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/s/ Phillip D. Wright

/s/ Donald R. Chappel

Phillip D. Wright
Management Committee Member

Donald R. Chappel
Management Committee Member

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 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, 2009


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

For the transition period from _____________________ to _________________________

Commission File Number 1-7414

NORTHWEST PIPELINE GP

(Exact name of registrant as specified in its charter)


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

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

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

Securities registered pursuant to Section 12(b) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:
None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

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

Documents Incorporated by Reference:
None

NORTHWEST PIPELINE GP

FORM 10-K

PART I


Item 1.		BUSINESS

GENERAL

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

On December 31, 2009, Northwest was owned 35 percent by Williams Pipeline Partners Holdings LLC, a wholly-owned subsidiary of Williams Pipeline Partners L.P. (WMZ) and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). Through its ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of Northwest as of December 31, 2009.

On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed its ownership in WGPC Holdings LLC to Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership which is controlled by and consolidated with Williams. Through its ownership interests in each of our partners, Williams indirectly owns 71.3 percent of Northwest as of February 17, 2010.

On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the successful consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in Northwest and Williams will hold an approximate 80 percent interest in WPZ.

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

PIPELINE SYSTEM, CUSTOMERS AND COMPETITION

Transportation and Storage

Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2009, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.7 Bcf* of natural gas per day.


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

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

We transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Our firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of our business. Additionally, we offer interruptible and short-term firm transportation services. During 2009, we served a total of 129 transportation and storage customers. Our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for approximately 21.8 percent and 11.3 percent, respectively, of our total operating revenues for the year ended December 31, 2009. No other customer accounted for more than 10 percent of our total operating revenues during that period.

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

We have approximately 13.0 Bcf of working natural gas storage capacity through the following three storage facilities. These natural gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to certain major customers.

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Jackson Prairie: We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of our distribution customers. As of December 31, 2009, our share of the firm seasonal storage service in this facility was approximately 7.7 Bcf of working natural gas storage capacity and up to 383 MMcf* per day of peak day deliveries. Additionally, our share of the best-efforts delivery capacity was 50 MMcf per day. As described below, we are participating in an ongoing expansion of Jackson Prairie.

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

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

Competition

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

Competition could arise from new ventures or expanded operations from existing competitors. For example, in late 2006, Northwest Natural Gas Co. (Northwest Natural), our 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.

We are also experiencing increased competition for domestic supply with the completion of projects such as Kinder Morgan’s Rockies Express and Wyoming Interstate’s Kanda Lateral, which are designed to transport natural gas produced in the Piceance and Uinta Basins to Midwestern and Eastern markets. 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 our 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, our customers’ capacity release and capacity segmentation activities have created an active secondary market which competes with our pipeline services. Some customers see this as a benefit because it allows them to effectively reduce the cost of their capacity reservation fees.

Supply and Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in natural gas supply and demand. Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields, and the introduction of new sources of natural gas supply, such as imported LNG, directly or indirectly affect the demand for our services from both producers and consumers. For example, western U.S. production levels are growing rapidly, but a large portion of the new production of natural gas from the Rocky Mountain region will be delivered to markets in the mid-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. However, recent U.S. and Canadian shale gas discoveries and related technological advancements may impact future North American natural gas flow patterns. As these supply dynamics shift, we anticipate that we will continue to actively pursue projects that link new sources of supply to customers willing to contract for transportation on a long-term firm basis. Changes in demographics, the amount of electricity generation, prevailing weather conditions, and shifts in residential and commercial usage affect our customers’ overall demand for natural gas. As customer demand dynamics change, we anticipate that we will create new services or capacity arrangements that meet their long-term requirements.

Customers

Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies (LDCs), municipal utilities, direct industrial users, electric utilities and independent 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 our transportation and storage services for a variety of reasons. Natural gas distribution companies and electric generation companies typically require a secure and reliable supply of natural gas over a prolonged period of time to meet the needs of their customers and frequently enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Producers of natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Natural gas marketers use storage and transportation services to capitalize on

price differentials over time or between markets. 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 were completed during 2009 or are significant future pipeline projects for which we have significant customer commitments.

Colorado Hub Connection Project

On November 10, 2009, we placed into service the new 27-mile, 24-inch diameter lateral referred to as the Colorado Hub Connection Project (CHC Project). The new lateral connects the Meeker/White River Hub near Meeker, Colorado to our mainline south of Rangely, Colorado, and is estimated to cost up to $60 million.

The CHC Project combined the new lateral capacity with existing mainline capacity to provide approximately 363 MDth per day of firm transportation from various receipt points to delivery points on the mainline as far south as Ignacio, Colorado. Approximately 243 MDth per day of the capacity was originally held by Pan-Alberta Gas under a contract that would have terminated on October 31, 2012 and approximately 98 MDth per day was previously sold on a short-term basis.

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 in the Piceance Basin for our on-system and off-system markets. We have entered into transportation agreements for approximately 363 MDth per day of capacity 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 April 2009, the FERC issued a certificate approving the CHC Project, including the presumption of rolling in the costs of the project in any future rate case filed with the FERC.

Jackson Prairie Underground Expansion

The Jackson Prairie Storage Project, connected to our transmission system near Chehalis, Washington, is operated by Puget Sound Energy and is jointly owned by Puget Sound Energy, Avista Corporation and us. A phased capacity expansion is currently underway and a deliverability expansion was placed in service on November 1, 2008.

As a one-third owner of Jackson Prairie, in early 2006, we held an open season for a new firm storage service based on our 100 million cubic feet per day share of the planned 2008 deliverability expansion and approximately 1.2 billion cubic feet of our share of the working natural gas storage capacity expansion being 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. Our one-third share of the deliverability expansion was placed in service on November 1, 2008 at a cost of approximately $16.0 million. Our 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 November 2009, we received approval from the FERC to construct approximately 16 miles of 30-inch loop between our existing Green River and Muddy Creek compressor stations in Wyoming as well as an upgrade to our 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 the existing compression at Vernal, which will enhance the efficiency of our system. We executed a precedent agreement to provide 150 MDth per day of firm transportation service from the Greasewood and Meeker Hubs in Colorado for delivery to the Opal Hub in Wyoming. We have proposed to collect our maximum

system rates, and have received approval from the FERC to roll-in the Sundance Trail Expansion costs in any future rate cases.

OPERATING STATISTICS

Throughput

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


	Year Ended December 31,
	2009		2008		2007
	(In trillion British Thermal Units)
Total Throughput (1)		769		781		757

Average Daily Transportation Volumes		2.1		2.1		2.1
Average Daily Reserved Capacity Under Base Firm Contracts, excluding peak capacity		2.7		2.5		2.5
Average Daily Reserved Capacity Under Short-Term Firm Contracts (2)		.5		.7		.8


(1)		Parachute Lateral volumes of 49 TBtu in 2009, 102 TBtu in 2008 and 55 TBtu in 2007 are excluded from total throughput as these volumes flowed under separate contracts that do not result in mainline throughput.

(2)		Includes additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis.

Seasonality

Although we deliver more gas to our market areas in the winter heating season months of November through March, because a significant percentage of our revenues are collected through reservation fees, our revenues remain fairly stable from quarter to quarter. The table below sets forth seasonal revenues, expenses and throughput for each quarter and the total year ended December 31, 2009.


	Jan-Mar			Apr-Jun			Jul-Sep			Oct-Dec			Total
2009
Revenues ($ in 000)	$	111,548		$	107,756		$	106,615		$	108,460		$	434,379
Revenue %		25.7	%		24.8	%		24.5	%		25.0	%		100	%
Operating Expenses ($ in 000)	$	58,396		$	60,743		$	57,470		$	57,261		$	233,870
Throughput (TBtu) (1)		224			173			166			206			769
Throughput %		29.1	%		22.5	%		21.6	%		26.8	%		100	%


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

REGULATORY MATTERS

FERC Regulation

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

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transportation and storage of natural gas;

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rates and charges;

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construction of new facilities;

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extension or abandonment of service and facilities;

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accounts and records;

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depreciation and amortization policies;

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relationships with gas marketing functions within Williams; and

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initiation and discontinuation of services.

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

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

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

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.

In a 2007 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. In 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. The effect of the application of FERC’s policy to our future rate proceedings is not certain and we cannot ensure that such application would not adversely affect our ability to achieve a reasonable level of return on equity.

Pursuant to our March 30, 2007 rate settlement, we are required to file a new rate case to be effective not later than January 1, 2013.

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 anti-manipulation 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 anti-manipulation 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 anti-manipulation 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 anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.

Safety and Maintenance

We are subject to regulation by the 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 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. Our natural gas pipeline has inspection and compliance programs designed to maintain compliance with federal and applicable state pipeline safety and pollution control requirements.

We are subject to a number of federal laws and regulations, including the federal Occupational Safety and Health Act (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

Our natural gas transportation and storage operations are subject to extensive and complex federal, state and local laws and regulations governing the discharge of materials into the environment or

otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including:

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requiring the acquisition of permits to conduct regulated activities;

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

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

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

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

As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we believe that they do not affect our competitive position in that the operations of our competitors are similarly affected. We believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements will not have a material adverse effect on us.

The following is a discussion of some of the environmental laws and regulations that are applicable to natural gas transportation and storage activities and that may have a material impact on our business.

Waste Management

Our 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 our operations, we may generate petroleum hydrocarbon wastes and ordinary industrial wastes such as paint wastes, waste solvents, and waste compressor oils that may be regulated as hazardous solid wastes. Similarly, the Toxic Substances Control Act (TSCA), and analogous state laws impose requirements on the use, disposal and storage of various chemicals and chemical substances. In the course of our operations, we may use chemicals and chemical substances 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.

We currently own or lease properties that for many years have been used for the transportation, compression, and storage of natural gas. Although we typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for recycling or disposal. In addition, some of these properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to (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.

We have established systems and procedures to meet our reporting obligations under the Mandatory Reporting Rule related to greenhouse gas emissions issued by the EPA in late 2009. Also, certain states in which we have operations have established reporting obligations. We have not incurred significant capital investment to meet the obligations imposed by these new rules. The EPA is developing additional regulations that will expand the scope of the Mandatory Reporting Rule, with particular emphasis on natural gas operations. We are participating directly and through trade associations in developmental aspects of that prospective rulemaking. It is likely that additional rules will be issued in 2010 which may expand our reporting obligations as early as 2011. As those rules are still being developed, at this time we are unable to estimate any capital investment that may be required to comply.

