UNITED STATES SECURITIES AND EXCHANGE COMMISSION ~~Washington, DC 20549~~

Washington, DC 20549

Form 10-K

(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2008
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

(Mark One)


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

For the fiscal year ended December 31, 2009


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

For the transition period from to

Commission file number 001-33917

Williams Pipeline Partners L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		26-0834035
Delaware (State or Other Jurisdiction of Incorporation or Organization)		26-0834035 (IRS Employer Identification No.)
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
One Williams Center, Tulsa, Oklahoma (Address of Principal Executive Offices)		74172-0172 (Zip Code)
One Williams Center, Tulsa, Oklahoma		74172-0172
(Address of Principal Executive Offices)		(Zip Code)

918-573-2000 (Registrant’s telephone number, including area code)

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered

Common Units		New York Stock Exchange

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

None

(Title of Class)

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

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

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

Indicate by check mark ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~has ~~filers pursuant~~submitted toelectronically ~~Item 405~~and ofposted on its ~~Regulation S-K is~~corporate ~~not~~Website, ~~contained~~if ~~herein~~any, ~~and~~every ~~will~~Interactive ~~not~~Data beFile ~~contained,~~required to ~~the~~be ~~best~~submitted and posted pursuant ofto ~~registrant’s~~Rule 405 ~~knowledge,~~of inRegulation S-T ~~definitive~~(§232.405 ~~proxy~~of ~~or information~~this ~~statements~~chapter) ~~incorporated~~during bythe ~~reference~~preceding ~~in Part~~12 ~~III~~months of(or ~~this~~for ~~Form 10-K or~~such ~~any~~shorter ~~amendment~~period that the registrant was required to ~~this Form 10-K~~submitted and post such files. ) Yes o No o

Indicate by check mark ~~whether~~if ~~the~~disclosure ~~registrant~~of isdelinquent afilers ~~large accelerated~~pursuant ~~filer,~~to anItem 405 ~~accelerated~~of ~~filer,~~Regulation S-K or(§229.405) ais ~~non-accelerated filer~~not contained herein, orand awill ~~smaller~~not ~~reporting~~be ~~company.~~contained, ~~See~~to the ~~definitions~~best of ~~“large~~registrant’s ~~accelerated filer~~knowledge,” ~~“accelerated filer”~~in ~~and~~definitive ~~“smaller~~proxy ~~reporting~~or ~~company”~~information statements incorporated by reference in ~~Rule~~Part ~~12b-2~~ III of ~~the~~this ~~Exchange~~Form ~~Act.~~10-K ~~(Check~~or ~~one):~~any amendment to this Form 10-K. þ

~~Large~~ Indicate by check mark whether the registrant is a large accelerated filer, oan ~~Accelerated~~ accelerated filer, oa ~~Non~~non-accelerated filer, þor ~~Smaller~~a smaller reporting company. oSee 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 þ Non-accelerated filer o(Do not check if a smaller reporting company) Smaller reporting company o

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

The aggregate market value of the registrant’s common units held by non-affiliates based on ~~Yes~~the closing sale price of such units as reported on the New York Stock Exchange, as of the last day ~~o No~~of the registrant’s most recently completed second quarter was þapproximately $407,362,588. This figure excludes common units beneficially owned by the directors and executive officers of Williams Pipeline GP LLC, our general partner.

The ~~aggregate~~registrant ~~market~~had ~~value~~22,607,430 ~~of the registrant’s~~ common units ~~held~~ byand ~~non-affiliates~~10,957,900 ~~based~~subordinated ~~on the closing sale price of such~~ units asoutstanding ~~reported on the New York Stock Exchange,~~ as of ~~the last~~ ~~day of the registrant’s most recently completed second quarter was approximately $309~~February 17,~~040,300.~~ ~~This figure excludes common units beneficially owned by the directors and executive officers of Williams Pipeline GP LLC, our general partner~~2010.

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

DOCUMENTS INCORPORATED BY REFERENCE

None

WILLIAMS PIPELINE PARTNERS L.P.

FORM 10-K

TABLE OF CONTENTS

Heading		Page
~~PART I~~	PART I
Item 1.	Business		24
Item 1A.	Risk Factors		12
Item 1B.	Unresolved Staff Comments		36
Item 2.	Properties		36
Item 3.	Legal Proceedings		36
Item 4.	Submission of Matters to a Vote of Security Holders		36
~~PART II~~	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities		37
Item 6.	Selected Financial Data		40
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 7A.	~~Qualitative~~Quantitative and ~~Quantitative~~Qualitative Disclosures about Market Risk		55
Item 8.	Financial Statements and Supplementary Data		5657
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		9395
Item 9A(T).	Controls and Procedures		93
Item 9A.	Controls and Procedures		95
Item 9B.	Other Information		9395
~~PART III~~	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		9496
Item 11.	Executive Compensation		~~101~~102
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		~~104~~105
Item 13.	Certain Relationships and Related Transactions and Director Independence		~~106~~108
Item 14.	Principal ~~Accountant~~Accounting Fees and Services		~~113~~115
~~PART IV~~	PART IV
Item 15.	Exhibits, ~~and~~ Financial Statement Schedules		~~114~~116
EX-10.6
EX-10.7
EX-10.8
EX-21.1
EX-23.1
EX-24.1
EX-31.1
EX-31.2
EX-32
EX-99.1

DEFINTIONS

We use the following oil and gas measurements in this report. All volumes of natural gas are stated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.

“Mcf” means thousand cubic feet.

“MMcf” means million cubic feet.

“Bcf” means billion cubic feet.

“MMBtu” means one million British Thermal Units.

“TBtu” means one trillion British Thermal Units.

“Dth” means one dekatherm, which is equal to one MMBtu.

“MDth” means thousand dekatherms.

“MMDth” means million dekatherms.

WILLIAMS PIPELINE PARTNERS L.P.

FORM 10-K

PART I

Item 1. Business

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

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

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

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

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

GENERAL

We are a Delaware limited partnership formed on August 31, 2007 by The Williams Companies, Inc. (“Williams”) to own and operate natural gas transportation and storage assets. Our primary business objectives are to generate stable cash flows and, over time, to increase our quarterly ~~cash~~ cash distributions per unit. We own a 35 percent general partnership interest in Northwest, which owns and operates an approximately 3,900-mile, bi-directional, interstate natural gas pipeline system that extends from the San Juan Basin in New Mexico, through the Rocky Mountains and to the northwestern ~~Northwestern~~ United States. Northwest also has working natural gas storage capacity of of approximately 1213.80 billion cubic feet, or Bcf. We account for our 35 percent interest in Northwest as an equity investment, and, therefore, do not consolidate its financial results.

The 35 percent of Northwest owned by us was owned by Williams prior to the initial public offering (“IPO”) of our common units in January 2008. As of ~~February~~December 2331, 2009, Williams indirectly owned ~~owns~~ an approximate 45.7 percent limited ~~partnership~~partner interest in us and all of our 2 percent ~~general~~ general partner interest.

Williams is an integrated energy company with ~~2008~~2009 revenues in excess of $128.32 billion that trades on the New York Stock Exchange under the symbol “WMB.” Williams operates in numerous aspects of the energy industry, including natural gas exploration and production, midstream services, and ~~interstate~~ interstate natural gas transportation. Williams has owned or operated interstate natural gas transportation and storage assets for more than 2425 years.

4 2

Recent Developments ~~2008 EVENTS~~

On ~~January~~February 2417, ~~2008~~2010, weWilliams completed ~~our~~a ~~IPO.~~strategic ~~Concurrent~~restructuring ~~with the~~to ~~closing~~contribute ofcertain ~~the IPO, (i) the public, through the~~of ~~underwriters~~its ofmidstream ~~the~~and ~~offering,~~pipeline ~~purchased common units~~assets, ~~representing~~ aincluding 47its 45.57 percent limited partner interest in us, its ~~(ii)~~100 ~~we purchased from Northwest a 15.9~~ percent ~~general~~ ~~partnership~~ownership interest in ~~Northwest~~our general partner, and ~~(iii)~~its 65 ~~a 19.1~~ percent interest in Northwest ~~was contributed~~ to ~~us by~~ Williams ~~Pipeline~~Partners GPL.P. ~~LLC~~(“Williams Partners”), ~~our~~an ~~General~~affiliate ~~Partner~~of Williams and of us, in exchange for a ~~2 percent~~cash ~~general~~and ~~partner~~units ~~interests~~ in ~~us,~~Williams ~~and~~Partners ~~all~~(the “Dropdown”). As part of ~~our~~the strategic restructuring, ~~incentive~~Williams ~~distribution~~Partners ~~rights.~~announced Onits ~~February 21,~~intention ~~2008,~~to ~~the underwriters~~commence ofan ~~the~~exchange ~~offering~~offer ~~exercised~~for ~~their~~any ~~right~~and toall ~~purchase~~of our ~~additional~~outstanding common units ~~from~~not usheld toby ~~cover~~Williams ~~over-allotments~~Partners ~~which represented~~or anits ~~additional~~affiliates ~~4.8 percent~~at ~~limited~~a ~~partner~~future date following ~~interest~~the inconsummation usof the Dropdown. ~~Concurrently~~The ~~with~~exact timing of the ~~exercise~~launch of ~~the~~such ~~option~~offer ~~and in~~was ~~accordance~~stated ~~with~~to be dependent on the ~~terms~~filing of necessary documentation with the ~~Contribution~~SEC and upon market conditions, ~~Conveyance~~but ~~and~~it ~~Assumption~~was ~~Agreement~~announced ~~entered~~that ~~into~~it inwould ~~connection~~be ~~with~~at ~~the~~a ~~closing of~~fixed ~~the~~exchange ~~IPO,~~ratio ~~the~~of ~~Partnership~~0.7584 ~~redeemed~~of ~~those~~its common units ~~from~~for ~~the~~each our ~~General~~common ~~Partner~~units.

FINANCIAL INFORMATION ABOUT SEGMENTS

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

NARRATIVE DESCRIPTION OF BUSINESS

We Our ~~are a Delaware limited partnership formed on August 31, 2007 by Williams to own and operate natural gas transportation and storage assets. We own a 35 percent~~ general partnership interest in Northwest. ~~The remainder of the interest in Northwest~~ is ~~owned~~our byprimary ~~Williams~~asset. ~~Gas~~As ~~Pipeline~~a ~~Company~~result, ~~LLC,~~we aare ~~wholly~~dependent ~~owned~~on ~~subsidiary~~Northwest offor ~~Williams.~~substantially Asall of ~~February 23, 2009,~~our ~~Williams,~~cash ~~through~~available ~~its~~for ~~subsidiary,~~distribution ~~Williams~~and ~~Pipeline GP~~the ~~LLC,~~narrative ~~owns~~description aof ~~2 percent~~business ~~general~~is ~~partner~~primarily ~~interest~~focused ~~and~~on ~~a 45~~Northwest.~~7 percent limited partner interest in us.~~

Northwest’s System

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

Northwest’s system includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. Its compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. AsAt of December 31, ~~2008~~2009, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 7 Bcf* of natural gas per day. ~~Northwest~~ ~~also has approximately 12.8 Bcf of working natural gas storage capacity.~~

Northwest has access to multiple strategic natural gas supply basins, including basins in the Rocky Mountain region, the San Juan Basin and the Western Canadian Sedimentary Basin (“WCSB”). Northwest is the only interstate natural gas pipeline that currently provides service to certain key markets, including Seattle, Washington; Portland, Oregon; and Boise, Idaho. In addition Northwest believes it provides competitively priced services in markets such as Reno, Nevada; Spokane, Washington ; and Medford, Oregon that are also ~~serviced~~served by other interstate natural gas pipelines.

* The Northwest ~~term~~transports ~~“Mcf”~~and ~~means~~stores ~~thousand~~natural ~~cubic~~gas ~~feet~~for a broad mix of customers, including local ~~“MMcf”~~natural ~~means~~gas ~~million~~distribution ~~cubic~~companies, ~~feet~~municipal ~~and~~utilities, ~~“Bcf”~~direct industrial users, electric power ~~means~~generators ~~billion~~and ~~cubic~~natural ~~feet~~gas marketers and producers. ~~All~~Northwest’s ~~volumes~~firm oftransportation ~~natural~~and ~~gas~~storage contracts are ~~stated at~~generally along-term ~~pressure~~contracts ~~base~~with ofvarious ~~14.73~~expiration ~~pounds~~dates ~~per~~and ~~square~~account ~~inch~~for ~~absolute~~the atmajor 60portion ~~degrees~~of ~~Fahrenheit~~its business. ~~The~~Additionally, ~~term~~Northwest ~~“MMBtu”~~offers ~~means~~interruptible ~~one~~and short-term firm ~~million~~transportation ~~British~~services. ~~Thermal~~During ~~Units~~2009, ~~and~~Northwest ~~“TBtu”~~served ~~means~~a ~~one trillion~~total ~~British~~of ~~Thermal~~129 ~~Units~~transportation and storage customers. ~~The~~Northwest’s ~~term~~two ~~“Dth”~~largest ~~means~~customers were Puget Sound Energy, Inc. and Northwest Natural ~~one~~Gas ~~dekatherm~~Company, which isaccounted ~~equal~~for toapproximately ~~one~~21.8 percent ~~MMBtu~~and 11.3 percent, ~~The~~respectively, ~~term~~of its ~~“MDth”~~total ~~means~~operating ~~thousand~~revenues ~~dekatherms~~for the year ended December 31, 2009. ~~The~~No ~~term~~other customer accounted for more ~~“MMDth”~~than ~~means~~10 percent ~~million~~of ~~dekatherms~~Northwest’s total operating revenues during that period.

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

Northwest’s Supply and Demand Dynamics

To effectively manage its business, Northwest monitors its market areas for both short-term and long-term shifts in natural gas supply and demand. Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as imported Liquified Natural Gas (“LNG”), directly or indirectly affect the demand for Northwest’s services from both producers and consumers. For example, western U.S. production levels are growing rapidly, but a large portion of the new production of natural gas from the Rocky Mountain region will be delivered to markets in the mid-continent and eastern U.S. through projects like the Rockies Express Pipeline. Canadian production levels, on the other hand, are in a flat to downward trend and exports to U.S. markets are declining. As a result, Northwest’s customers will face increasing competition from Mid-Continent and East Coast markets for Rocky Mountain natural gas supplies. As these supply dynamics shift, Northwest anticipates that it will continue to actively pursue projects that link new sources of supply to customers willing to contract for transportation on a long-term firm basis. Changes in demographics, the amount of electricity generation, prevailing weather conditions and shifts in residential and commercial usage affect Northwest’s customers’ overall demand for natural gas. As customer demand dynamics change, Northwest anticipates that it will create new services or capacity arrangements that meet their long-term requirements.

Northwest’s Transportation and Storage Services

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

5 Northwest has approximately 12.8 Bcf of working natural gas storage capacity through the following three storage facilities. These natural gas storage facilities enable Northwest to balance daily receipts and deliveries and provide storage services to certain major customers.

	•	Jackson Prairie: Northwest owns a one-third interest in the Jackson Prairie underground storage facility located near Chehalis, Washington, with the remaining interests owned by two of its distribution customers. As of December 31, 2008, Northwest’s share of the firm seasonal storage service in this facility was approximately 7.5 Bcf of working natural gas storage capacity and up to 383 MMcf per day of peak day deliveries. Additionally, Northwest’s share of the best-efforts delivery capacity was 50 MMcf per day. As described below, Northwest is participating in an ongoing expansion of Jackson Prairie.
	•	Plymouth LNG: Northwest also owns and operates an LNG storage facility located near Plymouth, Washington, which provides standby service for its customers during extreme peaks in demand. The facility has a total LNG storage capacity equivalent to 2.3 Bcf of working natural gas, liquefaction capability of

12percentage ~~MMcf~~of ~~per~~the ~~day~~total ~~and~~fees ~~regasification~~received ~~capability~~under a firm contract. Northwest also derives a small portion of ~~300~~its ~~MMcf~~revenues ~~per~~from ~~day~~short-term firm and interruptible contracts under which customers pay fees for transportation, storage and other related services. ~~Certain~~The high percentage of Northwest’s revenue ~~major~~derived ~~customers~~from ~~own~~capacity reservation fees helps mitigate the ~~working~~risk ~~natural~~of ~~gas~~revenue ~~stored~~fluctuations caused atby ~~the~~changing ~~LNG~~supply ~~plant~~and demand conditions.

~~• Clay Basin Field:~~ Northwest has aapproximately ~~contract~~13.0 ~~with~~Bcf aof ~~third~~working ~~party under which Northwest contracts for~~ natural gas storage ~~services~~capacity inthrough anthe following ~~underground~~three storage ~~reservoir~~facilities. inThese ~~the~~natural ~~Clay~~gas ~~Basin~~storage ~~Field~~facilities ~~located~~enable ~~in Daggett County, Utah.~~ Northwest ~~is authorized~~ to balance ~~utilize~~daily ~~the~~receipts ~~Clay~~and ~~Basin~~deliveries ~~Field~~and atprovide ~~a seasonal~~ storage ~~level~~services ofto ~~3.0~~certain ~~Bcf~~major ~~of working natural gas, with a firm delivery capability of 25 MMcf of natural gas per day~~customers.

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

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

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

Northwest’s Competition

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

Competition could arise from new ventures or expanded operations from existing competitors. For example, in late 2006, Northwest Natural Gas Co. (“Northwest Natural”), Northwest’s second largest customer, announced that it is partnering with TransCanada’s Gas Transmission Northwest (“GTN”), to build the Palomar Gas Transmission project. This proposed project would consist of a ~~Greenfield~~ greenfield pipeline from GTN’s system in central Oregon to Northwest Natural’s system in western Oregon. Palomar could also be used to transport natural gas from one of the proposed Columbia ~~River~~ River LNG terminals back to GTN’s system.

Northwest is also experiencing increased competition for domestic supply with the completion of projects such as Kinder Morgan’s Rockies Express and Wyoming Interstate’s Kanda Lateral, which are designed to transport natural gas produced in the Piceance and Uinta Basins to Midwestern and Eastern markets. El Paso Corporation has proposed a new pipeline project, called Ruby, which would begin at the Opal Hub in Wyoming and terminate in Malin, Oregon, near the California border, to create additional access to Rocky Mountain gas in western markets.

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

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

6 ~~Northwest’s Customers~~

Northwest transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies (“LDCs”), direct industrial users, electric power generators and natural gas marketers and producers. Northwest provides natural gas transportation services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona, either directly or indirectly through interconnections with other pipelines. Northwest’s customers use its transportation and storage services for a variety of reasons. Natural gas distribution companies and electric generation companies typically require a secure and reliable supply of natural gas over a prolonged period of time to meet the needs of their customers and frequently enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Producers of natural gas require the ability to deliver their product to market and frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Natural gas marketers use

~~storage and transportation services to capitalize on price differentials over time or between markets.~~ Northwest’s ~~customer~~ ~~mix~~Supply ~~can vary over time~~ and ~~largely~~Demand ~~depends on the~~Dynamics ~~natural gas supply and demand dynamics in its markets.~~

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

~~The pipeline projects listed below are significant future pipeline projects for which~~ Northwest’s ~~has significant customer~~Customers ~~commitments.~~

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

Northwest’s Capital Projects

The pipeline projects listed below were completed during 2009 or are significant future pipeline projects for which Northwest has significant customer commitments.

Colorado Hub Connection Project

On November 10, 2009, Northwest ~~has~~placed ~~proposed~~into ~~installing~~service athe new 27-mile, 24-inch diameter lateral ~~to connect the Meeker/White River Hub near~~ ~~Meeker, Colorado to Northwest’s mainline near Sand Springs, Colorado. This project is~~ referred to as the Colorado Hub Connection Project (“CHC Project”). ItThe isnew ~~estimated~~lateral ~~that~~connects the ~~construction~~Meeker/White ofRiver ~~the~~Hub ~~CHC~~near ~~Project~~Meeker, ~~will~~Colorado ~~cost up~~ to ~~$60 million with service targeted to commence in November 2009.~~ Northwest ~~will~~’s ~~combine~~mainline ~~the~~south ~~lateral capacity with 341 MDth per day~~ of ~~existing~~ ~~mainline capacity from various receipt points for delivery to Ignacio~~Rangely, Colorado, ~~including approximately 98 MDth~~ ~~per~~and ~~day~~is ofestimated ~~capacity~~to ~~that~~cost ~~was~~up ~~sold~~to ~~on a short-term basis. Approximately 243 MDth per day of this capacity was originally held by Pan-Alberta Gas under a contract that terminates on October~~$60 ~~31, 2012~~million.

In The ~~addition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the~~ CHC Project ~~provides~~combined ~~direct access to additional natural gas supplies at~~ the ~~Meeker/White~~new ~~River~~lateral ~~Hub~~capacity ~~for Northwest’s on-system and off-system markets. Northwest has entered into precedent agreements~~ with ~~terms~~existing ~~ranging~~mainline ~~between~~capacity ~~eight~~to ~~and~~provide ~~fifteen~~approximately ~~years~~363 atMDth ~~maximum~~per ~~rates~~day ~~for all~~ of ~~the short-term~~ firm ~~and~~ ~~Pan-Alberta~~transportation ~~capacity~~from ~~resulting~~various inreceipt ~~the~~points ~~successful~~to delivery ~~re-contracting~~points ofon the ~~capacity~~mainline ~~out~~as tofar ~~2018~~south ~~and~~as ~~beyond. In September 2008~~Ignacio, ~~Northwest filed an application for FERC certification and is awaiting necessary regulatory approvals~~Colorado. ~~If Northwest~~Approximately ~~does~~243 ~~not~~MDth ~~proceed~~per ~~with~~day ~~the CHC Project, Northwest will seek recovery~~ of ~~any shortfall in annual~~ the capacity ~~reservation revenues~~was ~~from~~originally ~~its~~held ~~remaining~~by ~~customers~~Pan-Alberta inGas under a ~~future~~contract ~~rate proceeding.~~that ~~Northwest~~would ~~expects~~have toterminated ~~collect maximum rates for the~~on ~~new~~October 31, ~~CHC~~2012 ~~Project capacity commitments~~ and ~~seek~~approximately ~~approval~~98 ~~to recover~~MDth ~~the~~per ~~CHC~~day ~~Project~~was ~~costs~~previously insold ~~any~~on ~~future~~a ~~rate~~short-term ~~case filed with FERC~~basis.

In addition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub in the Piceance Basin for Northwest’s on-system and off-system markets. Northwest has entered into transportation agreements for approximately 363 MDth per day of capacity with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. In April 2009, FERC issued a certificate approving the CHC Project, including the presumption of rolling in the costs of the project in any future rate case filed with the FERC.

Jackson Prairie Underground Expansion

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

As a one-third owner of Jackson Prairie, in early 2006, Northwest held an open season for a new firm storage service based on its 100 MMcf per day share of the planned 2008 ~~deliverability~~ deliverability expansion and ~~its~~ approximately 1.2 Bcf of its share of the working natural gas storage capacity expansion to be developed over approximately a six-year period from 2007 through 2012.

As a result of the open season, four shippers have executed long-term service agreements for the full amount of incremental storage service offered at contract terms averaging 33 years. The firm service relating to storage capacity rights will be phased-in as the expanded working natural gas capacity is developed. Northwest’s one-third share of the deliverability expansion was placed in service on November 1, 2008 at a cost of approximately $16.0 million. Northwest’s estimated capital cost for the capacity expansion component of the new storage service is $6.1 million, primarily for base natural gas.

Sundance Trail Expansion

In ~~February 2008~~November 2009, Northwest ~~initiated~~received anapproval ~~open~~from ~~season~~FERC ~~for~~to ~~the~~construct approximately 16 miles of ~~proposed~~30-inch ~~Sundance~~loop ~~Trail~~between ~~Expansion~~its ~~project~~existing ~~that~~Green ~~resulted~~River and Muddy Creek compressor stations in Wyoming as well as an upgrade to its existing Vernal compressor station, with service targeted to commence in November 2010. The total project is estimated to cost up to $65 million, including the cost of ~~execution~~replacing the existing compression at Vernal, which will enhance the efficiency of anNorthwest’s system. Northwest executed a precedent agreement ~~for~~to provide 150 MDth per day of firm transportation service from the ~~Meeker/White~~Greasewood ~~River~~and ~~Hub~~Meeker Hubs in Colorado for delivery to the Opal Hub in Wyoming. ~~The~~Northwest ~~project will~~has ~~include~~proposed ~~construction~~to ofcollect ~~approximately~~its ~~16 miles~~maximum ~~of 30-inch~~system ~~loop between~~rates, ~~Northwest’s existing Green River~~ and ~~Muddy~~has ~~Creek~~received approval ~~compressor~~from ~~stations~~FERC to roll-in ~~Wyoming~~the asSundance ~~well~~Trail asExpansion ancosts ~~upgrade~~in ~~to Northwest’s~~any ~~existing~~future ~~Vernal~~rate ~~compressor station, with~~cases. ~~service targeted~~

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

Regulatory Matters

FERC Regulation

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

	•		transportation and storage of natural gas;

	•		rates and charges;

	•		terms of service including creditworthiness requirements;

	•		construction of new facilities;

	•		extension or abandonment of service and facilities;

	•		accounts and records;

	•		depreciation and amortization policies;

	•		relationships with gas marketing functions within Williams; and

	•		initiation and discontinuation of services.

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

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

The maximum recourse rates that may be charged by interstate pipelines for their services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are level of plant investment and costs of providing service, allowed rate of return and volume throughput and contractual capacity commitments. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved tariff or established by reference to FERC’s regulations. Rate design and the allocation of costs also can impact a pipeline’s profitability. Interstate pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”

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

In a 2007 proposed policy statement, FERC proposed to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings. In 2008, FERC issued a final policy statement which rejected the concept of capping distributions in favor of an adjustment to the long-term growth rate used to calculate the equity cost of capital for publicly traded partnerships which are included in the proxy group. The effect of the application of FERC’s policy to Northwest’s future rate proceedings is not certain and Northwest cannot ensure that such application would not adversely affect its ability to achieve a reasonable level of return on equity.

Pursuant to Northwest’s March 30, 2007 rate settlement, Northwest is required to file a new rate case to be effective no later than January 1, 2013.

FERC Policy Statement on Income Tax Allowances

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

On December 8, 2006, FERC issued an order in an interstate oil pipeline proceeding addressing its income tax allowance policy, noting that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this creates an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling. On December 26, 2007, FERC issued an order on rehearing affirming its prior ruling. FERC indicated that it will continue to review on a case-by-case basis whether a pipeline’s owners have an actual or potential income tax liability and may utilize a normalization approach to reduce a pipeline’s income tax allowance as appropriate. On January 25, 2008, shippers on the pipeline asked FERC to reconsider its income tax allowance policy, including whether such allowance should be permitted at all. On February 15, 2008, FERC responded that the shipper’s income tax allowance issues are complex and will be addressed at a later time.

The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. If FERC were to disallow a substantial portion of Northwest’s income tax allowance, it may be more difficult for Northwest to justify its rates in future proceedings. While we have established the Eligible Holder certification requirement, we can provide no assurance that such certification will be effective to establish that our unitholders, or our unitholders’ owners, are subject to United States federal income taxation on the income generated by us. If Northwest is unable to satisfy the requirements necessary to qualify for a full income tax allowance in calculating its cost of service in future rate cases, FERC could disallow a substantial portion of Northwest’s income tax allowance, and its maximum lawful rates could decrease from current levels.

FERC Policy Statement on Proxy Groups and Return on Equity

In an effort to provide guidance and to obtain public comment on FERC’s policies concerning return on equity determinations, on July 19, 2007, FERC issued a proposed policy statement. In the proposed policy statement, FERC proposed to permit inclusion of publicly traded partnerships in the proxy group analysis relating to return on equity determinations in rate proceedings, provided that the analysis be limited to actual publicly traded partnership distributions capped at the level of the pipeline’s earnings.

