsibility to file all 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 2.	*Properties*

Northwest owns its system in fee simple. However, a substantial portion of that 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.


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.*


a)	Market Information

Our equity consists of a 2 percent general partner interest and a 98 percent limited partner interest. Our limited partner interests are represented by our common units, which are listed on the New York Stock Exchange (“NYSE”) under the trading symbol “WMZ.” The following table sets forth the high and low closing prices of our common units:


2008	High		Low

Fourth Quarter	$	16.00	$	11.57
Third Quarter		17.54		13.59
Second Quarter		18.86		17.26
First Quarter(1)		20.42		15.89


(1)		Represents the period from January 24, 2008, the date that the Partnership completed its IPO.


(b)	Holders

On February 23, 2009, there were 22,607,430 common units outstanding, held by approximately 5 holders of record and 400 beneficial holders, including common units held in street name and by affiliates of Williams.

On February 23, 2009, there were 10,957,900 subordinated units outstanding held by a subsidiary of Williams. The subordinated units are not publicly traded.


(c)	Cash Distributions

The following table sets forth the quarterly cash distribution declared and paid on our common units during the periods indicated:


2008	Cash Distribution per Unit(a)

Fourth Quarter	$	0.3200
Third Quarter		0.3150
Second Quarter		0.3100
First Quarter(b)		0.2242


(a)		Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its 2 percent general partner interest that totaled $0.8 million in 2008. Subordinated units participated in all of the cash distributions for the periods indicated above.

(b)		The first quarter distribution was prorated to cover the period of time from January 24, when the partnership’s initial public offering closed, through March 31. The prorated distribution of $0.2242 equates to a full quarter distribution of $0.30 per unit.

Cash Distribution Policy

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ended 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 percent 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 percent, of the cash we distribute from operating surplus in excess of $0.2875 per unit per quarter. The maximum distribution of 50 percent includes distributions paid to our general partner on its 2 percent general partner interest and assumes that our general partner maintains its general partner interest at 2 percent. The maximum distribution of 50 percent 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 percent 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 percent 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 percent to the common unitholders, pro rata, and 2 percent 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 percent to the common unitholders, pro rata, and 2 percent 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 percent to the subordinated unitholders, pro rata, and 2 percent 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 percent to all common and subordinated unitholders, pro rata, and 2 percent 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 percent to all common and subordinated unitholders, pro rata, and 15 percent 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 percent to all common and subordinated unitholders, pro rata, and 25 percent 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 percent to all common and subordinated unitholders, pro rata, and 50 percent to our general partner.


(d)	Securities Authorized for Issuance Under Equity Compensation Plans

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.


Item 6.	*Selected Financial Data*

The following tables show (i) selected financial data of Williams Pipeline Partners and Predecessor (which reflects a 35 percent ownership interest in Northwest) and (ii) selected financial and operating data of Northwest. The following financial data as of December 31, 2008 and 2007, and for the years ended December 31, 2008, 2007 and 2006 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 L.P. and/or Predecessor


	Years Ended December 31,
	2008		2007		2006		2005		2004
			(Predecessor)		(Predecessor)		(Predecessor)		(Predecessor)
	(Thousands of dollars)

Income Statement Data:
Equity earnings from investment in Northwest	$	54,380	$	153,904	$	19,062	$	24,141	$	25,891
Net income		51,880		153,904		19,062		24,141		25,891
Balance Sheet Data (at period end):
Investment in Northwest		414,069		414,966		300,281		264,721		258,080
Total partners’ capital		422,013		414,966		300,281		264,721		258,080
Basic and diluted net income per limited partner unit:
Common units	$	1.43
Subordinated units	$	1.43
Cash Dividends Declared	$	0.8492

Northwest (100%)


	Years Ended December 31,
	2008		2007			2006		2005		2004
	(Thousands of dollars)

Income Statement Data:
Operating revenues	$	434,854	$	421,851		$	324,250	$	321,457	$	338,532
Net income		155,371		439,726	(A)		54,462		68,974		73,974
Balance Sheet Data (at period end):
Total assets		2,082,172		2,056,471			2,049,324		1,692,371		1,670,499
Long-term debt, including current maturities		693,240		693,736			687,075		520,080		527,562
Total Owners’ equity		1,184,714		1,185,616			857,945		756,346		737,372
Cash Distributions		419,342		109,770			—		50,000		60,000

Note: Earnings and distributions/dividends per partnership unit/common share are not presented for 2004 through 2008. Northwest was a wholly-owned subsidiary of Williams as of December 31, 2007 and for all prior periods presented. Distributions for 2008 were made to Northwest’s partners based upon each partner’s ownership interest.


(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 deferred income tax liabilities of


		approximately $311.8 million to income and $10.2 million of deferred income tax assets to comprehensive income.


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*

Overview

We are a growth-oriented Delaware limited partnership formed on August 31, 2007 by Williams to own and operate natural gas transportation and storage assets. We own a 35 percent 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 12.8 Bcf. The remaining 65 percent 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, that 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 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, 2008, approximately 5.7 percent were derived from short-term firm and interruptible services.

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, 2008:


2008	Jan-Mar			Apr-Jun			Jul-Sep			Oct-Dec			Total

Revenues ($ in 000)	$	107,405		$	106,450		$	108,542		$	112,457		$	434,854
Revenue%		24.7	%		24.5	%		25.0	%		25.8	%		100	%
Operating Expenses ($ in 000)	$	58,239		$	59,774		$	55,500		$	60,163		$	233,676
Throughput (TBtu)(1)		220			171			179			211			781
Throughput%		28.2	%		21.9	%		22.9	%		27.0	%		100	%


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

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 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 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of Northwest’s business and to comply with any applicable law or agreement.

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 in “Narrative Description of Business” in Part I, Item 1. Business, play an important role in how Northwest manages its operations and implements its long-term strategies.

We believe the collective impact of these key factors 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 also believe the impact of the such factors described in “Northwest’s Customers” and “Northwest’s Competition” in Part I, Item 1. Business, 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.

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, 2008, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 Bcf of natural gas per day. Northwest also has approximately 12.8 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 that 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.

Recent Market Events

The recent instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. In this volatile economic environment, many financial markets, institutions and other businesses remain under considerable stress. These events are impacting our business. However, we note the following:


	•	Northwest has no significant debt maturities until 2016.

	•	As of December 31, 2008, Northwest had approximately $66.0 million of available cash from return of advances made to affiliates and available capacity under its Credit Facility. (See further discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity of Northwest.)

	•	A significant portion of Northwest’s transportation and storage services are provided pursuant to long-term firm contracts that obligate its customers to pay them monthly capacity reservation fees regardless of the amount of pipeline or storage capacity actually utilized by a customer.

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. See Part 1, Item 1. Business — Capital Projects.

The overall decline in the equity markets in 2008 negatively impacted the Williams employee benefit plan assets and will increase our net periodic benefit expense in future periods. (See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 5. Employee Benefit Plans).

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

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.

Pension and Postretirement Obligations

Northwest’s consolidated affiliate participates in the Williams’ sponsored employee benefit plans along with Williams and its subsidiaries that include pension and other postretirement benefits. Net periodic 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 cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.

Northwest’s Results of Operations

In the following discussion of the results of Northwest, all amounts represent 100 percent of the operations of Northwest, in which we hold a 35 percent general partnership interest. As such, we recognized equity earnings from investments of $54.4 million for 2008 compared with $153.9 million (Predecessor) for 2007.

Analysis of Financial Results

This analysis discusses financial results of Northwest’s operations for the years 2008, 2007 and 2006. 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.


	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)

Income Statement Data:
Operating revenues	$	434,854		$	421,851		$	324,250
Operating expenses:
General and administrative		60,403			65,772			56,463
Operation and maintenance		72,831			66,847			65,763
Depreciation		86,184			84,731			79,488
Regulatory credits		(2,617	)		(3,663	)		(4,469	)
Taxes, other than income taxes		16,875			13,997			15,018
Regulatory liability reversal		—			(16,562	)		—

Total operating expenses		233,676			211,122			212,263

Operating income		201,178			210,729			111,987

Other income (net)		1,623			25,437			16,597

Interest charges:
Interest on long-term debt		42,290			46,828			43,649
Other interest		5,571			5,585			3,824
Allowance for borrowed funds used during construction		(431	)		(1,306	)		(4,557	)

Total interest charges		47,430			51,107			42,916

Income before income taxes		155,371			185,059			85,668
Provision for (benefit) income taxes		—			(254,667	)		31,206

Net income	$	155,371		$	439,726		$	54,462

2008 vs. 2007

Operating revenues increased $13.0 million, or 3 percent, for the year ended December 31, 2008 as compared to the year ended December 31, 2007. This increase is attributed to a $3.9 million increase from the Parachute Lateral, placed into service in May 2007, and a $5.2 million increase from short-term firm transportation services, with the balance of the increase primarily attributed to certain small customers converting to large customer status resulting in higher reservation charges and to higher transportation volumes.

Northwest’s transportation service accounted for 96 percent of its operating revenues for each of the years ended December 31, 2008 and 2007. Natural gas storage service accounted for 3 percent of operating revenues in each of the years ended December 31, 2008 and 2007.

Operating expenses increased $22.6 million, or 11 percent, from 2007 to 2008. This increase is due primarily to the June 2007 reversal of Northwest’s pension regulatory liability of $16.6 million, and the new Parachute Lateral lease of $10.1 million which began January 1, 2008. Also contributing were higher use taxes of $1.0 million attributed primarily to the 2007 reversal of $0.8 million of accrued use taxes resulting from the settlement of prior year audits, and higher depreciation of $1.5 million and ad valorem taxes of $1.6 million resulting from property additions. These increases were partially offset by lower expenses of $5.0 million for contracted services attributed primarily to pipeline maintenance, lower overhead allocated by Williams of $2.0 million and lower bonus accruals

and deferred compensation of $1.0 million primarily attributed to lower bonus and deferred compensation levels in 2008.

Operating income decreased $9.6 million, or 5 percent, from 2007 to 2008, due to the reasons discussed above.

Other income decreased $23.8 million, or 94 percent, from 2007 to 2008, primarily due to the recognition in 2007 of $6.0 million of previously deferred income, the receipt of $12.2 million additional contract termination income, and $2.3 million additional interest related to the termination of the Grays Harbor transportation agreement. Also contributing to this decrease were a $2.2 million decrease in interest income from affiliates resulting primarily from lower interest rates and a $2.3 million decrease in the allowance for equity funds used during construction (“EAFUDC”) resulting from the lower capital expenditures in 2008 and the discontinuance of EAFUDC gross-ups after Northwest’s conversion to a partnership on October 1, 2007. These decreases were partially offset by the $1.3 million write-off of a regulatory asset associated with the Parachute Lateral in 2007.

Interest charges decreased $3.7 million, or 7 percent, from 2007 to 2008, due primarily to the April 2007 early retirement of $175.0 million of 8.125 percent senior unsecured notes, the December 2007 refinancing of $250.0 million of 6.625 percent senior unsecured notes with $250.0 million revolver debt at lower interest rates, and the May 2008 refinancing of the $250.0 million revolver debt with the issuance of $250.0 million of 6.05 percent senior unsecured notes. This decrease was partially offset by the April 2007 issuance of $185.0 million of 5.95 percent senior unsecured notes and a $0.9 million decrease in the allowance for borrowed funds used during construction resulting from lower capital expenditures in 2008.

The benefit for income taxes decreased $254.7 million to $0 from 2007 to 2008 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 percent. At the date of conversion, Northwest recognized income tax benefit of $311.8 million reflecting the removal of its net deferred tax liabilities.

2007 vs. 2006

Operating revenues increased $97.6 million, or 30 percent, for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Higher rates resulting from 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 percent of its operating revenues for each of the years ended December 31, 2007 and 2006. Natural gas storage service accounted for 3 percent of operating revenues for each of the years ended December 31, 2007 and 2006.

Operating expenses decreased $1.1 million, or 1 percent, from 2006 to 2007. This decrease was due primarily to the June 2007 reversal of 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 percent, from 2006 to 2007, due to the reasons discussed above.