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

Water Discharges

The Federal Water Pollution Control Act (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, that assess the potential direct, indirect and cumulative impacts of a proposed project and which may be made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

Endangered Species

The Endangered Species Act restricts activities that may affect threatened and endangered species or their habitats. Some of Northwest’s natural gas pipeline is located in areas inhabited by

threatened or endangered species. If Northwest’s activities adversely affect endangered species or their habitats, Northwest could incur additional costs or become subject to operating restrictions or bans in the affected area. Civil and criminal penalties can be imposed against any person violating the Endangered Species Act.

INSURANCE

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

EMPLOYEES

Northwest has no employees. Services are provided to Northwest by Northwest Pipeline Services LLC, a consolidated affiliate. As of January 31, 2010, Northwest Pipeline Services LLC had 440 employees.

TRANSACTIONS WITH AFFILIATES

We engage in transactions with Williams and other Williams’ subsidiaries. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 1. Summary of Significant Accounting Policies” and “Note 9. Transactions with Major Customers and Affiliates and Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.”


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 forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report 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,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•

Amounts and nature of future capital expenditures;

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Expansion and growth of our business and operations;

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Financial condition and liquidity;

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Business strategy;

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Cash flow from operations or results of operations;

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Rate case filings; and

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Natural gas prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

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

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Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);

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The strength and financial resources of our competitors;

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Development of alternative energy sources;

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The impact of operational and development hazards;

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Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation and rate proceedings;

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Our costs for defined benefit pension plans and other postretirement benefit plans;

•

Changes in maintenance and construction costs;

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Changes in the current geopolitical situation;

•

Our exposure to the credit risk of our customers;

•

Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of credit;

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Risks associated with future weather conditions;

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Acts of terrorism; and

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Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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 are described in the following section.

RISK FACTORS

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

Risks Inherent to our Industry and Business

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

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

	•		fires, blowouts, cratering and explosions;

	•		uncontrolled releases of natural gas;

	•		pollution and other environmental risks;

	•		natural disasters;

	•		aging pipeline infrastructure and mechanical problems;

	•		damages to pipelines and pipeline blockages;

	•		operator error;

	•		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, we maintain insurance against some, but not all of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as those described above could cause considerable harm to people or property and could have a material adverse effect on our financial condition and results of operations particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.

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

We compete primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors may have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services we provide to our customers. Moreover, WPZ and its other affiliates, including Williams may

not be limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal, fuel oils and other alternative energy sources.

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. FERC’s policies promoting competition in natural gas markets could have the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of, or increase the demand for, natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Please read “Part I. Item 1. Business — Pipeline System, Customers and Competition — Competition”. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Our primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Although none of our material contracts are terminable in 2010, upon expiration of the terms we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis.

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

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

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

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

	•		whether our business strategy continues to be successful;

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

	•		the effects of state regulation on customer contracting practices.

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

Competitive pressures could lead to decreases in the volume of natural gas contracted or transported through our pipeline system.

Although most of our pipeline system’s current capacity is fully contracted, the FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our

pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business and results of operations.

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

Our business is dependent on the continued availability of natural gas production and reserves. 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 our pipeline system. Low prices for natural gas, regulatory limitations, including environmental regulations, 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 our ability to fill the capacities of our transmission facilities.

Production from existing wells and natural gas supply basins with access to our pipeline will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on our pipeline and cash flows associated with the transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas.

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

Decreases in demand for natural gas could adversely affect our business.

Demand for our transportation services depends on the ability and willingness of shippers with access to our facilities to satisfy their demand by deliveries through our system. Any decrease in this demand could adversely affect our 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 control. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our transmission facilities.

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

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

Some portions of our current pipeline infrastructure and other assets have been in use for many decades, which may adversely affect our business.

Some portions of our assets, including our pipeline infrastructure, have been in use for many decades. The current age and condition of our assets could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining our facilities exceed current expectations.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of greenhouse gases have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, including those relating to climate change, which may expose us to significant costs and liabilities and could exceed our current expectations.

The risk of substantial environmental costs and liabilities is inherent in natural gas transportation and storage operations, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. For a description of these laws and regulations, please see “Part I, Item 1. Business — Regulatory Matters — Environmental Regulation.”

These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to limit or prevent releases of materials from our pipeline and facilities, and the imposition of substantial costs and penalties for spills, releases and emissions of various regulated substances into the environment resulting from those operations. Various governmental authorities, including the U.S. Environmental Protection Agency and analogous state agencies, and the United States Department of Homeland Security have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in our business, some of which may be material due to our 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 CERCLA, RCRA and analogous state laws, and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline passes and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental

regulatory approvals, or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs incurred to comply with such changes may not be recoverable under our regulatory rate structure or our customer contracts. In addition, new environmental laws and regulations might adversely affect our activities, including storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to legislative and regulatory responses to climate change with which compliance may be costly.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs), may be contributing to warming of the earth’s atmosphere, and various governmental bodies have considered legislative and regulatory responses in this area. Legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, federal, and international proposals to reduce or mitigate the emission of GHGs.

Several bills have been introduced in the United States Congress that would compel GHG emission reductions. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act” which is intended to decrease annual GHG emissions through a variety of measures, including a “cap and trade” system which limits the amount of GHGs that may be emitted and incentives to reduce the nation’s dependence on traditional energy sources. The U.S. Senate is currently considering similar legislation, and numerous states have also announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination could ultimately lead to the direct regulation of GHG emissions in our industry under the Clean Air Act. While it is not clear whether or when any federal or state climate change laws or regulations will be passed, any of these actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital.

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 our 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 our business, financial condition, results of operations and cash flows.

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

We rely on a limited number of customers for a significant portion of our revenues. For the year ended December 31, 2009, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company. These customers accounted for approximately 33.1 percent of our operating revenues for the year ended December 31, 2009. The loss of even a portion of our contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and cash flows, unless we are able to acquire comparable revenues from other sources.

We are exposed to the credit risk of our customers, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers in the ordinary course of our business. Generally our customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, results of operations, cash flows and financial condition

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

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas to end use markets, thereby reducing our 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 our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

We do not own all of the land on which our pipeline and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. We obtain, in certain instances, the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited term. We do not have the right of eminent domain over land owned by Native American tribes. Our loss of any of these rights, through our inability to renew right of way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

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

Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to onshore assets and resulting business interruption caused by terrorist acts. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to hurricane losses in recent years have impacted named windstorm insurance coverage, rates and availability for Gulf of Mexico area exposures, and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 our capital projects subjects us to construction risks, increases in labor costs and materials, and other risks that may adversely affect financial results.

A significant portion of our 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 results of operations, financial position or cash flows.

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 Related to Strategy and Financing

Our debt agreements and Williams’ and WPZ’s public indentures contain financial and operating restrictions that may limit our access to credit and affect our ability to operate our business. In addition, our ability to obtain credit in the future will be affected by Williams’ and WPZ’s credit ratings.

Our public indentures contain various covenants that, among other things, limit our ability to grant certain liens to support indebtedness, merge, or sell substantially all of our assets. In addition, our new credit facility entered into as part of Williams’ restructuring (New Credit Facility) contains certain financial covenants and restrictions on our ability and our subsidiaries’ ability to incur indebtedness, to consolidate or allow any material change in the nature of our business, enter into certain affiliate transactions, and make certain distributions during an event of default. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.

Williams’ and WPZ’s public indentures contain covenants that restrict their and our ability to incur liens to support indebtedness. These covenants could adversely affect our ability to finance our future operation or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Williams’ and WPZ’s ability to comply with the covenants contained in their respective debt instruments may be affected by events beyond our and their control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, Williams’ or WPZ’s ability to comply with these covenants may be negatively impacted.

Our failure to comply with the covenants in our 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. Certain payment defaults or an acceleration under our public indentures or other material indebtedness could cause a cross-default or cross-acceleration of our New Credit Facility. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if our New Credit Facility cross-defaults, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.”

Substantially all of Williams’ and WPZ’s operations are conducted through their respective subsidiaries. Williams’ and WPZ’s cash flows are substantially derived from loans, dividends and distributions paid to them by their respective subsidiaries.

Williams’ and WPZ’s cash flows are typically utilized to service debt and pay dividends or distributions on their equity, with the balance, if any, reinvested in their respective subsidiaries as loans or contributions to capital. Due to our relationship with Williams and WPZ , our ability to obtain credit will be affected by Williams’ and WPZ’s credit ratings. If Williams or WPZ were to experience deterioration in their respective credit standing or financial condition, our access to credit and our ratings could be adversely affected. Any future downgrading of a Williams’ or WPZ’s credit rating would likely also result in a downgrading of our credit rating. A downgrading of a Williams’ or WPZ’s credit rating could limit our ability to obtain financing in the future upon favorable terms, if at all.

Future disruptions in the global credit markets may make debt markets less accessible, create a shortage in the availability of credit and lead to credit market volatility.

In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. Future disruptions in the global financial marketplace, including the bankruptcy or restructuring of financial institutions, could make debt markets inaccessible and adversely affect the availability of credit already arranged and the availability and cost of credit in the future. We have availability under the New Credit Facility, but our ability to borrow under that facility could be impaired if one or more of our lenders fails to honor its contractual obligation to lend to us.

Adverse economic conditions could negatively affect our results of operations.

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

A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of doing business, and maintaining our credit ratings is under the control of independent third parties.

A downgrade of our credit rating might increase our cost of borrowing and could cause us to post collateral with third parties, thereby negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:

	•		economic downturns;

	•		deteriorating capital market conditions;

	•		declining market prices for natural gas;

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

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

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. We are currently rated investment grade by three of the major credit rating agencies. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies and no assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

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

As of December 31, 2009, our general partners were both indirectly controlled by Williams. As of February 17, 2010, we are an indirect partially-owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests as of such date are owned by Williams. The majority interest in our business is owned by a subsidiary of WPZ. As a result, WPZ exercises substantial control over our business and operations and makes determinations with respect to, among other things, the following:

	•		payment of distributions and repayment of advances;

	•		decisions on financings and our capital raising activities;

	•		mergers or other business combinations; and

	•		acquisition or disposition of assets.