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

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

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

Energy Policy Act of 2005

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

Safety and Maintenance

Northwest is subject to regulation by the United States Department of Transportation (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in high consequence areas. PHMSA regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. The PHMSA may assess fines and penalties for violations of these and other requirements imposed by its regulations.

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

Northwest is subject to a number of federal laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and some comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the U.S. Environmental Protection Agency (“EPA”) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be

~~maintained~~Safety ~~concerning hazardous materials used or produced in operations~~ and ~~that this information be provided to employees,~~Maintenance ~~state and local government authorities, and citizens.~~

Northwest is subject to regulation by the United States Department of Transportation (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”), pursuant to the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Pipeline Safety Improvement Act of 2002, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in high consequence areas. PHMSA regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to implement integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage, and commercially navigable waterways. The PHMSA may assess fines and penalties for violations of these and other requirements imposed by its regulations.

Environmental Regulation

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

• requiring the acquisition of permits to conduct regulated activities; • restricting the manner in which Northwest can release materials into the environment; • imposing investigatory and remedial obligations to mitigate pollution from former or current operations; • assessing administrative, civil, and criminal penalties for failure to comply with applicable legal requirements; and • in certain instances, enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to applicable laws and regulations.

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

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

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

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owner or operator of a site where a hazardous substance was released into the environment and companies that disposed or arranged for the disposal of hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that were released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the

comply with certain standards for the accumulation and storage of hazardous wastes, as well as ~~costs~~recordkeeping ~~that~~and ~~they~~reporting ~~incur~~requirements applicable to hazardous waste storage and disposal activities. ~~Moreover~~RCRA imposes fewer restrictions on the handling, itstorage isand ~~not~~disposal ~~uncommon~~of ~~for~~non-hazardous ~~neighboring~~solid ~~landowners~~wastes, which includes certain wastes associated with the exploration and ~~other~~production ~~third~~of ~~parties~~oil and tonatural ~~file~~gas. ~~claims~~In the course of its operations, Northwest may generate petroleum hydrocarbon ~~for~~wastes ~~personal~~and ~~injury~~ordinary industrial wastes such as paint wastes, waste solvents, and ~~property~~waste ~~damage~~compressor oils ~~allegedly~~that ~~caused~~may bybe regulated as hazardous solid wastes. Similarly, the Toxic Substances Control Act ~~release~~(“TSCA”), and analogous state laws impose requirements on the use, disposal and storage of ~~substances~~various chemicals orand ~~wastes~~chemical ~~into~~substances. In the ~~environment~~course of its operations, Northwest may use chemicals and chemical substances that are regulated by TSCA.

~~Northwest~~ Site ~~currently~~Remediation. ~~owns~~The orComprehensive ~~leases~~Environmental ~~properties~~Response, ~~that~~Compensation ~~for~~and ~~many~~Liability Act ~~years~~(“CERCLA”), ~~have~~and ~~been~~comparable ~~used~~state ~~for~~laws ~~the~~impose ~~transportation~~liability, ~~compression~~without ~~and storage~~regard ofto ~~natural~~fault ~~gas.~~or ~~Although~~the ~~Northwest~~legality ~~typically used~~of ~~operating~~the ~~and~~original ~~disposal~~conduct, ~~practices~~on ~~that~~certain ~~were~~classes ~~standard~~of inpersons ~~the industry~~responsible atfor the ~~time,~~release ~~petroleum~~of ~~hydrocarbons~~hazardous substances ~~and~~into ~~wastes~~the ~~may~~environment. ~~have been~~Such ~~disposed~~classes of orpersons ~~released~~include onthe orcurrent ~~under~~and ~~the~~past ~~properties~~owner ~~owned~~ or ~~leased~~operator byof ita orsite onwhere ora ~~under~~hazardous ~~other~~substance ~~locations~~was ~~where~~released ~~such substances~~into ~~have~~the ~~been~~environment, ~~taken~~and ~~for~~companies that ~~recycling~~disposed or ~~disposal.~~arranged ~~In addition,~~for ~~some~~the disposal of ~~these~~hazardous ~~properties~~substances ~~may~~found ~~have~~at ~~been~~the ~~operated~~site. byUnder CERCLA, ~~third~~such ~~parties~~persons ormay bybe ~~previous~~subject ~~owners~~to ~~whose~~joint ~~treatment~~ and ~~disposal or~~several ~~release~~strict ofliability ~~petroleum~~for ~~hydrocarbons~~the orcosts ~~wastes~~of ~~was~~cleaning ~~not~~up ~~under~~the ~~Northwest’s~~hazardous ~~control. These properties and the~~ substances ~~disposed~~ orthat were released oninto ~~them~~the ~~may~~environment, befor ~~subject~~damages to ~~CERCLA,~~natural ~~RCRA~~resources and ~~analogous~~for ~~state~~the ~~laws~~costs of certain health studies. ~~Under~~CERCLA ~~such~~also ~~laws~~authorizes the EPA, ~~Northwest~~and ~~could~~in besome cases third ~~required~~parties, to ~~(i) remove~~take ~~previously~~actions ~~disposed~~in ~~wastes, including~~response ~~waste~~to ~~disposed~~threats ofto bythe ~~prior~~public ~~owners~~health or ~~operators (ii) remediate~~the ~~contaminated~~environment ~~property,~~and ~~including~~to ~~groundwater~~seek ~~contamination,~~to ~~whether~~recover from ~~prior~~the ~~owners~~responsible orclasses ~~operators~~of orpersons ~~other historic~~the ~~activities~~costs orthat ~~spills~~they orincur. ~~(iii) perform~~Moreover, ~~remedial~~it is not ~~closure~~uncommon ~~operations~~for neighboring landowners and other third parties to ~~prevent~~file ~~future~~claims ~~contamination~~for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

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

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

Northwest ~~may~~has ~~incur~~established ~~expenditures~~systems inand ~~the~~procedures ~~future~~to ~~for~~meet ~~air~~its ~~pollution~~reporting obligations under ~~control~~the ~~equipment~~Mandatory inReporting ~~connection~~Rule ~~with~~related ~~obtaining~~to orgreenhouse ~~maintaining operating~~gas ~~permits~~emissions ~~and~~issued ~~approvals~~by ~~for~~the ~~air~~EPA ~~emissions.~~in ~~For~~late ~~instance~~2009. Also, certain states in which Northwest has operations have established reporting obligations. Northwest ~~may~~has benot ~~required~~incurred significant capital investment to ~~supplement~~meet orthe ~~modify~~obligations ~~its~~imposed ~~air~~by these ~~emission~~new ~~control~~rules. ~~equipment~~The ~~and~~EPA ~~strategies~~is ~~due~~developing toadditional ~~changes~~regulations ~~in state~~that ~~implementation~~will ~~plans~~expand ~~for~~the ~~controlling~~scope ~~air~~of ~~emissions~~the inMandatory ~~regional~~Reporting ~~non-attainment areas~~Rule, orwith ~~stricter~~particular ~~regulatory~~emphasis on natural gas operations. Northwest is participating ~~requirements~~directly ~~for~~and ~~sources~~through trade associations in developmental aspects of ~~hazardous~~that ~~air~~prospective ~~pollutants~~rulemaking. ~~We believe~~It is likely that ~~any~~additional ~~such~~rules ~~future~~will ~~requirements~~be ~~imposed~~issued onin 2010 which may expand Northwest’s ~~will~~reporting obligations ~~not~~as early as 2011. As those rules are still being developed, at this time Northwest is ~~have~~unable ato ~~material~~estimate ~~adverse~~any ~~effect~~capital oninvestment ~~its~~that ~~operations~~may be required to comply.

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

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

Activities on Federal Lands. Natural gas transportation activities conducted on federal lands are subject to review and assessment under provisions of the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, agencies prepare Environmental Assessments, or more detailed Environmental Impact Statements which assess the potential direct, indirect and cumulative impacts of a proposed project and which may be made available for public review and comment. Northwest’s current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

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

~~Northwest~~evaluations, ~~could~~agencies ~~incur~~prepare ~~additional~~Environmental ~~costs~~Assessments, or ~~become~~more ~~subject~~detailed toEnvironmental Impact ~~operating~~Statements, ~~restrictions~~that orassess ~~bans in~~ the ~~affected~~potential ~~area.~~direct, ~~Civil~~indirect and cumulative impacts of a proposed project ~~criminal~~and ~~penalties~~which ~~can~~may be ~~imposed~~made ~~against~~available ~~any~~for ~~person~~public ~~violating~~review and comment. Northwest’s current activities, as ~~the~~well ~~Endangered~~as ~~Species~~any ~~Act~~proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

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

Insurance

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

Employees

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

Transactions with Affiliates

Northwest engages in transactions with Williams and other Williams subsidiaries. See Part II, Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: 1. Summary of Significant Accounting Policies and 89. Transactions with ~~Major~~ Major Customers and Affiliates and Part III, Item 13. Certain Relationships and Related Transactions, and Director Independence.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

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

Item 1A. Risk Factors

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

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements ~~discuss~~relate ~~our~~to ~~expected~~anticipated financial performance, management’s plans and objectives for future ~~results~~operations, business prospects, outcome ~~based~~of onregulatory ~~current~~proceedings, market conditions and ~~pending~~other ~~business~~matters. ~~operations~~We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report, that address activities, events or developments that we expect, believe or anticipate will exist or ~~may~~ may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

• amounts and nature of future capital expenditures; • expansion and growth of our business and operations; • financial condition and liquidity; • business strategy; • cash flow from operations or results of operations;

• ~~the~~Amounts and nature of future capital expenditures; • Expansion and growth of our business and operations; • Financial condition and liquidity; • Business strategy; • Cash flow from operations or results of operations; • The levels of cash distributions to unitholders; • ~~rate~~Rate case filings; and • ~~natural~~Natural gas ~~and natural gas liquids~~ prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in in this ~~document~~report. Limited partner ~~interests~~units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. ~~The~~You ~~reader~~ should carefully consider the risk factors discussed below in addition to the other information in this ~~annual~~ report. If any of the following risks were actually to occur, our business, results of operations and financial ~~condition~~ condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units ~~and~~, the trading price of our common units could decline and unitholders could lose all or part of their investment. Many of the factors that could adversely affect our business, results of operations and financial condition are beyond our ability to control or ~~project~~predict. Specific factors ~~which~~that could cause actual results to differ from ~~those~~results incontemplated ~~the~~by the forward-looking statements include, among others, the following:

• ~~availability~~Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay the minimum quarterly distribution following establishment of cash reserves and payment of fees and expenses, including payments to our general partner; • Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and ~~costs~~cost of capital; • ~~inflation~~Inflation, interest rates, and general economic conditions (including ~~the~~future ~~recent~~disruptions ~~economic~~and ~~slowdown~~volatility ~~and~~in the ~~disruption of~~ global credit markets and the impact of these events on Northwest’s customers and suppliers); • ~~the~~The strength and financial resources of our and Northwest’s competitors; • ~~the~~Development ~~development~~ of alternative energy sources; • ~~the~~The impact of operational and development hazards; • ~~costs~~Costs of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation, and rate proceedings; • Northwest’s costs ~~and funding obligations~~ for defined benefit pension plans and other postretirement benefit plans; • ~~increasing~~Changes in maintenance and construction costs; • ~~changes~~Changes in the current geopolitical situation; • Northwest’s exposure to the credit ~~risks~~risk of its customers; • ~~risks~~Risks ~~relating~~related to strategy and financing, including restrictions stemming from Northwest’s debt agreements, future changes in Northwest’s credit ~~rating~~ratings and the availability and cost of credit; ~~• risks association with future weather conditions; • acts of terrorism; and • additional risks described in our filings with the Securities and Exchange Commission.~~

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.

~~Because~~• ~~forward-looking~~Risks ~~statements~~associated ~~involve~~with ~~risks~~future ~~and uncertainties,~~weather weconditions; ~~caution~~• ~~that~~Acts ~~there~~of ~~are~~terrorism; ~~important~~and ~~factors,~~• ~~in addition~~Additional torisks ~~those~~described ~~listed~~in ~~above,~~our ~~that~~filings ~~may~~with ~~cause actual results to differ materially from those contained in~~ the ~~forward-looking statements~~SEC. ~~These factors include following:~~

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 Relating to Recent Developments

The current trading price of our common units has been impacted by the announcement of Williams Partners of its intention to engage in an exchange offer for our common units at a fixed exchange ratio, and we do not know what the impact on the trading price of our common units will be when the other terms of the exchange offer are announced or if Williams Partners does not launch such exchange offer or does not consummate such exchange offer once launched.

Since the announcement by Williams Partners of its intention to launch an exchange offer for our common units described above under “Recent Developments” at a fixed exchange ratio of 0.7584 common units of Williams Partners for each of our common units, our common units have traded in a range that reflects that exchange ratio. We do not know whether such exchange offer will be launched, and if it is launched, what the other terms and conditions of the exchange offer will be. There can be no assurance that Williams Partners will launch the exchange offer. We do not know what the impact on the trading price of our common units will be when the other terms of the exchange offer are announced or if Williams Partners does not commence the exchange offer or does not consummate the exchange offer once launched because any of the conditions to the offer have not been satisfied.

If the Williams Partners’ exchange offer is consummated, it may have a negative impact on the trading market and price of our common units or result in the purchase of your units for cash by our General Partner.

If the exchange offer of Williams Partners described above under “Recent Developments” is consummated, depending on the number of common units exchanged, the trading market for our common units that remain outstanding after the expiration of the exchange offer will become less liquid because there will be a smaller number of units outstanding and available for trading (a smaller “float”). To the extent that the float is reduced, such reduced float may negatively impact the market for, and the price of, our common units and make the trading price of our units more volatile.

In addition, if Williams Partners acquires sufficient common units in the exchange offer so that it and its affiliates own more than 75 percent of our common units, it will have the right to exercise the “cash call” provision in our Agreement of Limited Partnership, which will allow it to acquire all remaining outstanding common units at a price based on then current market prices or prices it had previously paid to acquire units.

The Dropdown may significantly decrease the amount of natural gas transportation and storage assets that Williams would otherwise have had available to contribute to us.

Williams recently transferred a substantial majority of its natural gas transportation assets in the Dropdown to another publicly traded limited partnership controlled by Williams and incurred substantial expenses in connection with the Dropdown. As a result, the possibility that any of such assets would be further dropped down to us as an avenue for our future growth has been substantially diminished. While we still may be able to grow organically or through third party acquisitions, the pace of such growth will likely be slower than if we could obtain the contribution of assets to us by Williams.

Risks Inherent in Our Industry and Our Business

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

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

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

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

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

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

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

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

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

• the amount of cash distributed by Northwest in respect of our 35 percent general partnership interest, which is our sole asset; • the level of capital expenditures we and Northwest make, including expenditures to maintain Northwest’s facilities, to complete construction projects and to make acquisitions; • our and Northwest’s debt service requirements and other liabilities; • fluctuations in our and Northwest’s working capital needs; • our and Northwest’s ability to borrow funds and access capital markets; • the creditworthiness of, and timeliness of payment from, Northwest’s customers; • restrictions contained in Williams’ and Northwest’s credit agreement and in Northwest’s indentures, including restrictions on distributions; and • the amount of cash reserves established by Northwest and by our general partner.

15 14

• restrictions contained in Williams’ and Northwest’s credit agreement and in Northwest’s indentures, including restrictions on distributions; and • the amount of cash reserves established by Northwest and by our general partner.

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

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

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

~~Events~~ Future disruptions in the global ~~financial~~credit ~~crisis~~markets ~~have~~may ~~made~~make equity and debt markets less accessible, create ~~and created~~ a shortage in the availability of credit, ~~which could disrupt our financing plans~~ and ~~limit~~lead ~~our ability~~ to ~~grow~~credit market volatility.

In 2008, public equity markets experienced significant declines and global credit markets ~~have~~ experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. ~~Under~~Future ~~current~~disruptions ~~market~~in ~~conditions~~the global financial marketplace, itincluding isthe ~~unclear~~bankruptcy ~~whether~~or werestructuring ~~could~~of ~~issue~~financial ~~additional~~institutions, could make equity orand debt ~~securities~~markets ~~or,~~inaccessible ~~even if~~and weadversely ~~were~~affect ~~able,~~the ~~whether~~availability weof ~~could~~credit doalready soarranged atand ~~prices~~the availability and ~~pursuant~~cost toof ~~terms~~credit ~~that~~in ~~would~~the ~~be acceptable to us~~future. ~~Continuing~~Northwest ~~volatility~~has ~~or additional~~availability ~~disruptions~~under intheir ~~the~~New ~~global~~Credit ~~financial marketplace~~Facility, ~~including~~ ~~the~~but ~~bankruptcy~~its orability to ~~restructuring~~borrow ofunder ~~certain~~that ~~financial institutions,~~facility could ~~make~~be ~~equity~~impaired ~~and~~if ~~debt~~one ~~markets~~or ~~inaccessible and~~more ~~adversely~~of ~~affect~~its ~~the~~lenders ~~availability~~fails ofto ~~credit~~honor ~~already arranged~~its ~~and~~contractual ~~the~~obligation ~~availability~~to ~~and~~lend ~~cost~~to ~~of credit in the future~~Northwest.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• fires, blowouts, cratering and explosions; • uncontrolled releases of natural gas; • pollution and other environmental risks; • natural disasters; • aging pipeline infrastructure and mechanical problems; • 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~~Northwest’s 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~~Northwest’s operations and substantial losses to Northwest and us. In accordance with customary industry practice, Northwest maintains insurance against some, but not all of these risks and losses, and only at levels they believe to be appropriate. The location of certain segments of Northwest’s pipeline in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks. In spite of any precautions taken, an event such as

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

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

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

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

Northwest competes primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of Northwest’s competitors may have greater financial resources and access to greater supplies of natural gas than it does. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services Northwest provides to its customers. Moreover, Williams and its affiliates, including Williams Partners, are not limited in their ability to compete with Northwest or us. Further, natural gas also competes with other forms of energy available to Northwest’s customers, including electricity, coal, fuel oils and other alternative energy sources.

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

those described above could cause considerable harm to people or property and could have a material adverse effect on Northwest’s and our financial condition and results of operations particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to Northwest’s customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of Northwest’s pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of Northwest’s pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could adversely impact Northwest’s ability to meet contractual obligations and retain customers, with a resulting negative impact on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

Northwest competes primarily with other interstate pipelines and storage facilities in the transportation and storage of natural gas. Some of Northwest’s competitors may have greater financial resources and access to greater supplies of natural gas than Northwest does. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for natural gas supplies or the services Northwest provides to its customers. Moreover, Williams Partners and its affiliates, including Williams, may not be limited in their ability to compete with Northwest or us. Further, natural gas also competes with other forms of energy available to Northwest’s customers, including electricity, coal, fuel oils and other alternative energy sources.

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

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

Northwest’s primary exposure to market risk occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Although none of Northwest’s material contracts are terminable in ~~2009~~2010, upon expiration of the terms, Northwest may not be able to extend contracts with existing customers orto obtain replacement contracts at favorable rates or on a long-term basis.

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

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

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

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

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

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

	•		the effects of state regulation on customer contracting practices.

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

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

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

• transportation and sale for resale of natural gas in interstate commerce; • rates, operating terms and conditions of service, including initiation and discontinuation of services; • the types of services Northwest may offer to its customers, including initiation and discontinuation of services; • certification and construction of new facilities; • acquisition, extension, disposition or abandonment of facilities; • accounts and records; • depreciation and amortization policies; • relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and • market manipulation in connection with interstate sales, purchases or transportation of natural gas.

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

~~Regulatory~~Competitive ~~actions~~pressures incould ~~these~~lead ~~areas~~to ~~can~~decreases ~~affect Northwest’s business~~ in ~~many~~the ~~ways,~~volume ~~including~~of ~~decreasing~~natural ~~tariff~~gas ~~rates~~contracted ~~and~~or ~~revenues,~~transported ~~deceasing~~through ~~volumes in~~ Northwest’s ~~pipelines, increasing~~pipeline ~~Northwest’s costs and otherwise altering the profitability of Northwest’s business~~system.

~~The~~ Although ~~FERC~~most of Northwest’s ~~Standards~~pipeline ofsystem’s ~~Conduct~~current ~~govern~~capacity ~~the~~is ~~relationship~~fully contracted, FERC has ~~between~~taken certain actions to strengthen market forces in the natural gas ~~transmission~~pipeline ~~providers~~industry ~~and~~that ~~“marketing~~have ~~function~~led ~~employees”~~to asincreased ~~defined~~competition bythroughout the ~~rule~~industry. ~~The~~In ~~standards~~ a number of ~~conduct~~key ~~are~~markets, ~~intended~~interstate pipelines toare ~~prevent~~now ~~natural~~facing ~~gas~~competitive ~~transmission providers~~pressure from ~~preferentially~~other ~~benefiting~~major ~~their~~pipeline ~~gas~~systems, ~~marketing~~enabling local ~~functions~~distribution bycompanies ~~requiring~~and ~~the~~end ~~employees~~users ofto choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that ~~perform~~could ~~transmission~~potentially ~~functions~~serve the same markets as Northwest’s pipeline system. Any such new pipelines could offer transportation services that are more desirable to ~~function~~shippers ~~independently~~because of ~~from~~locations, ~~marketing~~facilities, ~~function~~or ~~employees~~other ~~and~~factors. byThese ~~restricting~~pipelines ~~the~~could charge rates or provide service to ~~information~~locations that ~~transmission~~would ~~providers~~result ~~may~~in ~~provide~~greater net profit for shippers and producers and thereby force Northwest to ~~gas~~lower the rates charged for service on its pipeline in order to extend its existing ~~marketing~~transportation ~~employees~~service agreements or to attract new customers. ~~The~~Northwest ~~inefficiencies~~is ~~created~~aware byof ~~the~~proposals by ~~restrictions~~competitors onto ~~the~~expand ~~sharing~~pipeline ofcapacity ~~employees~~in ~~and~~certain ~~information~~markets ~~may increase~~it ~~our~~also ~~costs~~serves which, ~~and~~if the ~~restrictions~~proposed projects onproceed, could increase the ~~sharing~~competitive ofpressure upon Northwest. There can be no ~~information~~assurance ~~may~~that ~~have~~Northwest anwill ~~adverse~~be ~~impact~~able onto ~~our~~compete ~~senior~~successfully against current and future ~~management’s~~competitors ~~ability~~and any failure to ~~effectively~~do ~~obtain~~so ~~important information~~could ~~about~~have ~~our~~a material adverse effect on Northwest’s business. and ~~Violators~~results of ~~these~~operations ~~rules~~and ~~are subject~~cash toflows, ~~potentially~~and ~~substantial~~on ~~civil~~our ~~penalty~~ability ~~assessments~~to make distributions to you.

~~The rates, terms and conditions for~~ Northwest’s ~~interstate pipeline~~natural gas transportation and storage ~~services~~operations are ~~set~~subject ~~forth~~to inregulation ~~its~~by FERC~~-approved~~, ~~tariff.~~which ~~Pursuant~~could tohave ~~the~~an ~~terms~~adverse ofimpact ~~Northwest’s~~on ~~most~~its ~~recent rate~~ability ~~settlement~~to ~~agreement,~~establish ~~Northwest~~transportation and ~~the~~storage ~~other parties to~~rates ~~the~~that ~~settlement~~would ~~are~~allow ~~precluded~~it ~~from~~to ~~filing~~recover ~~for~~the ~~any~~full ~~further increases~~cost orof ~~decreases~~operating inits ~~existing rates prior to January 1~~pipeline, ~~2009,~~including ~~and Northwest must file~~ a ~~new~~ reasonable rate ~~case~~of ~~to become effective not later than January 1~~return, ~~2013.~~and ~~Any successful complaint or protest against Northwest’s rates could have an adverse impact~~ on ~~Northwest’s~~our ~~revenues associated~~ability ~~with~~to ~~providing~~make ~~transportation~~distributions ~~and~~to ~~storage services~~you.

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

	•		certification and construction of new facilities;

	•		acquisition, extension, disposition or abandonment of facilities;

	•		accounts and records;

	•		depreciation and amortization policies;

	•		relationships with marketing functions within Williams involved in certain aspects of the natural gas business; and

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

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

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

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

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

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

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

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

There is a risk that the rates set by FERC will be inadequate to ~~recover~~ cover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that ~~higher~~ higher rates will cause Northwest’s 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 Northwest will be allowed to recover.

In May 2005, FERC issued a statement of general policy permitting a pipeline to include in its cost-of-service computations an income tax allowance provided that an entity or individual has an actual or potential income tax liability on income from the pipeline’s public utility assets. The extent to which owners of pipelines have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis in rate cases where the amounts of the allowances will be established.

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

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

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

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

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

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

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

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

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

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

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

Some portions of Northwest’s current pipeline infrastructure and other assets have been in use for many decades, which may adversely affect its business and our ability to make distributions to you.

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

The failure of new sources of natural gas production or LNG import terminals to be successfully developed in North America could increase natural gas prices and reduce the demand for Northwest’s services.

New sources of natural gas production in the United States and Canada, particularly in areas of shale development are expected to become an increasingly significant component of future ~~natural~~ natural gas supplies in North America. Additionally, increases in LNG supplies are expected to be imported through new LNG import terminals, particularly in the Gulf Coast region. If these additional sources of supply are not developed, natural gas prices could increase and cause consumers of natural gas to turn to alternative energy ~~sources which could have a material~~

21 20

sources which could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

Northwest relies on a limited number of customers for a significant portion of its revenues. For the year ended December 31, ~~2008~~2009, Northwest’s two largest ~~customer~~customers was Puget Sound Energy, Inc. ~~This~~and ~~customer~~Northwest Natural Gas Company. These customers accounted for approximately 2033.71 percent of Northwest’s operating revenues for the year ended December 31, ~~2008~~2009. The loss of even a portion of Northwest’s contracted volumes, as a result of competition, creditworthiness, inability to ~~negotiate~~ negotiate contract extensions or replacements of contracts or otherwise, could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you, unless Northwest is able to acquire comparable revenues ~~volumes~~ from other sources.

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

Northwest depends upon third-party pipelines and other facilities that provide delivery options to and from its pipeline and storage facilities. Because Northwest does not own ~~these~~ these third-party pipelines or facilities, their continuing operation is not within ~~its~~Northwest’s control. If these pipelines or other facilities were to become temporarily or permanently unavailable ~~due~~for any toreason, ~~repairs~~or if throughput were reduced because of testing, line repair, damage to pipelines or ~~the~~facilities, ~~facility~~reduced operating pressures, lack of capacity, increased credit requirements or ~~rates~~ rates charged by such pipelines or facilities or ~~any~~ other ~~reason~~ causes, Northwest’s ~~ability~~and toits ~~operate~~customers ~~efficiently~~would ~~and~~have ~~continue~~reduced ~~shipping~~capacity to transport, store or deliver natural gas to end- use markets ~~could be restricted~~, thereby reducing its revenues. Further, although there are laws and regulations designed to encourage competition in in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other ~~market~~ market participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on Northwest’s pipeline or stored at Northwest’s facilities could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Northwest is exposed to the credit ~~risks~~risk of its customers, and its credit risk management may not be adequate to protect against such risk.

Northwest is ~~exposed~~subject to the ~~credit~~ risk of loss resulting from nonpayment and/or nonperformance by its customers in the ordinary course of its business. Generally Northwest’s customers are rated investment grade, are otherwise considered creditworthy, or are required to make pre-payments or ~~provide~~ provide security to satisfy credit concerns. However, Northwest’s ~~cannot~~credit procedures and policies may not be adequate to fully eliminate customer credit risk. Northwest cannot predict to what extent its business would be impacted by deteriorating conditions in the economy, including declines in Northwest’s customers’ creditworthiness. ~~While~~ If Northwest ~~monitors~~fails ~~these~~to ~~situations~~adequately ~~carefully~~assess ~~and attempts to~~the ~~take~~creditworthiness ~~appropriate~~of ~~measures~~existing toor ~~protect~~future ~~itself~~customers, itunanticipated isdeterioration ~~possible~~in ~~that~~their ~~Northwest~~creditworthiness ~~may~~and ~~have~~any resulting increase in nonpayment and/or nonperformance by them could cause Northwest to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect Northwest’s operating results for the period in which they occur, and, if significant, could have a material adverse effect on its ~~operating~~business, results of operations, cash flows and financial condition.