Other income increased $8.8 million, or 53 percent, from 2006 to 2007, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million 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 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 percent, from 2006 to 2007, due to a $3.3 million decrease in the allowance for borrowed funds used during construction related to the lower capital expenditures in 2007, the issuance of $175.0 million of 7 percent senior unsecured notes, due 2016, in June of 2006, and the issuance of $185.0 million of 5.95 percent senior unsecured notes, due 2017, in April of 2007, partially offset by the early retirement of $175.0 million of 8.125 percent senior unsecured notes, due 2010, in April of 2007. A $1.8 million increase in other interest resulting from higher amortization of loss on reacquired debt related to the early debt retirement and the refinancing of $250.0 million of 6.625 percent 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 percent compared to 36.4 percent 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.

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, available cash is 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.

In January 2008, Northwest distributed $8.8 million to Williams representing available cash prior to our acquisition of our interest in Northwest. During 2008, Northwest declared and paid equity distributions of $109.6 million to its partners. Of this amount, $7.8 million represents the portion allocated to its partners prior to our acquisition. In January 2009, Northwest declared and paid equity distributions of $32.0 million to its partners.

Northwest funds its capital requirements with cash from operating activities, with third-party debt or with contributions from Northwest’s 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,
	2008			2007			2006
	(Thousands of dollars)

Net cash provided (used) by:
Operating activities	$	239,014		$	205,357		$	159,807
Financing activities		(126,848	)		(142,523	)		266,919
Investing activities		(112,318	)		(63,826	)		(484,946	)

Decrease in cash and cash equivalents	$	(152	)	$	(992	)	$	(58,220	)

Operating Activities

Northwest’s net cash provided by operating activities in 2008 increased from 2007 due primarily to the increase in its cash operating results, offset by the absence of the receipt of contract terminations proceeds of $14.5 million in 2007, and from changes in working capital.

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.

Financing Activities

2008


	•	Northwest issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018.

	•	Northwest repaid the $250 million borrowed under the Williams’ revolving credit agreement in 2007.

	•	Northwest received proceeds of $300.9 million from the sale of partnership interest.

	•	Northwest paid distributions of $419.3 million to its partners.

2007


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

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

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

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

	•	Northwest paid distributions of $109.8 million to Williams.

2006


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

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

Investing Activities

2008


	•	Capital expenditures totaled $78.6 million primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility.

	•	Northwest advanced $26.9 million to Williams.

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.

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.

During 2008, Northwest made distributions of available cash of $419.3 million to its partners, representing cash in excess of working capital requirements and reserves established by its management committee as necessary for the conduct of its business.

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, 2008 and 2007, the advances due to Northwest by Williams totaled approximately $66.0 million and $39.1 million, respectively. The advances are represented by one or more demand obligations. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rates on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately zero percent at December 31, 2008. Williams has indicated that it currently believes that it will continue to have the financial resources and liquidity to repay these advances.

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 (“LIBOR”) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $71.0 million, none of which are associated with Northwest, have been issued by the participating institutions. Northwest had no revolving credit loans outstanding as of December 31, 2008. In December 2007, Northwest borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250 million was repaid with proceeds from the issuance of $250 million of 6.05 percent senior unsecured notes due 2018. Northwest did not borrow under the agreement in 2008.

Lehman Commercial Paper Inc., which was committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction. See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements.

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’s shelf registration statement on file with the SEC expired on December 1, 2008. Northwest may 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. Historically, Northwest has been able to access public and private markets on terms commensurate with its credit ratings to finance its capital requirements, when needed. However, as a result of credit market conditions, this source of funding was considered economically unfavorable at December 31, 2008.

Capital Requirements

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

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 2009 capital expenditures will be between $125 million and $160 million of which includes $75 million to $90 million for maintenance capital and $100 million to $135 million considered nondiscretionary due to legal, regulatory and/or contractual requirements. The maintenance capital portion of Northwest’s 2008 capital expenditures was $61.3 million. In 2009, Northwest expects to fund its capital expenditures with cash from operations and repayment of advances to affiliate, with the exception of the CHC Project which will be funded by capital contributions from Williams.

Northwest’s expenditures for property, plant and equipment additions were $78.6 million, $157.2 million and $473.6 million for 2008, 2007 and 2006 respectively. The decrease in expenditures from 2006 to 2007 was primarily due to the completion of the Capacity Replacement Project 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.

Credit Ratings

During 2008, the credit ratings on Northwest’s senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below:


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

At December 31, 2008, and through the date of this report, the evaluation of Northwest’s credit rating is “stable outlook” from Standard and Poor’s. On November 6, 2008, Moody’s Investors Service (“Moody’s”) and Fitch Ratings (“Fitch”) changed the ratings outlook for Williams and each of Williams’ rated subsidiaries, including Northwest, to “negative” and “evolving” respectively. On February 23, 2009, Moody’s revised Northwest’s ratings outlook to “stable” from “negative” and on February 24, 2009, Fitch revised Northwest’s rating outlook to “stable” from “evolving”.

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

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

With respect to Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. A “BB” rating from Fitch indicates that there is a possibility of credit risk developing, particularly as the result of adverse economic change over time; however, business or financial alternatives may be available to allow financial commitments to be met. Fitch may add a “+” or a “−” sign to show the obligor’s relative standing within a major rating category.

Contractual Obligations

The table below summarizes the maturity dates of Northwest’s more significant contractual obligations and commitments as of December 31, 2008 (in millions of dollars):


	2009		2010-2011		2012-2013		Thereafter		Total

Long-term debt, including current portion:
Principal	$	—	$	—	$	—	$	695.0	$	695.0
Interest		44.4		88.9		88.9		209.9		432.1
Operating leases		13.9		7.5		7.5		18.8		47.7
Purchase obligations:
Natural gas purchase, storage, transportation and construction		28.4		4.9		2.0		—		35.3
Other		1.6		0.3		0.2		—		2.1
Other long-term liabilities, including current portion(1)(2)(3)		1.5		3.0		3.0		1.7		9.2

Total	$	89.8	$	104.6	$	101.6	$	925.4	$	1,221.4


(1)		Does not include estimated contributions to the pension and other postretirement benefit plans. Northwest made contributions to the pension and other postretirement benefit plans of $7.8 million in 2008, $3.2 million in 2007, and $5.7 million in 2006. (See Item 8. Financial Statements — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 5. Employee Benefit Plans.) The 2008 economic downturn resulted in a significant decrease in the funded status of the Williams sponsored tax-qualified pension plans. As a result, Northwest anticipates that future contributions to these pension plans may vary significantly from historical contributions if investment returns do not return to expected levels. Future contributions may also be impacted if actual results differ significantly from estimated results or assumptions such as interest rates, retirement rates, mortality and other significant assumptions or by changes to current legislation and regulations.

(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.

Impact of Inflation

Northwest has generally experienced increased costs in recent years due to the effect of inflation on the cost of labor, benefits, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies costs can directly affect income through increased operating and maintenance costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of the costs related to 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 Northwest’s ability to price services or products to ensure recovery of inflation’s effect on costs.

Environmental Matters

As discussed in Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements, 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

Please see Item 8. Financial Statements and Supplemental Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 3 Contingent Liabilities and Commitments.

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

Please see 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.

Summary

Litigation, arbitration, regulatory matters, environmental matters, and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there may be a material adverse impact on the results of operations in the period in which the ruling occurs. Northwest’s 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, and other indemnification arrangements, will not have a material adverse effect on Northwest’s future financial position.

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. As of December 31, 2008, we had cash and cash equivalents of $7.8 million.

We may invest cash through participation in Williams’ cash management program. Any 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 zero percent at December 31, 2008.

Northwest Distributions

Capital Contributions from Williams

Capital contributions from Williams required under the omnibus agreement consist of a quarterly credit for general and administrative expenses. The annual amounts of those credits are as follows: $2.0 million in 2008 (pro-rated for the portion of the year from January 24 to December 31), $1.5 million in 2009, $1.0 million in 2010 and $0.5 million in 2011.

Credit Facility

At the closing of the IPO on January 24, 2008, 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 was January 23, 2009. We exercised our automatic right to extend the facility for an additional 365-day term in January. The new maturity date is January 23, 2010. The interest rate on all borrowings will be the one-month LIBOR determined the date of the borrowing. The borrowings may be repaid prior to the end of the one-month LIBOR rate period. If a borrowing is not repaid within one month, the interest rate for such borrowing will be adjusted to the one-month LIBOR rate 30 days after the most recent borrowing. We pay a commitment fee to Williams on the unused portion of the credit agreement of 0.25 percent 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. At December 31, 2008, we have no outstanding borrowings under the working capital credit facility.

Cash Distributions to Unitholders

We have paid quarterly distributions to unitholders and our general partner after every quarter since our IPO on January 24, 2008. Our last quarterly distribution of $11.0 million was paid on February 13, 2009 to unitholders of record at the close of business on February 6, 2009.

Conclusion

We typically expect to fund our acquisitions or expansion capital expenditures primarily through commercial borrowings or the sale of debt or equity securities. However, beginning in the last half of 2008, public equity markets have experienced significant declines and global credit markets have experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Under current market conditions, it is unclear whether we could issue additional equity or debt securities or, even if we were able, whether we could do so at prices and pursuant to terms that would be acceptable to us.


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

Interest Rate Risk

Our interest rate 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, 2008

Fixed rates on long-term debt:
5.95% senior unsecured notes due 2017	$	185,000
6.05% senior unsecured notes due 2018		250,000
7.00% senior unsecured notes due 2016		175,000
7.125% senior unsecured notes due 2025		85,000

		695,000
Unamortized debt discount		1,760

Total long-term debt	$	693,240

Northwest’s total long-term debt at December 31, 2008 had a carrying value of $693.2 million and a fair market value of $572.0 million. As of December 31, 2008 the weighted-average interest rate on Northwest’s long-term debt was 6.4 percent. Northwest expects to have sensitivity to interest rate changes with respect to future debt facilities and its ability to prepay existing facilities.

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.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, our internal control over financial reporting was effective.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Williams Pipeline GP LLC

We have audited the accompanying consolidated balance sheets of Williams Pipeline Partners L.P. as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. 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 Williams Pipeline Partners L.P. at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 in conformity with U.S. generally accepted accounting principles.

Ernst & Young LLP

Houston, Texas

February 23, 2009

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2008			2007		2006
				(Predecessor)		(Predecessor)
	(Thousands of dollars, except per-unit amounts)

General and administrative expense	$	2,520		$	—	$	—
Earnings from Northwest Pipeline GP through January 23, 2008 (Predecessor)		4,002			153,904		19,062
Equity earnings from investment in Northwest Pipeline GP after January 23, 2008		50,378			—		—
Interest expense — affiliate		(47	)		—		—
Interest income		67			—		—

Net income	$	51,880		$	153,904	$	19,062

Allocation of 2008 net income used for earnings per unit calculation:
Net income	$	51,880
Net income applicable to the period through January 23, 2008		4,002

Net income applicable to the period after January 23, 2008		47,878
Allocation of net income (loss) to general partner		2

Allocation of net income to limited partners	$	47,876

Basic and diluted net income per limited partner unit:
Common units	$	1.43
Subordinated units	$	1.43
Weighted average number of units outstanding:
Common units		22,606,010
Subordinated units		10,957,900

See accompanying notes to consolidated financial statements.

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
				(Predecessor)
	(Thousands of dollars)

ASSETS
Current assets:
Cash and cash equivalents	$	7,760		$	—
Prepaid expense		184			—

Total current assets		7,944			—
Investment in Northwest Pipeline GP		414,069			414,966
Deferred costs		—			1,689

Total assets	$	422,013		$	416,655


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade	$	671		$	—
Affiliate		424			1,689

Total current liabilities		1,095			1,689
Contingent liabilities and commitments
Partners’ capital:
Common unitholders (22,607,430 units outstanding at December 31, 2008)		287,269			—
Subordinated unitholders (10,957,900 units outstanding at December 31, 2008)		138,835			—
Accumulated other comprehensive loss		(13,863	)		—
General partner		8,677			414,966

Total partners’ capital		420,918			414,966

Total liabilities and partners’ capital	$	422,013		$	416,655

See accompanying notes to consolidated financial statements.