Our majority partner’s board of directors could decide to increase distributions or advances to our partners consistent with existing debt covenants. This could adversely affect our liquidity.

Risks Related to Regulations that Affect our Industry

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

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

	•		transportation of natural gas in interstate commerce;

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

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

	•		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, 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 our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs and otherwise altering the profitability of our business.

The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and their marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting 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 the rules are subject to potentially substantial civil penalty assessments.

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

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

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

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

There is a risk that rates set by the FERC will be inadequate to cover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.

The outcome of future rate cases will determine the amount of income taxes that we will be allowed to recover.

In May 2005, the FERC issued a statement of general policy permitting a pipeline to include in its 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. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.

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 we or our affiliates are named as defendants. Both the shippers on our pipeline and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. We 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, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation,

which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. 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.

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

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

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

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

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

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

Our allocation from Williams for costs for its defined benefit pension plans and other postretirement benefit plans are affected by factors beyond our and Williams’ control.

As we have no employees, employees of Williams and its affiliates provide services to us. As a result, we are allocated a portion of Williams’ costs in defined benefit pensions plans covering substantially all of Williams’ or its affiliates’ employees providing services to us, as well as a portion of the costs of other postretirement benefit plans covering certain eligible participants providing services to us. The timing and amount of our allocations under the defined benefit pension plans depend upon a number of factors Williams controls, including changes to pension plan benefits, as well as factors outside of Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our allocations could have a significant adverse effect on our financial condition and results of operations.

Risks Related to Weather, Other Natural Phenomena and Business Disruption

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

Our assets and operations can be adversely affected by floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance may not be available. A significant disruption in operations

or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

Our 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 our financial condition, results of operations and cash flows.

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


Item 1B.		UNRESOLVED STAFF COMMENTS

None.


Item 2.		PROPERTIES

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


Item 3.		LEGAL PROCEEDINGS

The information called for by this item is provided in “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities and Commitments — Legal Proceedings.”


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

On December 31, 2009, we were owned 65 percent by Williams and 35 percent by Williams Pipeline Partners L.P., a publicly traded master limited partnership. Our partnership interest is not publicly traded. Through its partial ownership of Williams Pipeline Partners L.P., Williams directly and indirectly owns 81.7 percent of us as of December 31, 2009.

On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed its ownership in WGPC Holdings LLC to WPZ, a publicly traded Delaware limited partnership which is controlled by and consolidated with Williams. Through its ownership interests in each of our partners, Williams indirectly owns 71.3 percent of us as of February 17, 2010.

On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the successful consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in us and Williams will hold an approximate 80 percent interest in WPZ.

We paid $135.0 million and $419.3 million in cash distributions to our partners during 2009 and 2008, respectively.


Item 6.		SELECTED FINANCIAL DATA

The following financial data should be read in conjunction with “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8. Financial Statements and Supplementary Data.”


	Year Ended December 31,
	2009		2008		2007			2006		2005
			(Restated) (B)		(Restated) (B)			(Restated) (B)		(Restated) (B)
					(Thousands of Dollars)
Income Statement Data:
Operating revenues	$	434,379	$	434,854	$	421,851		$	324,250	$	321,457
Net income		153,651		155,371		439,726	(A)		54,462		68,974
Balance Sheet Data (at period end):
Total assets		2,081,277		2,078,812		2,033,596			2,034,748		1,661,324
Long-term debt, including current maturities		693,437		693,240		693,736			687,075		520,080
Total owners’ equity		1,207,150		1,210,547		1,177,098			846,809		728,505
Cash Distributions		135,000		419,342		109,770			—		50,000


Note:		Earnings and distributions/dividends per partnership unit/common share are not presented for 2005 through 2009. We were a wholly-owned subsidiary of Williams at December 31, 2007 and for all prior periods presented. Distributions for 2009 and 2008 were made to our partners based upon each partnership’s ownership interest.


(A)		Through September 30, 2007, we used the liability method of accounting for income taxes which required, among other things, provisions for all temporary differences between the financial basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. On October 1, 2007, we reversed deferred income tax liabilities of approximately $311.8 million to income and $0.2 million of deferred income tax assets to other comprehensive income.

(B)		Our financial statements have been restated as described in “Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 2. Restatement.” Accordingly, our 2005, 2006, 2007, and 2008 selected financial data has been restated to reflect


		the change in accounting treatment. The net impact of the balance sheet corrections resulted in an adjustment to loans to affiliate which have been reclassified to equity. A reconciliation between our original basis in our total assets and liabilities and the selected financial data above follows:


	Year Ended December 31,
	2008			2007		2006		2005
				(Thousands of Dollars)
Consolidated Balance Sheets:

Total assets, as previously reported	$	2,082,172		$	2,056,471	$	2,049,324	$	1,692,371
Benefit plans correction		3,360			22,875		14,576		31,047

Total assets, as restated	$	2,078,812		$	2,033,596	$	2,034,748	$	1,661,324


Total owners’ equity, as previously reported ,	$	1,184,714		$	1,185,616	$	857,945	$	756,346
Net (increase) decrease of benefit plans correction		(25,833	)		8,518		11,136		27,841

Total owners’ equity, as restated	$	1,210,547		$	1,177,098	$	846,809	$	728,505


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

GENERAL

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

On January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which we have presented and recognized pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor. We have previously recorded allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. The restatement did not have an impact on our 2008 or 2007 Net Income as our expense recognized approximated our contributions to the Williams-sponsored plans, nor did it have any impact on our 2008 or 2007 Statement of Cash Flows.

For a discussion of additional information on the restatement, see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 2. Restatement.”

RECENT DEVELOPMENTS

On January 19, 2010, WPZ announced that it intends to conduct an exchange offer for the outstanding publicly traded common units of WMZ (the WMZ Exchange Offer). Subject to the successful

consummation of the WMZ Exchange Offer, WPZ will own a 100 percent interest in us and Williams will hold an approximate 80 percent interest in WPZ.

HOW WE EVALUATE OUR OPERATIONS

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

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

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

	•		our operating expenses; and

	•		our cash available for distribution.

Long-Term Firm Service

We compete for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. To the extent our customers believe that we can offer these services at rates, terms and conditions that are more attractive than those of our competition, they will be more inclined to purchase our services. Firm transportation service requires us to reserve pipeline capacity for a customer at certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” charge based on the amount of capacity being reserved regardless of whether the capacity is used, plus a volumetric fee and an in-kind fuel reimbursement based on the volume of natural gas transported. Firm storage customers reserve a specific amount of storage capacity, including injection and withdrawal rights, and generally pay a capacity reservation charge based on the amount of capacity 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. Our ability to maintain or increase the amount of long-term firm service we provide is key to assuring a consistent revenue stream.

Short-Term Firm and Interruptible Service

A small portion of our revenues are generated by short-term firm and interruptible services under which customers pay fees for transportation, storage or other related services. Of our revenues for the twelve months ended December 31, 2009, approximately 4.4 percent were derived from short-term firm and interruptible services.

Operating Expenses

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

Cash Available for Distribution

Under our general partnership agreement, on or before the end of the calendar month following each quarter, our management committee is required to review the amount of available cash with respect

to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreements.

In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. In February 2010, our management committee authorized a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our Owners’ Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

FACTORS THAT IMPACT OUR BUSINESS

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

We believe the key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate, our customers and their requirements, and government regulation of natural gas pipelines. These key factors, described in “Item 1. Business — Pipeline System, Customers and Competition,” play an important role in how we manage our operations and implement our 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 our long-term firm contracts which could adversely affect our revenue over the long term. We also believe the impact of such factors may provide us with growth opportunities. These factors may also result in a need for increased capital expenditures to take advantage of opportunities to bring additional supplies of natural gas into our system to maintain or possibly increase our transportation commitments and volumes.

Please see “Part 1, Item 1. Business — Pipeline System, Customers and Competition” for a discussion regarding the impact of customers, competition and regulation on our business.

OPERATIONS

We own and operate a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Our system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Our compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, 2009, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.7 Bcf of natural gas per day. We also have approximately 13.0 Bcf of working natural gas storage capacity through our one-third interest in the Jackson Prairie underground storage facility, our ownership of the Plymouth LNG storage facility and contract storage at Clay Basin.

Transportation Services

Our transportation services consist primarily of a) firm transportation under long-term contracts, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points on the system, plus a volumetric fee and an in-kind fuel reimbursement based on the volume transported; and b) interruptible transportation, whereby the customer pays to transport natural gas

when capacity is available and used. Firm transportation capacity reservation revenues typically do not vary over the term of the contract, subject to adjustment in rate proceedings with FERC, because the revenues are primarily based upon the capacity reserved, and not upon the capacity actually used. We generate a small portion of our revenues from short-term firm and interruptible transportation services.

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

Storage Services

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

OUTLOOK

The overall economic recession and challenging financial markets during the past year have impacted our business. In the current economic environment, many financial markets, institutions and other businesses remain under considerable stress. These events continue to impact our business. However, we note the following:

	•		We have no significant debt maturities until 2016.

	•		As of December 31, 2009, we have approximately $66.8 million of available cash from return of advances made to affiliates and available capacity under our Credit Facility. (See further discussion in Management’s Discussion and Analysis of Financial Condition and Results of Operations — Method of Financing.)

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

Our strategy to create value focuses on maximizing the contracted capacity on our pipeline by providing high quality, low cost natural gas transportation and storage services to our markets. Changes in commodity prices and volumes transported have little impact on revenues because the majority of our revenues are recovered through firm capacity reservation charges. We grow our business primarily through expansion projects that are designed to increase our access to natural gas supplies and to serve the demand growth in our markets. Please see “Part 1, Item 1. Business — Capital Projects.”

CRITICAL ACCOUNTING POLICIES, ESTIMATES, JUDGMENTS AND SENSITIVITIES

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

Regulatory Accounting

We are regulated by the FERC. The Accounting Standards Codification Topic 980, Regulated Operations (Topic 980) provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management uses judgment in determining the probability that regulatory assets will be recoverable from, or regulatory liabilities will be refunded to, customers. A summary of regulatory assets and liabilities is included in Note 11 of Notes to Consolidated Financial Statements.

Contingencies

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

Environmental Liabilities

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

RESULTS OF OPERATIONS

Analysis of Financial Results

This analysis discusses financial results of our operations for the years 2009, 2008 and 2007. Variances due to changes in natural gas prices and transportation volumes have little impact on revenues, because under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in our transportation rates.