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

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

ANorthwest’s ~~failure to comply with the covenants in the credit agreement or in any existing or future~~ debt agreements could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and ~~payable~~ Williams’and ~~terminate all commitments, if any, to extend~~Williams ~~further~~Partners’ public ~~credit.~~indentures Ancontain ~~event~~financial ofand ~~default~~operating orrestrictions anthat ~~acceleration~~may ~~under~~limit ~~one debt agreement could cause a cross-default or cross-acceleration of other debt agreements. Such a cross-default or cross-acceleration could have a wider impact on~~ Northwest’s or ~~our~~access ~~liquidity~~to ~~than might otherwise arise from a default or~~credit ~~acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default,~~ and ~~the lenders~~affect ~~under~~its ~~the~~ability ~~affected~~to ~~debt~~operate ~~agreements~~its ~~accelerate~~business. In ~~the maturity of any loans or other debt outstanding~~addition, Northwest’s orability ~~we may not have sufficient liquidity~~ to ~~repay~~obtain ~~amounts~~credit ~~outstanding under~~in ~~such~~the ~~debt~~future ~~agreements. Any event of default or acceleration~~will atbe ~~Northwest~~affected ~~would~~by ~~materially~~Williams’ and ~~adversely~~Williams ~~affect~~Partners’ ~~our~~credit ~~ability to make distributions to you because distributions from Northwest represent substantially all of the cash we expect to distribute to our unitholders~~ratings.

Northwest’s ~~ability~~public toindentures ~~repay~~contain various covenants that, ~~extend~~among orother ~~refinance~~things, limit its ~~existing~~ ~~debt~~ability ~~obligations~~to ~~and~~grant certain liens to ~~obtain~~support ~~future~~indebtedness, ~~credit~~merge, ~~will~~or sell ~~depend~~substantially ~~primarily~~all onof its ~~operating~~assets. In ~~performance~~addition, ~~which~~Northwest’s ~~will~~new becredit facility entered into as part of Williams’ ~~affected~~restructuring by(“New ~~general~~Credit ~~economic,~~Facility”) contains certain financial, ~~competitive, legislative,~~covenants ~~regulatory,~~and ~~business~~restrictions on its ability and ~~other~~its subsidiaries’ ~~factors~~ability to incur indebtedness, ~~many~~to consolidate or allow any material change in the nature of its business, ~~which~~enter ~~are~~into ~~beyond~~certain ~~our~~affiliate ortransactions, ~~its~~and ~~control~~make certain distributions during an event of default. These covenants could adversely affect Northwest’s ability to ~~refinance~~ ~~existing~~finance ~~debt~~its ~~obligations~~future operations or ~~obtain~~capital ~~future~~needs ~~credit~~or ~~will~~engage in, expand or ~~also~~pursue ~~depend~~its ~~upon~~business ~~the~~activities ~~current~~and ~~conditions~~prevent init ~~the~~from ~~credit~~engaging ~~markets and~~in ~~the~~certain ~~availability~~transactions ofthat ~~credit~~might ~~generally.~~otherwise Ifbe considered beneficial to them. Northwest’s isability ~~unable~~ to ~~meet~~comply ~~its~~with ~~debt~~these ~~service~~covenants ~~obligations~~may orbe ~~obtain~~affected ~~future~~by ~~credit~~events ~~on favorable~~beyond ~~terms~~their control, including ifprevailing ~~at all~~economic, ~~Northwest~~financial ~~could~~and beindustry ~~forced~~conditions. If ~~to restructure~~market or ~~refinance~~other ~~its~~economic ~~indebtedness~~conditions deteriorate, Northwest’s ~~seek~~current ~~additional equity~~assumptions ~~capital~~about orfuture ~~sell~~economic ~~assets.~~conditions ~~Northwest~~turn ~~may~~out to be ~~unable~~incorrect toor ~~obtain~~unexpected events occur, ~~financing~~Northwest’s orability ~~sell~~to ~~assets~~comply onwith ~~satisfactory~~these ~~terms,~~covenants ormay atbe ~~all~~significantly impaired.

Williams’ and Williams Partners’ public indentures contain covenants that restrict their and Northwest’s ability to incur liens to support indebtedness. These ~~Although~~ covenants could adversely affect Northwest’s ability to finance its future operation or capital needs or engage in, expand or pursue its business activities and prevent them from engaging in certain transactions that might otherwise be considered beneficial to them. Williams’ and Williams Partners’ ability to comply with the covenants contained in their respective debt instruments may ~~contain~~be ~~limitations~~affected ~~on additional~~by ~~indebtedness,~~events beyond Northwest’s, ~~general~~Williams’ ~~partnership~~and Williams Partners’ ~~agreement~~control, ~~does~~including ~~not~~prevailing ~~prohibit~~economic, itfinancial ~~from~~and ~~incurring~~industry ~~indebtedness~~conditions. If market or other economic conditions deteriorate, ~~which~~Williams’ ~~may~~or ~~affect~~Williams ~~our~~Partners’ ability to ~~make~~comply ~~distributions~~with ~~to you~~these covenants may be negatively impacted.

As Northwest’s ~~discussed~~failure into ~~the~~comply ~~immediately~~with ~~preceding risk factor,~~the ~~Northwest’s~~covenants ~~existing~~in its debt ~~instruments~~agreements ~~contain~~could ~~restrictions on~~result ~~its~~in ~~ability~~events toof ~~incur~~default. ~~additional~~Upon ~~indebtedness.~~the ~~However,~~occurrence of such ~~restrictions~~ doan ~~not~~event ~~prohibit~~of ~~incurrence~~default, ofthe lenders ~~indebtedness~~could inelect to declare all ~~instances,~~ ~~and~~amounts ~~Northwest’s~~outstanding ~~general~~under ~~partnership~~a ~~agreement does~~particular ~~not~~facility ~~prohibit~~to itbe ~~from~~immediately ~~incurring~~due ~~indebtedness.~~and Atpayable and ~~December 31~~terminate all commitments, ~~2008~~if any, ~~Northwest~~to ~~had~~extend nofurther ~~loans~~credit. ~~outstanding~~Certain ~~under its~~payment ~~credit~~defaults ~~agreement,~~or ~~and~~an ~~approximately~~acceleration ~~$693.2 million~~under inNorthwest’s ~~outstanding~~public ~~senior~~indentures ~~notes~~or ~~which~~other ~~are~~material ~~not~~indebtedness ~~consolidated~~could oncause ~~our balance~~a ~~sheet.~~cross-default Ifor ~~permitted~~cross-acceleration ~~under~~of Northwest’s ~~credit~~New ~~agreement~~Credit ~~and~~Facility. ~~its~~Such ~~other~~a ~~indebtedness,~~cross-default ~~Northwest~~or cross-acceleration could ~~incur additional~~have ~~indebtedness.~~a wider impact on Northwest’s ~~incurrence~~liquidity ofthan ~~significant~~might ~~additional~~otherwise ~~indebtedness~~arise ~~could~~from ~~inhibit~~a ~~its~~default ~~ability~~or ~~to make~~acceleration ~~distributions~~of toa ussingle debt instrument. AnIf ~~inability~~an byevent ~~Northwest~~of todefault ~~make~~occurs, ~~distributions~~or toif usNorthwest’s ~~would~~New ~~materially~~Credit Facility cross-defaults, and ~~adversely~~the ~~affect~~lenders ~~our~~under the affected debt agreements ~~ability~~accelerate tothe ~~make~~maturity ~~distributions~~of any loans or other debt outstanding to ~~you~~Northwest, ~~because~~Northwest ~~distributions~~may ~~from~~not have sufficient liquidity to repay amounts outstanding under such debt agreements. For more information regarding Northwest’s debt ~~represent~~agreements, ~~substantially~~please ~~all~~read ofPart ~~the~~II, ~~cash~~Item we7. ~~expect~~Management’s toDiscussion and Analysis of Financial Condition and ~~distribute~~Results toof ~~our~~Operations ~~unitholders~~— Capital Resources and Liquidity of Northwest.

Substantially all of Williams’ and Williams Partners’ operations are conducted through their respective subsidiaries. Williams’ and Williams Partners’ cash flows are substantially derived from loans, dividends and distributions paid to it by their respective subsidiaries, including Williams Gas Pipeline Company, LLC (“WGP”), Northwest’s majority partner. Williams’ and Williams Partners’ 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 Northwest’s relationship with Williams and Williams Partners, its ability to obtain credit will be affected by Williams’ and Williams Partners’ credit ratings. If Williams and Williams Partners were to experience deterioration in their respective credit standing or financial condition, Northwest’s access to credit and its ratings could be adversely affected. Any future downgrading of a Williams’ and Williams Partners’ credit rating would likely also result in a downgrading of Northwest’s credit rating. A downgrading of a Williams’ and Williams Partners’ credit rating could limit Northwest’s ability to obtain financing in the future upon favorable terms, if at all.

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

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

• decreases in liquidity as a result of using a significant portion of available cash or borrowing capacity to finance the project or acquisition; • inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits; • inability to receive cash flows from a newly built or acquired asset until it is operational; ~~• unforeseen difficulties operating in new producing basins or end-use markets; and • customer losses at the acquired business.~~

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

	•		customer losses at the acquired business.

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

Northwest is subject to risks associated with climate change. 22

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

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

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

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

There is inherent risk of incurring significant environmental costs and liabilities in Northwest’s business, some of which may be material due to Northwest’s handling of petroleum hydrocarbons and wastes, the occurrence of air emissions and water discharges related to the operations, and historical industry operations and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, and in connection with spills or releases of natural gas and wastes on, under, or from Northwest’s properties and facilities. Private parties, including the owners of properties through which Northwest’s pipeline passes and facilities where Northwest’s wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from Northwest’s operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase Northwest’s compliance costs and the cost of any remediation that may become necessary. Northwest’s insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against Northwest.

Northwest’s 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, Northwest might not be able to obtain or maintain from time to time all required environmental regulatory approvals, or if Northwest fails to obtain and comply with them, the operation of its facilities could be prevented or become subject to additional costs resulting in potentially material adverse consequences to Northwest’s business financial condition, results of operations and cash flows, and on our ability to make distributions to you.

Northwest makes assumptions and develops 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, Northwest’s assumptions may change, and any new capital costs incurred to comply with such changes may not be recoverable under Northwest’s regulatory rate structure or its customer contracts. In addition, new environmental laws and regulations might adversely affect Northwest’s activities, including storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could have a material adverse effect on Northwest’s business, financial condition, results of operations and cash flows, and on our ability to make distributions to you.

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

Northwest’s natural gas transportation and storage operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities.

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

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

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

~~Legislative~~ Recent ~~and~~scientific ~~regulatory~~studies ~~responses~~have ~~related~~suggested tothat ~~climate~~emissions ~~change create~~of ~~financial risk. The United States Congress and~~ certain ~~states~~ ~~have~~gases, ~~for~~commonly ~~some~~referred ~~time been considering various forms of~~to ~~legislation~~as ~~related to~~ “greenhouse ~~gas~~gases” ~~emissions.~~(“GHGs”), ~~Increased public~~may ~~awareness~~be ~~and~~contributing ~~concern~~to ~~may~~warming ~~result~~of inthe ~~more~~earth’s ~~state~~atmosphere, ~~regional~~ and~~/or~~ ~~federal~~various ~~requirements~~governmental tobodies ~~reduce or mitigate the emission of greenhouse gases. Numerous states~~ have ~~announced~~considered orlegislative ~~adopted programs to stabilize~~ and ~~reduce~~regulatory ~~greenhouse~~responses ~~gases and similar federal legislation has been introduced~~ in ~~both~~this ~~houses of Congress~~area. Legislative ~~Northwest’s~~and ~~pipeline~~regulatory ~~may~~responses berelated ~~subject~~ to ~~regulation under~~GHGs and climate change ~~policies~~create ~~introduced at either~~ the ~~state~~potential orfor ~~federal~~financial ~~level within the next few years~~risk. ~~There~~The isUnited aStates ~~possibility that,~~Congress ~~when~~ and ifcertain ~~enacted,~~states ~~the~~have ~~final~~for ~~form~~some oftime ~~such~~been ~~legislation~~considering ~~could~~various ~~increase~~forms ~~our costs~~ of ~~compliance~~legislation ~~with environmental laws. If Northwest is unable to recover all costs~~ related to ~~complying with~~GHG ~~climate~~emissions. ~~change~~There ~~regulatory~~have ~~requirements~~also ~~imposed~~been oninternational ~~them, it~~efforts ~~could~~seeking ~~have~~legally abinding ~~material~~reductions ~~adverse~~in ~~effect~~emissions ~~on Northwest’s results~~ of ~~operations~~GHGs. ~~and~~In onaddition, ~~our~~increased ~~ability~~public ~~to make distributions to you.~~awareness Toand ~~the~~concern ~~extent~~may ~~financial~~result ~~markets~~in ~~view~~more ~~climate~~state, ~~change~~federal, and ~~emissions~~ ofinternational ~~greenhouse~~proposals ~~gases~~to asreduce aor ~~financial risk, this could~~mitigate ~~negatively~~the ~~impact~~emission ~~Northwest’s costs~~ of ~~and access to capital~~GHGs.

Several bills have been introduced in the United States Congress that would compel GHG emission reductions. On June 26, 2009, the U.S. House of Representatives passed the “American 23Clean Energy and Security Act” which is intended to decrease annual GHG emissions through a variety of measures, including a “cap and trade” system which limits the amount of GHGs that may be emitted and incentives to reduce the nation’s dependence on traditional energy sources. The U.S. Senate is currently considering similar legislation, and numerous states have also announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination could ultimately lead to the direct regulation of GHG emissions in our industry under the Clean Air Act. While it is not clear whether or when any federal or state climate change laws or regulations will be passed, any of these actions could result in increased costs to (i) operate and maintain Northwest’s facilities, (ii) install new emission controls on Northwest’s facilities, and (iii) administer and manage any GHG emissions program. If Northwest is unable to recover or pass through a significant level of its costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on Northwest’s results of operations and on our ability to make distributions to you. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact Northwest’s costs of and access to capital.

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

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

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

As Northwest has no employees, employees of Williams and its affiliates provide services to Northwest. As a result, Northwest is allocated a ~~participating~~portion ~~employer~~of Williams’ costs in defined benefit ~~pension~~ pension plans covering substantially all of Williams’ or its ~~U.S.~~ affiliates’ employees ~~and~~providing services to Northwest, as well as a portion of the costs of other postretirement benefit plans covering certain ~~eligible~~ eligible participants providing services to Northwest. The timing and amount of Northwest’s ~~funding~~ ~~allocation~~allocations ~~requirements~~ under the defined benefit pension plans in ~~which~~depend ~~it participates depends~~ upon a number of factors ~~Williams~~ Williams controls, including changes to pension plan benefits, as well as factors outside of ~~its~~ Williams’ control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase Northwest’s ~~funding~~ allocations ~~requirements~~ could have a significant adverse effect on ~~its~~Northwest’s financial condition., ~~The~~results ~~amount~~ of ~~expenses~~ ~~recorded~~operations ~~for the defined benefit pension plans~~ and ~~other~~ ~~postretirement~~cash ~~benefit plans~~flows, ~~in which Northwest participates, is also dependent on changes in several factors, including market interest rates~~ and ~~the returns~~ on ~~plan assets.~~our ~~Significant~~ability ~~changes~~to inmake ~~any~~distributions ofto ~~these factors may adversely impact Northwest’s future results of operations~~you.

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

We and Northwest are not fully insured against all risks inherent to our businesses, including environmental accidents that might occur. In addition, neither we nor Northwest maintain ~~business~~ business interruption insurance in the type and amount to cover all possible risks of loss. Williams currently maintains excess liability insurance with limits of $610.0 million per occurrence and in the aggregate annually and a deductible of $2.0 million per occurrence. This insurance covers ~~Williams~~ Williams, its subsidiaries and certain of its affiliates, including ~~our~~us and Northwest~~’s,~~ for legal ~~and~~ and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135.0 million of insurance ~~also~~ also providing gradual pollution liability coverage for natural gas and natural gas liquids operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of ~~substances arising from the combustion of fuels that~~ result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Williams and its affiliates.

25 Williams does not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to assets and resulting business interruption caused by terrorist acts committed by a U.S. person or interest. Also, all of Williams’ insurance is subject to deductibles. If a significant accident or event occurs for which we or Northwest are not fully insured, it could adversely affect Northwest’s or our operations and financial condition. We or Northwest may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina, Rita, Gustav and Ike have impacted the availability of certain types of coverage at reasonable rates, and we or Northwest may elect to self insure a portion of our asset portfolio. We cannot assure you that we or Northwest will in the future be able to obtain the levels or types of insurance we or Northwest would otherwise have obtained prior to these market changes or that the insurance coverage we or Northwest do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks

~~not~~substances ~~fully~~arising ~~covered~~from bythe ~~insurance~~combustion ~~could~~of ~~have~~fuels athat ~~material~~result ~~adverse effect~~in onacidic ~~Northwest’s~~deposition, and ~~our~~testing, monitoring, ~~business~~clean-up, ~~financial condition~~containment, ~~results~~treatment or removal of ~~operations~~pollutants ~~and~~from ~~cash~~property ~~flows~~owned, ~~and on our~~occupied ~~ability~~by, rented to, ~~make~~used ~~distributions~~by toor ~~you~~in the care, custody or control of Williams and its affiliates.

In Williams ~~addition~~does not insure onshore underground pipelines for physical damage, except at river crossings and at certain ~~insurance~~locations ~~companies~~such ~~that~~as ~~provide~~compressor stations. Williams maintains coverage of $300 million per occurrence for physical damage to ~~us,~~onshore ~~including~~assets ~~American~~and ~~International~~resulting ~~Group,~~business ~~Inc~~interruption caused by terrorist acts. Also, ~~have experienced~~all ~~negative~~of ~~developments~~Williams’ ~~that~~insurance ~~could~~is ~~impair~~subject ~~their~~to deductibles. If a ~~ability~~significant toaccident ~~pay~~or ~~any~~event ~~potential~~occurs ~~claims. As~~for awhich ~~result~~we or Northwest are not fully insured, weit could adversely affect Northwest’s or our operations and financial condition. We or Northwest may not be ~~exposed~~able to ~~greater~~maintain ~~losses~~or ~~than~~obtain ~~anticipated~~insurance of the type and ~~replacement~~amount we desire at reasonable rates. Changes in the insurance ~~may~~markets subsequent to hurricane losses have impacted named windstorm insurance coverage, rates and availability for Gulf of Mexico area exposures, and we or Northwest may elect to self insure a portion of our asset portfolio. We cannot assure you that we or Northwest will in the future be able to obtain the levels or types of insurance we or Northwest would otherwise have obtained, atprior to these market changes or that the insurance coverage we or Northwest do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a ~~greater~~material ~~cost~~adverse effect on Northwest’s and our business, iffinancial condition, results of operations and cash flows, ~~available~~and on our ability to make distributions to you.

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

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

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

• the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms; • the availability of skilled labor, equipment, and materials to complete expansion projects; • potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; • impediments on ~~our~~Northwest’s 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~~Northwest’s control, that may be material; and • the ability to access capital markets to fund construction projects.

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

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

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

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

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

~~significant~~ Northwest’s ~~reconstruction~~customers’ orenergy ~~remediation~~needs ~~costs,~~vary ~~which~~with ~~could~~weather conditions. To the extent weather ~~have~~conditions aare ~~material~~affected ~~adverse~~by ~~effect~~climate onchange ~~Northwest’s~~or ~~financial~~demand is impacted by regulations associated with ~~condition~~climate change, ~~results~~customers’ ofenergy ~~operations~~use ~~and~~could ~~cash~~increase ~~flows,~~or ~~and~~decrease depending on ~~our~~the duration and ~~ability~~magnitude toof ~~make~~the ~~distributions~~changes, leading either to ~~you~~increased investment or decreased revenues.

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

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

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

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

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

Some studies indicate a high failure rate of outsourcing relationships. Although Williams has taken steps to build a cooperative and mutually beneficial relationship with its ~~outsourcing~~ 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 usNorthwest to be able to conduct ~~our~~its business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.

Certain of Northwest’s accounting, information technology, application development, and help desk services are currently provided by Williams’ outsourcing provider from service centers outside of the United States. The economic and political conditions in certain countries from which Williams’ outsourcing providers may provide services to Northwest present similar risks ~~common to~~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.

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

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent registered public accounting firms and retirement plan practices. We cannot predict the ultimate impact of any future changes in ~~accounting~~ accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards ~~Board~~ Board (“FASB”), the SEC or ~~the~~ FERC could enact new accounting standards or FERC orders that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

Risks Inherent in an Investment in Us

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

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

interests and the interests of its affiliates over the interests of our unitholders. These conflicts, include, among others, the following factors:

• neither our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business strategy that favors us; • all of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and Williams Partners’ general partner, and these persons will also owe fiduciary duties to those entities; • our general partner is allowed to take into account the interests of parties other than us, such as Williams and its affiliates, in resolving conflicts of interest; • Williams owns the remaining 65 percent general partnership interest in Northwest; • Williams owns common and subordinated units representing an aggregate 45.7 percent limited partner interest in us, and if a vote of limited partners is required, Williams will be entitled to vote its units in accordance with its own interests, which may be contrary to our interests or your interests; • our general partner may make a determination to receive a quantity of our Class B common units and additional general partner units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders; • all of the executive officers and certain of the directors of our general partner will devote significant time to the business of Williams and/or Williams Partners, and will be compensated by Williams for the services rendered to them; • our general partner determines the amount and timing of our cash reserves, asset purchases and sales, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to unitholders; • our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. This determination can affect the amount of cash that is distributed to our unitholders, including distributions on our subordinated units, and to our general partner with respect to its incentive distribution rights, as well as the ability of the subordinated units to convert to common units; • our general partner determines which costs incurred by it and its affiliates are reimbursable by us; • in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; • our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf; • our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is required to be indemnified by us; • our general partner may exercise its limited right to call and purchase all common units not owned by it and its affiliates if they own more than 75 percent of the common units; • our general partner controls the enforcement of obligations owed to us by it and its affiliates; and • our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

~~The credit~~beneficial ~~and~~to ~~risk~~Williams ~~profile~~Partners. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner and ~~its~~Williams ~~owner~~Partners, on the one hand, and us ~~Williams~~and our unitholders, ~~could~~on ~~adversely~~the ~~affect~~other ~~our~~hand. orIn ~~Northwest’s~~resolving ~~credit ratings,~~these ~~which~~conflicts ~~could~~of ~~increase~~interest, our orgeneral partner ~~Northwest’s~~may ~~borrowing costs~~favor orits ~~hinder~~own ~~our~~interests orand ~~Northwest’s~~the ~~ability~~interests toof ~~raise~~its affiliates over the interests of our ~~capital~~unitholders. These conflicts, include, among others, the following factors:

~~The~~• ~~credit~~neither ~~and~~our partnership agreement nor any other agreement requires Williams or its affiliates to pursue a business ~~risk~~strategy ~~profiles~~that favors us; • all of the executive officers and certain of the directors of our general partner are also officers and /or directors of Williams ~~may~~and beWilliams ~~factors~~Partners’ ~~considered~~general inpartner, ~~credit~~and ~~evaluations~~these persons will also owe fiduciary duties to those entities; • our general partner is allowed to take into account the interests of parties other than us , such as Williams and its affiliates, in resolving conflicts of interest; • Williams Partners owns the remaining 65 percent general partnership interest in Northwest; • Williams Partners owns common and subordinated units representing an aggregate 45.7 ~~This~~percent limited partner interest in us, and if a vote of limited partners is ~~because~~required, Williams Partners will be entitled to vote its units in accordance with its own interests, ~~through~~which may be contrary to our interests or your interests; • our general partner, ~~controls~~may make a determination to receive a quantity of our Class B common units and additional general partner units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders; • all of the executive officers and certain of the directors of our general partner will devote significant time to the business ~~activities~~of Williams and/or Williams Partners, ~~including~~and will be compensated by Williams for the services rendered to them; • our general partner determines the amount and timing of our cash ~~distribution~~ ~~policy~~reserves, ~~acquisition~~asset ~~strategy~~purchases and ~~business~~sales, ~~risk profile~~borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to unitholders; • our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure or investment capital expenditure, neither of which reduces operating surplus. AThis ~~decline~~determination incan ~~Williams’~~affect ~~credit~~the ~~rating~~amount of cash that is distributed to our unitholders, ~~such~~including distributions on our subordinated units, and to our general partner with respect to its incentive distribution rights, as ~~occurred~~ well as the ability of the subordinated units to convert to common units; • our general partner determines which costs incurred by it and its affiliates are reimbursable by us; • in ~~2002~~some instances, ~~would~~our ~~adversely~~general ~~affect~~partner ~~Northwest~~may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; • our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf; • our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is required to be indemnified by us; • our general partner may exercise its limited right to call and purchase all common units not owned by it and its affiliates if they own more than 75 percent of the common units; • our general partner controls the enforcement of obligations owed to us by it and its affiliates; and • our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Our general partner has the right to reset the minimum quarterly distribution and the initial target distribution levels upon which the incentive distributions payable to our general partner are based at higher levels based on our cash distribution for the two quarters prior to the exercise of the reset election. Following a reset election by our general partner, the new minimum quarterly distribution amount and target distribution levels will be higher than they were prior to the reset such that incentive distributions to our general partner will be reduced or eliminated until cash distributions per common unit following the reset increase. Our general partner may initially exercise its right to reset the minimum quarterly distribution and target distribution levels at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48 percent) for each of the prior four consecutive fiscal quarters.

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

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

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

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

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

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

our general partner without its consent because our general partner owns sufficient units to be able to prevent its removal. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. In addition, under certain circumstances the successor general partner may be required to purchase the combined general partner interest and incentive distribution rights of the removed general partner, or alternatively, such interests will be converted into common units. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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

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

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

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

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

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

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

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

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

	•		the ratio of taxable income to distributions may increase;

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

	•		the market price of the common units may decline.

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

Our general partner holds an aggregate of 4,700,668 common units and 10,957,900 subordinated units. Our general partner may from time to time, sell all or a portion of its common units or subordinated units. Sales of substantial amounts of its common units or subordinated units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and at a price that we deem appropriate.

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

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

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

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

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

agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders ability to influence the manner or direction of management.

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

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

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

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

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

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

agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

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

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

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

Tax Risks to Common Unitholders

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which currently has a top marginal rate of 35 percent, and would likely pay state and local income tax at the corporate tax rate of the various states and localities imposing a corporate income tax. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. In addition, because of ~~widespread~~ widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any jurisdiction were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced. The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be adjusted to reflect the impact of that law on us.

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

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

The present tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Internal Revenue Code Section 7704(d) and the treatment of certain types of income earned from profits interests in partnerships. It is possible that these efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of the units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

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

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

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

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

If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if our common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. In addition, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

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

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

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

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

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

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

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

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

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

The sale or exchange of 50 percent or more of our capital and profits interests within any 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholders’ taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If we are treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

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

In addition to federal income taxes, you will likely be subject to other taxes, such as state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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

Item 3. Legal Proceedings

The information called for by this item is provided in Part II, Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to the Consolidated Financial Statements: Note 3 4. Contingent Liabilities and Commitments — Legal Proceedings, which information is incorporated into this Item 3 by reference.

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

None.

