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

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-7414

NORTHWEST PIPELINE GP

(Exact name of registrant as specified in its charter)

DELAWARE		26-1157701
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
295 Chipeta Way, Salt Lake City, Utah		84108
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

Indicate by check mark 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 of this chapter) 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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

DOCUMENTS INCORPORATED BY REFERENCE:
None

The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

 

 

NORTHWEST PIPELINE GP
FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1. BUSINESS			1
Item 1A. RISK FACTORS			3
Item 1B. UNRESOLVED STAFF COMMENTS			18
Item 2. PROPERTIES			18
Item 3. LEGAL PROCEEDINGS			18
PART II
Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES			19
Item 6. SELECTED FINANCIAL DATA (Omitted)			19
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			19
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			22
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA			23
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE			47
Item 9A. CONTROLS AND PROCEDURES			47
Item 9B. OTHER INFORMATION			47
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE (Omitted)			48
Item 11. EXECUTIVE COMPENSATION (Omitted)			48
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS (Omitted)			48
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE (Omitted)			48
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES			48
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES			49
EX-31.A
EX-31.B
EX-32.A

DEFINITIONS

     We use the following gas measurements in this report:

Mcf-means thousand cubic feet.

MMcf-means million cubic feet.

Bcf-means billion cubic feet.

MMBtu-means million British Thermal Units.

TBtu-means trillion British Thermal Units.

Dth-means dekatherm.

Mdth-means thousand dekatherms.

MMdth-means million dekatherms.

PART I

Item 1.		BUSINESS

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

     At December 31, 2010, Northwest is owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

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).

     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 477,000 horsepower. At December 31, 2010, we had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.8 Bcf of natural gas per day.

     We own a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington. 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 also have storage capacity in a Liquefied Natural Gas (LNG) facility near Plymouth, Washington, that we own and operate. We have approximately 13.2 Bcf of working natural gas storage capacity through these three storage facilities, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable us to balance daily receipts and deliveries and provide storage services to certain major customers.

     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 2010, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company, which accounted for approximately 22.7 percent and 11.4 percent, respectively, of our total operating revenues for the year ended December 31, 2010. 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.

CAPITAL PROJECTS

Sundance Trail Expansion

     On November 1, 2010, we placed the Sundance Trail Expansion Project in service which is comprised of 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. The total project is estimated to cost approximately $50 million, including the cost of replacing the existing compression at Vernal, which will enhance the efficiency of our system. We executed a transportation service 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 will collect our maximum system rates under the firm service agreement, and have received approval from the FERC to roll-in the Sundance Trail Expansion costs in any future rate cases.

REGULATION

     Our interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978 (NGPA), as amended, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of pipelines, facilities and properties under the NGA. The FERC’s Standards of Conduct govern the relationship between natural gas transmission providers and marketing function employees as defined by the rule. The standards of conduct are intended to prevent natural gas transmission providers from preferentially benefiting gas marketing functions by requiring the employees of a transmission provider that perform transmission functions to function independently from gas marketing employees and by restricting the information that transmission providers may provide to gas marketing employees. Under the Energy Policy Act of 2005, the FERC is authorized to impose civil penalties of up to $1 million per day for each violation of its rules.

     Our transportation rates are established through the FERC ratemaking process. Key determinants in the ratemaking process are (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes, and (3) contract volume and throughput assumptions. The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues may be collected subject to refund. We record estimates of rate refund liabilities considering our and third-party regulatory proceedings, advice of counsel and other risks.

Safety and Maintenance

     Pipeline Integrity Regulations We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety Act of 1979, and the Pipeline Safety Improvement Act of 2002 which regulate safety requirements in the design, construction, operation and maintenance of interstate gas transmission facilities.

     We have developed an Integrity Management Program 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. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required baseline assessments within the required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily

capital in nature and range between $50 million and $60 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. 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.

Environmental Regulation

     We are subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental quality control. Management believes that, capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations are generally recoverable in rates. For these reasons, management believes that compliance with applicable environmental requirements is not likely to have a material effect upon our competitive position or earnings. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements: Note 2. Contingent Liabilities and Commitments — Environmental Matters.”

EMPLOYEES

     Northwest has no employees. Operations, management, and certain administrative services are provided to Northwest by Northwest Pipeline Services LLC, a Williams affiliate. As of January 31, 2011, Northwest Pipeline Services LLC had 448 employees.

TRANSACTIONS WITH AFFILIATES

     We engage in transactions with WPZ, Williams and other Williams’ subsidiaries. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements: Note 1. Summary of Significant Accounting Policies” and “Note 7. Transactions with Major Customers.”

Item 1A.		RISK FACTORS

FORWARD-LOOKING STATEMENTS 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 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;
	•		Expansion and growth of our business and operations;
	•		Financial condition and liquidity;
	•		Business strategy;

	•		Cash flow from operations or results of operations;
	•		Rate case filings; and
	•		Natural gas prices and demand.

     Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this 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:

	•		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;
	•		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);
	•		The strength and financial resources of our competitors;
	•		Development of alternative energy sources;
	•		The impact of operational and development hazards;
	•		Costs of, changes in, or the results of laws, government regulations (including climate change legislation), environmental liabilities, litigation, and rate proceedings;
	•		Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
	•		Changes in maintenance and construction costs;
	•		Changes in the current geopolitical situation;
	•		Our exposure to the credit risks 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;
	•		Risks associated with future weather conditions;
	•		Acts of terrorism; and
	•		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 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 level of damages resulting from these risks. In spite of our 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 are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. As a result, we could experience some “turnback” of firm capacity as the primary terms of existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we or our remaining customers may have to bear the costs associated with the turned back capacity. Increased competition could reduce the amount of transportation or storage capacity contracted on our system or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas or increase the price of natural gas in the markets served by our pipeline system, such as competing or alternative forms of energy, a regional or national recession or other adverse economic conditions, weather, higher fuel costs and taxes, or other governmental or regulatory actions that directly or indirectly increase the price of natural gas or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Certain of our services are subject to long-term, discounted or negotiated rate contracts where the revenues received from such contracts may be less than the cost to perform such services.