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2008			2007			2006
				(Predecessor)			(Predecessor)
	(Thousands of dollars)

OPERATING ACTIVITIES:
Net income	$	51,880		$	153,904		$	19,062
Adjustments to reconcile to cash provided by operations:
Equity earnings from investment in Northwest Pipeline GP		(54,380	)		(153,904	)		(19,062	)
Distributions related to equity earnings from investment in Northwest Pipeline GP		41,454			—			—
Cash provided (used) by changes in assets and liabilities:
Other current assets		(184	)		—			—
Accounts payable		1,095			—			—
Other		114			—			—

Net cash provided by operating activities		39,979			—			—

INVESTING ACTIVITIES:
Purchase of 15.9% general partnership interest in Northwest Pipeline GP		(300,900	)		—			—

Net cash used by investing activities		(300,900	)		—			—

FINANCING ACTIVITIES:
Distributions paid		(34,896	)		—			—
Proceeds from sale of common units		336,520			—			—
Offering costs		(3,797	)		—			—
Redemption of common units held by general partner		(31,020	)		—			—
Contribution pursuant to the omnibus agreement		1,874			—			—

Net cash provided by financing activities		268,681			—			—

Increase in cash and cash equivalents		7,760			—			—
Cash and cash equivalents at beginning of period		—			—			—

Cash and cash equivalents at end of period	$	7,760		$	—		$	—

SCHEDULE OF NONCASH FINANCING ACTIVITIES:
Contribution of 19.1% in Northwest Pipeline GP	$	(115,020	)	$	—		$	—
Issuance of units to Williams Pipeline GP LLC		115,020			—			—

See accompanying notes to consolidated financial statements.

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL


													Accumulated
	Pre-IPO												Other			Total
	Owner’s			Limited Partner						General			Comprehensive			Partners’
	Equity			Common			Subordinated			Partner			Income			Capital
	(Thousands of dollars)
	(Unaudited)
Balance — January 1, 2006 (Predecessor)	$	264,721		$	—		$	—		$	—		$	—		$	264,721
Net income		19,062			—			—			—			—			19,062
Capital contribution from parent		22,750			—			—			—			—			22,750
Other comprehensive income:
Gain on cash flow hedges, net of reclassification adjustments		127			—			—			—			—			127
Adjustment to initially apply SFAS No. 158:
Pension benefits, net of tax:
Net actuarial loss		(6,272	)		—			—			—			—			(6,272	)
Prior service cost		(107	)		—			—			—			—			(107	)

Balance — December 31, 2006 (Predecessor)		300,281			—			—			—			—			300,281
Net income		153,904			—			—			—			—			153,904
Cash distributions		(38,420	)		—			—			—			—			(38,420	)
Elimination of deferred income taxes		(3,767	)		—			—			—			—			(3,767	)
Other comprehensive income:
Loss on cash flow hedges, net of reclassification adjustments		(22	)		—			—			—			—			(22	)
Pension benefits:
Amortization of net actuarial Loss		670			—			—			—			—			670
Amortization of prior service cost		27			—			—			—			—			27
Net actuarial gain arising during the period		2,293			—			—			—			—			2,293

Balance — December 31, 2007 (Predecessor)		414,966			—			—			—			—			414,966
Net income attributable to the period through January 23, 2008		4,002			—			—			—			—			4,002
Pre-IPO distribution		(3,088	)		—			—			—			—			(3,088	)
Distribution of Pre-IPO funds made in April 2008		(2,723	)		—			—			—			—			(2,723	)
Other comprehensive loss attributable to the period through January 23, 2008		40			—			—			—			—			40

Balance — January 23, 2008 (Predecessor)		413,197			—			—			—			—			413,197
Contribution of net assets of predecessor companies		(115,020	)		(26,392	)		133,094			8,318			—			—
Adjustment to contribution of net assets of predecessor companies		2,723			(1,798	)		(871	)		(54	)		—			—
Purchase of 15.9% general partnership interest in Northwest Pipeline GP		(300,900	)		—			—			—			—			(300,900	)
Issuance of units to public		—			336,520			—			—			—			336,520
Offering costs		—			(3,797	)		—			—			—			(3,797	)
Redemption of common units by general partner		—			(31,020	)		—			—			—			(31,020	)
Other comprehensive income attributable to the period January 24 through December 31, 2008:
Net unrealized gain on cash flow hedge		—			—			—			—			(20	)		(20	)
Pension benefits:
Amortization of net actuarial loss		—			—			—			—			457			457
Amortization of prior service cost		—			—			—			—			26			26
Net actuarial loss arising during the period		—			—			—			—			(14,326	)		(14,326	)

Total comprehensive income																	(13,863	)

Net income attributable to the period January 24 through December 31, 2008		—			32,839			15,918			(879	)		—			47,878
Cash distributions		—			(19,197	)		(9,306	)		(582	)		—			(29,085	)
Contributions pursuant to the omnibus agreement		—			—			—			1,874			—			1,874
Other		—			114			—			—			—			114

Balance — December 31, 2008	$	—		$	287,269		$	138,835		$	8,677		$	(13,863	)	$	420,918

See accompanying notes to consolidated financial statements.

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 1.	Organization and Basis of Presentation

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

We are 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. The 35 percent of Northwest owned by us was owned by The Williams Companies, Inc. (“Williams”) prior to the initial public offering (“IPO”) of our common units in January 2008. As of December 31, 2008, Williams, through its subsidiary, Williams Pipeline GP LLC, owns a 2 percent general partner interest and a 45.7 percent limited partner interest in us.

On January 24, 2008, we completed our IPO of 16,250,000 units representing limited partner interests in us at a price 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) to us in exchange for 16,250,000 common units, representing a 47.5 percent limited partner interest in us, (ii) we purchased from Northwest a 15.9 percent general partnership interest in Northwest, and (iii) a 19.1 percent 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 percent general partner interest 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, for $33.0 million ($31.0 million net of the underwriters’ discount), to cover over-allotments. The underwriters purchased the common units pursuant to that option on February 21, 2008 at the IPO price, net of underwriting discounts, of $18.80 per unit. 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.

Because the Northwest interests were acquired from an affiliate of Williams, the transaction was between entities under common control, and has been accounted for at historical cost. Accordingly, our consolidated financial statements and notes reflect the combined historical results of our investment in Northwest for all periods presented.

Our proportionate share of operating results is reflected as equity earnings from investment in Northwest in our financial statements beginning January 24, 2008, the effective date of the IPO. The general and administrative expenses reflected in our 2008 financial statements are attributable to the period January 24 through December 31, 2008. The financial information that precedes January 24, 2008 is referred to as “Predecessor.” The historical financial statements for the Predecessor, as the financial statement predecessor to the Partnership, reflect the ownership of the 35 percent investment in Northwest using the equity method of accounting. These Predecessor financial statements have been prepared from the books and records of Northwest and are not necessarily indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during these periods, nor are they necessarily indicative of future operating results.

The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at December 31, 2008, results of operations for the years ended December 31, 2008, 2007 and 2006, and cash flows for the years ended December 31, 2008, 2007 and 2006. All intercompany transactions have been eliminated.


Note 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.

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Investments. We account for our 35 percent investment in Northwest under the equity method due to our ability to exercise significant influence over Northwest.

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.

Income Taxes. With the January 2008 IPO 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.

Cash and Cash Equivalents. Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have an original maturity of three months or less.


Note 3.	Allocation of Net Income and Distributions

The allocation of net income between our general partner and limited partners, as reflected in the Consolidated Statement of Partners’ Capital, for the period January 24 through December 31, 2008 is as follows (in thousands):


	Period from
	January 24, 2008
	through
	December 31, 2008

Allocation to general partner:
Net income	$	47,878
Charges direct to general partner:
Reimbursable general and administrative costs		1,874

Income subject to 2% allocation of general partner interest		49,752
General partner’s share of net income		2.0	%

General partner’s allocated share of net income before items directly allocable to general partner interest		995
Incentive distributions paid to general partner*		—
Direct charges to general partner		(1,874	)

Net income (loss) allocated to general partner	$	(879	)

Net income	$	47,878
Net income (loss) allocated to general partner		(879	)

Net income allocated to limited partners	$	48,757


*		Under the “two class” method of computing earnings per share prescribed by SFAS No. 128, “Earnings Per Share,” earnings are to be allocated to participating securities as if all of the earnings for the period had been distributed. As a result, the general partner receives an additional allocation of income in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. There were no assumed incentive distributions for the three months ended March 31, 2008; however, for the three months ended June 30, 2008, the assumed incentive distribution

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


		rights were $71 thousand, for the three months ended September 30, 2008, the assumed incentive distribution rights were $471 thousand, and for the three months ended December 31, 2008, the assumed incentive distribution rights were $339 thousand. The resulting allocation of income for the calculation of earnings per limited partner unit is shown on the Consolidated Statements of Income.

Common and subordinated unitholders share equally, on a per-unit basis, in the net income allocated to limited partners for the year ended December 31, 2008.

We have authorized payments of the following post-IPO cash distributions (in thousands, except for per unit amounts):


							General Partner
									Incentive
	Per Unit		Common		Subordinated				Distribution		Total Cash
Payment Date	Distribution		Units		Units		2%		Rights		Distribution

5/15/2008	$	0.2242	$	5,068	$	2,457	$	154	$	—	$	7,679
8/14/2008		0.3100		7,008		3,397		212		—		10,617
11/14/2008		0.3150		7,121		3,452		216		—		10,789
2/13/2009(a)		0.3200		7,234		3,507		219		—		10,960


(a)		The board of directors of our general partner declared this cash distribution on January 26, 2009 to be paid on February 13, 2009 to unitholders of record at the close of business on February 6, 2009.

Subordinated units. Our partnership agreement provides that, 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 0.28750 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. Futhermore, 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 available cash to be distributed on the common units. The subordination period will end and the subordinated units will convert to common units, on a one-for-one basis when certain distribution requirements, as defined in the partnership agreement, have been met.


Note 4.	Credit Facilities

At the closing of the IPO on 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 was January 23, 2009. We exercised our automatic right to extend the facility for an additional 365-day term in January. The new maturity date is January 23, 2010. The interest rate on all borrowings will be the one-month LIBOR determined the date of the borrowing. The borrowings may be repaid prior to the end of the one-month LIBOR rate period. If a borrowing is not repaid within one month, the interest rate for such borrowing will be adjusted to the one-month LIBOR rate 30 days after the most recent borrowing. We pay a commitment fee to Williams on the unused portion of the credit agreement of 0.25 percent annually. We are 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. At December 31, 2008, we have no outstanding borrowings under the working capital credit facility.


Note 5.	Recent Accounting Standards

In March 2008, the Financial Accounting Standards Board (“FASB”) ratified the decisions reached by the Emerging Issues Task Force (“EITF”) with respect to EITF Issue No. 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” EITF 07-4 establishes,

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

among other things, that the calculation of earnings per unit should not reflect an allocation of undistributed earnings to the incentive distribution right (“IDR”) holders beyond amounts distributable to IDR holders under the terms of the partnership agreement. As described in “Note 3. Allocation of Net Income and Distributions,” we calculate earnings per unit as if all the earnings for the period have been distributed, which may result in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeds the actual incentive distribution. Following the adoption of the guidance in EITF 07-4, we will no longer calculate assumed incentive distributions. The final consensus is effective beginning with the first interim period of the fiscal year beginning after December 15, 2008, and must be retrospectively applied to all periods presented. Early application is prohibited. Retrospective application of this guidance will result in a decrease in the income allocated to the general partner and an increase in the income allocated to limited partners for the amount any assumed incentive distribution exceeded the actual incentive distribution paid during that period. The application of EITF 07-4 will result in an increase in earnings per unit of $0.01 for both the third and fourth quarters of 2008.