PART II

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

(a) Market Information

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

2008	High		Low
	High		Low
2009
Fourth Quarter	$	23.80	$	18.64
Third Quarter		19.30		17.27
Second Quarter		20.40		15.93
First Quarter		17.11		14.20
2008
Fourth Quarter	$	16.00	$	11.57
Third Quarter		17.54		13.59
Second Quarter		18.86		17.26
First Quarter(1)		20.42		15.89


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

(b) Holders

On February 2317, ~~2009~~2010, there were 22,607,430 common units outstanding, held by approximately 5 10 holders of record and ~~400~~ approximately 10,000 beneficial holders, including common units held in street name and by affiliates of Williams.

On February 2317, ~~2009~~2010, there were 10,957,900 subordinated units outstanding held by a subsidiary of Williams. The subordinated units are not publicly traded.

(c) Cash Distributions

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

2008	Cash Distribution per Unit(a)
	Cash Distribution per Unit(a)
2009
Fourth Quarter	$	0.3350
Third Quarter		0.3350
Second Quarter		0.3300
First Quarter		0.3250
2008
Fourth Quarter	$	0.3200
Third Quarter		0.3150
Second Quarter		0.3100
First Quarter(b)		0.2242

(a)		Represents cash distributions attributable to the quarter and declared and paid or to be paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its 2 percent general partner interest and incentive distribution rights that totaled $0.8 million in 2008 and $1.0 million in 2009. Subordinated units participated in all of the cash distributions for the periods indicated above.
(b)		The first quarter distribution was prorated to cover the period of time from January 24, when the partnership’s initial public offering closed, through March 31. The prorated distribution of $0.2242 equates to a full quarter distribution of $0.30 per unit.

Cash Distribution Policy

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

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

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

• ~~comply~~less ~~with~~the ~~applicable~~amount ~~law, any~~ of ~~our~~cash ~~debt~~reserves ~~instruments~~established orby ~~other agreements; or • provide funds for distribution to~~ our ~~unitholders and to our~~ general partner ~~for any one or more of the next four quarters;~~to:

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

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

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

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

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

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

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

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

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

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

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

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner: first, 98 percent to the common unitholders, pro rata, and 2 percent to the general partner, until we distribute for

each outstanding common unit an amount equal to the minimum quarterly distribution for that Ifquarter; second, 98 percent to the common unitholders, ~~remove~~pro rata, and 2 percent to the general partner, ~~without~~until ~~cause,~~we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; ~~may~~third, ~~also~~98 percent ~~end~~to ~~before~~the ~~December~~subordinated unitholders, pro rata, and 2 31percent to the general partner, ~~2010~~until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and thereafter, in the manner described in our partnership agreement.

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

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

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

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

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

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

(d) Securities Authorized for Issuance Under Equity Compensation Plans

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

Item 6. Selected Financial Data

The following tables show (i) selected financial data of Williams Pipeline Partners and Predecessor (which reflects a 35 percent ownership interest in Northwest) and (ii) selected financial and operating data of Northwest. The following financial data as of December 31, ~~2008~~2009 and ~~2007~~2008, and for the years ended December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~ 2007 was derived from financial statements included herein. All other amounts have been prepared from financial statements not included herein. The information in this selected Financial and Operating Data should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for information concerning significant trends in the financial condition and results of operations.

Williams Pipeline Partners L.P. and/or Predecessor

Years Ended December 31,

2008

2007

2006

2005

2004

2009

2008

2007

2006

2005

~~(Predecessor)~~

(Predecessor)

(Restated) (B)

(Thousands of dollars)

Income Statement Data:

Equity earnings from investment in Northwest

5453,~~380~~778

~~153~~54,~~904~~380

19153,~~062~~904

2419,~~141~~062

2524,~~891~~141

Net income

5150,~~880~~821

~~153~~51,~~904~~880

19153,~~062~~904

2419,~~141~~062

2524,~~891~~141

Balance Sheet Data (at period end):

Investment in Northwest

~~414~~441,~~069~~608

~~414~~435,~~966~~103

~~300~~422,~~281~~199

~~264~~306,~~721~~660

~~258~~264,~~080~~721

Total partners’ capital

~~422~~449,~~013~~372

~~414~~441,~~966~~952

~~300~~422,~~281~~199

~~264~~306,~~721~~660

~~258~~264,~~080~~721

Basic and diluted net income per limited partner unit:

Common units

1.4353

1.45

Subordinated units

1.4353

1.45

Cash Dividends Declared

01.~~8492~~31

0.8492

Northwest (100%)

	Years Ended December 31,
	2008		2007			2006			2005		2004
	2009		2008			2007			2006		2005
			(Restated) (B)			(Restated) (B)			(Restated) (B)		(Restated) (B)
	(Thousands of dollars)
Income Statement Data:
Operating revenues	$	434,~~854~~379	$	~~421~~434,~~851~~854		$	~~324~~421,~~250~~851		$	~~321~~324,~~457~~250	$	~~338~~321,~~532~~457
Net income		~~155~~153,~~371~~651		~~439~~155,~~726~~371	~~(A)~~		54439,~~462~~726	(A)		6854,~~974~~462		7368,974
Balance Sheet Data (at period end):
Total assets		2,~~082~~081,~~172~~277		2,~~056~~078,~~471~~812			2,~~049~~033,~~324~~596			12,~~692~~034,~~371~~748		1,~~670~~661,~~499~~324
Long-term debt, including current maturities		693,~~240~~437		693,~~736~~240			~~687~~693,~~075~~736			~~520~~687,~~080~~075		~~527~~520,~~562~~080
Total Owners’ equity		1,184,714		1,185,616			857,945			756,346		737,372
Total owners’ equity		1,207,150		1,210,547			1,177,098			846,809		728,505
Cash Distributions		~~419~~135,~~342~~000		~~109~~419,~~770~~342			—109,770			~~50,000~~—		6050,000

Note: Earnings and distributions/dividends per partnership unit/common share are not presented for ~~2004~~2005 through ~~2008~~ 2009. Northwest was a wholly-owned subsidiary of Williams as of December 31, 2007 and for all prior periods presented. Distributions for 2009 and 2008 were made to Northwest’s partners based upon each partner’s ownership interest.

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

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

(B)		Our and Northwest’s financial statements have been restated as described in Item 8. Financial Statements and Supplementary Data — Williams Pipeline Partners L.P. Notes to Consolidated Financial Statements: Note 2. Restatement and Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 2. Restatement. Accordingly, Northwest’s 2005, 2006, 2007, and 2008 selected financial data has been restated to reflect the change in accounting treatment. The net impact of the balance sheet corrections resulted in an adjustment to loans to affiliate which have been reclassified to equity. A reconciliation between Northwest’s original basis in its total assets and liabilities and the selected financial data above follows:

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


	Years Ended December 31,
	2008			2007		2006		2005
				(Thousands of dollars)
Consolidated Balance Sheets:
Total assets, as previously reported	$	2,082,172		$	2,056,471	$	2,049,324	$	1,692,371
Benefit plans correction		3,360			22,875		14,576		31,047

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


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

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

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

Overview

We are a growth-oriented Delaware limited partnership formed on August 31, 2007 by Williams to own and operate natural gas transportation and storage assets. We own a 35 percent ~~general~~ general partnership interest in Northwest, a subsidiary of Williams that owns an approximate 3,900-mile, bi-directional, interstate natural gas pipeline system that extends from the San Juan Basin in New Mexico, through the Rocky Mountains and to the ~~Northwestern~~northwestern United States. Northwest also has working natural gas storage capacity of approximately 12 13.8 0 Bcf. The remaining 65 percent general ~~partnership~~ partnership interest in Northwest is owned by a subsidiary of Williams.

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

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

For a discussion of additional information on the restatement, see Item 8. Financial Statements and Supplementary Data — Williams Pipeline Partners L.P. Notes to Consolidated Financial Statements: Note 2. Restatement.

On February 17, 2010, Williams completed a strategic restructuring to contribute certain of its midstream and pipeline assets, including its 45.7 percent limited partner interest in us, its 100 percent ownership interest in our general partner, and its 65 percent interest in Northwest to Williams Partners L.P. (“Williams Partners”), an affiliate of Williams and of us, in exchange for cash and units in Williams Partners (the “Dropdown”). As part of the strategic restructuring, Williams Partners announced its intention to commence an exchange offer for any and all of our outstanding common units not held by Williams Partners or its affiliates at a future date following the consummation of the Dropdown. The exact timing of the launch of such offer was stated to be dependent on the filing of necessary documentation with the SEC and upon market conditions, but it was announced that it would be at a fixed exchange ratio of 0.7584 of its common units for each our common units.

How We Evaluate Our Operations

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

• the level of capacity reserved under Northwest’s long-term firm transportation and storage contracts; • the level of revenues provided by Northwest’s short-term firm and interruptible transportation and storage services; • Northwest’s operating expenses; and • our and Northwest’s ~~estimated~~ cash available for distribution.

Long-Term Firm Service

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

Short-Term Firm and Interruptible Service

A small portion of Northwest’s revenues is generated by short-term firm and interruptible services under which customers pay fees for transportation, storage or other related services. Of Of Northwest’s revenues for the twelve months ended December 31, ~~2008~~2009, approximately 54.74 percent were derived from short-term firm and interruptible services.

Seasonality

Although Northwest delivers more gas to its market areas in the winter heating season months of November through March, because a significant percentage of Northwest’s revenues are ~~collected~~ collected through reservation fees, its revenues remain fairly stable from quarter to quarter. The table below sets forth seasonal revenues, expenses and throughput for each quarter and the total year ended December 31, ~~2008:~~2009.

2008	Jan-Mar			Apr-Jun			Jul-Sep			Oct-Dec			Total
2009	Jan-Mar			Apr-Jun			Jul-Sep			Oct-Dec			Total
Revenues ($ in 000)	$	~~107~~111,~~405~~548		$	~~106~~107,~~450~~756		$	~~108~~106,~~542~~615		$	~~112~~108,~~457~~460		$	434,~~854~~379
Revenue%		24.7	%		24.5	%		25.0	%		25.8	%		100	%
Revenue %		25.7	%		24.8	%		24.5	%		25.0	%		100	%
Operating Expenses ($ in 000)	$	58,~~239~~396		$	5960,~~774~~743		$	5557,~~500~~470		$	6057,~~163~~261		$	233,~~676~~870
Throughput (TBtu)(1)		~~220~~224			~~171~~173			~~179~~166			~~211~~206			~~781~~769
Throughput%		28.2	%		21.9	%		22.9	%		27.0	%		100	%
Throughput %		29.1	%		22.5	%		21.6	%		26.8	%		100	%

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

Northwest’s Operating Expenses

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

laws which can impact the activities it performs on its pipeline. Changes in these regulations or Northwest’s assessment of the condition of inspected facilities can increase costs. As an example, the Pipeline Safety Improvement Act of 2002 set new standards for pipelines in assessing the safety and reliability of their pipeline infrastructure. Northwest and other pipelines have incurred additional costs to meet these standards. Certain of Northwest’s markets are served by other interstate natural gas pipelines and Northwest needs to operate its system efficiently and reliably to effectively compete for transportation and storage services.

Our Cash Available for Distribution

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

Northwest’s Cash Available for Distribution

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

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

Factors that Impact Northwest’s Business

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

We believe the key factors that impact Northwest’s business are the supply of and demand for natural gas in the markets in which Northwest operates, Northwest’s customers and their 42requirements, and government regulation of natural gas pipelines. These key factors, described in “Narrative Description of Business” in Part I, Item 1. Business, play an important role in how Northwest manages its operations and implements its long-term strategies.

~~Table~~ We believe the collective impact of ~~Contents~~these key factors may result in an increasingly competitive natural gas transportation market. This could result in a reduction in the overall average life of Northwest’s long-term firm contracts which could adversely affect its revenue over the long term. We also believe the impact of such factors described in “Northwest’s Customers” and “Northwest’s Competition” in Part I, Item 1. Business, may also provide Northwest with growth opportunities. These factors may also result in a need for increased capital expenditures to take advantage of opportunities to bring additional supplies of natural gas into Northwest’s system to maintain or possibly increase its transportation commitments and volumes.

mix of services requested by its customers, competition and changes in regulatory requirements affecting its operations.

We believe the key factors that impact Northwest’s business are the supply of and demand for natural gas in the markets in which Northwest operates, Northwest’s customers and their requirements, and government regulation of natural gas pipelines. These key factors, discussed in more detail in “Narrative Description of Business” in Part I, Item 1. Business, play an important role in how Northwest manages its operations and implements its long-term strategies.

We believe the collective impact of these key factors may result in an increasingly competitive natural gas transportation market. This could result in a reduction in the overall average life of Northwest’s long-term firm contracts which could adversely affect its revenue over the long term. We also believe the impact of the such factors described in “Northwest’s Customers” and “Northwest’s Competition” in Part I, Item 1. Business, may also provide Northwest with growth opportunities. These factors may also result in a need for increased capital expenditures to take advantage of opportunities to bring additional supplies of natural gas into Northwest’s system to maintain or possibly increase its transportation commitments and volumes.

Northwest’s Operations

Northwest owns and operates a natural gas pipeline system that extends from the San Juan Basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Northwest’s system ~~includes~~ includes approximately 3,900 miles of mainline and lateral transmission pipeline and 41 transmission compressor stations. ~~Its~~ Northwest’s compression facilities have a combined sea level-rated capacity of approximately 473,000 horsepower. At December 31, ~~2008~~2009, Northwest had long-term firm transportation contracts, including peaking service, with aggregate capacity reservations of approximately 3.6 7 Bcf of natural gas per day. Northwest also has approximately 12 13.8 0 Bcf of working natural gas storage capacity through its one-third interest in the Jackson Prairie ~~underground~~ underground storage facility, its ownership of the Plymouth LNG storage facility and contract storage at Clay Basin.

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

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

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

revenues are primarily based upon the capacity reserved, and not upon the capacity actually used. Northwest generates a small portion of its revenues from short-term firm and interruptible ~~Recent Market~~transportation ~~Events~~services.

~~The~~ Northwest ~~recent~~is ~~instability~~not generally in ~~financial~~the ~~markets~~business ~~has~~of ~~created~~buying ~~global concerns~~and ~~about~~selling natural gas, but changes in the ~~liquidity~~price of ~~financial~~natural ~~institutions~~gas can affect the overall supply and isdemand for natural gas, which in turn ~~having~~can ~~overarching~~affect ~~impacts~~its results of operations. Northwest depends on the ~~economy~~availability asof acompetitively ~~whole.~~priced natural Ingas ~~this volatile~~supplies ~~economic~~that ~~environment,~~its ~~many~~customers ~~financial~~desire ~~markets, institutions~~to ~~and~~ship ~~other~~through ~~businesses~~its ~~remain~~system. ~~under~~Northwest ~~considerable~~delivers ~~stress.~~natural ~~These~~gas ~~events~~for ~~are~~a ~~impacting~~broad ~~our~~mix ~~business.~~of ~~However~~customers including LDCs, wemunicipal utilities, direct industrial ~~note~~users, ~~the~~electric ~~following:~~power generators and natural gas marketers and producers.

• Storage Services. Northwest’s ~~has~~natural nogas ~~significant~~storage ~~debt~~services ~~maturities~~allow ~~until~~it ~~2016.~~to •offer Ascustomers ofa ~~December~~high degree ~~31,~~of ~~2008,~~flexibility ~~Northwest~~in ~~had~~meeting ~~approximately~~their ~~$66.0~~delivery ~~million~~requirements ofand ~~available~~enable ~~cash~~Northwest ~~from~~to ~~return~~balance ofdaily receipts ~~advances~~and ~~made~~deliveries. toFor ~~affiliates~~example, ~~and~~LDCs ~~available~~use ~~capacity~~traditional ~~under~~storage ~~its~~services ~~Credit~~by ~~Facility.~~injecting ~~(See~~natural gas ~~further~~into ~~discussion~~storage in ~~Management’s~~the ~~Discussion~~summer ~~and~~months ~~Analysis~~when ofnatural ~~Financial~~gas ~~Condition~~prices are typically lower and ~~Results~~then withdrawing ofthe ~~Operations~~natural —gas ~~Capital~~during ~~Resources~~the ~~and~~winter ~~Liquidity~~months ofin ~~Northwest.)~~order •to Areduce ~~significant~~their ~~portion~~exposure to the potential volatility of winter natural gas prices. Northwest’s ~~transportation~~offers ~~and~~firm storage ~~services~~service, ~~are~~in ~~provided~~which the ~~pursuant~~customer toreserves ~~long-term~~and ~~firm~~pays ~~contracts~~for ~~that~~a ~~obligate~~specific ~~its~~amount ~~customers~~of tostorage ~~pay~~capacity, ~~them~~including ~~monthly~~injection ~~capacity~~and withdrawal ~~reservation~~rights, ~~fees~~and ~~regardless~~interruptible ofstorage ~~the~~service, ~~amount~~where ofthe ~~pipeline~~customer orreceives ~~storage~~and pays for capacity ~~actually~~only ~~utilized~~when byit ais ~~customer~~available and used.

Outlook

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

	•		Northwest has no significant debt maturities until 2016.

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

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

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

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

Critical Accounting Policies, Estimates, Judgments and Sensitivities

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

Regulatory Accounting

~~See~~ Northwest ~~Item 8~~is regulated by FERC. The ~~Financial~~Accounting ~~Statements~~Standards Codification Topic 980, Regulated Operations (“Topic 980”) provides that rate-regulated public utilities account for and ~~Supplementary~~report regulatory assets and liabilities consistent with the economic effect of ~~Data —~~the ~~Northwest~~way ~~Pipeline~~in GPwhich ~~Notes~~regulators establish rates if the rates established are designed to ~~Consolidated~~recover the costs of providing ~~Financial~~the ~~Statements:~~regulated ~~Note 1~~service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting ~~Summary~~for businesses that are regulated and apply the provisions of ~~Significant~~Topic 980 can differ from the accounting ~~Accounting~~requirements ~~Policies —~~for ~~Property~~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 ~~Plant~~of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations and ~~Equipment~~other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, Northwest’s management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Northwest’s management uses judgment in determining the probability that regulatory assets will be recoverable from, or regulatory liabilities will be refunded to, customers. A summary of regulatory assets and liabilities is included in Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 10 11. Regulatory Assets and Liabilities.

Contingencies

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

Environmental Liabilities

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

and the current facts and circumstances related to these environmental matters. Northwest’s accrued environmental liabilities could change substantially in the future due to factors such as the nature and extent of any contamination, changes in remedial requirements, technological changes, discovery of new information, and the involvement of and direction taken by the EPA, FERC and other governmental authorities on these matters. Northwest continues to conduct environmental assessments and is implementing a variety of remedial measures that may result in increases or decreases in the total estimated environmental costs.

Pension and Postretirement Obligations

Northwest’s consolidated affiliate participates in the Williams’ sponsored employee benefit plans along with Williams and its subsidiaries that include pension and other postretirement benefits. Net periodic benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed.

Northwest’s Results of Operations

In the following discussion of the results of Northwest, all amounts represent 100 percent of the operations of Northwest, in which we hold a 35 percent general partnership interest. As such, we recognized equity earnings from investments of $5453.48 million for ~~2008~~2009 compared with $~~153~~54.9 4 million ~~(Predecessor)~~ for ~~2007~~2008.

46 45

Analysis of Financial Results

This analysis discusses financial results of Northwest’s operations for the years ~~2008~~2009, ~~2007~~ 2008 and ~~2006~~2007. Variances due to changes in natural gas prices and transportation volumes have ~~little~~ little impact on revenues, because under Northwest’s rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in Northwest’s transportation rates.

Years Ended December 31,

2008

2007

2006

2009

2008

2007

(Thousands of dollars)

Income Statement Data:

Operating revenues

434,~~854~~379

~~421~~434,~~851~~854

~~324~~421,~~250~~851

Operating expenses:

General and administrative

6064,~~403~~657

6560,~~772~~403

5665,~~463~~772

Operation and maintenance

7271,~~831~~085

6672,~~847~~831

6566,~~763~~847

Depreciation

86,~~184~~373

8486,~~731~~184

7984,~~488~~731

Regulatory credits

(2,~~617~~403

)

(32,~~663~~617

)

(43,~~469~~663

)

Taxes, other than income taxes

1614,~~875~~158

1316,~~997~~875

1513,~~018~~997

Regulatory liability reversal

—

~~(16,562~~—

)

—(16,562

)

Total operating expenses

233,~~676~~870

~~211~~233,~~122~~676

~~212~~211,~~263~~122

Operating income

~~201~~200,~~178~~509

~~210~~201,~~729~~178

~~111~~210,~~987~~729

Other income (net)

1,623

25,437

16,597

Other income - net

1,951

1,623

25,437

Interest charges:

Interest on long-term debt

4244,~~290~~439

4642,~~828~~290

4346,~~649~~828

Other interest

5,~~571~~414

5,~~585~~571

35,~~824~~585

Allowance for borrowed funds used during construction

(~~431~~1,044

)

(~~1,306~~431

)

(41,~~557~~306

)

Total interest charges

4748,~~430~~809

5147,~~107~~430

4251,~~916~~107

Income before income taxes

~~155~~153,~~371~~651

~~185~~155,~~059~~371

85185,~~668~~059

Provision for (benefit) income taxes

—

(254,667

)

31,206

Benefit for income taxes

—

(254,667

)

Net income

~~155~~153,~~371~~651

~~439~~155,~~726~~371

54439,~~462~~726

Years Ended December 31, 2008 ~~vs.~~ ~~2007~~and 2009

Operating revenues ~~increased~~decreased $~~13.~~0.5 million, or 3 less than one percent, for the year ended December 31, ~~2008~~2009 as compared to the year ended December 31, ~~2007~~2008. This ~~increase~~ decrease is primarily attributed to a $34.94 million ~~increase~~lower ~~from~~revenues due to the termination of the Parachute Lateral lease agreement on August 1, ~~placed~~2009, ~~into~~and ~~service~~was inmostly ~~May~~offset ~~2007,~~by ~~and~~higher a transportation revenues of $51.2 7 million ~~increase~~resulting primarily from ~~short-term~~an increase in firm transportation ~~services,~~ ~~with~~under ~~the~~long-term ~~balance~~contracts and higher storage revenues of ~~the~~$2.6 million ~~increase~~resulting primarily ~~attributed~~from incremental reservation charges toassociated ~~certain~~with ~~small~~the ~~customers~~Jackson ~~converting~~Prairie todeliverability ~~large~~expansion ~~customer~~that ~~status~~was placed in service on ~~resulting~~November 1, 2008. The decrease in ~~higher~~the ~~reservation~~Parachute ~~charges~~Lateral ~~and~~lease torevenues ~~higher~~is substantially offset by ~~transportation~~a ~~volumes~~decrease in lease expense described below.

Northwest’s transportation service accounted for 96 percent of its operating revenues for each of the years ended December 31, ~~2008~~2009 and ~~2007~~2008. ~~Natural~~Additionally, gas storage service accounted for 4 percent and 3 percent of operating revenues ~~in each~~for of the years ended December 31, ~~2008~~2009 and ~~2007~~2008, respectively.

Operating expenses increased $220.62 million, or ~~11 percent,~~ ~~from~~less ~~2007~~than toone ~~2008~~percent. This increase is due primarily to ~~the~~i) ~~June~~higher ~~2007 reversal of Northwest’s~~ pension ~~regulatory~~ ~~liability~~expense of $164.60 million, ~~and~~ii) ~~the~~higher ~~new Parachute~~allocated ~~Lateral~~overhead ~~lease~~from Williams of $103.10 million ~~which~~attributed ~~began January 1,~~primarily ~~2008.~~to ~~Also~~higher ~~contributing~~pension ~~were~~expense, ~~higher~~and ~~use~~iii) ~~taxes~~higher labor of $1.06 million attributed primarily to ~~the~~pipeline ~~2007 reversal of $0~~maintenance.~~8 million~~ ofThese ~~accrued~~increases ~~use~~were ~~taxes~~mostly ~~resulting~~offset ~~from the~~by ~~settlement~~i) oflower ~~prior year audits~~taxes, ~~and~~other ~~higher~~than ~~depreciation~~income taxes, of $12.57 million primarily attributed to lower than anticipated property tax settlements and adlower ~~valorem~~sales ~~taxes~~and ofuse ~~$1.6 million~~ taxes resulting from ~~property~~lower ~~additions.~~fuel ~~These~~usage and ~~increases~~a ~~were partially~~refund ~~offset~~of bytaxes from prior years, ii) lower ~~expenses~~lease expense of $51.03 million ~~for~~attributed to the ~~contracted~~restructuring ~~services~~of ~~attributed~~the ~~primarily~~Salt toLake ~~pipeline maintenance,~~City ~~lower~~headquarters ~~overhead~~building ~~allocated~~lease, byand ~~Williams~~iii) of $24.03 million ~~and~~ lower ~~bonus~~expense from ~~accruals~~the termination of the Parachute Lateral lease agreement.

Other income — net increased $0.3 million, or 20 percent, due primarily to higher allowance for equity funds used during construction of $1.2 million attributed to higher capital 46expenditures in 2009, partially offset by lower interest income from affiliates of $0.7 million attributed to lower interest rates on advances to affiliates.

Interest charges increased $1.4 million, or 3 percent, due primarily to the May 2008 refinancing of the $250.0 million revolver debt with the issuance of $250.0 million of 6.05 percent senior unsecured notes.

~~and~~Years ~~deferred~~Ended ~~compensation of $1.0~~December ~~million~~31, ~~primarily attributed~~2007 ~~to lower bonus~~ and ~~deferred compensation levels in~~ 2008.

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

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

Operating expenses increased $22.6 million, or 11 percent, from 2007 to 2008. This increase is due primarily to the June 2007 reversal of Northwest’s pension regulatory liability of $16.6 million as described in Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 1. Summary of Significant Accounting Policies, and the new Parachute Lateral lease of $10.1 million, which began January 1, 2008. Also contributing were higher use taxes of $1.0 million attributed primarily to the 2007 reversal of $0.8 million of accrued use taxes resulting from the settlement of prior year audits, and higher depreciation of $1.5 million and ad valorem taxes of $1.6 million resulting from property additions. These increases were partially offset by lower expenses of $5.0 million for contracted services attributed primarily to pipeline maintenance, lower overhead allocated by Williams of $2.0 million and lower bonus accruals and deferred compensation of $1.0 million primarily attributed to lower bonus and deferred compensation levels in 2008.

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

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

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

The benefit for income taxes decreased $254.7 million to $0 from 2007 to 2008 due to Northwest’s conversion to a non-taxable general partnership on October 1, 2007. Prior to the conversion, Northwest recognized $57.1 million of tax expense resulting in an effective tax rate of 37.8 percent. At the date of conversion, Northwest recognized income tax benefit of $311.8 million reflecting the removal of its net deferred tax liabilities.

2007 vs. 2006

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

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

Operating expenses decreased $1.1 million, or 1 percent, from 2006 to 2007. This decrease was due primarily to the June 2007 reversal of Northwest’s pension regulatory liability of $16.6 million and a reduction of its accrued ad valorem taxes of $1.0 million to reflect lower 2007 tax assessments on its property. The pension regulatory liability was reversed based upon management’s assessment that the refundability of this obligation in future rates is no longer probable. These decreases were partially offset by a $6.3 million increase in lease expense due to a change in accounting for Northwest’s headquarters building lease in the fourth quarter of 2006, a $3.7 million increase in depreciation related to new property additions, a $1.5 million write-off of a regulatory asset associated with the Parachute Lateral, a $4.2 million increase in labor costs due to annual salary increases and an increase in the number of employees, and a $1.3 million increase in group insurance expense due primarily to rising medical costs.

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

Other income increased $8.8 million, or 53 percent, from 2006 to 2007, primarily due to the recognition of $6.0 million of previously deferred income and the receipt of $12.2 million of additional contract termination income and $2.3 million of additional interest related to the termination of the Grays Harbor transportation agreement. These increases were partially offset by a $5.6 million decrease in the EAFUDC resulting from lower capital expenditures in 2007 and the $1.3 million write-off of a regulatory asset associated with the Parachute

Lateral, a $3.1 million decrease in other interest income resulting from a reduced amount of short-term investments, and a $0.9 million decrease in interest income from affiliates resulting from note repayments from Williams.