     We provide some services pursuant to long-term, discounted or negotiated rate contracts. It is possible that costs to perform services under such contracts will exceed the revenues we collect for our services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a discount or “negotiated rate” that may be above or below FERC regulated cost-based rate for that service.

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. Upon expiration of the terms, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

     The extension or replacement of existing contracts depends on a number of factors beyond 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, 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 transportation, and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our transportation 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. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities.

     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, if development in new supply basins where we do not have significant pipeline systems reduces demand for our services, 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 reduction in or termination of our long-term transportation and storage contracts or throughput on our system.

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

Our costs of maintaining or repairing our facilities may exceed our expectations and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.

     We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service.

Our business is subject to complex government regulations. The operation of our business might be adversely affected by changes in these regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our business or our customers.

     Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition and results of operations. For example, several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment operated by us and subjecting additional pipelines (including gathering facilities) to more stringent regulation. Such reforms, if adopted, could significantly increase our costs.

We are subject to risks associated with climate change.

     There is a belief that emissions of greenhouse gases (GHGs) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs 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, 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. These laws include:

	•		Clean Air Act (CAA), and analogous state laws, which impose obligations related to air emissions;
	•		Clean Water Act (CWA), and analogous state laws, which regulate discharge of wastewaters from our facilities to state and federal waters;
	•		Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal; and
	•		Resource Conservation and Recovery Act (RCRA), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

     Various governmental authorities, including the U.S. Environmental Protection Agency (EPA) and analogous state agencies and the U.S. 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 the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products we transport and store, air emissions related to our operations, historical industry operations, waste disposal practices, and the prior use of flow meters containing mercury. 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, for the remediation of contaminated areas 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. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. 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 are also generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown.

     In addition, Legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. The U.S. 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, regional, and/or federal requirements to reduce or mitigate GHG emissions.

     Numerous states have 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 lead to the direct regulation of GHG emissions in our industry under the EPA’s interpretation of its authority and obligations under the CAA. The recent actions

of the EPA and the passage of any federal or state climate change laws or regulations 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.

     Certain environmental and other groups have suggested that additional laws and regulations may be needed to more closely regulate the hydraulic fracturing process commonly used in natural gas production. Legislation to further regulate hydraulic fracturing has been proposed in Congress and the U.S. Department of Interior has announced plans to formalize obligations for disclosure of chemicals associated with hydraulic fracturing on federal lands. In addition, some state and local authorities have considered or formalized new rules related to hydraulic fracturing and enacted moratoria on such activities. We cannot predict whether any additional federal, state or local legislation or regulation will be enacted in this area and if so, what its provisions would be. If additional levels of reporting, regulation and permitting were required, natural gas supplies and prices could be impacted and our operations could be adversely affected.

     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 affect our profitability.

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. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extension or replacements of these contracts on favorable terms, if at all. For the year ended December 31, 2010, our two largest customers were Puget Sound Energy, Inc. and Northwest Natural Gas Company. These customers accounted for approximately 34.1 percent of our operating revenues for the year ended December 31, 2010. The loss of all, or even a portion of, the revenues from contracted volumes supplied by these customers, 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, results of operations, financial condition, and cash flows, unless we are able to acquire comparable volumes 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.

The failure of counterparties to perform their contractual obligations could adversely affect our operating results and financial condition.

     Despite performing credit analysis prior to extending credit, we are exposed to the credit risk of our contractual counterparties in the ordinary course of business even though we monitor these situations and attempt to take appropriate measures to protect ourselves. In addition to credit risk, counterparties to our commercial agreements, such as transportation and storage agreements, may fail to perform their other contractual obligations. A failure of counterparties to perform their contractual obligations could cause us to write down or write off doubtful accounts, which could materially adversely affect our operating results 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 for the benefit of our customers. 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. 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. In those instances in which we do not own the land on which our facilities are located, we obtain 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 may 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, results of operations, financial condition and cash flows.

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

     We are not fully insured against all risks inherent to our business, including environmental accidents. We do not maintain insurance in the type and amount to cover all possible risks of loss.

     We currently maintain excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers us and certain of our affiliates for legal and contractual liabilities arising out of bodily 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.

     Although we maintain property insurance on property we own, lease, or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. All of our 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.

     In addition, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to

greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

     The occurrence of any risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows, and our ability to repay our debt.

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.

     Our growth may be dependent upon the construction of new transportation and storage facilities as well as the expansion of existing facilities. Construction or expansion 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 our 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, and companies’ relationships with their independent public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board (FASB), the SEC or FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.

We do not operate all of our assets. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

     Williams and other third parties operate certain of our assets. We have a limited ability to control these operations and the associated costs. The success of these operations is therefore dependent upon a number of factors that are outside our control, including the competence and financial resources of the operators.

     We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of

Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as operators and on Williams’ outsourcing relationships, and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, and financial condition.

Risks Related to Strategy and Financing

Restrictions in our debt agreements and our leverage may affect our future financial and operating flexibility.

     Our total outstanding long-term debt as of December 31, 2010, was $693.6 million.

     Our debt service obligations and restrictive covenants in our new credit facility entered into as part of Williams’ restructuring (New Credit Facility) and the indentures governing our senior unsecured notes could have important consequences. For example, they could:

	•		Make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;
	•		Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other purposes;
	•		Diminish our ability to withstand a continued or future downturn in our business or the economy generally;
	•		Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;
	•		Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
	•		Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

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

     We are not prohibited under our indentures from incurring additional indebtedness. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above, and could adversely affect our ability to repay our senior notes.

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 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 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. 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 credit rating would likely also result in a downgrading of our credit rating. A downgrading of a Williams or WPZ 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, WPZ, 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 independent third parties determine our credit ratings outside of our control.