In December 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 141(R) “Business Combinations.” SFAS No. 141(R) applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100 percent ownership in the acquiree. SFAS No. 141(R) also requires expensing of restructuring and acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS No. 141(R) is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of Accounting Research Bulletin No. 51.” SFAS 160 establishes accounting and reporting standards for noncontrolling ownership interests in subsidiaries (previously referred to as minority interests). SFAS No. 160 is effective for fiscal years beginning after December 15, 2008, and early adoption is prohibited. The statement will be applied prospectively to transactions involving noncontrolling interests, including noncontrolling interests that arose prior to the effective date, as of the beginning of the fiscal year it is initially adopted. However, the presentation of noncontrolling interests within stockholders’ equity and the inclusion of earnings attributable to the noncontrolling interests in consolidated net income requires retrospective application to all periods presented. Implementation of SFAS No. 160 will not have an impact on our Consolidated Financial Statements.


Note 6.	Related Party Transactions

During 2008, we received distributions of $41.5 million from Northwest. Of this amount, $5.8 million represents the portion allocated to us prior to the closing of the IPO on January 24, 2008. During 2008, we made distributions to Williams of $19.7 million.

Following the closing of the IPO on January 24, 2008, our general partner gives us a quarterly credit for general and administrative expenses under the terms of an omnibus agreement. The annual amounts of those credits are as follows: $2.0 million in 2008 (pro-rated for the portion of the year from January 24 to December 31), $1.5 million in 2009, $1.0 million in 2010 and $0.5 million in 2011. At December 31, 2008, $1.9 million is reflected as a capital contribution in our financial statements.


Note 7.	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

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

deferred assets and recorded a payable to the affiliate. These deferred costs were reclassified in the first quarter of 2008 and recorded as a reduction to partners’ capital when the transactions for the IPO were recorded.


Note 8.	Comprehensive Income

Comprehensive income is as follows:


	Years Ended December 31,
	2008			2007			2006
							(Predecessor)
				(Predecessor)
	(Thousands of dollars)

Net income	$	51,880		$	153,904		$	19,062
Reclassification of cash flow hedge gain into earnings		(22	)		(22	)		126
Pension benefits:
Amortization of net actuarial loss		498			670			—
Amortization of prior service cost		27			27			—
Net actuarial (loss) gain arising during the period		(14,326	)		2,293			—
Elimination of deferred income taxes		—			(3,767	)		—

Total comprehensive income	$	38,057		$	153,105		$	19,188


Note 9.	Equity Investments

Northwest is accounted for using the equity method of accounting. As such, our interest in Northwest’s net operating results is reflected as equity earnings in our Consolidated Statements of Income. The summarized results of operations for 100 percent of Northwest Pipeline are presented below:

Northwest (100%)


	Years Ended December 31,
	2008		2007			2006
	(Thousands of dollars)

Income Statement Data:
Operating revenues	$	434,854	$	421,851		$	324,250
Net income		155,371		439,726	(A)		54,462
Cash Distributions		419,342		109,770			—
Balance Sheet Data (at period end):
Total assets		2,082,172		2,056,471
Long-term debt, including current maturities		693,240		693,736
Total Partners’ equity		1,184,713		1,185,616

Note: Earnings and distributions/dividends per partnership unit/common share are not presented for 2006 through 2008. Northwest was a wholly-owned subsidiary of Williams as of December 31, 2007 and for all prior periods presented. Distributions for 2008 were made to Northwest’s partners based upon each partnership’s ownership interest.


(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.

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


10.	Quarterly Information (Unaudited)

Summarized quarterly financial data are as follows (thousands, except per-unit amounts):


	Quarter of 2008
	First			Second		Third		Fourth

Equity earnings from investment in Northwest	$	13,355	(a)	$	12,490	$	14,433	$	14,102
Net income		12,855	(a)		11,867		13,863		13,295
Basic and diluted net income per limited partner unit:
Common units		0.27			0.36		0.41		0.39
Subordinated units		0.27			0.36		0.41		0.39


	Quarter of 2007
	First		Second		Third		Fourth
	(Predecessor)		(Predecessor)		(Predecessor)		(Predecessor)

Equity earnings from investment in Northwest	$	8,175	$	13,085	$	11,583	$	121,061
Net income		8,175		13,085		11,583		121,061


(a)		Net income and equity earnings from investment in Northwest for the first quarter of 2008 include $4,002 of Predecessor equity earnings from investment in Northwest Pipeline GP, representing the first twenty-three days of January 2008.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment we believe that, as of December 31, 2008, our internal control over financial reporting was effective.

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

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, 2008 and 2007 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, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

Ernst & Young LLP

Houston, Texas

February 23, 2009

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME


	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)

OPERATING REVENUES	$	434,854		$	421,851		$	324,250

OPERATING EXPENSES:
General and administrative		60,403			65,772			56,463
Operation and maintenance		72,831			66,847			65,763
Depreciation		86,184			84,731			79,488
Regulatory credits		(2,617	)		(3,663	)		(4,469	)
Taxes, other than income taxes		16,875			13,997			15,018
Regulatory liability reversal		—			(16,562	)		—

Total operating expenses		233,676			211,122			212,263

Operating income		201,178			210,729			111,987

OTHER INCOME — net:
Interest income —
Affiliated		813			2,983			3,920
Other		6			2,681			3,423
Allowance for equity funds used during construction		812			2,091			8,947
Miscellaneous other income (expense), net		(8	)		(517	)		307
Contract termination income		—			18,199			—

Total other income — net		1,623			25,437			16,597

INTEREST CHARGES:
Interest on long-term debt		42,290			46,828			43,649
Other interest		5,571			5,585			3,824
Allowance for borrowed funds used during construction		(431	)		(1,306	)		(4,557	)

Total interest charges		47,430			51,107			42,916

INCOME BEFORE INCOME TAXES		155,371			185,059			85,668
PROVISION (BENEFIT) FOR INCOME TAXES (Note 6)		—			(254,667	)		31,206

NET INCOME	$	155,371		$	439,726		$	54,462

CASH DISTRIBUTIONS/DIVIDENDS	$	419,342		$	109,770		$	—

See accompanying notes to consolidated financial statements.

NORTHWEST PIPELINE GP

CONSOLIDATED BALANCE SHEETS


	December 31,
	2008			2007
	(Thousands of dollars)

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	345		$	497
Advances to affiliate		65,977			39,072
Accounts receivable —
Trade, less reserves of $0 for 2008 and $7 for 2007		40,116			40,689
Affiliated companies		1,230			3,514
Materials and supplies, less reserves of $111 for 2008 and $181 for 2007		9,817			10,344
Exchange gas due from others		17,000			10,155
Exchange gas offset		—			6,593
Prepayments and other		5,985			6,928

Total current assets		140,470			117,792

PROPERTY, PLANT AND EQUIPMENT, at cost		2,765,520			2,706,691
Less — Accumulated depreciation		901,613			864,999

Total property, plant and equipment, net		1,863,907			1,841,692

OTHER ASSETS:
Deferred charges		22,213			44,915
Regulatory assets		55,582			52,072

Total other assets		77,795			96,987

Total assets	$	2,082,172		$	2,056,471


LIABILITIES AND OWNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable —
Trade	$	12,172		$	32,055
Affiliated companies		6,484			13,056
Accrued liabilities —
Taxes, other than income taxes		10,019			7,935
Interest		4,045			4,517
Employee costs		10,505			12,106
Exchange gas due to others		12,165			16,748
Exchange gas offset		4,835			—
Other		8,784			5,713

Total current liabilities		69,009			92,130

LONG-TERM DEBT		693,240			693,736
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		135,209			84,989
CONTINGENT LIABILITIES AND COMMITMENTS
OWNERS’ EQUITY:
Owners’ capital		978,682			977,022
Retained earnings		265,668			228,739
Accumulated other comprehensive loss		(59,636	)		(20,145	)

Total owners’ equity		1,184,714			1,185,616

Total liabilities and owners’ equity	$	2,082,172		$	2,056,471

See accompanying notes to consolidated financial statements.

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY


	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars, except per share amounts)

Common stock, par value $1 per share, authorized, 1,000 shares
Balance at beginning of period, outstanding, 1,000 shares for 2007 and 2006	$	—		$	1		$	1
Conversion to GP		—			(1	)		—

Balance at end of period		—			—			1

Additional paid-in capital —
Balance at beginning of period		—			977,021			912,021
Capital contribution from parent		—			—			65,000
Conversion to GP		—			(977,021	)		—

Balance at end of period		—			—			977,021

Partners’ capital —
Balance at beginning of period		977,022			—			—
Capital contribution from partner		1,660			—			—
Conversion to GP		—			977,022			—

Balance at end of period		978,682			977,022			—

Retained earnings (deficit) —
Balance at beginning of period		228,739			(101,214	)		(155,676	)
Net income		155,371			439,726			54,462
Cash distributions		(419,342	)		(109,770	)		—
Sale of partnership interest		300,900			—			—
Other		—			(3	)		—

Balance at end of period		265,668			228,739			(101,214	)

Accumulated other comprehensive loss —
Balance at beginning of period		(20,145	)		(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		(61	)		(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 (loss)		(39,509	)		8,466			—
Prior service cost		79			77			—
Elimination of deferred income taxes		—			(10,763	)		—

Balance at end of period		(59,636	)		(20,145	)		(17,863	)

Total owners’ equity	$	1,184,714		$	1,185,616		$	857,945

See accompanying notes to consolidated financial statements.

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)

OPERATING ACTIVITIES:
Net Income	$	155,371		$	439,726		$	54,462
Adjustments to reconcile to net cash provided by operating activities —
Depreciation		86,184			84,731			79,488
Regulatory credits		(2,617	)		(3,663	)		(4,469	)
Provision (benefit) for deferred income taxes		—			(289,229	)		27,916
Amortization of deferred charges and credits		8,589			9,783			2,484
Allowance for equity funds used during construction		(812	)		(2,091	)		(8,947	)
Reserve for doubtful accounts		(7	)		(46	)		(38	)
Regulatory liability reversal		—			(16,562	)		—
Contract termination income		—			(6,045	)		—
Cash provided (used) by changes in operating assets and liabilities:
Trade accounts receivable		580			(8,413	)		(3,515	)
Affiliated receivables, including income taxes in 2007 and 2006		2,284			(2,923	)		4,899
Exchange gas due from others		4,583			(1,654	)		5,549
Materials and supplies		527			(331	)		(1,912	)
Other current assets		943			1,017			(5,264	)
Deferred charges		(423	)		(9,769	)		(1,610	)
Trade accounts payable		(2,599	)		4,653			(2,011	)
Affiliated payables, including income taxes in 2007 and 2006		(6,572	)		(5,259	)		13,037
Exchange gas due to others		(4,583	)		1,654			(5,549	)
Other accrued liabilities		3,082			2,105			1,192
Other deferred credits		(5,139	)		7,673			4,095
Other		(377	)		—			—

Net cash provided by operating activities		239,014			205,357			159,807

FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		249,333			434,362			174,447
Retirement of long-term debt		(250,000	)		(252,867	)		(7,500	)
Early retirement of long-term debt		—			(175,000	)		—
Debt issuance costs		(2,027	)		(2,059	)		(2,375	)
Premium on early retirement of long-term debt		—			(7,111	)		—
Capital contribution from parent		1,660			—			65,000
Proceeds from sale of partnership interest		300,900			—			—
Distributions paid		(419,342	)		(109,770	)		—
Changes in cash overdrafts		(7,372	)		(30,078	)		37,347

Net cash provided by (used in) financing activities		(126,848	)		(142,523	)		266,919

INVESTING ACTIVITIES:
Property, plant and equipment —
Capital expenditures		(78,566	)		(157,163	)		(473,566	)
Proceeds from sales		3,065			2,257			—
Asset removal cost		—			—			(9,733	)
Changes in accounts payable and accrued liabilities		(9,912	)		402			(5,015	)
Proceeds from contract termination payments		—			—			3,348
Proceeds from sale at Parachute facilities		—			79,770			—
Repayments from (advances to) affiliates		(26,905	)		10,908			20

Net cash used in investing activities		(112,318	)		(63,826	)		(484,946	)

NET DECREASE IN CASH AND CASH EQUIVALENTS		(152	)		(992	)		(58,220	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		497			1,489			59,709

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	345		$	497		$	1,489

See accompanying notes to consolidated financial statements.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Note 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 hereinafter referred to as “Northwest.” Coincident with the conversion, the partners of Northwest 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 deferred income tax liabilities of approximately $311.8 million to income and $10.2 million of deferred income tax assets to other comprehensive income.