Interest charges increased $8.2 million, or 19 percent, from 2006 to 2007, due to a $3.3 million decrease in the allowance for borrowed funds used during construction related to the lower capital expenditures in 2007, the issuance of $175.0 million of 7 percent senior unsecured notes, due 2016, in June of 2006, and the issuance of $185.0 million of 5.95 percent senior unsecured notes, due 2017, in April of 2007, partially offset by the early retirement of $175.0 million of 8.125 percent senior unsecured notes, due 2010, in April of 2007. A $1.8 million increase in other interest resulting from higher amortization of loss on reacquired debt related to the early debt retirement and the refinancing of $250.0 million of 6.625 percent senior unsecured notes with $250.0 million of revolver debt in December of 2007 also contributed to this increase.

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

Capital Resources and Liquidity of Northwest

Northwest’s ability to finance operations, (including funding capital expenditures and acquisitions), to meet its ~~indebtedness~~ debt obligations, and to refinance ~~its~~ indebtedness, ordepends ~~to meet collateral requirements, will depend~~ on its ability to generate future cash inflows ~~the future~~ and to borrow funds. Northwest’s ability to generate cash is subject to a number of factors, some of which are beyond its control, including the impact of regulators’ decisions on ~~its~~the ~~ability~~rates Northwest is able to establish for its transportation and storage ~~rates~~services.

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

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

Northwest funds its capital requirements with cash from operating activities, with third-party debt or with contributions from Northwest’s partners with the exception of the CHC Project, which will be funded by capital contributions from Williams.

Sources (Uses) of Cash

	Years Ended December 31,
	2008			2007			2006
	(Thousands of dollars)
Net cash provided (used) by:
Operating activities	$	239,014		$	205,357		$	159,807
Financing activities		(126,848	)		(142,523	)		266,919
Investing activities		(112,318	)		(63,826	)		(484,946	)
Decrease in cash and cash equivalents	$	(152	)	$	(992	)	$	(58,220	)

Northwest funds its capital requirements with cash from operating activities, third party debt and contributions from its partners with the exception of the CHC Project, which was funded by capital contributions from Williams. Through December 31, 2009, Northwest received $49.2 million in capital contributions from Williams to fund the CHC Project.

Sources (Uses) of Cash


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

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

Operating Activities

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

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

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

Financing Activities

2009

	•		Northwest paid distributions of $135.0 million to its partners.

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

2008

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

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

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

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

2007

• Northwest issued $185 million aggregate principal amount of 5.95 percent senior unsecured notes due 2017. • Northwest borrowed $250 million under the Williams’ revolving credit agreement. • Northwest retired $175 million of 8.125 percent senior unsecured notes due 2010. ~~• Northwest retired $250 million of 6.625 percent senior unsecured notes due 2007. • Northwest paid distributions of $109.8 million to Williams.~~

49 ~~2006~~

	•	Northwest issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016.
	•	Northwest received a capital contribution of $65 million from Williams.

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

	•		Northwest paid distributions of $109.8 million to Williams.

Investing Activities

2009

•

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

2008

	•	~~Capital expenditures totaled $78.6 million primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility.~~	Capital expenditures totaled $88.5 million, primarily related to normal maintenance and compliance and the expansion of the Jackson Prairie storage facility.
	•	~~Northwest advanced $26.9 million to Williams.~~	Northwest advanced $26.9 million to Williams.

2007

• Capital expenditures totaled $~~157~~156.28 million, primarily related to normal maintenance and compliance. • Northwest received $79.8 million of proceeds from the sale of the Parachute Lateral to an affiliate. • Northwest received $10.9 million repayment of advances made to Williams.

Method of Financing ~~2006~~

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

Working Capital

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

primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

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

During ~~2008~~2009, Northwest made distributions of available cash of $~~419~~135.30 million to its partners, representing cash in excess of working capital requirements and reserves established by its management committee as necessary for the conduct of its business.

Short-Term Liquidity

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

Northwest invests cash through participation in Williams’ cash management program. At December 31, ~~2008~~2009 and ~~2007~~2008, the advances due to Northwest by Williams totaled approximately $66.08 million and $3966.10 million, respectively. The advances are represented by one or more demand obligations. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest ~~rates~~rate on these demand notes was based upon the ~~overnight~~ overnight investment rate paid on Williams’ excess cash, which was approximately, ~~zero~~0.05 percent and zero percent at December 31, ~~2008.~~ ~~Williams~~2009 ~~has indicated that it currently believes that it will continue to have the financial resources~~ and ~~liquidity~~2008, ~~to repay these advances~~respectively.

Williams has an unsecured $1.5 billion revolving credit agreement that terminates in May 2012. Northwest has access to $400 million under the agreement to the extent not otherwise utilized by Williams. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent per annum) based on the unused portion of the agreement. The applicable margin is based on the specific borrower’s senior unsecured long-term debt ratings. Letters of credit totaling approximately $71.0 million, none of which are associated with Northwest, have been issued by the participating institutions. Northwest had no revolving credit loans outstanding as of December 31, 2008. In December 2007, Northwest borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250 million was repaid with proceeds from the issuance of $250 million of 6.05 percent senior unsecured notes due 2018. Northwest did not borrow under the agreement in 2008.

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

The credit agreement contains a number of restrictions on the business of the borrowers, including Northwest. These restrictions include restrictions on the borrowers’ and their subsidiaries’ ability to: (i) grant liens securing indebtedness; (ii) merge, consolidate, or sell, lease or otherwise transfer assets; (iii) incur indebtedness; and (iv) engage in transactions with related parties. Northwest and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in the case of Northwest, and 0.65 to 1, in the case of Williams. The credit agreement also contains affirmative covenants and events of default. If any borrower breaches financial or certain other covenants or if an event of default occurs, the lenders may cause the acceleration of the borrower’s

~~indebtedness~~of ~~and~~Northwest’s ~~may~~outstanding ~~terminate~~advances ~~lending~~as toof ~~all~~January 31, ~~borrowers under the credit agreement~~2010. ~~Additionally~~Accordingly, ~~if:~~the ~~(a) a borrower were~~balance tooutstanding ~~generally~~at ~~not~~December 31, ~~pay~~2009 ~~its~~is ~~debts~~reflected as ~~such debts come due or admit in writing its inability to pay its debts generally; (b)~~ a ~~borrower~~ ~~were~~reduction toof ~~make~~Northwest’s aOwners’ ~~general~~Equity ~~assignment~~as ~~for~~ the ~~benefit of~~ ~~its~~advances ~~creditors;~~will ornot ~~(c) proceedings~~be ~~relating~~available to ~~the bankruptcy~~Northwest oras ~~receivership~~working ofcapital. ~~any~~As ~~borrower~~a ~~were~~result toof ~~remain unstayed~~the ~~or undismissed for 60 days~~restructuring, ~~then all lending under~~ ~~the~~Northwest ~~credit~~will ~~agreement~~become ~~would~~a ~~terminate~~participant ~~and~~in ~~all indebtedness outstanding under~~ the ~~credit~~Williams ~~agreement~~Partners ~~would~~cash bemanagement ~~accelerated~~program.

Credit Agreement

Williams has an unsecured, $1.5 billion credit facility with a maturity date of May 1, 2012 (“Credit Facility”). Prior to the Williams’ restructuring, Northwest had access to $400 million under the Credit Facility to the extent not otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, Northwest expects its ability to borrow under the Credit Facility is reduced by approximately $18.7 million. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent) based on the unused portion of the Credit Facility. The margins and commitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. As of December 31, 2009, there were no letters of credit issued by the participating institutions and no revolving credit loans outstanding. In December 2007, Northwest borrowed $250.0 million under this Credit Facility to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250 million was repaid with proceeds from the issuance of $250 million of 6.05 percent senior unsecured notes due 2018. Northwest did not borrow under the Credit Facility in 2008 or 2009. See Item 8. Financial Statements and Supplementary Data – Northwest Pipeline GP Notes to Consolidated Financial Statements.

The Credit Facility contains a number of restrictions on the business of the borrowers, including Northwest. These restrictions include restrictions on the borrowers’ and their subsidiaries’ ability to: (i) grant liens securing indebtedness; (ii) merge, consolidate, or sell, lease or otherwise transfer assets; (iii) incur indebtedness; and (iv) engage in transactions with related parties. Northwest and Williams are also required to maintain a ratio of debt to capitalization of not more than 0.55 to 1, in Northwest’s case, and 0.65 to 1, in the case of Williams. The Credit Facility also contains affirmative covenants and events of default. If any borrower breaches financial or certain other covenants or if an event of default occurs, the lenders may cause the acceleration of the borrower’s indebtedness and may terminate lending to all borrowers under the Credit Facility. Additionally, if: (a) a borrower were to generally not pay its debts as such debts come due or admit in writing its inability to pay its debts generally; (b) a borrower were to make a general assignment for the benefit of its creditors; or (c) proceedings relating to the bankruptcy or receivership of any borrower were to remain unstayed or undismissed for 60 days, then all lending under the credit agreement would terminate and all indebtedness outstanding under the Credit Facility would be accelerated.

As part of the restructuring, Northwest was removed as a borrower under the Credit Facility, and on February 17, 2010, Northwest entered into a new $1.75 billion three-year senior unsecured revolving credit facility (the “New Credit Facility”) with Williams Partners 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 Williams Partners, and may be increased by up to an additional $250 million. Northwest may borrow up to $400 million under the New Credit Facility to the extent not otherwise utilized by Williams Partners and Transco. At closing, Williams Partners borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement.

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

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

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

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

Long-Term Financing

Northwest’s ~~shelf registration statement on file with the SEC expired on December 1, 2008. Northwest~~ may raise capital through private debt offerings, as well as offerings ~~registered~~ registered pursuant to offering-specific registration statements. Interest rates, market conditions, and ~~industry~~ industry conditions will affect future amounts raised, if any, in the capital markets. ~~Historically,~~ Northwest anticipates ~~has~~that ~~been~~it will be able to access public and private debt markets on terms commensurate with its credit ratings to finance its capital requirements, when needed. ~~However, as a result of credit market conditions, this source of funding was considered economically unfavorable at December 31, 2008.~~

Capital Requirements

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

Northwest categorizes its capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of Northwest’s assets, ~~including~~ 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~~ Expansion capital expenditures improve the service capability of the existing assets, ~~extend useful lives,~~ increase transmission or storage capacities from existing levels, ~~reduce costs~~ or enhance revenues. Northwest anticipates ~~2009~~2010 capital expenditures will be between $~~125~~120 million and $~~160~~140 million of which includes $7560 million to $90 80 million for maintenance capital and $~~100~~95 million to $~~135~~115 million considered nondiscretionary due to legal, regulatory and/or contractual requirements. The maintenance capital portion of Northwest’s 2009 ~~2008~~ capital expenditures was $6184.30 million. In ~~2009~~2010, Northwest expects to fund its ~~capital~~ capital expenditures with cash from operations ~~and repayment of advances to affiliate~~, with the exception of the final costs for the CHC Project which will be funded by capital contributions from Williams.

Northwest’s expenditures for property, plant and equipment additions were $78156.6 million, $~~157~~78.26 million and $~~473~~157.62 million for ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, respectively. The ~~decrease~~ in$78.0 million ~~expenditures~~ increase from ~~2006~~2008 to ~~2007~~2009 ~~was~~is primarily ~~due~~attributed to ~~the~~ ~~completion~~expenditures ofrelated ~~the~~to ~~Capacity~~pipeline ~~Replacement Project in late 2006. Northwest filed a rate case on June 30~~integrity, ~~2006 to recover~~ the ~~cost~~ ~~of property~~CHC Project, ~~plant~~ and ~~equipment~~the ~~placed~~Sundance ~~into~~Trail ~~service~~Expansion ~~as of December 31, 2006~~Project. ~~Its new rates became effective~~ ~~January 1, 2007.~~

Credit Ratings

During ~~2008~~2009, the credit ratings on Northwest’s senior unsecured long-term debt remained unchanged with investment grade ratings from all three agencies, as shown below:


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

At December 31, ~~2008,~~2009 and through the date of this report, the evaluation of Northwest’s credit rating is “stable ~~outlook~~” from ~~Standard and Poor’s. On November 6, 2008,~~ Moody’s Investors Service ~~(“Moody’s”)~~ and Fitch Ratings ~~(“Fitch”) changed the ratings outlook for Williams and each of Williams’ rated subsidiaries, including Northwest, to “negative” and “evolving” respectively~~. On ~~February~~January 2312, ~~2009~~2010, Standard ~~Moody~~and Poor’s revised Northwest’s ratings outlook to ~~“stable”~~ ~~from~~ “~~negative~~positive” ~~and on February 24, 2009, Fitch revised Northwest’s rating outlook to “stable”~~ from “~~evolving”~~stable.”

With respect to Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. A “Ba” rating indicates an 51obligation that is judged to have speculative elements and is subject to substantial credit risk. The “1”, “2” and “3” modifiers show the relative standing within a major category. A “1” indicates that an

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

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

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

Contractual Obligations

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

	2009		2010-2011		2012-2013		Thereafter		Total
Long-term debt, including current portion:
Principal	$	—	$	—	$	—	$	695.0	$	695.0
Interest		44.4		88.9		88.9		209.9		432.1
Operating leases		13.9		7.5		7.5		18.8		47.7
Purchase obligations:
Natural gas purchase, storage, transportation and construction		28.4		4.9		2.0		—		35.3
Other		1.6		0.3		0.2		—		2.1
Other long-term liabilities, including current portion(1)(2)(3)		1.5		3.0		3.0		1.7		9.2
Total	$	89.8	$	104.6	$	101.6	$	925.4	$	1,221.4

(1)		Does not include estimated contributions to the pension and other postretirement benefit plans. Northwest made contributions to the pension and other postretirement benefit plans of $7.8 million in 2008, $3.2 million in 2007, and $5.7 million in 2006. (See Item 8. Financial Statements — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 5. Employee Benefit Plans.) The 2008 economic downturn resulted in a significant decrease in the funded status of the Williams sponsored tax-qualified pension plans. As a result, Northwest anticipates that future contributions to these pension plans may vary significantly from historical contributions if investment returns do not return to expected levels. Future contributions may also be impacted if actual results differ significantly from estimated results or assumptions such as interest rates, retirement rates, mortality and other significant assumptions or by changes to current legislation and regulations.
(2)		Does not include estimated settlement of asset retirement obligations. (See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 9. Asset Retirement Obligations.)
(3)		Does not include non-current regulatory liabilities comprised of negative salvage and other postretirement benefits. (See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 10. Regulatory Assets and Liabilities.)

obligation ranks in the higher end of the broad rating category, “2” indicates a mid-range ranking, and “3” indicates a ranking at the lower end of the category.

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

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

Other

Contractual Obligations

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


	2010		2011-2012		2013-2014		Thereafter		Total
Long-term debt, including current portion:
Principal	$	—	$	—	$	—	$	695.0	$	695.0
Interest		44.4		88.9		88.9		165.5		387.7
Operating leases		2.3		4.6		4.5		11.8		23.2
Purchase obligations:
Natural gas purchase, storage, transportation and construction		27.1		4.6		4.1		—		35.8
Other		0.1		0.3		0.3		6.7		7.4
Other long-term liabilities, including current portion(1)(2)		1.5		3.0		3.3		—		7.8

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


(1)		Does not include estimated settlement of asset retirement obligations. (See Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 10. Asset Retirement Obligations.)

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

Off-Balance Sheet Arrangements

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

Impact of Inflation

Northwest has generally experienced increased costs in recent years due to the effect of inflation on the cost of labor, benefits, materials and supplies, and property, plant and equipment. A portion of the increased labor and materials and supplies costs can directly affect income through increased operating and maintenance costs. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of productive facilities. The majority of the costs related to Northwest’s property, plant and equipment and materials and supplies is subject to rate-making treatment, and under current FERC practices, recovery is limited to historical costs. While amounts in excess of historical cost are not recoverable under current FERC practices, Northwest believes it may be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. However, cost-based regulation along with competition and other market factors limit Northwest’s ability to price services or products to ensure recovery of inflation’s effect on costs.

Environmental Matters

As discussed in Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements,: Note 4. Contingent Liabilities and Commitments, Northwest is subject to extensive federal, state and local environmental laws and regulations which affect its operations related to the construction and operation of its pipeline facilities. ~~Northwest~~ Northwest considers environmental assessment and remediation costs and costs associated with compliance with environmental standards to be recoverable through rates, as they are prudent costs ~~incurred~~ incurred in the ordinary course of business. To date, Northwest has been permitted recovery of environmental costs incurred, and it is Northwest’s intent to continue seeking recovery of such costs, as incurred, through rate filings.

Safety Matters

Please see Item 8. Financial Statements and Supplemental Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 3 4. Contingent Liabilities and Commitments for information about pipeline integrity regulations.

Legal Matters

Northwest is party to various legal actions arising in the normal course of business. Northwest’s management believes that the disposition of outstanding legal actions will not have a a material adverse impact on its future liquidity or financial condition. Please see Item 8. Financial Statements and Supplementary Data — Northwest Pipeline GP Notes to Consolidated Financial Statements: Note 4. Contingent Liabilities and Commitments.

Regulatory Proceedings

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

Summary

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

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

Our principal ~~sources~~source of liquidity ~~include~~is cash distributed to us by Northwest ~~and our working capital credit agreement with Williams as the lender~~. We expect to fund our operating expenses, debt service and cash distributions primarily with distributions from Northwest. As of December 31, ~~2008~~2009, we had cash and cash equivalents of $7.8.1 million.

We Prior ~~may~~to the completion of the restructuring on February 17, 2010, we were able to invest cash through participation in Williams’ cash management program. Any advances ~~will~~were be represented by one or more demand obligations. The interest rate on the demand notes ~~will~~ bewas based upon the overnight investment rate paid on Williams’ excess cash, which was ~~zero~~ 0.05 percent at December 31, ~~2008~~2009. Subsequent to the restructuring, we may invest cash through the participation in the Williams Partners cash management program.

Northwest Distributions

In January 2008, Northwest distributed $8.8 million to Williams representing available cash prior to our acquisition of our interest in Northwest. During 2008, Northwest declared and ~~paid~~ paid equity distributions of $109.6 million to its partners. Of this amount, $7.8 million represents the portion allocated to its partners prior to our acquisition. ~~In January~~During 2009, Northwest ~~declared and paid equity distributions~~distributed of $32135.0 million of available cash to its partners.

Capital Contributions from Williams

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

Credit Facility

At the closing of the IPO on January 24, 2008, we entered into a $20 million working capital credit agreement with Williams as the lender. The facility iswas available exclusively to ~~fund~~ fund working capital borrowings. The initial maturity date of the facility was January 23, 2009. We exercised our automatic right to extend the facility for an additional 365-day term in January 2009. The new maturity date iswas January 23, 2010. ~~The~~ ~~interest~~This ~~rate~~facility onis ~~all~~terminated ~~borrowings~~since ~~will~~we bedid ~~the one-month LIBOR determined the date of the borrowing. The borrowings may be repaid prior to the end of the one-month LIBOR rate period. If a borrowing is~~ not ~~repaid~~exercise ~~within~~our ~~one~~automatic ~~month,~~right ~~the interest rate for such borrowing will be adjusted~~ to ~~the one-month LIBOR rate~~extend ~~30 days after~~ the ~~most~~facility ~~recent~~in ~~borrowing. We pay a commitment fee to Williams on the unused portion of the credit agreement of 0.25~~January ~~percent annually~~2010. We will be required to reduce all borrowings under our working capital credit agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the facility. At December 31, ~~2008~~2009, we have no outstanding borrowings under the working capital credit facility.

Cash Distributions to Unitholders

We have paid quarterly distributions to unitholders and our general partner after every quarter since our IPO on January 24, 2008. Our last quarterly distribution of $11.05 million was paid on February 1312, ~~2009~~2010 to unitholders of record at the close of business on February 65, ~~2009~~2010.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk ~~Conclusion~~

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

Item 7A. Qualitative and Quantitative Disclosures About Market Risk

Interest Rate Risk

Our interest rate risk indirectly includes Northwest’s long-term debt. All of Northwest’s interest on long-term debt is fixed in nature, except the interest on Northwest’s ~~revolver~~ ~~borrowing~~revolver borrowings, as shown on the following table (in thousands of dollars):

	December 31, 2008
	December 31, 2009
Fixed rates on long-term debt:
5.95% senior unsecured notes due 2017	$	185,000
6.05% senior unsecured notes due 2018		250,000
7.00% senior unsecured notes due 2016		175,000
7.125% senior unsecured notes due 2025		85,000
		695,000
Unamortized debt discount		1,~~760~~563
Total long-term debt	$	693,~~240~~437

Northwest’s total long-term debt at December 31, ~~2008~~ 2009 had a carrying value of $693.24 million and a fair market value of $~~572~~753.02 million. As of December 31, ~~2008~~2009 the weighted-average interest rate on Northwest’s long-term debt was 6.4 percent. Northwest expects to have sensitivity to to interest rate changes with respect to future debt facilities and its ability to prepay existing facilities.

Credit Risk

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

Market Risk

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

Market Risk

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

	Page
Williams Pipeline Partners L.P.
Management’s Annual Report on Internal Control Over Financial Reporting		57
Management’s Report on Internal Control Over Financial Reporting		58
Report of Independent Registered Public Accounting Firm		58
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting		59
Consolidated Statements of Income for the years ended December 31, 2008, 2007, and 2006		59
Report of Independent Registered Public Accounting Firm		60
Consolidated Balance Sheets at December 31, 2008 and 2007		60
Consolidated Statements of Income for the years ended December 31, 2009, 2008, and 2007		61
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		61
Consolidated Balance Sheets at December 31, 2009 and 2008		62
Consolidated Statement of Partners’ Capital for the years ended December 31, 2008, 2007 and 2006		62
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007		63
Notes to Consolidated Financial Statements		63
Consolidated Statement of Partners’ Capital for the years ended December 31, 2009, 2008 and 2007		64
Notes to Consolidated Financial Statements		65
Northwest Pipeline GP
Management’s Annual Report on Internal Control Over Financial Reporting		69
Management’s Report on Internal Control Over Financial Reporting		71
Report of Independent Registered Public Accounting Firm		7072
Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006		71
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007		73
Consolidated Balance Sheets at December 31, 2008 and 2007		72
Consolidated Balance Sheets at December 31, 2009 and 2008		74
Consolidated Statements of Owners’ Equity for the years ended December 31, 2008, 2007 and 2006		73
Consolidated Statements of Owners’ Equity for the years ended December 31, 2009, 2008 and 2007		75
Consolidated Statements of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006		74
Consolidated Statements of Comprehensive Income for the years ended December 31, 2009, 2008 and 2007		76
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006		75
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007		77
Notes to Consolidated Financial Statements		7678

57 56

MANAGEMENT’S ~~ANNUAL~~ REPORT ON INTERNAL CONTROL OVER ~~FINANCIAL~~ 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~~ 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~~ expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

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

Under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, ~~2008~~2009, based on the criteria set forth by by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. ~~Based~~Previously, on our ~~assessment~~management wehad ~~believe~~ concluded that, asour ofinternal control over financial reporting was effective for the period ended December 31, 2008. In the first quarter of 2010, ~~our~~we ~~internal~~identified ~~control~~a ~~over~~material weakness related to the manner in which we presented and ~~financial~~recognized ~~reporting~~pension ~~was~~and ~~effective~~post retirement related activity associated with our investment in Northwest. We hold a 35% interest in Northwest, which is our primary asset/business activity.

~~This~~ A ~~annual~~material ~~report~~weakness ~~does~~is ~~not~~a ~~include~~deficiency, anor ~~attestation~~combination ~~report~~ of ~~our registered~~deficiencies, ~~public~~in ~~accounting firm regarding~~ internal control ~~over~~ over financial reporting., ~~Management’s~~such ~~report~~that ~~was~~there ~~not subject~~is toa ~~attestation~~reasonable bypossibility ~~our~~that ~~registered~~a ~~public~~material ~~accounting~~misstatement ~~firm pursuant to temporary rules~~ of the ~~Securities~~annual ~~and~~or ~~Exchange Commission~~interim ~~that~~financial ~~permit~~statements uswill tonot ~~provide~~be ~~only~~prevented ~~management’s report~~or indetected ~~this~~on ~~annual~~a ~~report~~timely basis.

As discussed further in Note 2 of the Notes to Consolidated Financial Statements, Northwest had previously recorded parent-allocated amounts related to these plans on a single-employer basis 57rather than a multi-employer accounting model. As the plan assets are not legally segregated and Northwest is not contractually required to assume these obligations upon withdrawal, Northwest has now concluded that the appropriate accounting model for its historical financial statements is a multi-employer model. The error was significant to the Statement of Comprehensive Income for the period ended December 31, 2008. The impact of the correction also increased Owner’s Equity and reduced non-current assets and liabilities. It did not have an impact on our 2008 Net Income, nor did it have any impact on our 2008 Statement of Cash Flows.

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

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

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Board of Directors of Williams Pipeline GP LLC

We have audited Williams Pipeline Partners L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Williams Pipeline Partners L.P.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment. Management has identified a material weakness related to the manner in which they presented and recognized certain pension and post retirement related activity associated with their equity investee, for which the Partnership holds a 35% interest and is their primary asset. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2009 financial statements, and this report does not affect our report dated February 23, 2010 on those financial statements.

In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Williams Pipeline Partners L.P. has not maintained effective internal control over financial reporting as of December 31, 2009, based on the COSO criteria.

/s/ Ernst & Young LLP

Houston, Texas
February 23, 2010

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of Williams Pipeline GP LLC

We have audited the accompanying consolidated balance sheets of Williams Pipeline Partners L.P. as of December 31, ~~2008~~2009 and ~~2007~~ 2008, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, ~~2008~~2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Pipeline Partners L.P. at December 31, 2009 ~~2008~~ and ~~2007~~2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2008~~2009 in conformity with U.S. generally accepted accounting principles.

~~Ernst~~ As discussed in Note 2 to the consolidated financial statements, the Partnership restated its consolidated balance sheet as of December &31, 2008 and the related consolidated statement of ~~Young~~partners’ ~~LLP~~capital for each of the two years then ended, as a result of its proportionate share of other comprehensive income from its equity investee, whereby the equity investee restated its financial statements for the correction of an error related to pension and other postretirement benefit obligations in certain benefit plans for which their parent, The Williams Companies, Inc., is the plan sponsor.

We also have audited, in accordance with the standards of the Public Company Accounting ~~Houston~~Oversight Board (United States), ~~Texas~~Williams Pipeline Partners L.P.’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2010 expressed an adverse opinion thereon.

~~February 23,~~/s/ ~~2009~~Ernst & Young LLP

Houston, Texas February 23, 2010 58

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
				~~(Predecessor)~~			(Predecessor)
	(Thousands of dollars, except per-unit amounts)
General and administrative expense	$	2,~~520~~915		$	—2,520		$	—
Earnings from Northwest Pipeline GP through January 23, 2008 (Predecessor)		~~4,002~~—			~~153~~4,~~904~~002			19153,~~062~~904
Equity earnings from investment in Northwest Pipeline GP after January 23, 2008		5053,~~378~~778			—50,378			—
Interest expense — affiliate		(4750	)		—(47	)		—
Interest income		678			—67			—
Net income	$	5150,~~880~~821		$	~~153~~51,~~904~~880		$	19153,~~062~~904
Allocation of 2008 net income used for earnings per unit calculation:
Allocation of net income used for earnings per unit calculation:
Net income	$	5150,~~880~~821		$	51,880
Net income applicable to the period through January 23, 2008		~~4,002~~—			4,002
Net income applicable to the period after January 23, 2008		4750,~~878~~821			47,878
Allocation of net income (loss) to general partner		2
Allocation of net loss to general partner		(432	)		(879	)
Allocation of net income to limited partners	$	4751,~~876~~253		$	48,757
Basic and diluted net income per limited partner unit:
Common units	$	1.4353		$	1.45
Subordinated units	$	1.4353		$	1.45
Weighted average number of units outstanding:
Common units		22,~~606~~607,~~010~~430			22,606,010
Subordinated units		10,957,900			10,957,900

See accompanying notes to consolidated financial statements.