     A downgrade of our credit rating might increase our cost of borrowing and could cause us to post collateral with third parties, 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. 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 we will maintain our current credit ratings.

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, 2010, we are a wholly-owned subsidiary of WPZ, approximately 75 percent of whose limited and general partnership interests are owned by Williams. 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.

     WPZ 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 affiliated companies who are involved in marketing functions of the natural gas business; and
	•		market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

     Under the Natural Gas Act (NGA), FERC has authority to regulate interstate providers of natural gas pipeline transportation and storage services in interstate commerce, 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 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 FERC in our future rate cases will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates will cause 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 have adversely affected our business and may continue to do so.

     Public and regulatory scrutiny of the energy industry has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. 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. Adverse effects may 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, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and Williams’ 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 pension 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 has not been available at all. 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

     Our gas pipeline facilities are generally owned in fee. However, a substantial portion of such facilities 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 company 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 Financial Statements: Note 2. Contingent Liabilities and Commitments — Legal Proceedings.”

PART II

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

     On December 31, 2010, we were owned 100 percent by WPZ, a publicly traded master limited partnership, and Williams held an approximate 75 percent interest in WPZ. Our partnership interest is not publicly traded.

     We paid $191.5 million and $135.0 million in cash distributions to our partners during 2010 and 2009, respectively.

Item 6. SELECTED FINANCIAL DATA

     Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, this information is omitted.

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

GENERAL

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

CRITICAL ACCOUNTING ESTIMATES

     Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. We believe that the following are the most critical judgment areas in the application of accounting policies that currently affect our financial condition and results of operations.

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 financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Balance Sheet and included in the Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs.

The aggregate amounts of regulatory assets reflected in the Balance Sheet are $62.4 million and $59.3 million at December 31, 2010 and 2009, respectively. The aggregate amounts of regulatory liabilities reflected in the Balance Sheet are $17.0 million and $15.5 million at December 31, 2010 and 2009, respectively. A summary of regulatory assets and liabilities is included in Note 9 of Notes to Financial Statements.

Contingent Liabilities

     We record liabilities for estimated loss contingencies when we assess that a loss is probable and the amount of the loss can be reasonably estimated. At December 31, 2010 and 2009, we have an accrual for loss contingencies of $0 and $800 thousand, respectively. Revisions to contingent liabilities are generally reflected in income when new or 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 our assumptions and estimates pertaining to probability and amount of loss, and incorporate the advice of legal counsel, engineers or other third parties regarding the probable outcomes of the matter. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. If changes in these or other assumptions or the anticipated outcomes we use to estimate contingencies cause a loss to become more likely, it could materially affect future results of operations for any particular quarterly or annual period, but would not be expected to have a material adverse effect on our future liquidity or financial position.

RESULTS OF OPERATIONS

Analysis of Financial Results

     This analysis discusses financial results of our operations for the years 2010 and 2009. 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.

2010 Compared to 2009

     Our operating revenues decreased $12.6 million, or 3 percent, for the year ended December 31, 2010 as compared to the year ended December 31, 2009. This decrease is primarily attributed to i) a reduction in lease revenues of $6.1 million resulting from the termination of the Parachute Lateral lease on August 1, 2009, ii) lower other revenues of $3.3 million resulting from the absence of sublease income attributed to the restructuring of the Salt Lake City headquarters building lease, iii) lower firm transportation commodity revenues of $3.0 million due primarily to mild weather in our market area and lower off-system deliveries, iv) lower revenues of $2.7 million resulting from the termination of the Everett Delta Lateral lease on November 9, 2009, and v) lower storage revenue of $1.2 million due primarily to less capacity released at Clay Basin in 2010. These decreases are partially offset by higher reservation charges due primarily to the completion of the Sundance Trail Expansion Project. The revenue decreases from the Parachute and Everett Delta laterals as well as the reduction in building sublease revenues are substantially offset by decreases in lease expenses as described below.

     Our transportation service accounted for 97 percent and 96 percent of our operating revenues for the years ended December 31, 2010 and 2009, respectively. Additionally, gas storage service accounted for 3 percent and 4 percent of operating revenues for the years ended December 31, 2010 and 2009, respectively.

     Total operating expenses decreased $6.8 million, or 3 percent. This decrease is due primarily to i) the termination of the Parachute and Everett Delta leases, resulting in lower lease expense of $8.6 million, ii) the restructuring of the Salt Lake City headquarters building lease in 2009 resulting in lower building lease expense of $3.6 million, iii) lower incentive compensation expense of $1.5 million, and iv) lower pension expense of $1.4 million. These decreases were partially offset by i) higher property taxes of $3.6 million primarily attributed to a $2.6 million reduction in 2009 for lower than anticipated mill levies and property additions, ii) higher labor of $1.7 million and higher contractual expenses of $1.7 million attributed to higher maintenance, and iii) higher depreciation expense of $1.5 million due to property additions.

     Other income — net decreased $0.9 million, or 47 percent, due primarily to 2010 expenses of $1.3 million attributed to business development.

     Interest charges decreased $2.6 million, or 5 percent, due primarily to the completion of the amortization of debt expense associated with a retired debt issue.

Effects of Inflation

     We generally have experienced increased costs due to the effect of inflation on the cost of labor, materials and supplies, and property, plant, and equipment. A portion of the increased labor and materials and supplies cost can directly affect income through increased operation and maintenance expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of our property, plant, and equipment and materials and supplies inventory is subject to ratemaking treatment, and under current FERC practices, recovery is limited to historical costs. We believe that we will be allowed to recover and earn a return based on increased actual costs incurred when existing facilities are replaced. Cost-based regulation along with competition and other market factors limit our ability to price services or products based upon inflation’s effect on costs.

CAPITAL RESOURCES AND LIQUIDITY

METHOD OF FINANCING

     We fund our working capital and capital requirements with cash flows from operating activities, equity contributions from WPZ, collection of advances made to WPZ, accessing capital markets, and, if required, borrowings under the New Credit Facility (described below) and advances from WPZ.