Years Ended December 31, 2008 and 2009

Operating revenues decreased $0.5 million, or less than one percent, for the year ended December 31, 2009 as compared to the year ended December 31, 2008. This decrease is primarily attributed to $4.4 million lower revenues due to the termination of the Parachute Lateral lease agreement on August 1, 2009, and was mostly offset by higher transportation revenues of $1.7 million resulting primarily from an increase in firm transportation under long-term contracts and higher storage revenues of $2.6 million resulting primarily from incremental reservation charges associated with the Jackson Prairie deliverability expansion that was placed in service on November 1, 2008. The decrease in the Parachute Lateral lease revenues is substantially offset by a decrease in lease expense described below.

Our transportation service accounted for 96 percent of our operating revenues for each of the years ended December 31, 2009 and 2008. Additionally, gas storage service accounted for 4 percent and 3 percent of operating revenues for the years ended December 31, 2009 and 2008, respectively.

Operating expenses increased $0.2 million, or less than one percent. This increase is due primarily to i) higher pension expense of $4.0 million, ii) higher allocated overhead from Williams of $3.0 million attributed primarily to higher pension expense, and iii) higher labor of $1.6 million attributed primarily to pipeline maintenance. These increases were mostly offset by i) lower taxes, other than income taxes, of $2.7 million primarily attributed to lower than anticipated property tax settlements and lower sales and use taxes resulting from lower fuel usage and a refund of taxes from prior years, ii) lower lease expense of $1.3 million attributed to the restructuring of the Salt Lake City headquarters building lease, and iii) $4.3 million lower expense from the termination of the Parachute Lateral lease agreement.

Other income — net increased $0.3 million, or 20 percent, due primarily to higher allowance for equity funds used during construction of $1.2 million attributed to higher capital expenditures in 2009, partially offset by lower interest income from affiliates of $0.7 million attributed to lower interest rates on advances to affiliates.

Interest charges increased $1.4 million, or 3 percent, due primarily to 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.

Years Ended December 31, 2007 and 2008

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.

Our transportation service accounted for 96 percent of our operating revenues for each of the years ended December 31, 2008 and 2007. Natural gas storage service accounted for 3 percent of operating revenues for 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 our pension regulatory liability of $16.6 million as described in Note 1 of the Notes to Consolidated Financial Statements, 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 our 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 our conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, we recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8 percent. At the date of conversion, we recognized income tax benefit of $311.8 million reflecting the removal of our net deferred tax liabilities.

CAPITAL RESOURCES AND LIQUIDITY

Our ability to finance operations (including the funding of capital expenditures and acquisitions), to meet our debt obligations and to refinance indebtedness depends on our ability to generate future cash flows and to borrow funds. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including the impact of regulators’ decisions on the rates we are able to establish for our transportation and storage services.

On or before the end of the calendar month following each quarter, available cash is distributed to our partners as required by our general partnership agreement. Available cash is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreements. During 2009, we distributed $135.0 million of available cash to our partners.

In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. In February 2010, our management committee authorized a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 was reflected as a reduction of our Owners’ Equity as the advances will not be available to us as working capital. Effective with the restructuring, we will become a participant in the WPZ cash management program.

We fund our capital spending requirements with cash from operating activities, third party debt and contributions from our partners with the exception of the CHC Project, which was funded by capital contributions from Williams. Through December 31, 2009, we have received $50.8 million in capital contributions from Williams to fund the CHC Project.

SOURCES (USES) OF CASH


	Years Ended December 31,
	2009			2008			2007
				(Thousands of Dollars)
Net cash provided (used) by:
Operating activities	$	234,798		$	239,014		$	205,357
Financing activities		(83,608	)		(126,848	)		(142,523	)
Investing activities		(151,133	)		(112,318	)		(63,826	)

Increase (decrease) in cash and cash equivalents	$	57		$	(152	)	$	(992	)

Operating Activities

Our net cash provided by operating activities in 2009 decreased $4.2 million from 2008. This decrease is primarily attributed to changes in other noncurrent assets and liabilities and working capital, partially offset by an increase in our cash operating results.

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

Financing Activities

2009

	•		We paid distributions of $135.0 million to our partners.

	•		We received $49.2 million in capital contributions from Williams for the CHC Project.

2008

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

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

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

	•		We paid distributions of $419.3 million to our partners.

2007

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

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

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

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

	•		We paid distributions of $109.8 million to Williams.

Investing Activities

2009

•

Capital expenditures totaled $152.6 million, primarily related to normal maintenance and compliance projects and the CHC Project.

2008

	•		Capital expenditures totaled $88.5 million, primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility.

	•		We advanced $26.9 million to Williams.

2007

	•		Capital expenditures totaled $156.8 million, primarily related to normal maintenance and compliance.

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

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

METHOD OF FINANCING

Working Capital

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

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

During 2009, we made distributions of available cash of $135.0 million to our partners, representing cash in excess of working capital requirements and reserves established by the management committee as necessary for the conduct of our business.

Short-Term Liquidity

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

We invest cash through participation in Williams’ cash management program. At December 31, 2009 and 2008, the advances due to us by Williams totaled approximately $66.8 million and $66.0 million, respectively. The advances are represented by one or more demand obligations. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 0.05 percent and zero percent at December 31, 2009 and 2008, respectively.

Credit Agreement

Williams has an unsecured, $1.5 billion credit facility with a maturity date of May 1, 2012 (Credit Facility). Prior to Williams’ restructuring, we had access to $400 million under the Credit Facility to the extent not otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. 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) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. As of December 31, 2009, there were no letters of credit issued by the participating institutions and no revolving credit loans outstanding. In December 2007, we borrowed $250.0 million under the Credit Facility 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. We did not borrow under the Credit Facility in 2008 or 2009. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements.”

The Credit Facility contains a number of restrictions on the business of the borrowers, including us. These restrictions include restrictions on the borrowers’ and their subsidiaries’ ability to: (i) grant liens

securing indebtedness; (ii) merge, consolidate, or sell, lease or otherwise transfer assets; (iii) incur indebtedness; and (iv) engage in transactions with related parties. We and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in our case, and 0.65 to 1, in the case of Williams. The Credit Facility 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 Facility. 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 Facility would terminate and all indebtedness outstanding under the Credit Facility would be accelerated.

As part of the restructuring, we were removed as borrowers under the Credit Facility, and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with WPZ and Transcontinental Gas Pipe Line Company, LLC (Transco), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Transco. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement.

Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.

The New Credit Facility contains various covenants that limit, among other things, a borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of its business.

Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a rolling four-quarter basis.

The New Credit Facility includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-payment defaults, cross acceleration, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.

Long-Term Financing

We 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 future amounts raised, if any, in the capital markets. We anticipate that we will be able to access

public and private debt markets on terms commensurate with our credit ratings to finance our capital requirements, when needed.

CAPITAL REQUIREMENTS

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

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, increase transmission or storage capacities from existing levels or enhance revenues. We anticipate 2010 capital expenditures will be between $120 million and $140 million. Of this total, $95 million to $115 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2010, we expect to fund our capital expenditures with cash from operations, with the exception of the final costs for the CHC Project which will be funded by capital contributions from Williams.

Property, plant and equipment additions were $156.6 million, $78.6 million and $157.2 million for 2009, 2008 and 2007, respectively. The $78.0 million increase from 2008 to 2009 is primarily attributed to expenditures related to pipeline integrity, the CHC Project, and the Sundance Trail Expansion Project.

CREDIT RATINGS

During 2009, the credit ratings on our senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below.


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

At December 31, 2009 and through the date of this report, the evaluation of our credit rating is “stable” from Moody’s Investors Service and Fitch Ratings. On January 12, 2010, Standard and Poor’s revised our ratings outlook to “positive” from “stable.”

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.

OTHER

Contractual Obligations

The table below summarizes the maturity dates of our more significant contractual obligations and commitments as of December 31, 2009 (in millions of dollars).


	2010		2011-2012		2013-2014		Thereafter		Total

Long-term debt, including current portion:
Principal	$	—	$	—	$	—	$	695.0	$	695.0
Interest		44.4		88.9		88.9		165.5		387.7
Operating leases		2.3		4.6		4.5		11.8		23.2
Purchase Obligations:
Natural gas purchase, storage, transportation and construction		27.1		4.6		4.1		—		35.8
Other		0.1		0.3		0.3		6.7		7.4
Other long-term liabilities, including current portion (1)(2)		1.5		3.0		3.3		—		7.8

Total	$	75.4	$	101.4	$	101.1	$	879.0	$	1,156.9


(1)		Does not include estimated settlement of asset retirement obligations. (Please see “Item 8 Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 10. Asset Retirement Obligations.”)

(2)		Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. (Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 11. Regulatory Assets and Liabilities.”)

Off-Balance Sheet Arrangements

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

Impact of Inflation

We have generally experienced increased costs in recent years due to the effect of inflation on the cost of labor, benefits, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies costs can directly affect income through increased operating and maintenance costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of the costs related to our property, plant and equipment and materials and supplies is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, we believe we may be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. However, cost-based regulation along with competition and other market factors may limit our 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 — Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities and Commitments,” we are subject to extensive federal, state and local environmental laws and regulations which affect our operations related to the construction and operation of our pipeline facilities. We consider environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable

through rates, as they are prudent costs incurred in the ordinary course of business. To date, we have been permitted recovery of environmental costs incurred, and it is our intent to continue seeking recovery of such costs, as incurred, through rate filings.

Safety Matters

Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities and Commitments for information about pipeline integrity regulations.”

Legal Matters

We are party to various legal actions arising in the normal course of business. Our management believes that the disposition of outstanding legal actions will not have a material adverse impact on our future liquidity or financial condition. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities and Commitments.”

Regulatory Proceedings

Please see “Item 8. Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements: Note 3. Rate and Regulatory Matters and Note 4. Contingent Liabilities and Commitments” for information about regulatory and business developments which cause operating and financial uncertainties.

CONCLUSION

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


Item 7A.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

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


	December 31, 2009
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		1,563


Total long-term debt	$	693,437

Our total long-term debt at December 31, 2009 had a carrying value of $693.4 million and a fair market value of $753.2 million. As of December 31, 2009, the weighted-average interest rate on our long-term debt was 6.4 percent. We expect to have sensitivity to interest rate changes with respect to future debt facilities and our ability to prepay existing facilities.