61 59

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008			2007
	2009			2008
				(Predecessor)
				(Restated)
	(Thousands of dollars)
ASSETS
Current assets:
Cash and cash equivalents	$	78,~~760~~114		$	—7,760
Prepaid expense		~~184~~193			—184
Total current assets		78,~~944~~307			—7,944
Investment in Northwest Pipeline GP		~~414~~441,~~069~~608			~~414~~435,~~966~~103
Deferred costs		—			1,689
Total assets	$	449,915		$	443,047
Total assets	$	422,013		$	416,655
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable:
Trade	$	~~671~~419		$	—671
Affiliate		~~424~~124			~~1,689~~424
Total current liabilities		~~1,095~~543			1,~~689~~095
Contingent liabilities and commitments
Partners’ capital:
Common unitholders (22,607,430 units outstanding at December 31, 2008)		287,269			—
Common unitholders (22,607,430 units outstanding at December 31, 2009 and 2008)		296,932			292,015
Subordinated unitholders (10,957,900 units outstanding at December 31, 2008)		138,835			—
Subordinated unitholders (10,957,900 units outstanding at December 31, 2009 and 2008)		143,513			141,136
Accumulated other comprehensive loss		(~~13,863~~42	)		—(20	)
General partner		8,~~677~~969			~~414~~8,~~966~~821
Total partners’ capital		~~420~~449,~~918~~372			~~414~~441,~~966~~952
Total liabilities and partners’ capital	$	~~422~~449,~~013~~915		$	~~416~~443,~~655~~047

See accompanying notes to consolidated financial statements.

62 60

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
				~~(Predecessor)~~			(Predecessor)
	(Thousands of dollars)
OPERATING ACTIVITIES:
Net income	$	5150,~~880~~821		$	~~153~~51,~~904~~880		$	19153,~~062~~904
Adjustments to reconcile to cash provided by operations:
Equity earnings from investment in Northwest Pipeline GP		(5453,~~380~~778	)		(~~153~~54,~~904~~380	)		(19153,~~062~~904	)
Distributions related to equity earnings from investment in Northwest Pipeline GP		4147,~~454~~250			—41,454			—
Cash provided (used) by changes in assets and liabilities:
Other current assets		(~~184~~9	)		—(184	)		—
Accounts payable		~~1,095~~(552	)		—1,095			—
Other		~~114~~13			—114			—
Net cash provided by operating activities		3943,~~979~~745			—39,979			—
INVESTING ACTIVITIES:
Purchase of 15.9% general partnership interest in Northwest Pipeline GP		~~(300,900~~—	)		—(300,900	)		—
Net cash used by investing activities		~~(300,900~~—	)		—(300,900	)		—
FINANCING ACTIVITIES:
Distributions paid		(3444,~~896~~891	)		—(34,896	)		—
Proceeds from sale of common units		~~336,520~~—			—336,520			—
Offering costs		~~(3,797~~—	)		—(3,797	)		—
Redemption of common units held by general partner		~~(31,020~~—	)		—(31,020	)		—
Contribution pursuant to the omnibus agreement		1,~~874~~500			—1,874			—
Net cash provided by financing activities		~~268~~(43,~~681~~391	)		—268,681			—
Increase in cash and cash equivalents		~~7,760~~354			—7,760			—
Cash and cash equivalents at beginning of period		—7,760			—			—
Cash and cash equivalents at end of period	$	78,~~760~~114		$	—7,760		$	—
SCHEDULE OF NONCASH FINANCING ACTIVITIES:
Contribution of 19.1% in Northwest Pipeline GP	$	~~(115,020~~—	)	$	—(115,020	)	$	—
Issuance of units to Williams Pipeline GP LLC		~~115,020~~—			—115,020			—

See accompanying notes to consolidated financial statements.

63 61

WILLIAMS PIPELINE PARTNERS L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

													Accumulated
	Pre-IPO												Other			Total
	Owner’s			Limited Partner						General			Comprehensive			Partners’
	Equity			Common			Subordinated			Partner			Income			Capital
	(Thousands of dollars)
	(Unaudited)
Balance — January 1, 2006 (Predecessor)	$	264,721		$	—		$	—		$	—		$	—		$	264,721
Balance — January 1, 2007 (Predecessor) (Restated)	$	306,660		$	—		$	—		$	—		$	—		$	306,660
Net income		19,062			—			—			—			—			19,062
Capital contribution from parent		22,750			—			—			—			—			22,750
Other comprehensive income:
Gain on cash flow hedges, net of reclassification adjustments		127			—			—			—			—			127
Adjustment to initially apply SFAS No. 158:
Pension benefits, net of tax:
Net actuarial loss		(6,272	)		—			—			—			—			(6,272	)
Prior service cost		(107	)		—			—			—			—			(107	)
Balance — December 31, 2006 (Predecessor)		300,281			—			—			—			—			300,281
Net income		153,904			—			—			—			—			153,904
Cash distributions		(38,420	)		—			—			—			—			(38,420	)
Elimination of deferred income taxes		(3,767	)		—			—			—			—			(3,767	)
Other comprehensive income:
Loss on cash flow hedges, net of reclassification adjustments		(22	)		—			—			—			—			(22	)
Gain (loss) on cash flow hedges, net of reclassification adjustments		(22	)		—			—			—			—			(22	)
Pension benefits:
Elimination of deferred income taxes		77			—			—			—			—			77
Amortization of net actuarial Loss		670			—			—			—			—			670
Balance — December 31, 2007 (Predecessor) (Restated)		422,199			—			—			—			—			422,199
Amortization of prior service cost		27			—			—			—			—			27
Net actuarial gain arising during the period		2,293			—			—			—			—			2,293
Balance — December 31, 2007 (Predecessor)		414,966			—			—			—			—			414,966
Net income attributable to the period through January 23, 2008		4,002			—			—			—			—			4,002
Pre-IPO distribution		(3,088	)		—			—			—			—			(3,088	)
Distribution of Pre-IPO funds made in April 2008		(2,723	)		—			—			—			—			(2,723	)
Other comprehensive loss attributable to the period through January 23, 2008		40(2	)		—			—			—			—			40(2	)
Balance — January 23, 2008 (Predecessor)		413,197			—			—			—			—			413,197
Balance — January 23, 2008 (Predecessor) (Restated)		420,388			—			—			—			—			420,388
Contribution of net assets of predecessor companies		(115,020	)		(26,392	)		133,094			8,318			—			—
Adjustment to contribution of net assets of predecessor companies		2,723			(1,798	)		(871	)		(54	)		—			—
Restatement adjustment to contribution of net assets of predecessor companies		(7,191	)		4,746			2,301			144			—			—
Purchase of 15.9% general partnership interest in Northwest Pipeline GP		(300,900	)		—			—			—			—			(300,900	)
Issuance of units to public		—			336,520			—			—			—			336,520
Offering costs		—			(3,797	)		—			—			—			(3,797	)
Redemption of common units by general partner		—			(31,020	)		—			—			—			(31,020	)
Other comprehensive income attributable to the period January 24 through December 31, 2008:
Net unrealized gain on cash flow hedge		—			—			—			—			(20	)		(20	)
Pension benefits:
Total other comprehensive income																	(20	)
Amortization of net actuarial loss		—			—			—			—			457			457
Amortization of prior service cost		—			—			—			—			26			26
Net actuarial loss arising during the period		—			—			—			—			(14,326	)		(14,326	)
Total comprehensive income																	(13,863	)
Net income attributable to the period January 24 through December 31, 2008		—			32,839			15,918			(879	)		—			47,878
Cash distributions		—			(19,197	)		(9,306	)		(582	)		—			(29,085	)
Contributions pursuant to the omnibus agreement		—			—			—			1,874			—			1,874
Other		—			114			—			—			—			114
Balance — December 31, 2008	$	—		$	287,269		$	138,835		$	8,677		$	(13,863	)	$	420,918
Balance — December 31, 2008 (Restated)		—			292,015			141,136			8,821			(20	)		441,952
Net income		—			34,521			16,732			(432	)		—			50,821
Other comprehensive income:
Net unrealized gain on cash flow hedge		—			—			—			—			(22	)		(22	)
Total other comprehensive income																	(22	)
Cash distributions		—			(29,616	)		(14,355	)		(920	)		—			(44,891	)
Contributions pursuant to the omnibus agreement		—			—			—			1,500			—			1,500
Other		—			12			—			—			—			12
Balance — December 31, 2009	$	—		$	296,932		$	143,513		$	8,969		$	(42	)	$	449,372

See accompanying notes to consolidated financial statements.

64 62

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization and Basis of Presentation

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

We are a Delaware limited partnership formed on August 31, 2007 to own and operate natural gas transportation and storage assets, including a ~~minority~~non-controlling ownership interest in Northwest. On January 24, 2008, we completed our initial public offering (“IPO”) of common units. The 35 percent of Northwest owned by us was owned by The Williams Companies, Inc. (“Williams”) prior to the ~~initial~~ ~~public offering (“~~IPO”) of our common units in ~~January~~ January 2008. As of December 31, ~~2008~~2009, Williams, through its subsidiary, Williams Pipeline GP LLC, owns a 2 percent general partner interest and a 45.7 percent limited ~~partner~~ partner interest in us.

On January 24, 2008, we completed our IPO of 16,250,000 units representing limited partner interests in us at a price of $20.00 per unit ($18.80 net of underwriters’ discount). Concurrent with the closing of the IPO, (i) the public through the underwriters of the offering contributed $325.0 million ($305.5 million net of the underwriters’ discount) to us in exchange for 16,250,000 common units, representing a 47.5 percent limited partner interest in us, (ii) we purchased from Northwest a 15.9 percent general partnership interest in Northwest, and (iii) a 19.1 percent interest in Northwest was contributed to us by Williams Pipeline GP LLC, our General Partner, in exchange for 6,350,668 common units, 10,957,900 subordinated units, 684,869 units representing a 2 percent general partner interest in us, and all of our incentive distribution rights. On February 15, 2008, the underwriters of the offering exercised their right to purchase an additional 1,650,000 common units from us, for $33.0 million ($31.0 million net of the underwriters’ discount), to cover over-allotments. The underwriters purchased the common units pursuant to that option on February 21, 2008 at the IPO price, net of underwriting discounts, of $18.80 per unit. Concurrently with the exercise of the option and in accordance with the terms of the Contribution, Conveyance and Assumption Agreement entered into in connection with the closing of the IPO, the Partnership redeemed 1,650,000 common units held by the General Partner.

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

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

The accompanying consolidated financial statements include all normal recurring adjustments that, in the opinion of management, are necessary to present fairly our financial position at December 31, ~~2008~~2009, results of operations for the years ended December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, and cash flows for the years ended December 31, ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007. All intercompany transactions have been eliminated.

~~Note~~ We 2.have ~~Summary~~evaluated our disclosure of ~~Significant~~subsequent ~~Accounting~~events ~~Policies~~through the time of filing this Form 10-K with the SEC on February 23, 2010.

~~Use~~Note ~~of Estimates~~2. ~~The~~ ~~preparation of financial~~Restatement 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.

On January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which Northwest had presented and recognized 63pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor. Northwest had previously recorded parent amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and Northwest is not contractually required to assume these obligations upon withdrawal, Northwest has now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model.

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

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

respectively. The effect of the adjustments to our Comprehensive Income is an increase of $13.8 million in 2008, $0.8 million in 2007, and $6.4 million cumulative in the periods prior to 2007. The impact of this error correction also increased Northwest’s Owners’ Equity, our Partners’ Capital and Investment in Northwest Pipeline GP, and reduced Northwest’s noncurrent assets and liabilities at December 31, 2008. It did not have an impact on Northwest’s or our 2008 or 2007 Net Income as Northwest’s expense recognized approximated its contributions to the Williams’ sponsored plan, nor did it have any impact on Northwest’s or our 2008 or 2007 Consolidated Statements of Cash Flows.

Note 3. Subsequent Event

Note 4. Summary of Significant Accounting Policies

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

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

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

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

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

~~Note 3. Allocation of Net Income and Distributions~~66

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

	Period from
	January 24, 2008
	through
	December 31, 2008
Allocation to general partner:
Net income	$	47,878
Charges direct to general partner:
Reimbursable general and administrative costs		1,874
Income subject to 2% allocation of general partner interest		49,752
General partner’s share of net income		2.0	%
General partner’s allocated share of net income before items directly allocable to general partner interest		995
Incentive distributions paid to general partner*		—
Direct charges to general partner		(1,874	)
Net income (loss) allocated to general partner	$	(879	)
Net income	$	47,878
Net income (loss) allocated to general partner		(879	)
Net income allocated to limited partners	$	48,757

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

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~rights~~Note were $71 thousand, for the three months ended September 30, 2008, the assumed incentive distribution rights were $471 thousand, and for the three months ended December 31, 2008, the assumed incentive distribution rights were $339 thousand5. ~~The~~Allocation ~~resulting allocation~~ of ~~income~~Net ~~for~~Income ~~the~~and ~~calculation of earnings per limited partner unit is shown on the Consolidated Statements of Income.~~Distributions

~~Common~~ The ~~and~~allocation ~~subordinated~~of ~~unitholders~~net ~~share~~income ~~equally,~~between onour ~~a per-unit basis~~general partner and limited partners, inas reflected in the ~~net~~Consolidated ~~income~~Statement ~~allocated~~of toPartners’ ~~limited~~Capital, ~~partners~~ for the year ended December 31, 2009 and the period January 24 through December 31, 2008. is as follows (in thousands):


	Years Ended December 31,
	2009			2008
Allocation to general partner:
Net income	$	50,821		$	47,878
Charges direct to general partner:
Reimbursable general and administrative costs		1,500			1,874

Income subject to 2% allocation of general partner interest		52,321			49,752
General partner’s share of net income		2.0	%		2.0	%

General partner’s allocated share of net income before items directly allocable to general partner interest		1,046			995
Incentive distributions paid to general partner		22			—
Direct charges to general partner		(1,500	)		(1,874	)

Net loss allocated to general partner	$	(432	)	$	(879	)

Net income	$	50,821		$	47,878
Net loss allocated to general partner		(432	)		(879	)

Net income allocated to limited partners	$	51,253		$	48,757

Certain of our historical periods’ earnings per unit have been revised as a result of adopting Emerging Issues Task Force Issue No. 07-4 (Accounting Standards Codification Topic 260) in 2009. The retrospective application of this new guidance resulted in an increase in earnings per unit of $0.01 for both third and fourth quarters of 2008. Adoption of this new standard only impacts the allocation of earnings for purposes of calculating our earnings per limited partner and has no impact on our results of operations, allocation of earnings to capital accounts, or distributions of available cash to unitholders and our general partner.

Common and subordinated unitholders share equally, on a per-unit basis, in the net income allocated to limited partners for the years ended December 31, 2009 and 2008.

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

							General Partner
									Incentive
	Per Unit		Common		Subordinated				Distribution		Total Cash
Payment Date	Distribution		Units		Units		2%		Rights		Distribution
5/15/2008	$	0.2242	$	5,068	$	2,457	$	154	$	—	$	7,679
8/14/2008		0.3100		7,008		3,397		212		—		10,617
11/14/2008		0.3150		7,121		3,452		216		—		10,789
2/13/2009(a)		0.3200		7,234		3,507		219		—		10,960
2/13/2009		0.3200		7,234		3,507		219		—		10,960
5/15/2009		0.3250		7,347		3,561		223		—		11,131
8/14/2009		0.3300		7,461		3,616		226		—		11,303
11/13/2009		0.3350		7,574		3,671		230		22		11,497
2/12/2010(a)		0.3350		7,574		3,671		230		22		11,497

(a) The board of directors of our general partner declared this cash distribution on January 2625, ~~2009~~2010 to be paid on February 1312, ~~2009~~2010 to unitholders of record at the close of business on February 65, ~~2009~~2010.

Subordinated units. Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to 0.28750 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. ~~Futhermore~~ Furthermore, no arrearages will be paid on the subordinated units. The practical effect ~~of the~~ subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. The subordination period will end and the subordinated units will convert to common units, on a one-for-one basis when certain distribution requirements, as defined in the partnership agreement, have been met.

~~Note 4. Credit Facilities~~67

At the closing of the IPO on January 24, 2008, we entered into a 20 million working capital credit agreement with Williams as the lender. The facility will be available exclusively to fund working capital borrowings. The initial maturity date of the facility was January 23, 2009. We exercised our automatic right to extend the facility for an additional 365-day term in January. The new maturity date is January 23, 2010. The interest rate on all borrowings will be the one-month LIBOR determined the date of the borrowing. The borrowings may be repaid prior to the end of the one-month LIBOR rate period. If a borrowing is not repaid within one month, the interest rate for such borrowing will be adjusted to the one-month LIBOR rate 30 days after the most recent borrowing. We pay a commitment fee to Williams on the unused portion of the credit agreement of 0.25 percent annually. We are required to reduce all borrowings under our working capital credit agreement to zero for a period of at least 15 consecutive days once each twelve-month period prior to the maturity date of the facility. At December 31, 2008, we have no outstanding borrowings under the working capital credit facility.

Note 5. Recent Accounting Standards

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

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

InNote ~~December 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No~~6. ~~141(R) “Business~~ ~~Combinations.”~~Credit ~~SFAS No. 141(R)~~Facilities applies to all business combinations and establishes guidance for recognizing and measuring identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree and goodwill. Most of these items are recognized at their full fair value on the acquisition date, including acquisitions where the acquirer obtains control but less than 100 percent ownership in the acquiree. SFAS No. 141(R) also requires expensing of restructuring and acquisition-related costs as incurred and establishes disclosure requirements to enable the evaluation of the nature and financial effects of the business combination. SFAS No. 141(R) is effective for business combinations with an acquisition date in fiscal years beginning after December 15, 2008.

In At ~~December~~the ~~2007,~~closing of the ~~FASB~~IPO ~~issued~~on ~~SFAS~~January ~~No. 160~~24, ~~“Noncontrolling~~ ~~Interests~~2008, inwe ~~Consolidated~~entered ~~Financial Statements —~~into ana ~~amendment of Accounting Research Bulletin~~$20 ~~No. 51.”~~million ~~SFAS 160~~working ~~establishes~~capital ~~accounting~~credit ~~and~~agreement ~~reporting~~with ~~standards~~Williams ~~for noncontrolling ownership interests in subsidiaries (previously referred to~~ as ~~minority interests).~~the ~~SFAS No~~lender. ~~160~~ isThe ~~effective~~facility ~~for~~was ~~fiscal~~available ~~years beginning~~exclusively ~~after~~to ~~December 15,~~fund working ~~2008,~~capital ~~and early adoption is prohibited~~borrowings. The ~~statement~~initial ~~will~~maturity bedate ~~applied~~of ~~prospectively~~the ~~to transactions~~facility ~~involving~~was ~~noncontrolling interests~~January 23, ~~including~~2009. We ~~noncontrolling~~exercised ~~interests~~our ~~that~~automatic ~~arose~~right ~~prior~~ to ~~the~~extend ~~effective date, as of~~ the ~~beginning~~facility offor ~~the~~an ~~fiscal~~additional ~~year~~365-day itterm isin ~~initially adopted.~~January ~~However,~~2009. ~~the~~The ~~presentation~~new ofmaturity ~~noncontrolling~~date ~~interests~~was ~~within stockholders’~~January 23, ~~equity~~2010. ~~and~~This ~~the inclusion of earnings~~facility ~~attributable~~is toterminated ~~the~~since ~~noncontrolling~~we ~~interests~~did innot ~~consolidated~~exercise ~~net income~~our ~~requires~~automatic ~~retrospective~~right ~~application~~ to ~~all periods~~extend ~~presented.~~the ~~Implementation~~facility ofin ~~SFAS~~January No2010. At December ~~160~~31, ~~will~~2009, ~~not~~ we have anno ~~impact~~outstanding onborrowings ~~our~~under ~~Consolidated~~the working ~~Financial~~capital ~~Statements~~credit facility.

Note 67. Related Party Transactions

During 2009, we received distributions of $47.3 million from Northwest and we made distributions to Williams of $21.4 million. During 2008, we received distributions of $41.5 ~~million~~ million from Northwest. Of this amount, $5.8 million represents the portion allocated to us prior to the closing of the IPO on January 24, 2008. During 2008, we made distributions to Williams of $19.7 million.

Following the closing of the IPO on January 24, 2008, our general partner gives us a quarterly credit for general and administrative expenses under the terms of an omnibus agreement. The annual amounts of those credits are as follows: $2.0 million in 2008 (pro-rated for the portion of the ~~year~~ year from January 24 to December 31), and $1.5 million in 2009~~, $1~~.~~0 million~~ inAt ~~2010~~December 31, 2009 and 2008, $01.5 million inand ~~2011. At December 31, 2008,~~ $1.9 million, isrespectively, are reflected as a capital ~~contribution~~contributions in our financial statements.

Note 78. ~~Deferred~~Comprehensive ~~Costs~~Income

As Comprehensive ofincome ~~December 31,~~is ~~2007,~~as ~~an affiliate of the Partnership~~follows: ~~had incurred $1.7 million of offering and related formation expenses on behalf of the Partnership. At December 31, 2007, the Partnership recorded these costs to~~


	Years Ended December 31,
	2009			2008			2007
				(Predecessor)			(Predecessor)
				(Restated)			(Restated)
	(Thousands of dollars)
Net income	$	50,821		$	51,880		$	153,904
Reclassification of cash flow hedge gain into earnings		(22	)		(22	)		(22	)
Elimination of deferred income taxes		—			—			77

Total comprehensive income	$	50,799		$	51,858		$	153,959

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8. Comprehensive Income

Comprehensive income is as follows:

	Years Ended December 31,
	2008			2007			2006
							(Predecessor)
				(Predecessor)
	(Thousands of dollars)
Net income	$	51,880		$	153,904		$	19,062
Reclassification of cash flow hedge gain into earnings		(22	)		(22	)		126
Pension benefits:
Amortization of net actuarial loss		498			670			—
Amortization of prior service cost		27			27			—
Net actuarial (loss) gain arising during the period		(14,326	)		2,293			—
Elimination of deferred income taxes		—			(3,767	)		—
Total comprehensive income	$	38,057		$	153,105		$	19,188

Note 9. Equity Investments

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

Northwest ~~(100%)~~

	Years Ended December 31,
	2008		2007			2006
	2009		2008			2007
	(Thousands of dollars)
Income Statement Data:
Operating revenues	$	434,~~854~~379	$	~~421~~434,~~851~~854		$	~~324~~421,~~250~~851
Net income		~~155~~153,~~371~~651		~~439~~155,~~726~~371	~~(A)~~		54439,~~462~~726	(A)
Cash Distributions		~~419~~135,~~342~~000		~~109~~419,~~770~~342			—109,770
Balance Sheet Data (at period end):
Total assets		2,082,172		2,056,471
Total assets (B)		2,081,277		2,078,812			2,033,596
Long-term debt, including current maturities		693,~~240~~437		693,~~736~~240			693,736
Total Partners’ equity		1,184,713		1,185,616
Total Partners’ equity (B)		1,207,150		1,210,547			1,177,098

Note: Earnings and distributions/dividends per partnership unit/common share are not presented for 2007 ~~2006~~ through ~~2008~~ 2009. Northwest was a wholly-owned subsidiary of Williams as of December 31, 2007 ~~and for all prior periods presented~~. Distributions for 2009 and 2008 were made to Northwest’s partners based upon each partnership’s ownership interest.


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

(B)		Northwest’s financial statements have been restated due to the manner in which it presented and recognized pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor. Northwest previously recorded Williams-allocated amounts related to these plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and Northwest is not contractually required to assume these obligations upon withdrawal, Northwest has now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. Accordingly, our 2007, 2008, and 2009 summarized results for Northwest have been restated to reflect the change in accounting treatment.

69 67

WILLIAMS PIPELINE PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 10. Quarterly Information (Unaudited)

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

Quarter of 2008

Quarter of 2009

First

Second

Third

Fourth

Equity earnings from investment in Northwest

1314,~~355~~318

~~(a)~~

12,~~490~~307

1413,~~433~~391

1413,~~102~~762

Net income

1213,~~855~~655

~~(a)~~

11,~~867~~560

1312,~~863~~480

13,~~295~~126

Basic and diluted net income per limited partner unit:

Common units

0.2741

0.3635

0.4138

0.39

Subordinated units

0.2741

0.3635

0.4138

0.39

	Quarter of 2007
	Quarter of 2008
	First			Second		Third		Fourth
	(Predecessor)			(Predecessor)		(Predecessor)		(Predecessor)
Equity earnings from investment in Northwest	$	13,355	(a)	$	12,490	$	14,433	$	14,102
Equity earnings from investment in Northwest	$	8,175		$	13,085	$	11,583	$	121,061
Net income		12,855	(a)		11,867		13,863		13,295
Net income		8,175			13,085		11,583		121,061
Basic and diluted net income per limited partner unit:
Common units		0.27			0.36		0.42		0.40
Subordinated units		0.27			0.36		0.42		0.40


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

Note 11. Disclosures About the Fair Value of Financial Instruments 68

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 — The carrying amounts of these items approximates their fair value.

NORTHWEST’S MANAGEMENT’S ~~ANNUAL~~ REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

~~This~~ A ~~annual~~material ~~report~~weakness ~~does~~is ~~not~~a ~~include~~deficiency, anor ~~attestation~~combination ~~report~~ of ~~Northwest’s~~ ~~registered~~deficiencies, ~~public~~in ~~accounting firm regarding~~ internal control over financial reporting., ~~Management’s report~~such ~~was~~that ~~not~~there ~~subject~~is toa ~~attestation~~reasonable bypossibility ~~Northwest’s~~that a ~~registered~~material ~~public~~misstatement ~~accounting firm pursuant to temporary rules~~ of the ~~SEC~~annual ~~that~~or ~~permit~~interim ~~Northwest~~financial tostatements ~~provide~~will ~~only~~not ~~management’s~~be ~~report~~prevented inor ~~this~~detected ~~annual~~on ~~report~~a timely basis.

As discussed further in Note 2 of the Notes to Consolidated Financial Statements, we previously recorded parent-allocated amounts related to these plans on a 69single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we have now concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. The error was significant to the Statement of Comprehensive Income for the period ended December 31, 2008. The impact of the correction also increased Owners’ Equity and reduced non-current assets and liabilities. It did not have an impact on our 2008 Net Income, nor did it have any impact on our 2008 Statement of Cash Flows.