     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.

     Through January 31, 2010, we were a participant in Williams’ cash management program and made advances to and received advances from Williams. As a result of the restructuring, we became a participant in WPZ’s cash management program. At December 31, 2010, the advances due to us by WPZ totaled $45.0 million. The advances are represented by demand notes. The interest rate on the WPZ demand notes is based upon the overnight investment rate paid on WPZ’s excess cash, which was approximately 0.06 percent at December 31, 2010.

     Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. 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, under certain conditions, 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 December 31, 2010, the full $400 million under the New Credit Facility was available. Please see “Item 8. Financial Statements and Supplementary Data — Notes to Financial Statements: Note 3. Debt, Financing Arrangements, and Leases — Revolving Credit and Letter of Credit Facility.”

CAPITAL EXPENDITURES

     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 2011 capital expenditures will be between $115 million and $135 million. Of this total, $60 million to $70 million is considered nondiscretionary due to legal, regulatory, and/or contractual requirements. In 2011, we expect to fund our capital expenditures with cash from operations.

     Property, plant, and equipment additions were $120.2 million, $152.6 million and $88.5 million for 2010, 2009 and 2008, respectively. The $64.1 million increase from 2008 to 2009 is primarily attributed to expenditures related to pipeline integrity, the Colorado Hub Connection Project, and the Sundance Trail Expansion Project.

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, 2010
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			(1,366	)
Total long-term debt		$	693,634

     Our total long-term debt at December 31, 2010 had a carrying value of $693.6 million and a fair market value of $796.1 million. As of December 31, 2010, the weighted-average interest rate on our long-term debt was 6.4 percent.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

				Page
		Management’s Annual Report on Internal Control over Financial Reporting			24
		Report of Independent Registered Public Accounting Firm			25
		Statement of Income			26
		Balance Sheet			27
		Statement of Owners’ Equity			29
		Statement of Comprehensive Income			30
		Statement of Cash Flows			31
		Notes to Financial Statements			32

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

     Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a — 15(f) and 15d — 15(f) under the Securities Exchange Act of 1934). Our internal controls over financial reporting are designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management; and (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, 2010, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2010, our internal control over financial reporting was effective.

     This annual report does not include a report of our registered public accounting firm regarding internal control over financial reporting. A report by our registered public accounting firm is not required pursuant to rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of

Northwest Pipeline GP

     We have audited the accompanying balance sheets of Northwest Pipeline GP as of December 31, 2010 and 2009, and the related statements of income, comprehensive income, owner’s equity, and cash flows for each of the three years in the period ended December 31, 2010. 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 financial position of Northwest Pipeline GP at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, 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.

/s/ Ernst & Young LLP

Houston, Texas
February 24, 2011

NORTHWEST PIPELINE GP

STATEMENT OF INCOME

(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
OPERATING REVENUES		$	421,817			$	434,379			$	434,854
OPERATING EXPENSES:
General and administrative			57,162				64,657				60,403
Operation and maintenance			65,516				71,085				72,831
Depreciation			87,915				86,373				86,184
Regulatory credits			(1,662	)			(2,403	)			(2,617	)
Taxes, other than income taxes			18,106				14,158				16,875
Total operating expenses			227,037				233,870				233,676
Operating income			194,780				200,509				201,178
OTHER INCOME — net:
Interest income —
Affiliated			27				74				813
Other			3				16				6
Allowance for equity funds used during construction			1,947				1,996				812
Miscellaneous other expense, net			(942	)			(135	)			(8	)
Total other income — net			1,035				1,951				1,623
INTEREST CHARGES:
Interest on long-term debt			44,458				44,439				42,290
Other interest			2,664				5,414				5,571
Allowance for borrowed funds used during construction			(877	)			(1,044	)			(431	)
Total interest charges			46,245				48,809				47,430
INCOME BEFORE INCOME TAXES			149,570				153,651				155,371
INCOME TAXES (Note 5)			43				—				—
NET INCOME		$	149,527			$	153,651			$	155,371

See accompanying notes.

NORTHWEST PIPELINE GP

BALANCE SHEET

(Thousands of Dollars)

		December 31,
		2010				2009
						(Restated)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	5			$	402
Advances to affiliate			45,045				—
Accounts receivable —
Trade			38,515				40,442
Affiliated companies			2,118				4,514
Materials and supplies, less reserves of $613 for 2010 and $11 for 2009			11,719				9,960
Exchange gas due from others			2,323				4,089
Exchange gas offset			3,854				10,288
Prepayments and other			3,415				4,241
Total current assets			106,994				73,936
PROPERTY, PLANT AND EQUIPMENT, at cost			2,965,097				2,887,021
Less — Accumulated depreciation			1,017,634				950,708
Total property, plant and equipment, net			1,947,463				1,936,313
OTHER ASSETS:
Deferred charges			11,817				13,996
Regulatory assets			60,176				57,032
Total other assets			71,993				71,028
Total assets		$	2,126,450			$	2,081,277

See accompanying notes.

NORTHWEST PIPELINE GP

BALANCE SHEET

(Thousands of Dollars)

		December 31,
		2010				2009
						(Restated)
LIABILITIES AND OWNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable —
Trade		$	13,177			$	17,552
Affiliated companies			10,105				23,131
Accrued liabilities —
Taxes, other than income taxes			10,186				8,176
Interest			4,045				4,045
Exchange gas due to others			13,115				14,377
Other			4,245				5,270
Total current liabilities			54,873				72,551
LONG-TERM DEBT			693,634				693,437
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES			88,347				108,139
CONTINGENT LIABILITIES AND COMMITMENTS
OWNERS’ EQUITY:
Owners’ capital			1,046,862				1,027,862
Loan to affiliate			—				(105,431	)
Retained earnings			242,396				284,319
Accumulated other comprehensive income			338				400
Total owners’ equity			1,289,596				1,207,150
Total liabilities and owners’ equity		$	2,126,450			$	2,081,277

See accompanying notes.