On January 24, 2008, Williams Pipeline Partners L.P. (“WMZ”) (previously a wholly-owned subsidiary of The Williams Companies, Inc. (“Williams”)) completed its initial public offering of limited partnership units, the net proceeds of which were used to acquire a 15.9 percent interest in Northwest. Williams contributed 19.1 percent of its ownership in Northwest in return for limited and general partnership interests in WMZ. Northwest received net proceeds of $300.9 million on January 24, 2008 from WMZ for the purchase of its 15.9 percent interest, and Northwest in turn made a distribution to Williams of $300.9 million. After these transactions, Northwest is owned 35 percent by WMZ and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of Williams. Through its ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of Northwest as of February 26, 2009.

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 and Northwest Pipeline Services LLC entered into an agreement whereby the employees of Northwest Pipeline Services LLC provide services to Northwest. Northwest reimburses 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 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 other risks. Our current rates were approved pursuant to a rate settlement. As a result, our current revenues are not subject to refund.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Statement of Financial Accounting Standards (“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, 2008 and 2007, we had approximately $57.8 million and $54.3 million, respectively, of regulatory assets primarily related to equity funds used during construction, levelized incremental depreciation, asset retirement obligations, environmental costs and other post-employment benefits, and approximately $2.9 million and $17.8 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 Pipeline Services LLC, a variable interest entity for which Northwest is the primary beneficiary.

Our 1983 acquisition by Williams was accounted for using the purchase method of accounting. Accordingly, Williams performed an allocation of the purchase price to our assets and liabilities, based on their estimated fair values at the time of the acquisition. We have elected to include Williams’ purchase price allocations in our financial statements.

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 2.79 percent, 2.76 percent and 2.86 percent for 2008, 2007 and 2006, 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 $2.6 million in 2008, $3.7 million in 2007, and $4.5 million in 2006 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 $28.4 million at December 31, 2008, and $25.8 million at December 31, 2007. 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, 2008 and 2007 were $26.8 million and $21.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($25.6 million and $21.8 million at December 31, 2008 and 2007, respectively) was reclassified to a noncurrent regulatory asset or liability and has been netted against the amount of the ARO regulatory asset expected to be collected in rates.

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 percent for 2008 and 2007 and approximately 10 percent for 2006. Equity AFUDC of $0.8 million, $2.1 million and $8.9 million for 2008, 2007 and 2006, 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 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 was based upon the overnight investment rate paid on Williams’ excess cash, which was zero percent at December 31, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

Impairments 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 each subsidiary had filed a separate return.

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

Deferred Charges

We amortize deferred charges over varying periods consistent with 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Cash and Cash Equivalents

Our cash and cash equivalents balance includes amounts primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These have an original maturity of three months or less.

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a demand charge based on the volume of contracted capacity and a commodity charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for demand charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges, from both firm and interruptible transportation services and storage injection and withdrawal services, are recognized when natural gas is scheduled to be delivered at the agreed upon delivery point or when the natural gas is scheduled to be injected or withdrawn from the storage facility.

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 the Platts “Gas Daily Price Guide.” 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.

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 FERC. We record estimates of rate refund liabilities considering our and other third party regulatory proceedings, advice of counsel and estimated total exposure, as discounted and risk weighted, as well as collection and other risks. At December 31, 2008, 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, 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 $43.1 million, $49.7 million and $43.5 million in 2008, 2007 and 2006, respectively.

Recent Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB’’) issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

November 15, 2007. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2008, we adopted SFAS 157. We had no assets or liabilities measured at fair value on a recurring basis. Therefore, the initial adoption of SFAS 157 had no impact on our Consolidated Financial Statements. Beginning January 1, 2009, we will prospectively apply SFAS 157 fair value measurement guidance to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis when such fair value measurements are required. Had we not elected to defer portions of SFAS 157, fair value measurement for nonfinancial items would have been applied to the initial measurement at fair value of asset retirement obligations in 2008.

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 had historically recorded a regulatory asset or liability for the difference between pension expense as estimated under SFAS No. 87, “Employer’s Accounting for Pensions” (“SFAS 87”), and the amount we funded as a contribution to our pension plans. As a result of additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.

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.


Note 2.	Rate and Regulatory Matters

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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As contemplated in the application for amendment, Parachute has leased the facilities back to us. We will continue to operate the facilities under FERC certificate. When Williams Field Services Company, LLC 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 pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral.


Note 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 on behalf of himself and the federal government, 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. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorney’s fees and costs. 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. In 1999, the DOJ announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against Williams and its wholly-owned subsidiaries, including us. The matter is on appeal to the Tenth Circuit Court of Appeals.

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that it is in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, 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-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (“PCB”), contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (“EPA”) in the late 1980s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous mercury clean-ups in Washington. Currently, we are conducting assessment and remediation activities needed to bring the sites up to Washington’s current environmental standards. At December 31, 2008, we had accrued liabilities totaling approximately $9.2 million for these costs which are expected to be incurred through 2014. The increase from prior year accruals is due to the completion of assessments at certain compressor station facilities. 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.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard for ground-level ozone. Within three years, the EPA is expected to designate new eight-hour ozone non-attainment areas.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Designation of new eight-hour ozone non-attainment areas will result in additional federal and state regulatory actions that will likely impact our operations. As a result, we expect the cost of additions to property, plant and equipment to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (“DOT PHMSA”) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and associated remediation will be between $120 million and $145 million over the remaining assessment period of 2009 through 2012. The cost estimates have been revised to reflect refinements in the scope of required remediation and for increases in assessment and remediation costs. Our management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

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

Summary

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

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $12.4 million at December 31, 2008.

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

In January 2008, we received net proceeds of $300.9 million from Williams Pipeline Partners L.P. for its purchase of a partnership interest and we made a distribution of $300.9 million to Williams. During the year ended December 31, 2008, we declared and paid equity distributions of $118.4 million to our partners, including $8.8 million to Williams representing available cash prior to Williams Pipeline Partners L.P.’s acquisition of its

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest in us. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. In January 2009, we declared and paid equity distributions of $32.0 million to our partners.


Note 4.	Debt, Financing Arrangements and Leases

Debt Covenants

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

Long-Term Debt

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

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

On May 22, 2008, we issued $250.0 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 to certain institutional investors in a Rule 144A private debt placement. Interest is payable on June 15 and December 15 of each year, beginning December 15, 2008. We used these proceeds to repay our December 2007 $250.0 million loan under the Credit Facility. In September 2008, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

In the second quarter 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 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,
	2008		2007
	(Thousands of dollars)

5.95%, payable 2017	$	184,471	$	184,407
6.05%, payable 2018		249,374		—
7.00%, payable 2016		174,587		174,532
7.125%, payable 2025		84,808		84,797
Revolving credit debt, payable 2012		—		250,000

Total long-term debt	$	693,240	$	693,736

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of December 31, 2008, 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)

2009	$	—
2010		—
2011		—
2012		—
2013		—
Thereafter		695,000

Total	$	695,000

Line-of-Credit Arrangements

Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012 (“Credit Facility”). 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 (“LIBOR”) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $71 million, none of which are associated with us, have been issued by the participating institutions. There were no revolving credit loans outstanding as of December 31, 2008. In December 2007, we borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250.0 million was repaid with proceeds from the issuance of $250.0 million of 6.05 percent senior unsecured notes due 2018. We did not access the agreement in 2008.

Significant financial covenants under the credit agreement include the following:


	•	Williams’ ratio of debt to capitalization must be no greater than 65 percent. Williams was in compliance with this covenant at December 31, 2008.

	•	Our ratio of debt to capitalization and that of another participating subsidiary of Williams must be no greater than 55 percent. We were in compliance with this covenant at December 31, 2008.

Leases

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

The major operating lease is a leveraged lease for our headquarters building, which became effective during 1982. The agreement has an initial term of approximately 27 years, with options for consecutive renewal terms of approximately 9 years and 10 years. As required by the terms of the lease, we have exercised our option to renew the term of the lease for approximately 9 years, beginning October 1, 2009. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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)

2009	$	6,369
2010		3,749
2011		3,749
2012		3,749
2013		3,749

		21,365
Less: noncancelable subleases		2,819

Total	$	18,546

Operating lease rental expense, net of sublease revenues, amounted to $4.9 million, $4.9 million, and ($1.2) million for 2008, 2007 and 2006, 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 continue to operate the facilities under the FERC certificate. When Williams Field Services Company, LLC completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate. Under the terms of the lease, we pay Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral. This operating lease is not included in the future minimum annual rental payments shown above due to the contingent nature of the Parachute lease payments.


Note 5.	Employee Benefit Plans

Pension Plans

We participate in Williams’ sponsored noncontributory defined benefit pension plans along with Williams and its subsidiaries that provide pension benefits for eligible participant employees. Cash contributions related to our participation in the plans totaled $7.7 million in 2008, $3.1 million in 2007 and $3.3 million in 2006. We expensed $3.5 million in 2008, $4.0 million in 2007 and $3.5 million in 2006. For the tax-qualified pension plans, we had historically recorded a regulatory asset or liability for the difference between pension expense as estimated under SFAS 87 and the amount we funded as a contribution to the pension plans. 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 additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.

Accumulated other comprehensive loss at December 31, 2008 and 2007, includes the following:


	Pension Benefits
	2008			2007
	(Thousands of dollars)

Amounts not yet recognized in net periodic benefit expense:
Prior service cost	$	(339	)	$	(417	)
Net actuarial losses		(59,759	)		(20,251	)

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net actuarial losses of $3,848 thousand and prior services costs of $82 thousand related to the pension plans that are included in accumulated other comprehensive loss at December 31, 2008, are expected to be amortized in net periodic benefit expense in 2009.

Postretirement Benefits Other than Pensions

We participate in a Williams sponsored plan along with 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 2008 and 2007 and $2.4 million in 2006. 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, 2008 and 2007 are $2.9 million and $17.8 million, respectively. No expense was recorded in 2008 or 2007. We expensed $2.3 million in 2006.

At December 31, 2008, regulatory liabilities include prior service credits of $2.8 million and net actuarial losses of $14.6 million related to other postretirement benefit plans. These amounts have not yet been recognized in net periodic benefit expense. At December 31, 2007, regulatory liabilities included prior service costs of $2.6 million and net actuarial gains of $6.4 million related to other postretirement benefit plans.

Defined Contribution Plan

Employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $2.1 million in 2008, $2.0 million in 2007 and $1.8 million in 2006.

Stock-Based Compensation

Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (the “Plan”) was approved by stockholders on May 17, 2007. The Plan provides for Williams common-stock-based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, stock options and deferred stock. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets being achieved.

Williams currently bills us directly for compensation expense related to stock-based compensation awards granted directly to our employees based on the fair value of such awards. We are also billed for our proportionate share of both Williams Gas Pipeline Company, LLC’s (“WGP”) and Williams’ stock-based compensation expense through various allocation processes.

Accounting for Stock-Based Compensation

Compensation cost for share-based payments is based on the grant date fair value. Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2008, 2007 and 2006 was $1.0 million, $1.1 million and $0.9 million, respectively, excluding amounts allocated from WGP and Williams.


Note 6.	Income Taxes

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The provision (benefit) for income taxes includes:


	Years Ended December 31,
	2008		2007			2006
	(Thousands of dollars)

Current:
Federal	$	—	$	30,888		$	2,940
State		—		3,674			350

		—		34,562			3,290

Deferred:
Federal		—		(258,459	)		24,945
State		—		(30,770	)		2,971

		—		(289,229	)		27,916

Total provision (benefit)	$	—	$	(254,667	)	$	31,206

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


	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)

Provision at statutory Federal income tax rate of 35 percent(1)	$	—		$	52,831		$	29,984
Increase (decrease) in tax provision resulting from -
State income taxes net of Federal tax benefit		—			3,948			2,159
Book/tax basis reconciliation adjustment		—			—			(723	)
Other — net		—			330			(214	)

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

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

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

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


(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, as a result of additional analysis of our tax basis and book basis assets and liabilities, we recorded a $0.7 million tax benefit adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet. Management concluded that the effect of this correction was not material to prior annual or interim periods, to 2006 results, or to the trend of earnings.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

No cash payments for income taxes were made to or received from Williams in 2008. Net cash payments (received from) made to Williams for income taxes were $37.7 million and ($1.3) million in 2007 and 2006, respectively.