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

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Management Committee of Northwest Pipeline GP

We have audited the accompanying consolidated balance sheets of Northwest Pipeline GP as of December 31, ~~2008~~2009 and ~~2007~~2008, and the related consolidated statements of income, comprehensive income, ~~owners~~owner’s equity, and cash flows for each of the three years in the period ended December 31, ~~2008~~ 2009. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the ~~Partnership~~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~~ obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the ~~Partnership~~Company’s internal control over ~~financial~~ 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~~ for the purpose of expressing an opinion on the effectiveness of the ~~Partnership~~Company’s internal control over ~~financial~~ financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Northwest Pipeline GP at December 31, ~~2008~~ ~~and~~2009 ~~2007~~and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2008~~2009, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

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

/s/ ~~Houston,~~Ernst ~~Texas~~& Young LLP

Houston, Texas February 23, ~~2009~~2010

72 70

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF INCOME

Years Ended December 31,

2008

2007

2006

2009

2008

2007

(Thousands of dollars)

OPERATING REVENUES

434,~~854~~379

~~421~~434,~~851~~854

~~324~~421,~~250~~851

OPERATING EXPENSES:

General and administrative

6064,~~403~~657

6560,~~772~~403

5665,~~463~~772

Operation and maintenance

7271,~~831~~085

6672,~~847~~831

6566,~~763~~847

Depreciation

86,~~184~~373

8486,~~731~~184

7984,~~488~~731

Regulatory credits

(2,~~617~~403

)

(32,~~663~~617

)

(43,~~469~~663

)

Taxes, other than income taxes

1614,~~875~~158

1316,~~997~~875

1513,~~018~~997

Regulatory liability reversal

—

~~(16,562~~—

)

—(16,562

)

Total operating expenses

233,~~676~~870

~~211~~233,~~122~~676

~~212~~211,~~263~~122

Operating income

~~201~~200,~~178~~509

~~210~~201,~~729~~178

~~111~~210,~~987~~729

OTHER INCOME — net:

Interest income —

Affiliated

~~813~~74

~~2,983~~813

32,~~920~~983

Other

616

~~2,681~~6

32,~~423~~681

Allowance for equity funds used during construction

~~812~~1,996

~~2,091~~812

82,~~947~~091

Miscellaneous other income (expense), net

(8135

)

(~~517~~8

)

~~307~~(517

)

Contract termination income

—

~~18,199~~—

—18,199

Total other income — net

1,~~623~~951

251,~~437~~623

1625,~~597~~437

INTEREST CHARGES:

Interest on long-term debt

4244,~~290~~439

4642,~~828~~290

4346,~~649~~828

Other interest

5,~~571~~414

5,~~585~~571

35,~~824~~585

Allowance for borrowed funds used during construction

(~~431~~1,044

)

(~~1,306~~431

)

(41,~~557~~306

)

Total interest charges

4748,~~430~~809

5147,~~107~~430

4251,~~916~~107

INCOME BEFORE INCOME TAXES

~~155~~153,~~371~~651

~~185~~155,~~059~~371

85185,~~668~~059

PROVISION (BENEFIT) FOR INCOME TAXES (Note 6)

—

(254,667

)

31,206

PROVISION (BENEFIT) FOR INCOME TAXES (Note 7)

—

(254,667

)

NET INCOME

~~155~~153,~~371~~651

~~439~~155,~~726~~371

54439,~~462~~726

CASH DISTRIBUTIONS/DIVIDENDS

~~419~~135,~~342~~000

~~109~~419,~~770~~342

—109,770

See accompanying notes to consolidated financial statements.

73 71

NORTHWEST PIPELINE GP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008			2007
	2009			2008
				(Restated)
	(Thousands of dollars)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	~~345~~402		$	~~497~~345
Advances to affiliate		~~65,977~~—			3965,~~072~~977
Accounts receivable —
Trade, less reserves of $0 for 2008 and $7 for 2007		40,116			40,689
Trade		40,442			40,116
Affiliated companies		14,~~230~~514			31,~~514~~230
Materials and supplies, less reserves of $111 for 2008 and $181 for 2007		9,817			10,344
Materials and supplies, less reserves of $11 for 2009 and $111 for 2008		9,960			9,817
Exchange gas due from others		174,~~000~~089			1017,~~155~~000
Exchange gas offset		—10,288			~~6,593~~—
Prepayments and other		54,~~985~~241			65,~~928~~985
Total current assets		~~140~~73,~~470~~936			~~117~~140,~~792~~470
PROPERTY, PLANT AND EQUIPMENT, at cost		2,~~765~~887,~~520~~021			2,~~706~~765,~~691~~520
Less — Accumulated depreciation		~~901~~950,~~613~~708			~~864~~901,~~999~~613
Total property, plant and equipment, net		1,~~863~~936,~~907~~313			1,~~841~~863,~~692~~907
OTHER ASSETS:
Deferred charges		2213,~~213~~996			4418,~~915~~853
Regulatory assets		5557,~~582~~032			5255,~~072~~582
Total other assets		7771,~~795~~028			9674,~~987~~435
Total assets	$	2,~~082~~081,~~172~~277		$	2,~~056~~078,~~471~~812
LIABILITIES AND OWNERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable —
Trade	$	1217,~~172~~552		$	3212,~~055~~172
Affiliated companies		612,~~484~~136			136,~~056~~484
Accrued liabilities —
Taxes, other than income taxes		108,~~019~~176			710,~~935~~019
Interest		4,045			4,~~517~~045
Employee costs		109,~~505~~435			1210,~~106~~426
Exchange gas due to others		1214,~~165~~377			1612,~~748~~165
Exchange gas offset		~~4,835~~—			—4,835
Other		85,~~784~~839			58,~~713~~784
Total current liabilities		6971,~~009~~560			9268,~~130~~930
LONG-TERM DEBT		693,~~240~~437			693,~~736~~240
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES		~~135~~109,~~209~~130			84106,~~989~~095
CONTINGENT LIABILITIES AND COMMITMENTS
OWNERS’ EQUITY:
Owners’ capital		~~978~~1,~~682~~027,862			~~977~~978,~~022~~682
Retained earnings		265,668			228,739
Loan to affiliate		(105,431	)		(34,265	)
Accumulated other comprehensive loss		(59,636	)		(20,145	)
Retained earnings		284,319			265,668
Total owners’ equity		1,184,714			1,185,616
Accumulated other comprehensive income		400			462
Total liabilities and owners’ equity	$	2,082,172		$	2,056,471
Total owners’ equity		1,207,150			1,210,547
Total liabilities and owners’ equity	$	2,081,277		$	2,078,812

See accompanying notes to consolidated financial statements.

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NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF OWNERS’ EQUITY

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
				(Restated)			(Restated)
	(Thousands of dollars, except per share amounts)
Common stock, par value $1 per share, authorized, 1,000 shares
Balance at beginning of period, outstanding, 1,000 shares for 2007 and 2006	$	—		$	1		$	1
Balance at beginning of period, outstanding, 1,000 shares for 2007	$	—		$	—		$	1
Conversion to GP		—			(1—	)		—(1	)
Balance at end of period		—			—			1—
Additional paid-in capital —
Balance at beginning of period		—			~~977,021~~—			~~912~~977,021
Capital contribution from parent		—			—			65,000
Conversion to GP		—			—			(977,021	)
Conversion to GP		—			(977,021	)		—
Balance at end of period		—			—			—
Balance at end of period		—			—			977,021
Partners’ capital —
Balance at beginning of period		~~977~~978,~~022~~682			—977,022			—
Capital contribution from partner		149,~~660~~180			—1,660			—
Conversion to GP		—			~~977,022~~—			—977,022
Balance at end of period		~~978~~1,~~682~~027,862			~~977~~978,~~022~~682			—977,022
Loans (to) from affiliate —
Balance at beginning of period		(34,265	)		(29,186	)		(29,364	)
Loans (to) from affiliate		(71,166	)		(5,079	)		178
Balance at end of period		(105,431	)		(34,265	)		(29,186	)
Retained earnings (deficit) —
Balance at beginning of period		~~228~~265,~~739~~668			~~(101~~228,~~214~~739	)		(~~155~~101,~~676~~214	)
Net income		~~155~~153,~~371~~651			~~439~~155,~~726~~371			54439,~~462~~726
Cash distributions		(~~419~~135,~~342~~000	)		(~~109~~419,~~770~~342	)		—(109,770	)
Sale of partnership interest		~~300,900~~—			—300,900			—
Other		—			(3—	)		—(3	)
Balance at end of period		~~265~~284,~~668~~319			~~228~~265,~~739~~668			~~(101~~228,~~214~~739	)
Accumulated other comprehensive loss —
Accumulated other comprehensive income (loss) —
Balance at beginning of period		~~(20,145~~462	)		~~(17,863~~523	)		—365
Cash flow hedges:
Gain, net of tax of ($233) for 2006		—			—			386
Reclassification of gain into earnings		(62	)		(61	)		(62	)
Reclassification of gain into earnings, net of tax of $13 for 2006		(61	)		(62	)		(21	)
Elimination of deferred income taxes		—			—			220
Pension benefits:
Balance at end of period		400			462			523
Adjustment to initially apply SFAS No. 158:
Total owners’ equity	$	1,207,150		$	1,210,547		$	1,177,098
Prior service cost, net of tax of $186 for 2006		—			—			(308	)
Net actuarial loss, net of tax of $10,797 for 2006		—			—			(17,920	)
Net actuarial gain (loss)		(39,509	)		8,466			—
Prior service cost		79			77			—
Elimination of deferred income taxes		—			(10,763	)		—
Balance at end of period		(59,636	)		(20,145	)		(17,863	)
Total owners’ equity	$	1,184,714		$	1,185,616		$	857,945

See accompanying notes to consolidated financial statements.

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NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
				(Restated)			(Restated)
	(Thousands of dollars)
Net Income	$	~~155~~153,~~371~~651		$	~~439~~155,~~726~~371		$	54439,~~462~~726
Cash Flow Hedges:
Gain on cash flow hedges, net of tax of ($233) for 2006		—			—			386
Amortization of cash flow hedges		(62	)		(61	)		(62	)
Amortization of cash flow hedges, net of tax of $13 for 2006		(61	)		(62	)		(21	)
Elimination of deferred income taxes		—			—			220
Pension Benefits:
Total comprehensive income	$	153,589		$	155,310		$	439,884
Amortization of prior service cost		79			77			—
Amortization of net actuarial loss		1,423			1,913			—
Net actuarial gain (loss) arising during the period		(40,932	)		6,553			—
Elimination of deferred income taxes		—			(10,763	)		—
Total comprehensive income	$	115,880		$	437,444		$	54,827

See accompanying notes to consolidated financial statements.

76 74

NORTHWEST PIPELINE GP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
				(Restated)			(Restated)
	(Thousands of dollars)
OPERATING ACTIVITIES:
Net Income	$	~~155~~153,~~371~~651		$	~~439~~155,~~726~~371		$	54439,~~462~~726
Adjustments to reconcile to net cash provided by operating activities —
Depreciation		86,~~184~~373			8486,~~731~~184			7984,~~488~~731
Regulatory credits		(2,~~617~~403	)		(32,~~663~~617	)		(43,~~469~~663	)
Provision (benefit) for deferred income taxes		—			(289,229	)		27,916
Gain on sale of property, plant and equipment		(508	)		(378	)		—
Amortization of deferred charges and credits		8,589			9,783			2,484
Provision (benefit) for deferred income taxes		—			—			(289,229	)
Allowance for equity funds used during construction		(812	)		(2,091	)		(8,947	)
Amortization of deferred charges and credits		12,561			8,589			9,783
Reserve for doubtful accounts		(7	)		(46	)		(38	)
Allowance for equity funds used during construction		(1,996	)		(812	)		(2,091	)
Regulatory liability reversal		—			(16,562	)		—
Reserve for doubtful accounts		—			(7	)		(46	)
Contract termination income		—			(6,045	)		—
Regulatory liability reversal		—			—			(16,562	)
Cash provided (used) by changes in operating assets and liabilities:
Contract termination income		—			—			(6,045	)
Trade accounts receivable		580			(8,413	)		(3,515	)
Cash provided (used) by changes in current assets and liabilities:
Affiliated receivables, including income taxes in 2007 and 2006		2,284			(2,923	)		4,899
Trade accounts receivable		(326	)		580			(8,413	)
Exchange gas due from others		4,583			(1,654	)		5,549
Affiliated receivables, including income taxes in 2007		(3,284	)		2,284			(2,923	)
Materials and supplies		527			(331	)		(1,912	)
Exchange gas due from others		2,623			4,583			(1,654	)
Other current assets		943			1,017			(5,264	)
Materials and supplies		(143	)		527			(331	)
Deferred charges		(423	)		(9,769	)		(1,610	)
Other current assets		1,744			943			1,017
Trade accounts payable		(~~2,599~~828	)		4(2,~~653~~599	)		(24,~~011~~653	)
Affiliated payables, including income taxes in 2007 and 2006		(6,572	)		(5,259	)		13,037
Affiliated payables, including income taxes in 2007		275			(6,572	)		(5,259	)
Exchange gas due to others		(42,~~583~~623	)		1(4,~~654~~583	)		(51,~~549~~654	)
Other accrued liabilities		~~3,082~~(533	)		23,~~105~~083			12,~~192~~105
Other deferred credits		(5,139	)		7,673			4,095
Changes in noncurrent assets and liabilities:
Other		(377	)		—			—
Deferred charges		(4,580	)		(423	)		(9,769	)
Net cash provided by operating activities		239,014			205,357			159,807
Other deferred credits		(5,205	)		(5,139	)		7,673
Net cash provided by operating activities		234,798			239,014			205,357
FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt		~~249,333~~—			~~434~~249,~~362~~333			~~174~~434,~~447~~362
Retirement of long-term debt		~~(250,000~~—	)		(~~252~~250,~~867~~000	)		(7252,~~500~~867	)
Early retirement of long-term debt		—			~~(175,000~~—	)		—(175,000	)
Debt issuance costs		~~(2,027~~—	)		(2,~~059~~027	)		(2,~~375~~059	)
Premium on early retirement of long-term debt		—			~~(7,111~~—	)		—(7,111	)
Capital contribution from parent		149,~~660~~180			—1,660			~~65,000~~—
Proceeds from sale of partnership interest		~~300,900~~—			—300,900			—
Distributions paid		(~~419~~135,~~342~~000	)		(~~109~~419,~~770~~342	)		—(109,770	)
Changes in cash overdrafts		(72,~~372~~212	)		(307,~~078~~372	)		37(30,~~347~~078	)
Net cash provided by (used in) financing activities		(126,848	)		(142,523	)		266,919
Net cash used in financing activities		(83,608	)		(126,848	)		(142,523	)
INVESTING ACTIVITIES:
Property, plant and equipment —
Capital expenditures		(78,566	)		(157,163	)		(473,566	)
Capital expenditures*		(152,580	)		(88,478	)		(156,761	)
Proceeds from sales		32,~~065~~234			23,~~257~~065			—2,257
Asset removal cost		—			—			(9,733	)
Proceeds from sale of Parachute facilities		—			—			79,770
Changes in accounts payable and accrued liabilities		(9,912	)		402			(5,015	)
Repayments from (advances to) affiliates		(787	)		(26,905	)		10,908
Proceeds from contract termination payments		—			—			3,348
Net cash used in investing activities		(151,133	)		(112,318	)		(63,826	)
Proceeds from sale at Parachute facilities		—			79,770			—
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		57			(152	)		(992	)
Repayments from (advances to) affiliates		(26,905	)		10,908			20
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		345			497			1,489
Net cash used in investing activities		(112,318	)		(63,826	)		(484,946	)
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	402		$	345		$	497
NET DECREASE IN CASH AND CASH EQUIVALENTS		(152	)		(992	)		(58,220	)
* Increases to property, plant and equipment	$	(156,576	)	$	(78,566	)	$	(157,163	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		497			1,489			59,709
Changes in related accounts payable and accrued liabilities		3,996			(9,912	)		402
CASH AND CASH EQUIVALENTS AT END OF YEAR	$	345		$	497		$	1,489
Capital expenditures	$	(152,580	)	$	(88,478	)	$	(156,761	)
Supplemental disclosures of non-cash transactions:
Adjustment to owners’ equity for benefit plans correction	$	(4,402	)	$	(5,079	)	$	178
Advances to affiliates reclassified to owners’ equity		66,764			—			—

See accompanying notes to consolidated financial statements.

77 75

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Summary of Significant Accounting Policies

Corporate Structure and Control

~~On October 1, 2007,~~ Northwest Pipeline ~~Corporation converted from a Delaware corporation to a general partnership, Northwest Pipeline~~ GP. ~~Northwest Pipeline Corporation, prior to October 1, 2007, and Northwest Pipeline GP, subsequent to September 30, 2007, are hereinafter referred to as~~ (“Northwest.”) ~~Coincident with the conversion, the partners of Northwest entered into a partnership agreement. Northwest~~ is a Delaware general partnership whose purpose is generally to own and operate the Northwest interstate pipeline system and related facilities and to conduct such other business activities as its management committee may from time to time determine, provided that such activity either generates “qualifying income” (as defined in Section 7704 of the Internal Revenue Code of 1986) or enhances operations that generate such qualified income. Because ~~of our~~ ~~conversion~~we toare a general partnership, we ~~will~~are nonot ~~longer be~~ subject to federal and state income taxes. OnCoincident with our conversion to a general partnership on October 1, 2007, we reversed deferred income tax liabilities of approximately $311.8 million to income and $10.2 million of deferred income tax assets to other comprehensive income.

On January 24, 2008, Williams Pipeline Partners L.P. (“WMZ”) (previously a wholly-owned subsidiary of The Williams Companies, Inc. (“Williams”)) completed its initial public offering of limited partnership units, the net proceeds of which were used to acquire a 15.9 percent ~~interest~~ interest in Northwest. Williams contributed 19.1 percent of its ownership in Northwest in return for limited and general partnership interests in WMZ. Northwest received net proceeds of $300.9 million on January 24, 2008 from WMZ for the purchase of its 15.9 percent interest, and Northwest in in turn made a distribution to Williams of $300.9 million. After these transactions, Northwest is was owned 35 percent by WMZ and 65 percent by WGPC Holdings LLC, a wholly-owned subsidiary of Williams. Through its ownership interests in each of our partners, Williams directly and indirectly owns 81.7 percent of Northwest as of ~~February~~December 2631, 2009.

On ~~Concurrent~~February 17, ~~with~~2010, ~~the~~Williams ~~conversion~~completed to a ~~general~~strategic ~~partnership~~restructuring, ~~Northwest~~pursuant ~~Pipeline Corporation ceased~~ to ~~be an employer.~~ ~~Employees~~which ~~previously~~Williams ~~employed~~contributed byits ~~Northwest~~ownership ~~Pipeline~~in ~~Corporation became~~WGPC ~~employees~~Holdings ofLLC ~~Northwest~~to ~~Pipeline~~Williams ~~Services~~Partners ~~LLC~~L.P. (“WPZ”), a ~~consolidated~~ ~~affiliate. Northwest and Northwest Pipeline~~publicly ~~Services~~traded ~~LLC~~Delaware ~~entered~~limited ~~into~~partnership anwhich ~~agreement~~is ~~whereby~~controlled ~~the~~by ~~employees of~~and ~~Northwest~~consolidated ~~Pipeline~~with ~~Services~~Williams ~~LLC~~in ~~provide services to Northwest~~2005. ~~Northwest~~ ~~reimburses~~Through ~~Northwest~~its ~~Pipeline~~ownership ~~Services~~interests ~~LLC for the~~in ~~costs~~each of ~~the~~our ~~employees~~partners, ~~including~~Williams ~~compensation~~indirectly ~~and~~owns ~~employee benefit~~71.3 percent ~~plan~~of ~~costs~~Northwest ~~and~~as ~~all~~of ~~related~~February 17, ~~administrative costs~~2010.

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

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

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

Nature of Operations

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

Regulatory Accounting

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

78 76

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Statement~~ The ~~of Financial~~ Accounting Standards ~~(“SFAS”) No. 71,~~Codification ~~“Accounting~~Regulated ~~for~~Operations ~~the~~(“Topic ~~Effects of Certain Types of Regulation,~~980”) ~~requires~~provides that rate-regulated public utilities ~~that apply this standard to~~ account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators establish rates. In applying ~~SFAS No. 71~~Topic 980, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods. The accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. At December 31, ~~2008~~2009 and ~~2007~~2008, we had approximately $5759.82 million and $5457.38 million, respectively, of regulatory assets primarily related to equity funds used during construction, levelized incremental depreciation, asset retirement obligations, environmental costs and other post-employment benefits, and approximately $215.9 1 million and $1714.87 million, respectively, of regulatory liabilities related to postretirement benefits and asset retirement obligations included on the accompanying Balance Sheet.

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Northwest and Northwest Pipeline Services LLC, a variable interest entity for which Northwest is the primary beneficiary.

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) litigation-related contingencies; 2) environmental remediation obligations; 3) ~~impairment~~ impairment assessments of long-lived assets; 4) depreciation; ~~5) pension~~ and ~~other post-employment benefits; and 6~~5) asset retirement obligations.

Property, Plant and Equipment

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

Depreciation is provided by the straight-line method by class of assets for property, plant and equipment. The annual weighted average composite depreciation rate recorded for transmission and storage plant was 2.7977 percent, 2.7679 percent and 2.8676 percent for ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, respectively, including an allowance for negative salvage.

The incrementally priced Evergreen Expansion Project, which was an expansion of our pipeline system, was placed in service on October 1, 2003. The levelized rate design of this project ~~created~~ 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 $2.4 million in 2009, $2.6 million in 2008, and $3.7 million in 2007 in the accompanying Statements of Income. These credits relate primarily to the 77levelized depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related regulatory assets of $30.8 million at December 31, 2009, and $28.4 million at December 31, 2008. Such amounts will be amortized over the primary terms of the shipper agreements as such costs are collected through rates.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~depreciation~~ We record an asset and a liability equal to the ~~Evergreen~~present ~~Expansion~~value ~~Project’s~~of each expected future asset ~~levelized~~retirement ~~depreciation~~obligation as(“ARO”). The ARO asset is depreciated in a ~~regulatory~~manner consistent with the depreciation of the underlying physical asset with the ~~offsetting~~offset to a regulatory asset. We measure ~~credit~~changes ~~recorded~~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 ~~credit~~asset. onThe regulatory asset is being recovered through the ~~accompanying~~net negative ~~Income~~salvage ~~Statement~~component of depreciation included in our rates beginning January 1, 2007, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2009 and 2008 were $33.8 million and $26.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

We The ~~recorded~~negative ~~regulatory~~salvage ~~credits~~component ~~totaling~~of ~~$2.6 million~~accumulated ~~in 2008,~~depreciation ($329.75 million ~~in 2007,~~ and $425.56 million ~~in 2006~~at inDecember 31, ~~the~~2009 ~~accompanying~~and ~~Statements~~2008, ofrespectively) ~~Income.~~was ~~These~~reclassified ~~credits relate primarily~~ to ~~the~~a ~~levelized~~noncurrent ~~depreciation for the Evergreen Project discussed above. The accompanying Balance Sheet reflects the related~~ regulatory ~~assets~~asset ~~of $28.4 million at~~or ~~December 31,~~liability ~~2008,~~ and ~~$25.8 million~~has ~~at December 31,~~been ~~2007.~~netted ~~Such~~against ~~amounts will be amortized over~~ the ~~primary~~ ~~terms~~amount of the ~~shipper~~ARO ~~agreements~~regulatory asasset ~~such~~expected ~~costs~~to ~~are~~be collected ~~through~~in rates.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (“ARO”). The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset with the offset to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through the net negative salvage component of depreciation included in our rates beginning January 1, 2007, and is being amortized to expense consistent with the amounts collected in rates. The regulatory asset balances as of December 31, 2008 and 2007 were $26.8 million and $21.8 million, respectively. The full amount of the regulatory asset is expected to be recovered in future rates.

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

Allowance for Borrowed and Equity Funds Used During Construction

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

The composite rate used to capitalize AFUDC was approximately 9 percent for 2009, 2008 and ~~2007 and approximately~~ ~~10 percent for 2006~~2007. Equity AFUDC of $02.80 million, $20.18 million and $82.91 million for ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, respectively, is reflected in Other Income — net.

Regulatory Allowance for Equity Funds Used During Construction

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

Advances to Affiliates

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. The advances are represented by demand notes. Advances are stated at ~~the~~ the historical carrying amounts. Interest income is recognized when chargeable and ~~collectibility~~collectability is reasonably assured. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based upon the overnight investment rate paid on Williams’ excess cash, which was ~~zero~~0.05 percent and zero percent at December 31, 2009 and 2008, respectively.

In accordance with Williams’ restructuring of its business, our participation in Williams’ cash management program was terminated. In February 2010, our management committee authorized 78a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our Owners’ Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

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.

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Accounts Receivable and Allowance for Doubtful Receivables

Materials and Supplies Inventory

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

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

~~Impairments~~ Impairment of Long-Lived Assets

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

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

Income Taxes

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

Through September 30, 2007, we used the liability method of accounting for income taxes which required, among other things, provisions for all temporary differences between the financial ~~basis~~ basis and the tax basis in our assets and liabilities and adjustments to the existing deferred tax balances for changes in tax rates. Following our conversion to a general partnership on October 1, 2007, we are no longer subject to income tax. (See Note 6 7.)

Deferred Charges

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

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Cash and Cash Equivalents

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

Revenue Recognition

Our revenues are primarily from services pursuant to long term firm transportation and storage agreements. These agreements provide for a ~~demand~~reservation charge based on the volume of contracted capacity and a ~~commodity~~volumetric charge based on the volume of gas delivered, both at rates specified in our FERC tariffs. We recognize revenues for ~~demand~~reservation charges ratably over the contract ~~period~~ period regardless of the volume of natural gas that is transported or stored. Revenues for ~~commodity~~ 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 ~~with FERC~~. We ~~record~~ record estimates of rate refund liabilities considering our and ~~other~~ third -party regulatory proceedings, advice of counsel and ~~estimated~~ ~~total exposure, as discounted and risk weighted, as well as collection and~~ other risks. At December 31, ~~2008~~2009, we had no rate refund liabilities.

Environmental Matters

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

Interest Payments

Cash payments for interest were $4344.15 million, $4943.71 million and $4349.57 million in ~~2008~~2009, ~~2007 and~~2008 ~~2006~~and 2007, respectively.

~~Recent Accounting~~Subsequent ~~Standards~~ Events

In We ~~September~~have ~~2006,~~evaluated ~~the~~our ~~Financial~~disclosure ~~Accounting~~of ~~Standards~~subsequent ~~Board (“FASB’’)~~events ~~issued~~through ~~SFAS No. 157, “Fair~~the ~~Value~~time ~~Measurements”~~of ~~(“SFAS 157”). This~~filing ~~Statement~~this ~~establishes a framework for fair value~~Form ~~measurements~~10-K inwith the ~~financial~~SEC ~~statements by providing a definition of fair value, provides guidance~~ on ~~the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS~~February ~~157~~23, ~~is effective for fiscal years~~2010. ~~beginning after~~

80 Accounting Standards Issued But Not Yet Adopted

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

In January 2010, the FASB issued ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This Update requires new disclosures regarding the amount of transfers in or out of levels 1 and 2 along with the reason for such transfers and also requires a greater level of disaggregation when disclosing valuation techniques and inputs used in estimating level 2 and level 3 fair value measurements. This Update also includes conforming

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~November 15,~~amendments ~~2007.~~to ~~In February 2008,~~ the ~~FASB~~guidance ~~issued~~on ~~FASB Staff~~employers’ ~~Position~~disclosures ~~(“FSP”) No. FAS 157-2, permitting~~about ~~entities~~postretirement tobenefit ~~delay~~plan ~~application~~assets. ~~of SFAS 157 to~~The ~~fiscal~~disclosures ~~years~~will ~~beginning~~be ~~after~~required ~~November 15, 2008,~~ for ~~nonfinancial~~ ~~assets~~reporting ~~and~~beginning ~~nonfinancial liabilities, except for items that are recognized or disclosed at fair value~~ in the ~~financial~~ ~~statements~~first onquarter aof ~~recurring basis (at least annually)~~2010. On ~~January 1~~Also, ~~2008, we adopted SFAS 157. We had no~~beginning ~~assets~~with ~~or liabilities measured at fair value on a recurring basis. Therefore,~~ the ~~initial~~first ~~adoption~~quarter of ~~SFAS 157 had no impact on our Consolidated Financial Statements. Beginning January 1~~2011, ~~2009,~~the weStandard ~~will~~requires ~~prospectively~~additional ~~apply~~categorization ~~SFAS 157 fair~~of ~~value~~items ~~measurement guidance to nonfinancial assets and~~included ~~nonfinancial~~in ~~liabilities~~the ~~that~~rollforward ~~are~~of ~~not~~activity ~~recognized~~for orlevel ~~disclosed~~3 inputs on a ~~recurring~~gross basis. ~~when~~We ~~such~~are ~~fair~~assessing ~~value measurements are~~the ~~required.~~application ~~Had we not elected to defer portions~~ of ~~SFAS 157, fair~~this ~~value~~Standard ~~measurement for nonfinancial items would have been applied~~ to ~~the~~disclosures ~~initial~~in ~~measurement~~our atConsolidated ~~fair~~Financial ~~value of asset retirement obligations in 2008~~Statements.