NORTHWEST PIPELINE GP

STATEMENT OF OWNERS’ EQUITY

(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Owners’ capital —
Balance at beginning of period		$	1,027,862			$	978,682			$	977,022
Capital contribution from Williams			19,000				49,180				1,660
Balance at end of period			1,046,862				1,027,862				978,682
Loans (to) from affiliate —
Balance at beginning of period			(105,431	)			(34,265	)			(29,186	)
Loans (to) from affiliate			105,431				(71,166	)			(5,079	)
Balance at end of period			—				(105,431	)			(34,265	)
Retained earnings —
Balance at beginning of period			284,319				265,668				228,739
Net income			149,527				153,651				155,371
Cash distributions			(191,450	)			(135,000	)			(419,342	)
Sale of partnership interest			—				—				300,900
Balance at end of period			242,396				284,319				265,668
Accumulated other comprehensive income (loss) —
Balance at beginning of period			400				462				523
Cash flow hedges:
Reclassification of gain into earnings			(62	)			(62	)			(61	)
Balance at end of period			338				400				462
Total owners’ equity		$	1,289,596			$	1,207,150			$	1,210,547

See accompanying notes.

NORTHWEST PIPELINE GP

STATEMENT OF COMPREHENSIVE INCOME

(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
Net Income		$	149,527			$	153,651			$	155,371
Cash Flow Hedges:
Amortization of cash flow hedges			(62	)			(62	)			(61	)
Total comprehensive income		$	149,465			$	153,589			$	155,310

See accompanying notes.

NORTHWEST PIPELINE GP

STATEMENT OF CASH FLOWS
(Thousands of Dollars)

		Years Ended December 31,
		2010				2009				2008
						(Restated)				(Restated)
OPERATING ACTIVITIES:
Net Income		$	149,527			$	153,651			$	155,371
Adjustments to reconcile to net cash provided by operating activities —
Depreciation			87,915				86,373				86,184
Regulatory credits			(1,662	)			(2,403	)			(2,617	)
Gain on sale of property, plant and equipment			—				(508	)			(378	)
Amortization of deferred charges and credits			2,293				5,050				5,132
Allowance for equity funds used during construction			(1,947	)			(1,996	)			(812	)
Reserve for doubtful accounts			—				—				(7	)
Cash provided (used) by changes in current assets and liabilities:
Trade accounts receivable			1,927				(326	)			580
Affiliated receivables, including income taxes			2,396				(3,284	)			2,284
Exchange gas due from others			1,262				2,623				(252	)
Materials and supplies			(1,759	)			(143	)			527
Other current assets			826				1,744				943
Trade accounts payable			(559	)			(828	)			(2,599	)
Affiliated payables, including income taxes			(13,026	)			350				(12,084	)
Exchange gas due to others			(1,262	)			(2,623	)			252
Other accrued liabilities			985				(4,860	)			4,487
Changes in noncurrent assets and liabilities:
Deferred charges			(5,865	)			(3,362	)			(4,747	)
Other deferred credits			8,148				5,340				6,750
Net cash provided by operating activities			229,199				234,798				239,014
FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt			8,000				—				249,333
Retirement of long-term debt			(8,000	)			—				(250,000	)
Debt issuance costs			—				—				(2,027	)
Capital contribution from parent			19,000				49,180				1,660
Proceeds from sale of partnership interest			—				—				300,900
Distributions paid			(191,450	)			(135,000	)			(419,342	)
Changes in cash overdrafts			(1,209	)			2,212				(7,372	)
Net cash used in financing activities			(173,659	)			(83,608	)			(126,848	)
INVESTING ACTIVITIES:
Property, plant and equipment —
Capital expenditures*			(120,236	)			(152,580	)			(88,478	)
Proceeds from sales			3,913				2,234				3,065
Repayments from (advances to) affiliates			60,386				(787	)			(26,905	)
Net cash used in investing activities			(55,937	)			(151,133	)			(112,318	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(397	)			57				(152	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR			402				345				497
CASH AND CASH EQUIVALENTS AT END OF YEAR		$	5			$	402			$	345
______________________
* Increases to property, plant and equipment		$	(117,629	)		$	(156,576	)		$	(78,566	)
Changes in related accounts payable and accrued liabilities			(2,607	)			3,996				(9,912	)
Capital expenditures		$	(120,236	)		$	(152,580	)		$	(88,478	)
Supplemental disclosures of non-cash transactions:
Adjustment to owners’ equity for benefit plans correction		$	—			$	(4,402	)		$	(5,079	)
Loans to affiliate reclassified to equity			—				66,764				—

See accompanying notes.

NORTHWEST PIPELINE GP

NOTES TO 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.

     At December 31, 2010, Northwest is owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams), and Williams holds an approximate 75 percent interest in WPZ, comprised of an approximate 73 percent limited partner interest and all of WPZ’s 2 percent general partner interest.

     Northwest is not an employer. Services are provided to Northwest by Northwest Pipeline Services LLC (NPS), a Williams’ affiliate. Northwest reimburses NPS for the costs of the employees including compensation and employee benefit plan costs and all related administrative costs.

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

Nature of Operations

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

Regulatory Accounting

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

     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. (See Note 9 for further discussion.)

Basis of Presentation

     The financial statements prior to 2010 included the accounts of Northwest and Northwest Pipeline Services, LLC (Services Company), which was a variable interest entity (VIE) for which Northwest was considered the primary beneficiary. As a result of Williams’ strategic restructuring on February 17, 2010, which reorganized entities under common control, we have reevaluated the status of the Services Company as a consolidated VIE and have concluded that the Services Company is no longer considered a VIE, and therefore, will no longer be consolidated.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

     The Accounting Standards Codification (Topic 250), “Accounting Changes and Error Corrections,” requires that when a change in the reporting entity occurs, the change shall be retrospectively applied to the financial statement of all prior periods to show financial information for the new reporting entity.