Note 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 indicative year-end traded bond market prices. Private debt is valued based on market rates and 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 $693.2 million and $572.0 million, respectively, at December 31, 2008, and $693.7 million and $710.9 million, respectively, at December 31, 2007.


Note 8.	Transactions with Major Customers and Affiliates

Concentration of Off-Balance Sheet and Other Credit Risk

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


	Years Ended December 31,
	2008	2007		2006
	(Thousands of dollars)

Puget Sound Energy, Inc.	$89,988	$	85,059	$	64,428
Northwest Natural Gas Co.	(a)		48,648		35,242


(a)		Under 10 percent in 2008.

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, 2008 and 2007, the advances due to us by Williams totaled approximately $66.0 million and $39.1 million, respectively. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately zero percent at December 31, 2008. We received interest income from advances to Williams of $0.8 million, $3.0 million, and $3.9 million during 2008, 2007 and 2006, respectively. Such interest income is included in Other Income — net on the accompanying Statement of Income.

Williams’ corporate overhead expenses allocated to us were $16.9 million, $19.6 million and $18.7 million for 2008, 2007 and 2006, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, data

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $15.8 million, $16.6 million and $16.6 million for 2008, 2007 and 2006, 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 $14.8 million, $11.8 million and $3.4 million for 2008, 2007 and 2006, 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.

As of January 1, 2008, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we pay monthly rent equal to the revenues collected from transportation services on the lateral less 3 percent to cover costs related to the operation of the lateral. This lease expense, totaling $10.1 million for the year ended December 31, 2008, is included in operation and maintenance expense on the accompanying consolidated statement of income.

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


Note 9.	Asset Retirement Obligations

During 2008 and 2007, we adjusted the ARO liability and Property, Plant and Equipment for a change in the inflation and discount rates.

During 2008 and 2007, our overall asset retirement obligation changed as follows (in thousands):


	2008			2007

Beginning balance	$	50,423		$	48,020
Accretion		4,341			3,673
New obligations		116			1,912
Obligations transferred to an affiliate		—			(1,996	)
Changes in estimates of existing obligations		27,790			(1,186	)
Obligation settled		(4	)		—

Ending Balance	$	82,666		$	50,423

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.


Note 10.	Regulatory Assets and Liabilities

Our regulatory assets and liabilities result from our application of the provisions of SFAS 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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2008 and 2007:


	2008		2007
	(Thousands of dollars)

Current regulatory assets — environmental costs	$	2,200	$	2,200

Non-current regulatory assets
Environmental costs		5,790		4,841
Grossed-up deferred taxes on equity funds used during construction		19,234		20,122
Levelized incremental depreciation		28,397		25,780
Asset retirement obligations, net		1,189		—
Other postemployment benefits		972		1,329

Total non-current regulatory assets		55,582		52,072

Total regulatory assets	$	57,782	$	54,272

Non-current regulatory liabilities
Asset retirement obligations, net	$	—	$	10
Postretirement benefits		2,888		17,806

Total regulatory liabilities	$	2,888	$	17,816


Note 11.	Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss includes the following as of December 31, 2008 and 2007:


	2008			2007
	(Thousands of dollars)

Cash flow hedges	$	462		$	523
Pension Benefits		(60,098	)		(20,668	)

Accumulated other comprehensive loss before taxes		(59,636	)		(20,145	)
Deferred income taxes		—			—

Total accumulated other comprehensive loss	$	(59,636	)	$	(20,145	)


Note 12.	Quarterly Information (Unaudited)

The following is a summary of unaudited quarterly financial data for 2008 and 2007:


	Quarter of 2008
	First		Second		Third		Fourth
			(Thousands of dollars)

Operating revenues	$	107,405	$	106,450	$	108,452	$	112,457
Operating income		49,166		46,676		53,042		52,294
Net income		38,158		35,685		41,236		40,292

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Quarter of 2007
	First		Second		Third		Fourth
			(Thousands of dollars)

Operating revenues	$	103,043	$	102,655	$	106,364	$	109,789
Operating income		49,317		64,456		49,980		46,976
Net income		23,357		37,387		33,092		345,890

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


Item 9.	*Changes in and Disagreements with Accountants on Accounting and Financial Disclosure*

None.


Item 9A(T).	*Controls and Procedures*

Disclosure Controls and Procedures

Our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a — 15(e) and 15d — 15(e) of the Securities Exchange Act) (“Disclosure Controls”) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Williams Pipeline Partners LP have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls will be modified as systems change and conditions warrant.

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our general partner’s Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Management’s Annual Report on Internal Control over Financial Reporting

See report set forth above in Item 8, “Financial Statements and Supplementary Data.”

Changes in Internal Controls Over Financial Reporting

There have been no changes during the fourth quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.


Item 9B.	*Other Information*

None.

PART III


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

As a limited partnership, we have no directors or officers. Instead, our general partner, Williams Pipeline GP LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.

We are managed and operated by the directors and officers of our general partner. All of our operational personnel are employees of an affiliate 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 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.

All of the executive officers of our general partner who oversee the management, operations, corporate development and future acquisition initiatives of our business are also officers of Williams and Williams Partners. Phillip D. Wright, the Chief Operating Officer of our general partner is the principal executive responsible for the oversight of our affairs.

H. Brent Austin, Stephen C. Beasley and Emmitt C. House are our independent directors.

Information for the directors and executive officers of our general partner is set forth below as of February 25, 2009 is set forth below:


Name	Age		Position with Williams Pipeline GP LLC

Steven J. Malcolm		60	Chairman of the Board and Chief Executive Officer
Donald R. Chappel		57	Chief Financial Officer and Director
Phillip D. Wright		53	Chief Operating Officer and Director
James J. Bender		52	General Counsel
Rodney J. Sailor		50	Treasurer and Director
H. Brent Austin		54	Director
Stephen C. Beasley		57	Director
Emmitt C. House		59	Director

Directors are elected to one-year terms. Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

Steven J. Malcolm has served as chief executive officer and chairman of the board of Williams since January 2002 and May 2002, respectively. He was elected president and chief operating officer of Williams in September 2001. Prior to that, he was an executive vice president of Williams since May 2001, president and chief executive officer of Williams Energy Services, LLC, a subsidiary of Williams, since December 1998 and the senior vice president and general manager of Williams Field Services Company, a subsidiary of Williams, since November 1994, Mr. Malcolm serves as a director of Williams Partners GP LLC, the general partner of Williams Partners L.P. Mr. Malcolm also serves on the boards of BOK Financial Corporation and Bank of Oklahoma N.A.

Donald R. Chappel has served as senior vice president and chief financial officer of Williams since April 2003. Mr. Chappel has served as chief financial officer and director of Williams Partners GP LLC, the general partner of Williams Partners L.P., since August 2005. Mr. Chappel has served as our chief financial officer since August 2007.

Phillip D. 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. From 1989 to 1996, Mr. Wright 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. (now known as Magellan Midstream Partners, L.P.) from its initial public offering in February 2001 to the sale of Williams’ interests therein in June 2003.

James J. Bender has served has senior vice president and general counsel of Williams since December 2002. From June 2000 until June 2002, 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. 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 has served as vice president and treasurer of Williams since July 2005. He served as assistant treasurer of Williams from 2001 to 2005 and was responsible for capital restructuring and capital markets transactions, management of Williams’ liquidity position and oversight of Williams’ balance sheet restructuring program. From 1985 to 2001, Mr. Sailor served in various capacities for Williams. Mr. Sailor has served as a director of Apco Argentina Inc., a subsidiary of Williams engaged in oil and gas exploration in Argentina, since September 2006 and as a director of Williams Partners GP LLC, the general partner of Williams Partners L.P. since October 2007.

H. Brent Austin has been managing partner and chief investment officer of Alsamora L.P., a Houston-based private limited partnership with real estate and diversified equity investments since June 2003. Prior to his current position, he was president and chief operating officer of El Paso Corporation from October 2002 to May 2003, where he managed all non-regulated operations as well as all financial functions.

Stephen C. 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 from 2000 until 2007, and 2003 to 2007 respectively. He is currently president and chief executive officer of Eaton Group Inc., a privately-held business solutions and strategic investment firm.

Emmitt C. House has been associated with the law firm of Gonzalez, Saggio & Harlan since 2000 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 12 month period within the last three years more than $120,000 per year in direct compensation from our general partner, us, or 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 (other than executive officer) 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 an 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 percent 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.

	•	(a) the director is (i) a current partner of the internal or external auditor of the Partnership Group, or (ii) was within the last three years a partner or employee of the internal or external auditor for the Partnership Group and personally worked on an audit for the Partnership Group within that time; or (b) an immediate family member of the director (i) is a current partner of the internal or external auditor of the Partnership Group; (ii) is a current employee of the internal or external auditor for the Partnership Group and personally works on an audit for the Partnership Group, or (iii) was within the last three years a partner or employee of the internal or external auditor of the Partnership Group 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 serves or served on the compensation committee at the same time.

	•	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. Austin, 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.

Messrs. Austin, 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 percent 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.

Messrs. Malcolm, Chappel, Wright and Sailor were not independent because they are each officers and/or directors of Williams.

Meeting Attendance and Preparation

Members of the board of directors are expected to attend at least 75 percent 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 periodically meet outside the presence of our general partners’ executive officers. The chairman of the audit committee, H. Brent Austin, serves 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

Email: lafleur.browne@williams.com

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

Board Committees

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

Board Committee Membership


	Audit	Conflicts
	Committee	Committee

H. Brent Austin	•	ü
Stephen C. Beasley	ü	•
Emmitt C. House	ü	ü


ü	=	committee member
•	=	chairperson

Audit Committee

Our general partner’s board of directors has determined that 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. In addition, Mr. Austin

qualifies as an audit committee “financial expert” as defined by the rules of the SEC. 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.

Code of Business Conduct and Ethics

Our general partner has adopted a code of business conduct and ethics for directors, officers and employees that applies to our general partner, chief executive officer, chief financial officer, controller, and persons performing similar functions. Our code of conduct and ethics is available on our website at www.williamspipelinepartners.com under the “Investor Relations” caption. 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 corporate 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 percent 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 percent 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, 2008, our general partner’s officers, directors and greater than 10 percent common unitholders filed all reports they were required to file under Section 16(a), except for Mr. House, a director who filed a late Form 4 on February 9, 2009 with respect to the purchase of 1,500 of our common units.

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

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 from Ernst & Young LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding the independent accountant’s communications with the audit committee concerning independence, and discussed with Ernst & Young LLP its independence;

	•	discussed with Ernst & Young LLP the matters required to be discussed by the statement on Auditing Standards No. 61, as amended, as adopted by the Public Company Accounting Oversight Board in Rule 3200T;

	•	discussed with Williams Pipeline Partners L.P.’s internal auditors and Ernst & Young LLP the overall scope and plans for their respective audits. The audit committee meets with the internal auditors and Ernst & Young LLP, with and without management present, to discuss the results of their examinations, their evaluations of Williams Pipeline Partners L.P.’s internal controls and the overall quality of Williams Pipeline Partners L.P.’s financial reporting;

	•	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, 2008, 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:


	•	H. Brent Austin, Chair

	•	Stephen C. Beasley

	•	Emmitt C. House

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, Williams Pipeline GP LLC, 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’ 2009 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 corporate 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

Information regarding the portion of Mr. Chappel’s, and Mr. Malcolm’s compensation and employment-related expenses allocable to us may be found in Item 13. Certain Relationships and Related Transactions — Reimbursement of Expenses of Our General Partner.