Credit Risk

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

Market Risk

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

MANAGEMENT’S 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 Senior Vice President and our Vice President and Treasurer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2009, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Previously, our management had concluded that our internal control over financial reporting was effective for the period ended December 31, 2008. In the first quarter of 2010, we identified a material weakness related to the manner in which we presented and recognized pension and post retirement obligations in certain benefit plans for which our parent is the plan sponsor.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

As discussed further in Note 2 of the Notes to Consolidated Financial Statements, we previously recorded parent-allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. The error was significant to the Statement of Comprehensive Income for the period ended December 31, 2008. The impact of the correction also increased Owners’ Equity and reduced non-current assets and liabilities. It did not have an impact on our 2008 Net Income, nor did it have any impact on our 2008 Statement of Cash Flows.

Based upon our current assessment, which considered the material weakness described above, our management concluded that our internal control over financial reporting was not effective at December 31, 2008. Our management also concluded that our internal control over financial reporting was not effective at December 31, 2009.

We have corrected our method of accounting to the multi-employer model, and this change is reflected in our financial statements for the period ended December 31, 2009. We have also enhanced our controls that ensure proper selection and application of generally accepted accounting principles.

This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company 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, 2009 and 2008, and the related consolidated statements of income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2009. 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 Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Northwest Pipeline GP at December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the Company restated its consolidated balance sheet as of December 31, 2008 and the related consolidated statements of comprehensive income, and owner’s equity for each of the two years then ended, as a result of the correction of an error related to pension and other postretirement benefit obligations in certain benefit plans for which their parent, The Williams Companies, Inc., is the plan sponsor.



	/s/ Ernst & Young

Houston, Texas
February 23, 2010

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME

(Thousands of Dollars)


	Years Ended December 31,
	2009			2008			2007
OPERATING REVENUES	$	434,379		$	434,854		$	421,851


OPERATING EXPENSES:
General and administrative		64,657			60,403			65,772
Operation and maintenance		71,085			72,831			66,847
Depreciation		86,373			86,184			84,731
Regulatory credits		(2,403	)		(2,617	)		(3,663	)
Taxes, other than income taxes		14,158			16,875			13,997
Regulatory liability reversal		—			—			(16,562	)


Total operating expenses		233,870			233,676			211,122


Operating income		200,509			201,178			210,729


OTHER INCOME — net:
Interest income —
Affiliated		74			813			2,983
Other		16			6			2,681
Allowance for equity funds used during construction		1,996			812			2,091
Miscellaneous other expense, net		(135	)		(8	)		(517	)
Contract termination income		—			—			18,199


Total other income — net		1,951			1,623			25,437


INTEREST CHARGES:
Interest on long-term debt		44,439			42,290			46,828
Other interest		5,414			5,571			5,585
Allowance for borrowed funds used during construction		(1,044	)		(431	)		(1,306	)


Total interest charges		48,809			47,430			51,107


INCOME BEFORE INCOME TAXES		153,651			155,371			185,059

BENEFIT FOR INCOME TAXES (Note 7)		—			—			(254,667	)


NET INCOME	$	153,651		$	155,371		$	439,726


CASH DISTRIBUTIONS/DIVIDENDS	$	135,000		$	419,342		$	109,770

See accompanying notes.

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY

(Thousands of Dollars, Except Per Share Amounts)


	Years Ended December 31,
	2009			2008			2007
				(Restated)			(Restated)
Common stock, par value $1 per share, authorized, 1,000 shares
Balance at beginning of period, outstanding, 1,000 shares for 2007	$	—		$	—		$	1
Conversion to GP		—			—			(1	)

Balance at end of period		—			—			—


Additional paid-in capital -
Balance at beginning of period		—			—			977,021
Conversion to GP		—			—			(977,021	)


Balance at end of period		—			—			—


Partners’ capital -
Balance at beginning of period		978,682			977,022			—
Capital contribution from partner		49,180			1,660			—
Conversion to GP		—			—			977,022


Balance at end of period		1,027,862			978,682			977,022


Loans (to) from affiliate -
Balance at beginning of period		(34,265	)		(29,186	)		(29,364	)
Loans (to) from affiliate		(71,166	)		(5,079	)		178


Balance at end of period		(105,431	)		(34,265	)		(29,186	)


Retained earnings (deficit) -
Balance at beginning of period		265,668			228,739			(101,214	)
Net income		153,651			155,371			439,726
Cash distributions		(135,000	)		(419,342	)		(109,770	)
Sale of partnership interest		—			300,900			—
Other		—			—			(3	)

Balance at end of period		284,319			265,668			228,739


Accumulated other comprehensive income (loss) —
Balance at beginning of period		462			523			365
Cash flow hedges:
Reclassification of gain into earnings		(62	)		(61	)		(62	)
Elimination of deferred income taxes		—			—			220

Balance at end of period		400			462			523


Total owners’ equity	$	1,207,150		$	1,210,547		$	1,177,098

See accompanying notes.

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)


	Years Ended December 31,
	2009			2008			2007
				(Restated)			(Restated)
OPERATING ACTIVITIES:
Net Income	$	153,651		$	155,371		$	439,726
Adjustments to reconcile to net cash provided by operating activities -
Depreciation		86,373			86,184			84,731
Regulatory credits		(2,403	)		(2,617	)		(3,663	)
Gain on sale of property, plant and equipment		(508	)		(378	)		—
Provision (benefit) for deferred income taxes		—			—			(289,229	)
Amortization of deferred charges and credits		12,561			8,589			9,783
Allowance for equity funds used during construction		(1,996	)		(812	)		(2,091	)
Reserve for doubtful accounts		—			(7	)		(46	)
Regulatory liability reversal		—			—			(16,562	)
Contract termination income		—			—			(6,045	)
Cash provided (used) by changes in current assets and liabilities:
Trade accounts receivable		(326	)		580			(8,413	)
Affiliated receivables, including income taxes in 2007		(3,284	)		2,284			(2,923	)
Exchange gas due from others		2,623			4,583			(1,654	)
Materials and supplies		(143	)		527			(331	)
Other current assets		1,744			943			1,017
Trade accounts payable		(828	)		(2,599	)		4,653
Affiliated payables, including income taxes in 2007		275			(6,572	)		(5,259	)
Exchange gas due to others		(2,623	)		(4,583	)		1,654
Other accrued liabilities		(533	)		3,083			2,105
Changes in noncurrent assets and liabilities:
Deferred charges		(4,580	)		(423	)		(9,769	)
Other deferred credits		(5,205	)		(5,139	)		7,673

Net cash provided by operating activities		234,798			239,014			205,357

FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		—			249,333			434,362
Retirement of long-term debt		—			(250,000	)		(252,867	)
Early retirement of long-term debt		—			—			(175,000	)
Debt issuance costs		—			(2,027	)		(2,059	)
Premium on early retirement of long-term debt		—			—			(7,111	)
Capital contribution from parent		49,180			1,660			—
Proceeds from sale of partnership interest		—			300,900			—
Distributions paid		(135,000	)		(419,342	)		(109,770	)
Changes in cash overdrafts		2,212			(7,372	)		(30,078	)

Net cash used in financing activities		(83,608	)		(126,848	)		(142,523	)

INVESTING ACTIVITIES:
Property, plant and equipment -
Capital expenditures*		(152,580	)		(88,478	)		(156,761	)
Proceeds from sales		2,234			3,065			2,257
Proceeds from sale of Parachute facilities		—			—			79,770
Repayments from (advances to) affiliates		(787	)		(26,905	)		10,908

Net cash used in investing activities		(151,133	)		(112,318	)		(63,826	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		57			(152	)		(992	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		345			497			1,489

CASH AND CASH EQUIVALENTS AT END OF YEAR	$	402		$	345		$	497


^* Increases to property, plant and equipment	$	(156,576	)	$	(78,566	)	$	(157,163	)
Changes in related accounts payable and accrued liabilities		3,996			(9,912	)		402

Capital expenditures	$	(152,580	)	$	(88,478	)	$	(156,761	)


Supplemental disclosures of non-cash transactions:
Adjustment to owners’ equity for benefit plans correction	$	(4,402	)	$	(5,079	)	$	178
Advances to affiliates reclassified to owners’ equity		66,764			—			—

See accompanying notes.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure and Control

Northwest Pipeline GP (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 we are a general partnership, we are not subject to federal and state income taxes. Coincident with our conversion to a general partnership 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 was 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 December 31, 2009.

Northwest is not an employer. Services are provided to Northwest by Northwest Pipeline Services LLC, a consolidated affiliate. 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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

The Accounting Standards Codification Regulated Operations (Topic 980) provides that rate-regulated public utilities 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 Topic 980, 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, 2009 and 2008, we had approximately $59.2 million and $57.8 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 $15.1 million and $14.7 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.

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; and 5) 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 2.77 percent, 2.79 percent and 2.76 percent for 2009, 2008 and 2007, respectively, including an allowance for negative salvage.

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We recorded regulatory credits totaling $2.4 million in 2009, $2.6 million in 2008, and $3.7 million in 2007 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 $30.8 million at December 31, 2009, and $28.4 million at December 31, 2008. 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, 2009 and 2008 were $33.8 million and $26.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

The negative salvage component of accumulated depreciation ($29.5 million and $25.6 million at December 31, 2009 and 2008, 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 2009, 2008 and 2007. Equity AFUDC of $2.0 million, $0.8 million and $2.1 million for 2009, 2008 and 2007, 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 do not record 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 0.05 percent and zero percent at December 31, 2009 and 2008, respectively.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

Accounts Receivable and Allowance for Doubtful Receivables

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

Materials and Supplies Inventory

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

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

Impairment of Long-Lived Assets

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

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

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 7.)

Deferred Charges

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED 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.

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a reservation charge based on the volume of contracted capacity and a volumetric charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for reservation charges ratably over the contract period regardless of the volume of natural gas that is transported or stored. Revenues for volumetric 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 the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks. At December 31, 2009, 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 $44.5 million, $43.1 million and $49.7 million in 2009, 2008 and 2007, respectively.