     The impact of these retrospective adjustments decreased accrued employee costs and increased accounts payable to affiliated companies as of December 31, 2009. These retrospective adjustments had no impact on net income.

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.

     We provide for depreciation using the straight-line method at FERC prescribed rates, including negative salvage (cost of removal) for transmission and storage facilities. Depreciation of general plant is provided on a group basis at straight-line rates. Included in our depreciation rates is a negative salvage component that we currently collect in rates. Depreciation rates used for major regulated gas plant facilities at December 31, 2010, 2009 and 2008 are as follows:

Category of Property
Storage facilities			0.15%-2.23	%
Onshore transmission facilities			0.15%-7.25	%

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

     We recorded regulatory credits totaling $1.7 million in 2010, $2.4 million in 2009, and $2.6 million in 2008 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 $32.5 million at December 31, 2010, and $30.8 million at December 31, 2009. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

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NOTES TO FINANCIAL STATEMENTS

     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 expected timing of the future abandonment of the underlying physical assets. Measurement of AROs includes, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as market-risk premium. 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, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2010 and 2009 were $40.5 million and $33.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

     The negative salvage component of accumulated depreciation ($33.6 million and $29.5 million at December 31, 2010 and 2009, 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 10 percent for 2010 and 9 percent for 2009 and 2008. Equity AFUDC of $1.9 million, $2.0 million and $0.8 million for 2010, 2009 and 2008, 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

     Through January 31, 2010, we were a participant in Williams’ cash management program and made advances to and received advances from Williams. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. In 2010, our management committee authorized cash distributions 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 were not available to us as working capital. As a result of the restructuring, we became a participant in the WPZ cash management program. The advances are represented by demand notes. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on the WPZ demand notes is based upon the overnight investment rate paid on WPZ’s excess cash, which was approximately 0.06 percent at December 31, 2010. The interest rate on the Williams demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was 0.05 percent at December 31, 2009.

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NOTES TO FINANCIAL STATEMENTS

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.

     Following our conversion to a general partnership on October 1, 2007, we are no longer subject to federal and state income tax. We are subject to local income tax in some areas where we operate. (See Note 5.)

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.

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NOTES TO 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, 2010, 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 $44.6 million, $44.5 million and $43.1 million in 2010, 2009 and 2008, respectively.

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

2. 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, the FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

     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 for mercury and other constituents to bring the sites up to Washington’s current environmental standards. At December 31, 2010, we had accrued liabilities totaling approximately $8.4 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 are also subject to the Federal Clean Air Act (the Act) and to the Federal Clean Air Act Amendments of 1990, which added significantly to the existing requirements established by the Act.

     In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground-level ozone to ensure that the standards were clearly grounded in science, and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA currently anticipates finalization of the new ground-level ozone standard in the third quarter of 2011. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment. We are unable at this time to estimate the cost of additions that may be required to meet the new regulation.

     Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with hazardous air pollutant regulations are estimated to include costs in the range of $6 million to $9 million through 2013, the compliance date.

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NOTES TO FINANCIAL STATEMENTS

     Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide (CO₂) equivalent per year from stationary fossil-fuel combustion sources to report GHG emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. Subsequently, the EPA proposed additional reporting requirements on April 12, 2010 to address fugitive/vented GHG emissions from petroleum and natural gas facilities. The EPA promulgated additional reporting requirements for fugitive/vented emissions on November 30, 2010, with an effective date of January 1, 2011. Facilities that emit 25,000 metric tons or more CO₂ equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined are required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with this reporting obligation is estimated to cost $3 million to $5 million over the next four to five years.

     In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO₂) National Ambient Air Quality Standard. The effective date of the new NO₂ standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

Safety Matters

     Pipeline Integrity Regulations We have developed an Integrity Management Program 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. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required assessments within the required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $50 million and $60 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. 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

     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 $9.4 million at December 31, 2010.

Cash Distributions to Partners

     During January 2011, we declared and paid equity distributions of $26 million to WPZ.

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NOTES TO FINANCIAL STATEMENTS

3. DEBT, FINANCING ARRANGEMENTS, AND LEASES

Long-Term Debt

     Long-term debt consists of the following:

		December 31,
		2010				2009
		(Thousands of Dollars)
5.95% senior unsecured notes due 2017		$	184,599			$	184,535
6.05% senior unsecured notes due 2018			249,506				249,440
7% senior unsecured notes due 2016			174,698				174,643
7.125% senior unsecured notes due 2025			84,831				84,819
Total long-term debt		$	693,634			$	693,437

     There are no maturities applicable to long-term debt outstanding for the next five years.

     In the second quarter of 2006, we entered into certain forward starting interest rate swaps prior to our issuance of fixed rate, long-term debt. The swaps, which were settled near the date of the June 2006 debt issuance, hedged the variability of forecasted interest payments arising from changes in interest rates prior to the issuance of our fixed rate debt. The settlement resulted in a gain that is being amortized to reduce interest expense over the life of the related debt.

Restrictive Debt Covenants

     At December 31, 2010, none of our debt instruments restrict the amount of distributions to our parent. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels.

Revolving Credit and Letter of Credit Facility

     Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. 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, under certain conditions, 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 December 31, 2010, the full $400 million under the New Credit Facility was available.

     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 an applicable margin, or (2) a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an 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 based on the specific borrower’s senior unsecured long-term debt ratings.

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NOTES TO FINANCIAL STATEMENTS

     The New Credit Facility contains various covenants that limit, among other things, the borrowers’ 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, with EBITDA measured on a rolling four-quarter basis) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. For us, 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 is tested at the end of each fiscal quarter (with the first full year measured on an annualized basis). At December 31, 2010, we are in compliance with these covenants.

     The New Credit Facility includes customary events of default. 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.