Further information regarding the compensation of our principal executive officer, Mr. Malcolm, who also serves as the chairman, president and chief executive officer of Williams, our principal financial officer, Mr. Chappel, who also serves as the chief financial officer of Williams, and Mr. Wright, our chief operating officer, who also serves as a senior vice president of Williams, will be set forth in the proxy statement for Williams’ 2009 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. Mr. Malcolm, our general partner’s chief executive officer and chairman of the board of directors serves as the chairman of the board, president and chief executive officer of Williams. Messrs. Chappel, Wright and Sailor, who are directors of our general partner, are also 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” 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 Pipeline GP LLC:

H. Brent Austin,
Stephen C. Beasley,
Emmitt C. House,
Steven J. Malcolm,
Donald R. Chappel,
Rodney J. Sailor, and
Phillip D. Wright

Compensation of Directors

We are managed by the board of directors of our general partner. Members of the board of directors who are also officers or employees of Williams or an affiliate of us or Williams do not receive additional compensation for serving on the board of directors. Please read Item 13. Certain Relationships and Related Transactions — Reimbursement of Expenses of Our General Partner for information about how we reimburse our general partner for direct and indirect general and administrative expenses attributable to our management.

In 2008, non-employee directors each received 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; (c) $5,000 cash for service on the conflicts committee of the board of directors; and (d) $5,000 cash for service on the audit committee of the board of directors. 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. Our policy regarding non-employee directors was amended effective January 23, 2009. In 2009, the amended policy provides non-employees directors will receive an annual compensation package consisting of the following: (a) $75,000 cash retainer; (b) $5,000 cash for service on the conflicts committee of the board of directors; and (c) $5,000 cash for service on the audit committee 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 on January 24 of each year and ending on January 23 of the following year. If a non-employee director’s service on the board of directors commences on or after January 24 of a fiscal year, such non-employee director will receive a prorated annual compensation package for such fiscal year.

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 were granted under the Williams Pipeline GP LLC Long-Term Incentive Plan and vested 180 days after the date of grant. Cash distributions were paid on these restricted units. Going forward under the amended policy, each new non-employee director will instead receive a one-time cash payment of $25,000 on the date of first election to the board of directors.

Each non-employee director serving as a member of the conflicts committee of the board of directors receives $1,250 cash for each conflicts committee meeting attended by such director. Fees for attendance at meetings of the conflicts committee are paid on January 24 of each year for meetings held during the preceding 12 months.

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.

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The compensation received for 2008 by each non-employee Director is detailed below:


	Fees Earned or Paid				All Other
Name	in Cash		Unit Awards(1)		Compensation		Total

H. Brent Austin(2)	$	28,333.33	$	12,779.58		—	$	41,112.91
Stephen C. Beasley(3)		62,500.00		50,000.00		—		112,500.00
Emmitt C. House(4)		60,000.00		50,000.00		—		110,000.00


(1)		Awards were granted under the Williams Pipeline GP LLC Long-Term Incentive Plan. Awards are in the form of restricted units and are shown using a dollar value equal to the 2008 compensation expense computed in accordance with the Statement of Financial Accounting Standards No. 123(R). Cash distributions are paid on these restricted units at the same time and same rate as distributions paid to our unitholders. For 2008, all non-employee Directors received a one-time grant of Restricted Units valued at $25,000 on the date of election to the Board.

(2)		Mr. Austin was elected as a non-employee Director on October 1, 2008. Per the Company’s Director Compensation Policy, Mr. Austin received a pro-rated annual compensation package on January 24, 2009 for his service on the Board in 2008. The grant date fair value for the 2008 restricted units for Mr. Austin is $25,002.78. At fiscal year end, Mr. Austin had an aggregate of 1,762 restricted units outstanding.

(3)		Mr. Beasley received a payment for $2,500 in 2008 for attendance of two qualifying conflicts committee meetings. The grant date fair value for the 2008 restricted units for Mr. Beasley is $50,000. At fiscal year end, Mr. Beasley has no restricted units outstanding.

(4)		The grant date fair value for the 2008 restricted units for Mr. House is $50,000. At fiscal year end, Mr. House has no restricted units outstanding.

Effective January 23, 2009, non-management directors will no longer receive restricted units as part of their compensation package. The revision to the policy will not affect restricted units previously granted.

Long-Term Incentive Plan

Our general partner adopted the Williams Pipeline GP LLC Long-Term Incentive Plan, as amended, 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, of which 6,762 units have been distributed, leaving 1,993,238 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

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. Our general partner may determine to make grants under the plan of restricted 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 granted to employees, consultants and directors will vest. The general partner may base its determination upon the achievement of specified financial objectives. In addition, the restricted 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 will be automatically forfeited unless, and to the extent, our general partner

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provides otherwise. Common units to be delivered in connection with the grant of restricted 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 will be borne by us. If we issue new common units in connection with the grant of restricted 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.


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 percent 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 is based on 22,607,430 limited partner common units and 10,957,900 subordinated units outstanding. Except as noted, the address for the beneficial owners listed below is One Williams Center, Tulsa, Oklahoma 74172-0172.


			Percentage of					Percentage of			Percentage of
	Common		Common			Subordinated		Subordinated			Total
	Units		Units to be			Units to be		Units to be			Units to be
	Beneficially		Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner	Owned		Owned			Owned		Owned			Owned

Tortoise Capital Advisors, L.L.C.(1)		1,887,575		8	%		—		—			8	%
Williams Pipeline GP LLC(2)		4,700,668		20.79	%		10,957,900		100	%		45.72	%
Steven J. Malcolm		10,000		*			—		—			*
Donald R. Chappel		10,000		*			—		—			*
James J. Bender		10,000		*			—		—			*
Phillip D. Wright		10,100		*			—		—			*
Rodney J. Sailor		500		*			—		—			*
H. Brent Austin		0		*			—		—			*
Stephen C. Beasley		17,500		*			—		—			*
Emmitt C. House		4,000		*			—		—			*
All executive officers and directors as a group (8 persons)		62,100		*			—		—			*


*		Less than 1 percent.

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(1)		Based solely on the Schedule 13G filed with the SEC on February 12, 2009, Tortoise Capital Advisors, L.L.C., located at 11550 Ash Street, Suite 300, Leawood, Kansas 66211, (“Tortoise”), an investment advisor, as defined in section 240.13(d)(b)(1)(ii)(E), may be deemed the beneficial owner of 1,887,575 common units owned by investment companies for which it acts as an investment advisor. The Schedule 13G notes that Tortoise has shared voting power of 1,689,285 beneficially owned common units and shared investment power of 1,887,575.

(2)		Williams Pipeline GP LLC is a wholly owned subsidiary of The Williams Companies, Inc., the common stock of which 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.

The following table sets forth, as of February 17, 2009, 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

904,524

1,917,876

2,822,400

Donald R. Chappel

290,567

396,145

686,712

James J. Bender

137,900

123,670

261,570

Phillip D. Wright

273,755

360,965

634,720

Rodney J. Sailor

33,613

53,530

87,143

H. Brent Austin

Stephen C. Beasley

Emmitt C. House

All directors and executive officers as a group (8 persons)

1,640,359

2,852,186

4,492,545


*		Less than 1 percent.

(1)		Includes shares held under the terms of incentive and investment plans as follows: Mr. Malcolm, 46,680 shares in The Williams Companies Investment Plus Plan, 292,192 restricted stock units and 565,652 beneficially owned shares; Mr. Chappel, 171,433 restricted stock units and 119,134 beneficially owned shares; Mr. Bender, 2,800 shares owned by children, 101,538 restricted stock units and 33,562 beneficially owned shares; Mr. Wright, 15,421 shares in The Williams Companies Investment Plus Plan, 107,259 restricted stock units and 151,075 beneficially owned shares; and Mr. Sailor, 6,241 shares in The Williams Companies Investment Plus Plan, 25,671 restricted stock units and 1,701 beneficially owned shares. 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 19, 2009. Shares subject to options cannot be voted.

(3)		Based on 579,213,365 shares outstanding as of February 19, 2009.

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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 GP LLC Long-Term Incentive Plan as of December 31, 2008. 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

—

1,993,238

Total

—

(1)

—

1,993,238


(1)		1,762 unvested restricted units granted pursuant to the Williams Pipeline GP LLC Long-Term Incentive Plan as of December 31, 2008. All of these restricted units will vest on March 29, 2009. No value is shown in column (b) of the table because the restricted units do not have an exercise price. To date, the only grants under the plan have been grants of restricted units.


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 20.79 percent limited partner interest in us. In addition, our general partner owns 684,869 general partner units, representing a 2 percent general partner interest in us and the incentive distribution rights. Certain officers and directors of our general partner also serve as officers and directors of Williams. In addition to the related transactions and relationships discussed below, information about such transactions and relationships is included in Part II, Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: 6. Related Party Transactions.

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 percent 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 percent general partner interest and the incentive distribution rights

The interest in Northwest purchased by us using proceeds of our initial public offering		15.9 percent 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.

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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.

Operational Stage


Distributions of available cash to our general partner		We will generally make cash distributions 98 percent 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 percent 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 percent 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.

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.”

For the fiscal year ended December 31, 2008, we incurred on behalf of our general partner $39,505 of salary expense for Steven J. Malcolm, the chairman of the board and chief executive officer of our general partner, $27,699

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of salary expense for Donald R. Chappel, the chief financial officer of our general partner. We also incurred on behalf of our general partner $13,451 for Mr. Malcolm and $9,431 for Mr. Chappel, which expenses are attributable to additional compensation paid to each of them and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams 401(k) plan and premiums for life insurance. No awards were granted to our general partner’s executive officers under the Williams Pipeline GP LLC Long-Term Incentive Plan in 2007 or 2008. The total compensation received by Mr. Malcolm, the chairman of the board and chief executive officer of our general partner who is also the chairman, president and chief executive officer of Williams, and Mr. Chappel, the chief financial officer of our general partner who is also the chief financial officer of Williams, will be set forth in the proxy statement for Williams’ 2009 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.”

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.

Omnibus Agreement

Upon the closing of our IPO, 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 2009, the amount of the general and administrative expense credit will be $1.5 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 until January 23, 2011, 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 January 24, 2008, and for which Northwest has not created and publicly disclosed a reserve. The maximum liability of Williams for this indemnification obligation may not exceed $9 million and Williams does not have any obligation under this indemnification until our aggregate losses exceed $0.25 million. Williams has 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.

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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 percent general partnership interest in Northwest; our failure to obtain any consent or governmental permit necessary to allow the transfer of a 35 percent 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 percent 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.

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 percent general partnership interest in Northwest and we purchased a 15.9 percent general partnership interest in Northwest. As a result, we indirectly own a 35 percent general partnership interest in Northwest, and a Williams subsidiary owns a 65 percent 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 percent general partnership interest and the other partner of which is a wholly owned subsidiary of ours owning a 35 percent 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.

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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;

	•	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 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the

110

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 CHC 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 CHC Project. The Northwest general partnership agreement provides that the capital expenditures related to the Colorado Hub Connection Project will be funded by the affiliate of Williams holding the 65 percent general partnership interest in Northwest not owned by us. See Item 1. Business — Capital Projects — Colorado Hub Connection Project.

Working Capital Agreement

Williams’ Cash Management Program

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, 2008 and 2007, the advances due to Northwest by Williams totaled approximately $66.0 million and $39.1 million, respectively. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was zero percent at December 31, 2008. Northwest received interest income from advances to Williams of $0.8 million, $3.0 million, and $3.9 million during 2008, 2007 and 2006, respectively.

Williams’ corporate overhead expenses allocated to Northwest were $16.9 million, $19.6 million and $18.7 million for 2008, 2007 and 2006, respectively. Such expenses have been allocated to Northwest by Williams

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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 $15.8 million, $16.6 million and $16.6 million for 2008, 2007 and 2006, 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 $14.8 million, $11.8 million and $3.4 million for 2008, 2007 and 2006, 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 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 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.

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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 Item 10. Directors, Executive Officers and Corporate 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.


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:


	Years Ended December 31,
	2008		2007
	(Thousands of dollars)

Audit Fees	$	248	$	695
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	248	$	695

Fees for audit services in 2008 include fees associated with the annual audit, the reviews of our quarterly reports on Form 10-Q, and services provided in connection with other filings with the SEC.

The audit committee of our general partner 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 our 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.