Subsequent Events

We have evaluated our disclosure of subsequent events through the time of filing this Form 10-K with the SEC on February 23, 2010.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Accounting Standards Issued But Not Yet Adopted

In June 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2009-17, “Consolidations (Topic 810) — Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities” (ASU No. 2009-17). This Update amends Interpretation 46(R) to require an entity to perform a qualitative analysis to determine whether the entity’s variable interest or interests give it a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the entity that has both the power to direct the activities that most significantly impact the VIE’s economic performance and the obligation to absorb losses or the right to receive benefits of the VIE. ASU No. 2009-17 amends Interpretation 46(R) to replace the quantitative-based risks and rewards approach previously required for determining the primary beneficiary of a VIE. ASU No. 2009-17 is effective as of the beginning of an entity’s first annual reporting period that begins after November 15, 2009 and for interim periods within that first annual reporting period. Earlier application is prohibited. We will assess the application of this Statement on our Consolidated Financial Statements.

In January 2010, the FASB issued ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This Update requires new disclosures regarding the amount of transfers in or out of levels 1 and 2 along with the reason for such transfers and also requires a greater level of disaggregation when disclosing valuation techniques and inputs used in estimating level 2 and level 3 fair value measurements. This Update also includes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plan assets. The disclosures will be required for reporting beginning in the first quarter of 2010. Also, beginning with the first quarter of 2011, the Standard requires additional categorization of items included in the rollforward of activity for level 3 inputs on a gross basis. We are assessing the application of this Standard to disclosures in our Consolidated Financial Statements.

Change in Accounting Estimate

In the second quarter of 2007, we recorded $16.6 million in income for a change in accounting estimate related to a pension regulatory liability. For the tax-qualified pension plans, we had historically recorded a regulatory asset or liability for the difference between pension expense and the amount we funded as a contribution to our pension plans. As a result of additional information, including the most recent rate filing, we re-assessed the probability of refunding or recovering this difference and concluded that it was not probable that it would be refundable or recoverable in future rates.

2. RESTATEMENT

We participate in pension and postretirement benefit plans sponsored by Williams. However, we have historically accounted for these plans as if they were our own. We have now determined that ASC 715-30-55-63 requires us to account for the plans as if we are a participant in a multi-employer plan. This error in methodology had the most significant impact to our financial statements for the year ended December 31, 2008. In that year, we recognized a significant Williams-allocated actuarial loss on our Consolidated Balance Sheet, Consolidated Statement of Owners’ Equity and Consolidated Statement of Comprehensive Income. We have determined that the error was significant to the Statement of Comprehensive Income for the year ended December 31, 2008. For this period, Comprehensive Income should have approximated Net Income. The effect of the adjustments to Comprehensive Income is an increase of $39.4 million in 2008 and $2.4 million in 2007, respectively. The impact of this error correction also increased Owners’ Equity and reduced noncurrent assets and liabilities at December 31,

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2008, with an offsetting impact to Loans to Affiliate, which is presented as a reduction to Owners’ Equity (See Note 1). The impact of the error correction did not have an impact on our 2008 or 2007 Net Income as our expense recognized approximated our contributions to the Williams’-sponsored plans, nor did it have any impact on our 2008 or 2007 Consolidated Statements of Cash Flows.

The following schedules reconcile the amounts previously reported in our consolidated Financial Statements as of December 31, 2008 and for the years ended December 31, 2008 and 2007.


	December 31,
	2008
Consolidated Balance Sheet:
Deferred charges, as previously reported	$	22,213
Correction to remove benefit plan assets		3,360

Deferred charges, as restated	$	18,853


Total other assets, as previously reported	$	77,795
Correction to remove benefit plan assets		3,360

Total other assets, as restated	$	74,435


Total assets, as previously reported	$	2,082,172
Correction to remove benefit plan assets		3,360

Total assets, as restated	$	2,078,812


Accrued liabilities -
Employee costs, as previously reported	$	10,505
Correction to remove benefit plan liabilities		79

Employee costs, as restated	$	10,426


Total current liabilities, as previously reported	$	69,009
Correction to remove benefit plan liabilities		79

Total current liabilities as restated	$	68,930


Deferred credits and other noncurrent liabilities, as previously reported	$	135,209
Correction to remove benefit plan liabilities		29,114

Deferred credits and other noncurrent liabilities, as restated	$	106,095


Loan to affiliate, as previously reported	$	—
Correction to remove benefit plan assets and liabilities		34,265

Loan to affiliate, as restated	$	(34,265	)


Accumulated other comprehensive loss, as previously reported	$	(59,636	)
Correction to remove benefit plans		(60,098	)

Accumulated other comprehensive income, as restated	$	462


Total owners’ equity, as previously reported	$	1,184,714
Correction to remove benefit plan assets, liabilities, and other comprehensive loss		(25,833	)

Total owners’ equity, as restated	$	1,210,547


Total liabilities and owners’ equity, as previously reported	$	2,082,172
Correction to remove benefit plan assets, liabilities, and other comprehensive loss		3,360

Total liabilities and owners’ equity, as restated	$	2,078,812

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Years Ended December 31,
	2008			2007
Consolidated Statements of Owners’ Equity:
Loan to affiliate -
Balance at beginning of period, as previously reported	$	—		$	—
Cumulative amount of benefit plans correction		—			(29,364	)

Balance at beginning of period, as restated		(29,186	)		(29,364	)
Loans (to) from affiliate		(5,079	)		178

Balance at end of period	$	(34,265	)	$	(29,186	)

Accumulated other comprehensive income (loss) —
Balance at beginning of period, as previously stated	$	—		$	(17,863	)
Cumulative amount of benefit plans correction		—			18,228

Balance at beginning of period, as restated		523			365

Cash flow hedges:
Reclassification of gain into earnings		(61	)		(62	)
Elimination of deferred income taxes		—			220

Balance at end of period	$	462		$	523


	Years Ended December 31,
	2008			2007
Consolidated Statements of Comprehensive Income:

Total comprehensive income, as previously reported	$	115,880		$	437,444
Correction to remove benefit plans		(39,430	)		(2,440	)

Total comprehensive income, as restated	$	155,310		$	439,884

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

As contemplated in the application for amendment, Parachute leased the facilities back to us, and we continued to operate the facilities under the FERC certificate. Under the terms of the lease, we paid

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Parachute 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. The lease was terminated on August 1, 2009, and Parachute assumed full operational control and responsibility for the Parachute Lateral.

4. CONTINGENT LIABILITIES AND COMMITMENTS

Legal Proceedings

We are a party to legal, administrative, and regulatory proceedings arising in the ordinary course of business.

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 we are 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, 2009, we had accrued liabilities totaling approximately $7.8 million for these costs which are expected to be incurred through 2015. 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 issued new air quality standards for ground level ozone, but in September 2009, the EPA announced that it would reconsider those standards. In January 2010, the EPA proposed standards more stringent than the March 2008 standards. The EPA expects that these proposed standards will be final in August 2010 and that new eight-hour ozone non-attainment areas will be designated in July 2011. The new standards and non-attainment areas will likely impact the operations of our interstate gas pipeline and cause us to incur additional capital expenditures. At this time, we are unable to estimate the cost of the additions that may be required to meet these regulations. We expect that costs associated with these compliance efforts will be recoverable through 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 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 primarily capital in nature and range between $65 million and $85 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

over the remaining assessment period of 2010 through 2012. 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 liquidity or financial position.

Other Commitments

We have commitments for construction and acquisition of property, plant and equipment of approximately $13.4 million at December 31, 2009.

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 interest in us. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. During the year ended December 31, 2009, we declared and paid equity distributions of $135.0 million to our partners. In January 2010, we declared and paid equity distributions of $36.0 million to our partners.

5. DEBT, FINANCING ARRANGEMENTS AND LEASES

Debt Covenants

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Long-Term Debt

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.

Long-term debt consists of the following:


	December 31,
	2009		2008
	(Thousands of Dollars)
5.95%, payable 2017	$	184,535	$	184,471
6.05%, payable 2018		249,440		249,374
7%, payable 2016		174,643		174,587
7.125%, payable 2025		84,819		84,808


Total long-term debt	$	693,437	$	693,240

As of December 31, 2009, 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)
2010	$	—
2011		—
2012		—
2013		—
2014		—
Thereafter		695,000

Total	$	695,000

Line-of-Credit Arrangements

Williams has an unsecured, $1.5 billion credit facility (Credit Facility) with a maturity date of May 1, 2012. Prior to Williams restructuring, we had access to $400 million under the Credit Facility to the extent not otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. 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) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. As of December 31, 2009, there were no letters of credit issued by the participating institutions and no revolving credit loans outstanding. We did not access the Credit Facility in 2009 or 2008.

Significant financial covenants under the Credit Facility include the following:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	•		Williams’ ratio of debt to capitalization must be no greater than 65 percent. Williams was in compliance with this covenant at December 31, 2009.

	•		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, 2009.

On February 17, 2010, Williams completed a strategic restructuring, pursuant to which Williams contributed substantially all of its domestic midstream and pipeline businesses, which includes us, into WPZ. We are now a partially-owned subsidiary of WPZ. As part of the restructuring, we were removed as borrowers under the Credit Facility, and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (New Credit Facility) with WPZ and Transcontinental Gas Pipe Line Company, LLC (Transco), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the New Credit Facility is available to WPZ, and may be increased by up to an additional $250 million. We may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by WPZ and Transco. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement.

Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus the applicable margin, or (2) a periodic fixed rate equal to LIBOR plus the applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank, N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are determined by reference to a pricing schedule based on a borrower’s senior unsecured debt ratings.

Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios will be tested beginning June 30, 2010 at the end of each fiscal quarter, and the debt to EBITDA ratio is measured on a rolling four-quarter basis.

Leases

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

Through September 30, 2009, the major operating lease was a leveraged lease for our headquarters building, which became effective during 1982. The agreement had 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 exercised our option to renew the term of the lease for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

approximately 9 years, beginning October 1, 2009. The major component of the lease payment was set through the initial and first renewal terms of the lease. Various purchase options existed under the building lease, including options involving adverse regulatory developments. Through September 30, 2009, we subleased portions of our headquarters building to third parties under agreements with varying terms. This leveraged lease for our headquarters building was assigned to a third party effective October 1, 2009.

Effective October 1, 2009, we entered into an agreement to lease office space from a third party. The agreement has an initial term of approximately 10 years, with an option to renew for an additional 5 or 10 year term.