Leases

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

     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)
2011		$	2,469
2012			2,469
2013			2,469
2014			2,469
2015			2,495
Total		$	12,371

     Operating lease rental expense, net of sublease revenues, amounted to $2.2 million, $3.6 million, and $4.9 million for 2010, 2009 and 2008, respectively.

4. BENEFIT PLANS

     Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below.

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NOTES TO FINANCIAL STATEMENTS

Pension and Other Postretirement Benefit Plans

     Williams has noncontributory defined benefit pension plans that provide pension benefits for its eligible employees. Pension expense charged to us by Williams was $6.1 million in 2010, $7.5 million in 2009 and $3.5 million in 2008.

     Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991. No other postretirement benefit expense was recognized in 2010, 2009 or 2008, as such costs are not currently being recovered in our rates. (See Note 9.)

Defined Contribution Plan

     Williams charged us compensation expense of $2.2 million in 2010, $2.2 million in 2009 and $2.1 million in 2008 for Williams’ company matching contributions to this plan.

Stock-Based Compensation

Plan Information

     The Williams Companies, Inc. 2007 Incentive Plan, as restated and amended on February 23, 2010, (Plan) was approved by stockholders on May 20, 2010. 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 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

     Williams’ 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, 2010, 2009 and 2008 was $1.4 million, $1.3 million and $1.0 million, respectively, excluding amounts allocated from WGP and Williams.

5. INCOME TAXES

     As a partnership, we are generally not subject to federal or state and local income taxes. We do incur income tax in jurisdictions that impose their tax on partnerships, including Multnomah County, Oregon, Business Income Tax. For the year ended December 31, 2010, we recorded current local income tax for Multnomah County, Oregon, of $43 thousand. No income tax expense was recorded in 2009 or 2008.

     Cash payments for income taxes of $31 thousand were made to Williams in 2010. No cash payments for federal and state income taxes were made to or received from Williams in 2009 or 2008.

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NOTES TO FINANCIAL STATEMENTS

6. 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. The carrying amount and estimated fair value of our long term debt, including current maturities, were $693.6 million and $796.1 million, respectively, at December 31, 2010, and $693.4 million and $754.8 million, respectively, at December 31, 2009.

7. 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,
		2010				2009				2008
		(Thousands of Dollars)
Puget Sound Energy, Inc.		$	95,564			$	94,508			$	89,988
Northwest Natural Gas Co.			48,022				49,256				(a	)

     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

     Through January 31, 2010, we were a participant in Williams’ cash management program and made advances to and received advances from Williams. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program was terminated. As of December 31, 2010, no cash advances to Williams remain outstanding. The balance owed by Williams to us pursuant to the cash management program at December 31, 2009 is reflected as a reduction of our Owners’ Equity as the advances were not available to us as working capital. As a result of the restructuring, we became a participant in WPZ’s cash management program. At December 31, 2010, the advances due to us by WPZ totaled $45.0 million. The advances are represented by demand notes. The interest rate on the Williams 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. The interest rate on the WPZ demand notes is based upon the overnight investment rate paid on WPZ’s excess cash, which was approximately 0.06 percent at December 31, 2010. We received interest income from advances to our affiliates of $27 thousand, $74 thousand and $813 thousand during the years ended December 31, 2010, 2009, and 2008, respectively. Such interest income is included in “Other Income — net: Interest income — Affiliated” on the accompanying Statements of Income.

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NOTES TO FINANCIAL STATEMENTS

          Williams charges its subsidiary companies for management services provided by it and other affiliated companies. Such corporate expenses charged by Williams, WPZ, and other affiliated companies were $34.1 million, $36.0 million and $32.7 million for the years ended December 31, 2010, 2009 and 2008, respectively. These expenses are included in “General and administrative expense” on the accompanying Statements of Income. Management considers the cost of these services to be reasonable.

          Northwest has no employees. Services are provided to us by an affiliate, NPS. In return, we reimburse NPS for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation, pension and other benefits) in connection with these services. We were billed $60.6 million, $60.1 million and $53.6 million in the years ended December 31, 2010, 2009 and 2008, respectively. Such expenses are primarily included in “General and administrative” and “Operation and maintenance” expenses on the accompanying Statement of Income.

          During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $6.8 million, $9.9 million, and $14.8 million for the years ended December 31, 2010, 2009, and 2008, respectively.

          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 Statements of Income. The lease was terminated on August 1, 2009.

          In October 2010, Williams Partners Operating LLC made a $15.0 million capital contribution to us to fund a portion of our expenditures for additions to property, plant and equipment.

          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.

8. ASSET RETIREMENT OBLIGATIONS

          We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset which will be amortized commensurate with our collection of those costs in rates.

          During 2010 and 2009, our overall asset retirement obligation changed as follows (in thousands):

		2010				2009
Beginning balance		$	86,749			$	82,666
Accretion			6,058				6,068
New obligations			27				2,594
Changes in estimates of existing obligations (1)			(27,679	)			(4,579	)
Ending Balance		$	65,155			$	86,749

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NOTES TO FINANCIAL STATEMENTS

          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.

9. 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. Current regulatory liabilities are included in other accrued liabilities and noncurrent 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 or refundable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2010 and 2009:

		2010				2009
		(Thousands of Dollars)
Current regulatory assets
Environmental costs		$	2,200			$	2,200
Fuel recovery			45				52
Total current regulatory assets			2,245				2,252
Noncurrent regulatory assets
Environmental costs			3,317				3,590
Grossed-up deferred taxes on equity funds used during construction			17,458				18,346
Levelized depreciation			32,463				30,801
Asset retirement obligations, net			6,938				4,295
Total noncurrent regulatory assets			60,176				57,032
Total regulatory assets		$	62,421			$	59,284
Current regulatory liabilities
Fuel recovery		$	731			$	337
Noncurrent regulatory liabilities
Postretirement benefits			16,264				15,134
Total regulatory liabilities		$	16,995			$	15,471

          The significant regulatory assets and liabilities include:

          Environmental Costs We have accrued liabilities for assessment and remediation activities to bring certain sites up to current environmental standards. The accrual for these liabilities is offset by a

NORTHWEST PIPELINE GP

NOTES TO FINANCIAL STATEMENTS

regulatory asset. The regulatory asset is being amortized to expense consistent with amounts collected in rates.