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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 L.P.
Consolidated Statements of Income for the years ended December 31, 2008, 2007, and 2006		59
Consolidated Balance Sheets at December 31, 2008 and 2007		60
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		61
Consolidated Statement of Partners’ Capital for the years ended December 31, 2008, 2007 and 2006		62
Notes to Consolidated Financial Statements		63
Northwest Pipeline GP
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006		71
Consolidated Balance Sheets at December 31, 2008 and 2007		72
Consolidated Statements of Owners’ Equity for the years ended December 31, 2008, 2007 and 2006		73
Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006		74
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		75
Notes to Consolidated Financial Statements		76

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:

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).

114


Exhibit
Number			Description

	4	.1	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	.2	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	.3	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).
	4	.4	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed as exhibit 4.1 to Northwest Pipeline GP’s Form 8-K, filed May 23, 2008).
	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*	Amendment No. 1 to the Williams Pipeline GP LLC Long-Term Incentive Plan, dated December 3, 2008.
	10	.7*	Williams Pipeline GP LLC Long-Term Incentive Plan Form of Restricted Unit Grant Agreement for Non-Employee Directors.
	10	.8*	Williams Pipeline GP LLC Director Compensation Policy, dated January 23, 2009.
	10	.9	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	.10	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	.11	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).

115


Exhibit
Number			Description

	10	.12	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	.13	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	.14	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	.15	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.
	23	.1*	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP
	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/ Ted T. Timmermans

Ted T. Timmermans
Chief Accounting Officer

Date: February 26, 2009

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 26, 2009

/s/ Donald R. Chappel Donald R. Chappel		Chief Financial Officer and Director (Principal Financial Officer)	February 26, 2009

/s/ Ted T. Timmermans Ted T. Timmermans		Chief Accounting Officer (Principal Accounting Officer)	February 26, 2009

/s/ H. Brent Austin H. Brent Austin		Director	February 26, 2009

/s/ Stephen C. Beasley Stephen C. Beasley		Director	February 26, 2009

/s/ Emmitt C. House Emmitt C. House		Director	February 26, 2009

/s/ Rodney J. Sailor Rodney J. Sailor		Treasurer and Director	February 26, 2009

/s/ Phillip D. Wright Phillip D. Wright		Chief Operating Officer and Director	February 26, 2009

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	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	.2	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	.3	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).
	4	.4	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed as exhibit 4.1 to Northwest Pipeline GP’s Form 8-K, filed May 23, 2008).
	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*	Amendment No. 1 to the Williams Pipeline GP LLC Long-Term Incentive Plan, dated December 3, 2008.
	10	.7*	Williams Pipeline GP LLC Long-Term Incentive Plan Form of Restricted Unit Grant Agreement for Non-Employee Directors.
	10	.8*	Williams Pipeline GP LLC Director Compensation Policy, dated January 23, 2009.

118


Exhibit
Number			Description

	10	.9	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	.10	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	.11	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	.12	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	.13	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	.14	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	.15	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).
	10	.16	Registration Rights Agreement, dated as of April 5, 2007, among Northwest Pipeline Corporation and Greenwich Capital Markets, Inc. and Banc of America Securities LLC, acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (Exhibit 10.1 to Northwest report on Form 8-K, No. 1-7414, filed April 6, 2007).
	10	.17	Registration Rights Agreement, dated as of May 22, 2008, among Northwest Pipeline GP and Banc of America Securities LLC, BNP Paribas Securities Corp., and Greenwich Capital Markets, Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule I thereto (filed as Exhibit 10.1 to our Form 8-K, dated May 23, 2008).
	21	.1*	List of subsidiaries of Williams Pipeline Partners L.P.
	23	.1*	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP
	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.	Business		2
Item 1A.	Risk Factors		12
Item 1B.	Unresolved Staff Comments		36
Item 2.	Properties		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		37
Item 6.	Selected Financial Data		40
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 and Financial Disclosure		93
Item 9A(T).	Controls and Procedures		93
Item 9B.	Other Information		93

PART III
Item 10.	Directors, Executive Officers and Corporate Governance		94
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
EX-10.6
EX-10.7
EX-10.8
EX-21.1
EX-23.1
EX-31.1
EX-31.2
EX-32
EX-99.1


Item 8.	*Financial Statements and Supplementary Data*


	Page

Williams Pipeline Partners L.P.
Management’s Annual Report on Internal Control Over Financial Reporting		57
Report of Independent Registered Public Accounting Firm		58
Consolidated Statements of Income for the years ended December 31, 2008, 2007, and 2006		59
Consolidated Balance Sheets at December 31, 2008 and 2007		60
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		61
Consolidated Statement of Partners’ Capital for the years ended December 31, 2008, 2007 and 2006		62
Notes to Consolidated Financial Statements		63
Northwest Pipeline GP
Management’s Annual Report on Internal Control Over Financial Reporting		69
Report of Independent Registered Public Accounting Firm		70
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006		71
Consolidated Balance Sheets at December 31, 2008 and 2007		72
Consolidated Statements of Owners’ Equity for the years ended December 31, 2008, 2007 and 2006		73
Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006		74
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		75
Notes to Consolidated Financial Statements		76

1.		*Grant of Restricted Units.* Williams Pipeline GP LLC (the “Company”) hereby grants to you ___Restricted Units under the Williams Pipeline GP LLC Long-Term Incentive Plan (the “Plan”) on the terms and conditions set forth herein and in the Plan, which is incorporated herein by reference as a part of this Agreement. In the event of any conflict between the terms of this Agreement and the Plan, the Plan shall control. Capitalized terms used in this Agreement but not defined herein shall have the meanings ascribed to such terms in the Plan, unless the context requires otherwise.

2.		*UDRs.* You are entitled to receive all cash distributions made with respect to Restricted Units registered in your name and are entitled to vote such Restricted Units, unless and until the Restricted Units are forfeited. Such cash distribution shall be made without interest no later than on the first day of the month next following the month in which cash distributions are made to Unitholders.

3.		*Regular Vesting.* Except as otherwise provided in Section 4 below, the Restricted Units granted hereunder shall vest 180 calendar days from the Grant Date. Your service as a member of the Board of the Company must be continuous from the Grant Date through such date in order for the Award to become vested.

4.		*Events Occurring Prior to Regular Vesting.*

	(a)		*Death or Disability.* If your service with the Company terminates as a result of your death or a disability (within the meaning of Section 22(e)(3) of the Internal Revenue Code of 1986, as amended and in effect from time to time (the “Code”)), the Restricted Units then held by you automatically will become fully vested upon such termination.

	(b)		*Termination by the Company other than for Cause.* If your service is terminated by the Company for any reason other than “Cause,” as determined by the Company in accordance with the definition below, the Restricted Units then held by you automatically will become fully vested upon such termination.

	(c)		*Change of Control.* All outstanding Restricted Units held by you automatically shall become fully vested upon a Change of Control.

	(d)		*Other Terminations.* If your service with the Company terminates for any reason other than as provided in (a) and (b) above, and (c) does not apply, all unvested Restricted Units then held by you automatically shall be forfeited without payment upon termination of your service with the Company.

		For purposes of this Section 4, “service with the Company” shall include being an employee of or a director or consultant to the Company or an Affiliate.

		For purposes of this Section 4, “Cause” shall mean:

		Company shall cause a certificate or certificates to be issued without legend in your name in exchange for the certificate evidencing the Restricted Units.

6.		*Limitations Upon Transfer.* All rights under this Agreement shall belong to you alone and may not be transferred, assigned, pledged, or hypothecated by you in any way (whether by operation of law or otherwise), other than by will or the laws of descent and distribution and shall not be subject to execution, attachment, or similar process. Upon any attempt by you to transfer, assign, pledge, hypothecate, or otherwise dispose of such rights contrary to the provisions in this Agreement or the Plan, or upon the levy of any attachment or similar process upon such rights, such rights shall immediately become null and void.

7.		*Restrictions.* By accepting this grant, you agree that any Units which you may acquire upon vesting of this Award will not be sold or otherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws. You also agree that (i) the certificates representing the Units acquired under this Award may bear such legend or legends as the Committee deems appropriate in order to assure compliance with applicable securities laws, (ii) the Company may refuse to register the transfer of the Units acquired under this Award on the transfer records of the Company if such proposed transfer would in the opinion of counsel satisfactory to the Company constitute a violation of any applicable securities law, and (iii) the Company may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Units to be acquired under this Award.

8.		*Withholding of Tax.* To the extent that the grant or vesting of a Restricted Unit results in the receipt of compensation by you with respect to which the Company or an Affiliate has a tax withholding obligation pursuant to applicable law, unless other arrangements have been made by you that are acceptable to the Company or such Affiliate, you shall deliver to the Company or the Affiliate such amount of money as the Company or the Affiliate may require to meet its withholding obligations under such applicable law. No issuance of an unrestricted Unit shall be made pursuant to this Agreement until you have paid or made arrangements approved by the Company or the Affiliate to satisfy in full the applicable tax withholding requirements of the Company or Affiliate with respect to such event.

9.		*Code* *Section 83(b)* *Election.* You shall be permitted to make an election under Section 83(b) of the Code, to include an amount in income in respect of the Award of Restricted Units in accordance with the requirements of Section 83(b) of the Code.

10.		*Binding Effect.* This Agreement shall be binding upon and inure to the benefit of any successor or successors of the Company and upon any person lawfully claiming under you.

11.		*Entire Agreement.* This Agreement, together with the Plan, constitute the entire agreement of the parties with regard to the subject matter hereof, and together contain all the covenants, promises, representations, warranties and agreements between the parties with respect to the Restricted Units granted hereby. Without limiting the scope of the

		preceding sentence, all prior understandings and agreements, if any, among the parties hereto relating to the subject matter hereof are hereby null and void and of no further force and effect. Any modification of this Agreement shall be effective only if it is in writing and signed by both you and an authorized officer of the Company.

12.		*Governing Law.* This grant shall be governed by, and construed in accordance with, the laws of the State of Oklahoma, without regard to conflicts of laws principles thereof that would apply the law of any other state.

	1.		$75,000 cash; and

	2.		$5,000 cash each for service on the conflicts and audit committees of the Board.

	1.		for a person first elected as a Non-Employee Director, a one-time payment of $25,000 cash on the date of election to the Board; and

	2.		reimbursement for reasonable out-of-pocket expenses incurred in connection with attending Board and committee meetings and attending education programs relevant to their duties as members of the Board.

	1.		Interim Payment and Grant Dates.

			A person who first becomes a Non-Employee Director after January 24 and prior to May 1 shall receive the full Annual Compensation Package for such Annual Compensation Period paid as of May 15.

			A person who first becomes a Non-Employee Director on or after May 1 and on or before July 31 shall receive a prorated Annual Compensation Package for such first Annual Compensation Period paid as of August 15.

			A person who first becomes a Non-Employee Director on or after August 1 and prior to January 24 shall receive a prorated Annual Compensation Package for such first Annual Compensation Period paid as of January 24.

	2.		Proration.

			The amount of cash compensation for a prorated Annual Compensation Package shall be the product of the aggregate annual cash compensation amount applicable to such Non-Employee Director as set forth in Section I above multiplied by a fraction, the numerator of which is the number of full and fractional calendar months elapsing between the date such person first becomes a Non-Employee Director and the following January 23 and the denominator of which is 12.


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

	(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 26, 2009


/s/ Donald R. Chappel
Donald R. Chappel
Chief Financial Officer February 26, 2009


	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	7,760
Prepaid expense		184

Total current assets		7,944
Investment in Northwest Pipeline GP		414,069

Total assets	$	422,013

LIABILITIES AND OWNER’S EQUITY
Current liabilities:
Accounts payable:
Trade	$	671
Affiliate		424

Total current liabilities		1,095
Minority interest		335,226
Contingent liabilities and commitments
Owner’s Equity:
Owner’s equity		92,305
Notes receivable — affiliate		(1	)
Accumulated other comprehensive loss		(6,612	)

Total owner’s equity		85,692

Total liabilities and owner’s equity	$	422,013


				General
Quarterly Distribution Target Amount (per unit)	Unitholders			Partner
Minimum quarterly distribution of $0.2875		98	%		2	%
Up to $0.330625		98			2
Above $0.330625 up to $0.359375		85			15
Above $0.359375 up to $0.431250		75			25
Above $0.431250		50			50