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)
2010	$	2,284

2011		2,284

2012		2,284

2013		2,284

2014		2,285


Total	$	11,421

Operating lease rental expense, net of sublease revenues, amounted to $3.6 million, $4.9 million, and $4.9 million for 2009, 2008 and 2007, respectively.

On December 31, 2007, in connection with the sale of Parachute to an affiliate of Williams, Parachute leased the facilities back to us. We continued to operate the facilities under the FERC certificate through July 31, 2009. The lease terminated on August 1, 2009. Under the terms of the lease, we paid 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.

6. EMPLOYEE BENEFIT PLANS

Pension and other postretirement benefit plans

We participate in pension and other postretirement benefit plans sponsored by Williams. We account for these plans on the multi-employer accounting model in which we expense the amounts billed to us by Williams or other Williams’ affiliates for our participation in these plans. We recognized pension expense of $7.5 million in 2009, $3.5 million in 2008 and $4.0 million in 2007. No other postretirement benefit expense was recognized in 2009, 2008 or 2007.

Defined contribution plan

Employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $2.2 million in 2009, $2.1 million in 2008 and $2.0 million in 2007 for Williams’ company matching contributions to this plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation

Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (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 the options. 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 awards is based on the grant date fair value. The performance targets for certain performance based restricted stock units have not been established and therefore, expense is not currently recognized. Expense associated with these performance-based awards will be recognized in future periods when performance targets are established.

Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2009, 2008 and 2007 was $1.3 million, $1.0 million and $1.1 million, respectively, excluding amounts allocated from WGP and Williams.

7. INCOME TAXES

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

The benefit for income taxes includes:


	Year Ended December 31,
	2009		2008		2007
	(Thousands of Dollars)
Current:
Federal	$	—	$	—	$	30,888
State		—		—		3,674

		—		—		34,562


Deferred:
Federal		—		—		(258,459	)
State		—		—		(30,770	)


		—		—		(289,229	)


Total benefit	$	—	$	—	$	(254,667	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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


	Year Ended December 31,
	2009		2008		2007
	(Thousands of Dollars)
Provision at statutory Federal income tax rate of 35 percent (1)	$	—	$	—	$	52,831
Increase in tax provision resulting from -
State income taxes net of Federal tax benefit		—		—		3,948
Book/tax basis reconciliation adjustment		—		—		—
Other — net		—		—		330


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


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


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


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


(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.

No cash payments for income taxes were made to or received from Williams in 2009 or 2008. Net cash payments made to Williams for income taxes were $37.7 million in 2007.

8. FINANCIAL INSTRUMENTS

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 $693.4 million and $753.2 million, respectively, at December 31, 2009, and $693.2 million and $572.0 million, respectively, at December 31, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES

Concentration of Off-Balance-Sheet and Other Credit Risk

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


	Year Ended December 31,
	2009		2008		2007
	(Thousands of Dollars)
Puget Sound Energy, Inc.	$	94,508	$	89,988	$	85,059
Northwest Natural Gas Co.		49,256		(a)		48,648


(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, 2009 and 2008, the advances due to us by Williams totaled approximately $66.8 million and $66.0 million, respectively. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was approximately 0.05 percent and zero percent at December 31, 2009 and 2008, respectively. We received interest income from advances to Williams of $74 thousand, $813 thousand, and $2,983 thousand during 2009, 2008 and 2007, respectively. Such interest income is included in “Other Income — net: Interest income — Affiliated” on the accompanying Consolidated Statements of Income. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. In February 2010, our management committee authorized a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our Owners’ Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

Williams’ corporate overhead expenses allocated to us were $19.7 million, $16.9 million and $19.6 million for 2009, 2008 and 2007, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC-approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $16.3 million, $15.8 million and $16.6 million for 2009, 2008 and 2007, respectively. These expenses are included in “General and administrative expense” on the accompanying Consolidated Statements of Income. A portion of such expenses relates to the compensation of our principal executive officer, principal financial officer and three other most highly compensated officers (our Named Executive Officers or NEOs). Please see “Item 11. Executive Compensation,” for more information about the compensation of such NEOs.

During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $9.9 million, $14.8 million and $11.8 million for 2009, 2008 and 2007, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

From January 2008 through July 2009, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we paid 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 $5.9 million and $10.1 million for the years ended December 31, 2009 and 2008, respectively, is included in “Operation and maintenance expense” on the accompanying Consolidated Statements of Income. The lease was terminated on August 1, 2009.

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.

10. ASSET RETIREMENT OBLIGATIONS

During 2009 and 2008, we adjusted the ARO liability and “Property, Plant and Equipment” for a change in the inflation and discount rates.

During 2009 and 2008, our overall asset retirement obligation changed as follows (in thousands):


	2009			2008
Beginning balance	$	82,666		$	50,423
Accretion		6,068			4,341
New obligations		2,594			116
Changes in estimates of existing obligations		(4,579	)		27,790
Obligation settled		—			(4	)

Ending Balance	$	86,749		$	82,666

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.

11. REGULATORY ASSETS AND LIABILITIES

Our regulatory assets and liabilities result from our application of the provisions of Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and other. Regulatory liabilities are included in deferred credits and other noncurrent liabilities. These balances are presented on our balance sheet on a gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2009 and 2008:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	2009		2008
			(Restated)
	(Thousands of Dollars)
Current regulatory assets — environmental costs	$	2,200	$	2,200


Noncurrent regulatory assets
Environmental costs		3,590		5,790
Grossed-up deferred taxes on equity funds used during construction		18,346		19,234
Levelized incremental depreciation		30,801		28,397
Asset retirement obligations, net		4,295		1,189
Other post-employment benefits		—		972


Total noncurrent regulatory assets		57,032		55,582


Total regulatory assets	$	59,232	$	57,782


Noncurrent regulatory liabilities
Postretirement benefits	$	15,134	$	14,652


Total regulatory liabilities	$	15,134	$	14,652

12. QUARTERLY INFORMATION (UNAUDITED)

The following is a summary of unaudited quarterly financial data for 2009 and 2008:


	Quarter of 2009
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	111,548	$	107,756	$	106,615	$	108,460
Operating income		53,152		47,013		49,145		51,199
Net income		40,908		35,162		38,260		39,321


	Quarter of 2008
	First		Second		Third		Fourth
	(Thousands of Dollars)
Operating revenues	$	107,405	$	106,450	$	108,542	$	112,457
Operating income		49,166		46,676		53,042		52,294
Net income		38,158		35,685		41,236		40,292


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 Senior Vice President and our Vice President and Treasurer, 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 Northwest 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 Senior Vice President and our Vice President and Treasurer. Previously, our management had concluded that our Disclosure Controls were effective at a reasonable assurance level at December 31, 2008. Based upon our current evaluation, which considered the material weakness described in Management’s Report on Internal Control Over Financial Reporting, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls were not effective at a reasonable assurance level at December 31, 2008. Our management also concluded that these Disclosure Controls were not effective at a reasonable assurance level at December 31, 2009.

As discussed in Item 8. Financial Statements and Supplementary Data—Management’s Report on Internal Control Over Financial Reporting and Note 2 of the Notes to Consolidated Financial Statements, in the first quarter of 2010, we identified a material weakness related to the manner in which we presented and recognized pension and postretirement obligations in certain benefit plans for which our parent is the plan sponsor. We have corrected our method of accounting for the parent-allocated amounts related to pension and postretirement plans to the multi-employer model. We have also enhanced our controls that ensure proper selection and application of generally accepted accounting principles.

Management’s Annual Report on Internal Control over Financial Reporting

See report set forth 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 2009 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting. However, in the first quarter of 2010, we enhanced our controls that ensure proper selection and application of generally accepted accounting principles. We also made the change described above in our method of accounting for parent-allocated amounts related to certain pension and post retirement plans and that change is reflected in our financial statements for the period ended December 31, 2009.

PART III


Item 10.		DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management Committee Member and Executive Officers

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

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


Name	Age		Position
Phillip D. Wright		54	Senior Vice President and Management Committee Member (Principal Executive Officer)
Donald R. Chappel		58	Management Committee Member
Steven J. Malcolm		61	Chief Executive Officer
Richard D. Rodekohr		51	Vice President and Treasurer (Principal Financial Officer)
Allison G. Bridges		50	Vice President
Randall L. Barnard		51	Vice President
Lawrence G. Hjalmarson		55	Vice President
Randall R. Conklin		53	Vice President and General Counsel
Frank J. Ferazzi		53	Vice President

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

Mr. Chappel has served as a member of our management committee since October 1, 2007. Since 2003, Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams. Mr. Chappel is Chief Financial Officer and a director of Williams Pipeline GP LLC, the general partner of WMZ. Mr. Chappel is also Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of Williams Partners L.P.

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

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

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

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

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

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

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

Section 16(a) Beneficial Ownership Reporting Compliance

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

Code of Ethics

As an indirect subsidiary of Williams, we have not adopted a separate code of ethics. We follow the Code of Business Conduct adopted by Williams. The Code of Business Conduct adopted by Williams is located on Williams’ website at http://www.williams.com under the heading Corporate Responsibility — Corporate Governance — Ethics and Compliance Program — Williams’ Code of Business Conduct.

Corporate Governance

We do not have an audit committee, nominating and governance committee, or compensation committee.


Item 11.		EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We are managed by the employees of Williams and each of our executive officers are employees of Williams or one of its subsidiaries. Each of our executive officers is compensated directly by Williams rather than by us. All decisions as to the compensation of our executive officers are made by Williams. Therefore, we do not have any policies or programs relating to compensation of our executive officers and do not make any decisions relating to such compensation. A full discussion of the policies and programs of Williams will be set forth in the proxy statement for Williams’ 2010 annual meeting of stockholders which will be available upon its filing on the SEC’s website at http://www.sec.gov and on Williams’ website at http://www.williams.com under the heading Investors — SEC Filings. Williams charges us an allocated amount for the services of Williams’ employees who dedicate time to our affairs.