          Fuel Recovery These amounts reflect the value of the cumulative volumetric difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base, but are expected to be recovered or refunded by changing the fuel reimbursement factor in subsequent fuel filings.

          Grossed-Up Deferred Taxes on Equity Funds Used During Construction The regulatory asset balance was established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

          Levelized Depreciation Levelized depreciation allows contract revenue streams to remain constant over the primary contract terms by recognizing lower than book depreciation in the early years and higher than book depreciation in later years. The depreciation component of the levelized incremental rates will equal the accumulated book depreciation by the end of the primary contract terms. The difference between levelized depreciation and straight-line book depreciation is recorded in a FERC approved regulatory asset or liability and is extinguished over the levelization period.

          Asset Retirement Obligations We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected future abandonment of the underlying physical assets. 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, and is being amortized to expense consistent with the amounts collected in rates.

          Postretirement Benefits We seek to recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as regulatory assets or liabilities and collected or refunded through future rate adjustments. These amounts are not included in the rate base, and we are not currently recovering postretirement benefit costs in our rates.

NORTHWEST PIPELINE GP

QUARTERLY FINANCIAL DATA
(Unaudited)

          The following is a summary of unaudited quarterly financial data for 2010 and 2009:

		Quarter of 2010
		First				Second				Third				Fourth
		(Thousands of Dollars)
Operating revenues		$	106,110			$	102,578			$	103,562			$	109,567
Operating income			50,291				45,419				48,348				50,722
Net income			37,883				34,378				37,673				39,593

		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

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

None.

ITEM 9A.		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.

Evaluation of Disclosure Controls and Procedures

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

Management’s Annual Report on Internal Control over Financial Reporting

     See report set forth 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 2010 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

Item 9B.		OTHER INFORMATION

None.

PART III

          Since we meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K, the information required by Items 10, 11, 12, and 13 is omitted.

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:

		2010				2009
		(Thousands of Dollars)
Audit Fees		$	791			$	862
Audit-Related Fees			—				—
Tax Fees			—				—
All Other Fees			—				—
		$	791			$	862

          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 WPZ, we do not have a separate audit committee. The policies and procedures for pre-approving audit and non-audit services of the Audit Committee of the Board of Directors of WPZ’s general partner have been set forth in WPZ’s 2010 annual report on Form 10-K, which is available on the SEC’s website at http://www.sec.gov and on WPZ’s website at http://williamslp.com under the heading “Investors — SEC Filings.”

PART IV

Item 15.		EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements

Index

		Page
		Reference
		to 2010
		Form 10-K
Management’s Annual Report on Internal Control over Financial Reporting		24
Report of Independent Registered Public Accounting Firm		25
Statement of Income for the Years Ended December 31, 2010, 2009 and 2008		26
Balance Sheet at December 31, 2010 and 2009		27
Statement of Owners’ Equity for the Years Ended December 31, 2010, 2009 and 2008		29
Statement of Comprehensive Income for the Years Ended December 31, 2010, 2009 and 2008		30
Statement of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		31
Notes to Financial Statements		32

(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, 2010:
Reserve for doubtful receivables		$	—			$	—			$	—			$	—
Reserve for obsolescence of materials and supplies			11				622				(20	)			613
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

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

(a) 3 and b. Exhibits:

Exhibit		Description
2(a)		Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007) and incorporated herein by reference.
3(a)		Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, 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 our report on Form 8-K, 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 our Registration Statement on Form S-3, 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 our report on Form 8-K, 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 our report on Form 8-K, 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 (Exhibit 4.1 to our 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., No. 1-4174, report on Form 8-K filed May 1, 2006) 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., No. 1-4174, report on Form 8-K filed May 15, 2007) and incorporated herein by reference.

Exhibit		Description
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., No. 1-4174, report on Form 8-K, filed November 28, 2007) 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 our report on Form 8-K, 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 our report on Form 8-K, filed January 30, 2008) and incorporated herein by reference.
10(f)		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, No. 1-32599, report on Form 8-K, filed on February 22, 2010) and incorporated herein by reference.
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.

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.

Date: February 24, 2011

          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/ Randall L. Barnard		Senior Vice President and Management Committee Member
Randall L. Barnard		(Principal Executive Officer)
/s/ Richard D. Rodekohr		Vice President and Treasurer
Richard D. Rodekohr		(Principal Financial Officer)
/s/ Allison G. Bridges		Vice President
Allison G. Bridges
/s/ R. Rand Clark		Controller (Principal Accounting Officer)
R. Rand Clark
/s/ Donald R. Chappel		Management Committee Member
Donald R. Chappel

Date: February 24, 2011

EXHIBIT INDEX

Exhibit		Description
2(a)		Certificate of Conversion of Northwest Pipeline Corporation (Exhibit 2.1 to our report on Form 8-K, filed October 2, 2007) and incorporated herein by reference.
3(a)		Statement of Partnership Existence of Northwest Pipeline GP (Exhibit 3.1 to our report on Form 8-K, 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 our report on Form 8-K, 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 our Registration Statement on Form S-3, 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 our report on Form 8-K, 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 our report on Form 8-K, 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 (Exhibit 4.1 to our 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., No. 1-4174, report on Form 8-K filed May 1, 2006) 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., No. 1-4174, report on Form 8-K filed May 15, 2007) 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., No. 1-4174, report on Form 8-K, filed November 28, 2007) 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 our report on Form 8-K, 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 our report on Form 8-K, filed January 30, 2008) and incorporated herein by reference.
10(f)		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, No. 1-32599, report on Form 8-K, filed on February 22, 2010) and incorporated herein by reference.

Exhibit		Description
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.