Executive Compensation

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

2009 Summary Compensation Table


														Change in
														Pension Value
														and
														Nonqualified
												Non-Equity		Deferred
							Stock			Option		Incentive Plan		Compensation			All Other
Name	Year		Salary		Bonus		Awards			Awards		Compensation		Earnings			Compensation		Total
Phillip D. Wright		2009	$	111,204	$	—	$	96,651		$	148,250	$	120,287	$	89,934		$	4,607	$	570,933
Senior Vice President		2008		130,579		—		(21,196	)		84,665		146,250		100,148			2,626		443,072
(Principal Executive Officer)		2007		92,681		—		408,204			66,898		129,929		13,203			1,902		712,817

Richard D, Rodekohr		2009		48,225		—		17,480			22,518		33,606		36,789			3,109		161,727
Vice President and Treasurer		2008		53,474		—		14,028			21,662		35,696		40,088			3,396		168,344
(Principal Financial Officer)		2007		44,358		—		100,495			22,953		36,913		(121	)		2,966		207,564

Allison G. Bridges		2009		259,615		—		73,173			96,301		202,488		188,741			15,105		835,423
Vice President		2008		248,500		—		12,850			94,020		196,013		217,251			11,905		780,539
		2007		235,211		—		421,027			95,960		196,919		1,832			13,895		964,844

Randall L. Barnard		2009		21,527		—		6,473			8,366		19,277		16,355			1,044		73,042
Vice President		2008		32,038		—		1,318			12,783		28,739		23,379			1,529		99,786
		2007		72,584		—		142,715			33,037		76,975		3,091			3,644		332,046

Lawrence G. Hjalmarson		2009		8,964		—		3,202			4,444		6,079		6,370			618		29,677
Vice President		2008		10,823		—		2,563			5,729		7,098		6,573			606		33,392
		2007		68,301		—		16,427			22,957		51,332		1,345			5,009		165,371

Compensation Committee Interlocks and Insider Participation

We do not maintain a compensation committee. Our executive officers during 2009 were employees of Williams or one of its subsidiaries, and compensation decisions with respect to those individuals were determined by Williams.

Compensation of Directors

The members of the management committee are employees of Williams or one of its subsidiaries, and receive no compensation for service on Northwest’s management committee.

Compensation Committee Report

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

Management Committee:
Donald R. Chappel
Phillip D. Wright


Item 12.		SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

We do not have publicly traded equity securities; therefore, we do not have securities authorized for issuance under an equity compensation plan or securities owned by certain beneficial owners and management.


Item 13.		CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of December 31, 2009, our two general partners are subsidiaries of Williams. WGPC Holdings LLC owns 65 percent of our general partnership interest and WMZ owns the remaining 35 percent of our general partnership interest. See “Part 1, Item 1. Business-General” for a description of our current ownership structure.

Although management of Northwest is vested in its partners, the partners of Northwest have agreed to delegate management of Northwest 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 WMZ. 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 Northwest;

	•		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, beginning after the end of the first quarter 2008, the management committee of Northwest is required to review the amount of available cash with respect to that quarter and distribute 100 percent of the available cash to the partners in accordance with their percentage interests, subject to limited exceptions. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves established by the management committee as necessary or appropriate for the conduct of Northwest’s business and to comply with any applicable law or agreement.

Capital Calls to the Partners

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

Restrictions on Transfer of Interests in Northwest

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

Profit and Loss Allocations

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

Agreement with Regard to Colorado Hub Connection Project

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

Williams’ Cash Management Program

We will invest cash through participation in Williams’ cash management program. The advances will be represented by one or more demand obligations. As a participant in Williams’ cash management program, Northwest makes advances to and receives advances from Williams. At December 31, 2009, the advances due to Northwest by Williams totaled approximately $66.8 million. The advances are represented by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. 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 0.05 percent and zero percent at December 31, 2009 and 2008, respectively. Northwest received interest income from advances to Williams of $74 thousand, $813 thousand and $2,983 thousand during 2009, 2008 and 2007, respectively. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. In February 2010, our management committee authorized a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our Owners’

Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

Other Related Party Transactions

Williams’ corporate overhead expenses allocated to Northwest were $19.7 million, $16.9 million and $19.6 million for 2009, 2008 and 2007, respectively. Such expenses have been allocated to Northwest by Williams primarily based on the Modified Massachusetts formula, which is a FERC approved method utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to Northwest on a direct charge basis, which totaled $16.3 million, $15.8 million and $16.6 million for 2009, 2008 and 2007, respectively. A portion of such expenses relates to the compensation of our principal executive officer, principal financial officer and three other most highly compensated officers (our Named Executive Officers or NEOs). Please see “Item 11. Executive Compensation,” for more information about the compensation of such NEOs.

We also have transportation transactions and agreements relating to the rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $9.9 million, $14.8 million and $11.8 million for 2009, 2008 and 2007, respectively.

From January 2008 through July 2009, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, Northwest paid 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 $5.9 million and $10.1 million for the years ended December 31, 2009 and 2008, respectively, is included in “Operation and maintenance expense” on the accompanying Consolidated Statements of Income.

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

The above-described transactions are made on the basis of commercial relationships and prevailing market prices or general industry practices.

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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


	2009		2008
	(Thousands of Dollars)
Audit Fees	$	862	$	1,038
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—

	$	862	$	1,038

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

As a wholly-owned subsidiary of Williams, we do not have a separate audit committee. The Williams audit committee policies and procedures for pre-approving audit and non-audit services will be set forth in the Proxy Statement for Williams’ 2010 annual meeting of stockholders which will be available

(a) 2. Financial Statement Schedules

NORTHWEST PIPELINE GP
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)


			Charged to
	Beginning		Costs and						Ending
Description	Balance		Expenses			Deductions			Balances
Year ended December 31, 2009:
Reserve for doubtful receivables	$	—	$	—		$	—		$	—
Reserve for obsolescence of materials and supplies		111		145			(245	)		11
Year ended December 31, 2008:
Reserve for doubtful receivables		7		(7	)		—			—
Reserve for obsolescence of materials and supplies		181		141			(211	)		111
Year ended December 31, 2007:
Reserve for doubtful receivables		53		(46	)		—			7
Reserve for obsolescence of materials and supplies		472		104			(395	)		181

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

(a) 3 and b. Exhibits:

(2)

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

(a)

Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference.

(3)

Articles of incorporation and by-laws:

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

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

(4)

Instruments defining the rights of security holders, including indentures:

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

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

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

	(d)		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) and incorporated herein by reference.

(10)

Material contracts:


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

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

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

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

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

	(f)		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) and incorporated herein by reference.

	(g)		Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K, filed February 22, 2010) and incorporated herein by reference.

(12)*

Computation of Ratio of Earnings to Fixed Charges

(23)*		Consent of Independent Registered Public Accounting Firm

(24)*		Power of Attorney

(31)		Section 302 Certifications

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	NORTHWEST PIPELINE GP (Registrant)
	By	/s/ R. Rand Clark
		R. Rand Clark
		Controller

Date: February 23, 2010

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


Signature		Title
/s/ Phillip D. Wright*		Senior Vice President and Management Committee Member
Phillip D. Wright		(Principal Executive Officer)

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

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

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

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

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

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

Date: February 23, 2010

EXHIBIT INDEX


Exhibit			Description
	2	(a)	Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to Northwest report on Form 8-K, No. 1-7414, filed October 2, 2007) and incorporated herein by reference.

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

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

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

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

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

	4	(d)	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) and incorporated herein by reference.

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

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

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

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

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


Exhibit		Description
	10(f)	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) and incorporated herein by reference.

	10(g)	Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K, filed February 22, 2010) and incorporated herein by reference.

	12*	Computation of Ratio of Earnings to Fixed Charges

	23*	Consent of Independent Registered Public Accounting Firm

	24*	Power of Attorney

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

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

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


*		Filed herewith


	Page
Management’s annual report on internal control over financial reporting		41

Report of independent registered public accounting firm		42

Consolidated statements of income for the years ended December 31, 2009, 2008 and 2007		43

Consolidated balance sheets at December 31, 2009 and 2008		44

Consolidated statements of owners’ equity for the years ended December 31, 2009, 2008 and 2007		46

Consolidated statements of comprehensive income for the years ended December 31, 2009, 2008 and 2007		47

Consolidated statements of cash flows for the years ended December 31, 2009, 2008 and 2007		48

Notes to consolidated financial statements		49


	December 31,
	2009			2008
				(Restated)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	402	$	345
Advances to affiliate		—		65,977
Accounts receivable —
Trade		40,442		40,116
Affiliated companies		4,514		1,230
Materials and supplies, less reserves of $11 for 2009 and $111 for 2008		9,960		9,817
Exchange gas due from others		4,089		17,000
Exchange gas offset		10,288		—
Prepayments and other		4,241		5,985


Total current assets		73,936		140,470


PROPERTY, PLANT AND EQUIPMENT, at cost		2,887,021		2,765,520
Less — Accumulated depreciation		950,708		901,613


Total property, plant and equipment, net		1,936,313		1,863,907


OTHER ASSETS:
Deferred charges		13,996		18,853
Regulatory assets		57,032		55,582


Total other assets		71,028		74,435


Total assets	$	2,081,277	$	2,078,812


Heading		Page
PART I

Item 1.	BUSINESS		1

Item 1A.	RISK FACTORS		10

Item 1B.	UNRESOLVED STAFF COMMENTS		24

Item 2.	PROPERTIES		24

Item 3.	LEGAL PROCEEDINGS		24

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

PART II

Item 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES		25

Item 6.	SELECTED FINANCIAL DATA		25

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

Item 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		38

Item 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA		40

Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE		67

Item 9A(T).	CONTROLS AND PROCEDURES		67

Item 9B.	OTHER INFORMATION		68

PART III

Item 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		69

Item 11.	EXECUTIVE COMPENSATION		70

Item 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		72

Item 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		72

Item 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES		74

PART IV

Item 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES		76
EX-12
EX-23
EX-24
EX-31.A
EX-31.B
EX-32.A


	Page Reference to
	2009 Form 10-K
Management’s Annual Report on Internal Control over Financial Reporting		41

Report of Independent Registered Public Accounting Firm		42

Consolidated Statements of Income for the Years Ended December 31, 2009, 2008		43
and 2007

Consolidated Balance Sheets at December 31, 2009 and 2008		44

Consolidated Statements of Owners’ Equity for the Years Ended December 31, 2009,		46
2008 and 2007

Consolidated Statements of Comprehensive Income for the Years Ended December		47
31, 2009, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2009,		48
2008 and 2007

Notes to Consolidated Financial Statements		49

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

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



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

1.		I have reviewed this annual report on Form 10-K of Northwest Pipeline GP;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

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



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

	(1)		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	(2)		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.