Change in Accounting Estimate

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

~~Reclassifications and~~Note ~~Adjustments~~2. Restatement

In On ~~the~~January 20, ~~third quarter of 2006~~2010, we ~~made~~concluded anthat ~~adjustment~~our tofinancial ~~correct an~~statements ~~error~~for ~~resulting~~the ~~from~~year anended ~~analysis~~December 31, of2008 ~~our~~should ~~regulatory~~be ~~assets. Property,~~restated ~~plant~~due ~~and~~to ~~equipment~~the ~~includes~~manner ~~the~~in ~~capitalization~~which ~~of equity~~we ~~funds~~have ~~used~~presented ~~during~~and ~~construction~~recognized ~~(“EAFUDC”).~~pension and ~~Prior~~postretirement toobligations ~~our~~in ~~conversion~~certain tobenefit aplans ~~partnership,~~for which Williams is the ~~capitalization~~plan ofsponsor. We ~~EAFUDC~~have ~~created~~previously arecorded ~~deferred~~allocated ~~tax~~amounts ~~liability~~related ~~and~~to anthese ~~associated regulatory~~plans ~~asset.~~on ~~The~~a ~~regulatory~~single-employer ~~asset~~basis ~~was~~rather than ~~not~~a ~~properly~~multi-employer ~~reduced for~~accounting ~~certain~~model. ~~retirements~~As ofthe ~~property,~~plan ~~plant~~assets ~~and~~are ~~equipment~~not ~~made prior~~legally tosegregated ~~2000.~~and ~~The~~we ~~correction~~are not ofcontractually ~~the~~required ~~error~~to ~~resulted~~assume inthese ~~a decrease~~obligations toupon ~~miscellaneous~~withdrawal, ~~other~~we ~~income~~have ofnow ~~$4.7 million~~concluded ~~and~~that athe ~~decrease~~appropriate toaccounting ~~net~~model ~~income~~for ofthese ~~$3.0 million~~historical ~~during~~financial ~~2006~~statements is a multi-employer model.

In We ~~the~~participate ~~fourth~~in ~~quarter~~pension ofand ~~2006~~postretirement benefit plans sponsored by Williams. However, we have ~~made~~historically ~~adjustments~~accounted tofor ~~correct~~these plans as if they were our own. We have now determined that ~~errors~~ASC ~~related~~715-30-55-63 requires us to account for the ~~accounting~~plans as if we are a participant in a multi-employer plan. This error in methodology had the most significant impact to our financial statements for the year ended December 31, 2008. In that year, we recognized a significant Williams-allocated actuarial loss on our ~~headquarters~~Consolidated ~~building~~Balance Sheet, Consolidated Statement of ~~lease~~Owners’ ~~expense~~Equity and ~~depreciation~~Consolidated Statement of ~~leasehold~~Comprehensive ~~improvements~~Income. ~~The~~We have determined that the ~~correction~~error was significant to the Statement of Comprehensive Income for the ~~errors~~year ~~resulted~~ended inDecember 31, 2008. aFor ~~decrease~~this toperiod, ~~general~~Comprehensive ~~and~~Income should have approximated Net Income. The effect of ~~administrative~~the ~~expense~~adjustments to Comprehensive Income is an increase of $639.4 million in 2008 and $2.4 million in 2007, respectively. The impact of this error correction also increased Owners’ Equity and reduced noncurrent assets and liabilities at December 31, 2008, with an ~~increase~~offsetting impact to Loans to ~~depreciation~~Affiliate, ~~expense~~which ofis $2presented as a reduction to Owners’ Equity (See Note 1).~~9 million~~ ~~and~~The impact of the error correction did not have an ~~increase~~impact toon our 2008 or 2007 Net Income ofas ~~$2.1 million~~our ~~during~~expense ~~2006~~recognized approximated our contributions to the Williams’-sponsored plans, nor did it have any impact on our 2008 or 2007 Consolidated Statements of Cash Flows.

~~Note 2. Rate and Regulatory Matters~~83

Parachute Lateral Project

We placed our Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, we filed an application with FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (“Parachute”), which is owned by an affiliate of Williams. This application was approved by the FERC on November 15, 2007, and we completed the transfer of the Parachute Lateral on December 31, 2007. We received cash proceeds of $79.8 million from Parachute equal to the net book value of the net assets transferred, and subsequently made a distribution to Williams in an equal amount. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. Prior to the transfer of the facilities, we reassessed the probability of recovering certain regulatory assets associated with the Parachute Lateral and concluded that with the change of ownership it was not probable that these assets would be recovered in future rates. In the fourth quarter 2007, $2.8 million of these assets were charged to expense.

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As The ~~contemplated~~following inschedules ~~the~~reconcile ~~application for amendment, Parachute has leased~~ the ~~facilities~~amounts ~~back~~previously toreported ~~us.~~in Weour ~~will continue to operate~~consolidated ~~the~~Financial ~~facilities~~Statements ~~under~~as ~~FERC~~of ~~certificate. When Williams Field Services Company~~December 31, ~~LLC~~2008 ~~completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate,~~ and ~~Parachute will assume full operational control and responsibility~~ for the ~~Parachute~~years ~~Lateral.~~ended ~~Under the terms of the lease~~December 31, we2008 ~~pay~~and ~~Parachute monthly rent equal to the revenues collected from transportation services on the Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral~~2007.

Note 3. Contingent Liabilities and Commitments


	December 31,
	2008
	(Thousands of
	dollars)

Consolidated Balance Sheet:

Deferred charges, as previously reported	$	22,213
Correction to remove benefit plan assets		3,360

Deferred charges, as restated	$	18,853


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

Total other assets, as restated	$	74,435


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

Total assets, as restated	$	2,078,812


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

Employee costs, as restated	$	10,426


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

Total current liabilities, as restated	$	68,930


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

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


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

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


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

Accumulated other comprehensive income, as restated	$	462


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

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


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

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

84 ~~Legal Proceedings~~

In 1998, the United States Department of Justice (“DOJ”) informed Williams that Jack Grynberg, an individual, had filed claims on behalf of himself and the federal government, in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries, including us. The claims sought an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorney’s fees and costs. Grynberg had also filed claims against approximately 300 other energy companies alleging that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. In 1999, the DOJ announced that it would not intervene in any of the Grynberg cases. Also in 1999, the Panel on Multi-District Litigation transferred all of these cases, including those filed against us, to the federal court in Wyoming for pre-trial purposes. The District Court dismissed all claims against Williams and its wholly-owned subsidiaries, including us. The matter is on appeal to the Tenth Circuit Court of Appeals.

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that it is in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (“PCB”), contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (“EPA”) in the late 1980s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous mercury clean-ups in Washington. Currently, we are conducting assessment and remediation activities needed to bring the sites up to Washington’s current environmental standards. At December 31, 2008, we had accrued liabilities totaling approximately $9.2 million for these costs which are expected to be incurred through 2014. The increase from prior year accruals is due to the completion of assessments at certain compressor station facilities. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. We consider these costs associated with compliance with environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

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

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


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

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

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


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

Balance at beginning of period, as restated		523			365
Cash flow hedges:
Reclassification of gain into earnings		(61	)		(62	)
Elimination of deferred income taxes		—			220

Balance at end of period	$	462		$	523


	Years Ended December 31,
	2008			2007
	(Thousands of dollars)
Consolidated Statements of Comprehensive Income:
Total comprehensive income, as previously reported	$	115,880		$	437,444
Correction to remove benefit plans		(39,430	)		(2,440	)

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

Note 3. Rate and Regulatory Matters

Parachute Lateral Project

We placed our Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. On August 24, 2007, we filed an application with the FERC to amend our certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of our Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (“Parachute”), which is owned by an affiliate of Williams. This application was approved by the FERC on November 15, 2007, and we completed the transfer of the Parachute Lateral on December 31, 2007. We received cash proceeds of $79.8 million from Parachute equal to the net book value of the net assets transferred, and subsequently made a distribution to Williams in an equal amount. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado. Prior to the transfer of the facilities, we reassessed the probability of recovering certain regulatory assets associated with the Parachute Lateral and concluded that with the change of ownership it was not probable that these assets would be recovered in future rates. In the fourth quarter 2007, $2.8 million of these assets were charged to expense.

As contemplated in the application for amendment, Parachute leased the facilities back to us, and we continued to operate the facilities under the FERC certificate. Under the terms of the lease, we paid Parachute monthly rent equal to the revenues collected from transportation services on the lateral, less 3 percent to cover costs related to the operation of the lateral. The lease was terminated on August 1, 2009, and Parachute assumed full operational control and responsibility for the Parachute Lateral.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4. Contingent Liabilities and Commitments

Legal Proceedings

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

Environmental Matters

We are subject to the National Environmental Policy Act and other federal and state legislation regulating the environmental aspects of our business. Except as discussed below, our management believes that we are in substantial compliance with existing environmental requirements. Environmental expenditures are expensed or capitalized depending on their future economic benefit and potential for rate recovery. We believe that, with respect to any expenditures required to meet applicable standards and regulations, FERC would grant the requisite rate relief so that substantially all of such expenditures would be permitted to be recovered through rates. We believe that compliance with applicable environmental requirements is not likely to have a material effect upon our financial position or results of operations.

Beginning in the mid-1980s, we evaluated many of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation might be necessary. We identified polychlorinated biphenyl (“PCB”), contamination in air compressor systems, soils and related properties at certain compressor station sites. Similarly, we identified hydrocarbon impacts at these facilities due to the former use of earthen pits and mercury contamination at certain natural gas metering sites. The PCBs were remediated pursuant to a Consent Decree with the U.S. Environmental Protection Agency (“EPA”) in the late 1980s and we conducted a voluntary clean-up of the hydrocarbon and mercury impacts in the early 1990s. In 2005, the Washington Department of Ecology required us to re-evaluate our previous mercury clean-ups in Washington. Currently, we are conducting assessment and remediation activities needed to bring the sites up to Washington’s current environmental standards. At December 31, 2009, we had accrued liabilities totaling approximately $7.8 million for these costs which are expected to be incurred through 2015. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. We consider these costs associated with compliance with environmental laws and regulations to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.

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

Safety Matters

Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration ~~(“DOT PHMSA”)~~ final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high ~~consequence~~ consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and associated remediation will be primarily capital in nature and range between $~~120~~ 65 million and $~~145~~85 million over the remaining assessment period of ~~2009~~2010 through 2012. ~~The cost estimates have been revised to reflect refinements in the scope of required remediation and for increases in assessment and remediation costs.~~ Our management considers the costs associated with compliance with the rule to be prudent costs incurred in ~~the~~ the ordinary course of business and, therefore, recoverable through our rates.

Other Matters

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summary

Litigation, arbitration, regulatory matters, environmental matters, and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists ~~the~~ 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~~ approximately $1213.4 million at December 31, ~~2008~~2009.

Cash Distributions to Partners

On or before the end of the calendar month following each quarter, beginning after the end of the first quarter 2008, available cash is distributed to our partners as required by our general partnership agreement. Available cash with respect to any quarter is generally defined as the sum of all cash and cash equivalents on hand at the end of the quarter, plus cash on hand from working capital borrowings made subsequent to the end of that quarter (as determined by the management committee), less cash reserves as established by the management committee as necessary or appropriate for the conduct of our business and to comply with any applicable law or agreement.

In ~~January~~accordance ~~2008,~~with weWilliams’ ~~received~~restructuring ~~net~~of ~~proceeds~~its ofbusiness, ~~$300.9 million from~~our participation in the Williams’ cash ~~Pipeline~~management ~~Partners~~program Lwas terminated.P. ~~for~~In ~~its~~February 2010, ~~purchase~~our ofmanagement acommittee authorized ~~partnership~~a ~~interest~~cash ~~and~~distribution wewhich ~~made~~included athe ~~distribution~~amount of ~~$300.9 million~~ toour ~~Williams.~~outstanding ~~During~~advances ~~the~~as ~~year~~of ~~ended~~January 31, 2010. Accordingly, the balance outstanding at December 31, ~~2008,~~2009 weis ~~declared~~reflected ~~and~~as ~~paid~~a ~~equity distributions~~reduction of ~~$118.4 million~~our Owners’ toEquity ~~our~~as ~~partners,~~the ~~including $8.8 million~~advances towill ~~Williams~~not ~~representing~~be available ~~cash prior~~ to ~~Williams~~us ~~Pipeline~~as ~~Partners~~working Lcapital.~~P.’s~~ ~~acquisition~~As a result of ~~its~~the restructuring, we will become a participant in the WPZ cash management program.

In January 2008, we received net proceeds of $300.9 million from Williams Pipeline Partners L.P. for its purchase of a partnership interest and we made a distribution of $300.9 million to 83Williams. During the year ended December 31, 2008, we declared and paid equity distributions of $118.4 million to our partners, including $8.8 million to Williams representing available cash prior to Williams Pipeline Partners L.P.’s acquisition of its interest in us. Of this amount, $7.8 million represents the portion allocated to our partners prior to the acquisition. During the year ended December 31, 2009, we declared and paid equity distributions of $135.0 million to our partners. In January 2010, we declared and paid equity distributions of $36.0 million to our partners.

~~Table~~Note of5. ~~Contents~~Debt, Financing Arrangements and Leases

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4. Debt, Financing Arrangements and Leases

Debt Covenants

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

Long-Term Debt

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

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

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

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

Long-term debt consists of the following:

	December 31,
	2008		2007
	(Thousands of dollars)
5.95%, payable 2017	$	184,471	$	184,407
6.05%, payable 2018		249,374		—
7.00%, payable 2016		174,587		174,532
7.125%, payable 2025		84,808		84,797
Revolving credit debt, payable 2012		—		250,000
Total long-term debt	$	693,240	$	693,736

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~As of December 31, 2008, cumulative sinking fund requirements and other maturities of long~~ Long-term debt ~~(at~~consists ~~face value) for each~~ of the ~~next five years are as follows~~following:

	(Thousands of dollars)
	December 31,
~~2009~~	$2009	—	2008
2010		—
	(Thousands of dollars)
2011		—
5.95%, payable 2017	$	184,535	$	184,471
2012		—
6.05%, payable 2018		249,440		249,374
2013		—
7.00%, payable 2016		174,643		174,587
Thereafter		695,000
7.125%, payable 2025		84,819		84,808
Total	$	695,000
Total long-term debt	$	693,437	$	693,240

As of December 31, 2009, cumulative sinking fund requirements and other maturities of long-term debt (at face value) for each of the next five years are as follows:


	(Thousands of dollars)
2010	$	—
2011		—
2012		—
2013		—
2014		—
Thereafter		695,000

Total	$	695,000

Line-of-Credit Arrangements

Williams has an unsecured, $1.5 billion ~~revolving~~ credit ~~agreement~~ ~~that~~facility ~~terminates in May 2012~~ (“Credit Facility”) with a maturity date of May 1, 2012. WePrior ~~have~~to Williams’ restructuring, we had access to $400 million under the ~~agreement~~ Credit Facility to the extent not otherwise utilized by Williams. Williams expects that its ability to borrow under the Credit Facility is reduced by $70 million due to the bankruptcy of a participating bank. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. Interest is calculated based on a choice of two methods: a fluctuating rate equal to the lender’s base rate plus an applicable margin, or a periodic fixed rate equal to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin. Williams is required to pay a commitment fee (currently 0.125 percent ~~per annum~~) based on the unused portion of the ~~agreement~~ Credit Facility. The ~~applicable~~margins ~~margin~~and iscommitment fee are generally based on the specific borrower’s senior unsecured long-term debt ratings. ~~Letters of~~As ~~credit totaling approximately $71~~of December ~~million~~31, ~~none~~2009, ofthere ~~which are~~were ~~associated~~no ~~with~~letters ~~us,~~of ~~have~~credit ~~been~~ issued by the participating institutions. ~~There~~and ~~were~~ no revolving credit loans outstanding ~~as of December 31, 2008~~. In December 2007, we borrowed $250.0 million under this agreement to repay $250.0 million in 6.625 percent senior notes at maturity. In May 2008, the loan of $250.0 million was repaid with proceeds from the issuance of $250.0 million of 6.05 percent senior unsecured notes due 2018. We did not access the ~~agreement~~Credit Facility in 2009 or 2008.

~~Lehman~~ Significant ~~Commercial~~financial ~~Paper~~covenants ~~Inc.,~~under ~~which was committed to fund up to $70 million of~~ the Credit Facility, ~~has~~include ~~filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under~~ the ~~Credit Facility is~~following: ~~reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by this reduction.~~

Significant financial covenants under the credit agreement include the following:

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

	•		Our ratio of debt to capitalization and that of another participating subsidiary of Williams must be no greater than 55 percent. We were in compliance with this covenant at December 31, 2009.

	•	Williams’ ratio of debt to capitalization must be no greater than 65 percent. Williams was in compliance with this covenant at December 31, 2008.
	•	Our ratio of debt to capitalization and that of another participating subsidiary of Williams must be no greater than 55 percent. We were in compliance with this covenant at December 31, 2008.

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

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

The major operating lease is a leveraged lease for our headquarters building, which became effective during 1982. The agreement has an initial term of approximately 27 years, with options for consecutive renewal terms of approximately 9 years and 10 years. As required by the terms of the lease, we have exercised our option to renew the term of the lease for approximately 9 years, beginning October 1, 2009. The major component of the lease payment is set through the initial and first renewal terms of the lease. Various purchase options exist under the building lease, including options involving adverse regulatory developments.

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

WeLIBOR ~~sublease~~plus ~~portions~~the applicable margin. The adjusted base rate will be the highest of ~~our~~(i) the federal ~~headquarters~~funds ~~building~~rate toplus ~~third~~0.5 percent, (ii) Citibank, N.A.’s publicly announced base rate, and (iii) ~~parties~~one-month ~~under~~LIBOR ~~agreements~~plus ~~with~~1.0 percent. ~~varying~~WPZ ~~terms~~pays a commitment fee (currently 0.5 ~~Following~~percent) ~~are~~based on the ~~estimated~~unused ~~future~~portion ~~minimum~~of ~~annual~~the ~~rental~~New ~~payments~~Credit ~~required~~Facility. ~~under operating~~The ~~leases,~~applicable ~~which~~margin ~~have~~and ~~initial~~the orcommitment ~~remaining~~fee ~~noncancelable~~are ~~lease~~determined ~~terms~~by inreference ~~excess~~to ofa ~~one~~pricing ~~year:~~schedule based on a borrower’s senior unsecured debt ratings.

	(Thousands of dollars)
2009	$	6,369
2010		3,749
2011		3,749
2012		3,749
2013		3,749
		21,365
Less: noncancelable subleases		2,819
Total	$	18,546

~~Operating~~ Under ~~lease~~the ~~rental~~New ~~expense~~Credit Facility, ~~net~~WPZ ofis ~~sublease~~required ~~revenues, amounted~~to maintain a ratio of debt to ~~$4.9 million~~Earnings Before Income Taxes, ~~$4.9 million~~Interest, Depreciation and Amortization ($“EBITDA”) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.~~2) million~~00 for ~~2008,~~itself ~~2007~~and its consolidated subsidiaries. For us and our ~~2006~~consolidated subsidiaries, ~~respectively.~~the ratio of debt to capitalization (~~See~~defined as net worth plus debt) ~~Note~~is not permitted to be greater than 55 1percent. Each of the above ratios will be tested beginning June —30, ~~Reclassifications~~2010 at the end of each fiscal quarter, and ~~Adjustments~~the debt to EBITDA ratio is measured on a rolling four-quarter basis.)

On The ~~December 31,~~New ~~2007,~~Credit inFacility ~~connection~~includes ~~with~~customary ~~the~~events ~~sale~~ of ~~Parachute~~ todefault, anincluding ~~affiliate~~events of ~~Williams,~~default relating ~~Parachute~~to ~~leased~~non-payment ~~the facilities~~of ~~back~~principal, tointerest ~~us.~~or Wefees, ~~continue~~inaccuracy toof ~~operate~~representations ~~the facilities~~and ~~under~~warranties ~~the~~in ~~FERC~~any ~~certificate.~~material ~~When~~respect ~~Williams~~when ~~Field~~made ~~Services Company,~~or ~~LLC~~when ~~completes~~deemed ~~its~~made, violation ~~Willow~~of ~~Creek~~covenants, ~~Processing~~cross-payment ~~Plant~~defaults, ~~the lease~~cross ~~(subject~~acceleration, tobankruptcy ~~further~~and ~~regulatory~~insolvency ~~approval)~~events, ~~will~~certain ~~terminate.~~unsatisfied ~~Under~~judgments ~~the~~and ~~terms~~a change of ~~the~~control. ~~lease,~~If wean ~~pay~~event ~~Parachute~~of ~~monthly~~default ~~rent equal~~with respect to ~~the~~a ~~revenues~~borrower ~~collected~~occurs ~~from transportation services on~~under the ~~Parachute~~New ~~Lateral~~Credit Facility, ~~less~~the ~~3 percent~~lenders towill ~~cover~~be ~~costs related~~able to ~~the~~terminate ~~operation of~~ the ~~lateral.~~commitments ~~This~~for ~~operating~~all ~~lease is~~borrowers ~~not~~and ~~included~~accelerate in the ~~future~~maturity ~~minimum~~of ~~annual~~the ~~rental~~loans ~~payments~~of ~~shown above~~the ~~due~~defaulting toborrower under the ~~contingent~~New ~~nature~~Credit ofFacility and ~~the~~exercise ~~Parachute~~other ~~lease payments~~rights and remedies.

~~Note 5. Employee Benefit Plans~~Leases

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

We Through ~~participate~~September 30, in2009, ~~Williams’~~the ~~sponsored~~major ~~noncontributory defined~~operating ~~benefit~~lease ~~pension~~was ~~plans~~a ~~along~~leveraged ~~with~~lease ~~Williams~~for ~~and its~~our ~~subsidiaries~~headquarters ~~that~~building, ~~provide~~which ~~pension~~became ~~benefits~~effective ~~for~~during ~~eligible participant employees~~1982. ~~Cash~~The ~~contributions~~agreement ~~related~~had toan ~~our participation~~initial interm ~~the~~of approximately ~~plans totaled $7.7~~27 ~~million in 2008~~years, ~~$3.1 million~~ inwith ~~2007~~options ~~and~~for ~~$3.3 million~~consecutive inrenewal ~~2006.~~terms ~~We expensed~~of ~~$3.5 million~~approximately ~~in 2008, $4.0~~9 ~~million~~years ~~in 2007~~ and $310 years.~~5 million~~ inAs ~~2006.~~required ~~For~~by the ~~tax-qualified~~terms ~~pension plans~~of the lease, we ~~had~~exercised ~~historically~~our ~~recorded~~option ato ~~regulatory~~renew ~~asset~~the ~~or liability~~term ~~for~~of the lease ~~difference~~for ~~between~~approximately ~~pension~~9 years, ~~expense~~beginning ~~as estimated under SFAS~~October 871, ~~and~~2009. ~~the~~The ~~amount~~major wecomponent ~~funded~~of asthe alease ~~contribution~~payment towas ~~the~~set ~~pension~~through ~~plans.~~the Ininitial ~~the~~and ~~second~~first ~~quarter~~renewal terms of ~~2007,~~ wethe ~~recorded $16~~lease.~~6 million~~ inVarious ~~income~~purchase ~~for~~options existed aunder ~~change~~the ~~in accounting~~building ~~estimate~~lease, ~~related~~including tooptions ~~this~~involving ~~pension~~adverse regulatory ~~liability~~ developments. Through AsSeptember 30, ~~a result of additional information~~2009, ~~including~~we ~~the most~~subleased ~~recent~~portions ~~rate~~of ~~filing,~~our weheadquarters ~~re-assessed~~building ~~the~~to ~~probability~~third ofparties ~~refunding~~under oragreements ~~recovering~~with ~~this~~varying ~~difference~~terms. ~~and~~This ~~concluded~~leveraged ~~that~~lease ~~it was~~for ~~not~~our ~~probable~~headquarters ~~that~~building itwas assigned ~~would~~to bea ~~refundable~~third orparty ~~recoverable~~effective ~~in future~~October 1, ~~rates~~2009.

Effective October 1, 2009, we entered into an agreement to lease office space from a third ~~Accumulated~~party. ~~other~~The ~~comprehensive~~agreement ~~loss~~has atan ~~December~~initial term of approximately 10 31years, ~~2008~~with an option to renew for an ~~and~~additional ~~2007,~~5 ~~includes~~or ~~the~~10 year ~~following:~~term.

	Pension Benefits
	2008			2007
	(Thousands of dollars)
Amounts not yet recognized in net periodic benefit expense:
Prior service cost	$	(339	)	$	(417	)
Net actuarial losses		(59,759	)		(20,251	)

Following are the estimated future minimum annual rental payments required under operating leases, which have initial or remaining noncancelable lease terms in excess of one year:


	(Thousands of dollars)
2010	$	2,284
2011		2,284
2012		2,284
2013		2,284
2014		2,285

Total	$	11,421

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Net~~ On ~~actuarial~~December 31, ~~losses~~2007, in connection with the sale of ~~$3,848~~Parachute ~~thousand~~to ~~and~~an ~~prior~~affiliate ~~services~~of ~~costs~~Williams, ofParachute ~~$82~~leased ~~thousand~~the ~~related~~facilities back to ~~the~~us. ~~pension~~We ~~plans~~continued ~~that~~to ~~are~~operate ~~included in~~the ~~accumulated~~facilities ~~other~~under ~~comprehensive~~the ~~loss~~FERC certificate atthrough ~~December~~July 31, 2009. The lease terminated on August 1, 2009. Under the terms of the ~~2008~~lease, ~~are~~we ~~expected~~paid Parachute monthly rent equal to bethe ~~amortized~~revenues incollected ~~net~~from ~~periodic~~transportation ~~benefit~~services ~~expense~~on inthe ~~2009~~Parachute Lateral, less 3 percent to cover costs related to the operation of the lateral.

~~Postretirement Benefits~~Note ~~Other~~6. ~~than~~Employee ~~Pensions~~Benefit Plans

WePension ~~participate in a Williams sponsored plan along with Williams~~ and ~~its~~Other ~~subsidiaries~~Postretirement ~~that~~Benefit provides certain retiree health care and life insurance benefits for our eligible participants that were hired prior to January 1, 1992. The accounting for the plan anticipates future cost-sharing changes to the plan that are consistent with Williams’ expressed intent to increase the retiree contribution level, generally in line with health care cost increases. Cash contributions totaled $0.1 million in 2008 and 2007 and $2.4 million in 2006. We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to a regulatory asset or liability and any unrecovered amounts will be collected through future rate adjustments. The amounts of postretirement benefits costs deferred as a regulatory liability at December 31, 2008 and 2007 are $2.9 million and $17.8 million, respectively. No expense was recorded in 2008 or 2007. We expensed $2.3 million in 2006. Plans

At We ~~December 31,~~participate ~~2008,~~in ~~regulatory~~pension ~~liabilities~~and ~~include~~other ~~prior service~~postretirement ~~credits~~benefit ofplans $2sponsored by Williams.~~8 million~~ ~~and~~We account ~~net~~for ~~actuarial~~these ~~losses~~plans ~~of $14.6 million~~on ~~related~~the tomulti-employer ~~other~~accounting ~~postretirement~~model ~~benefit plans.~~in ~~These~~which we expense the amounts billed ~~have~~to ~~not~~us ~~yet~~by ~~been~~Williams ~~recognized~~or inother ~~net periodic~~Williams’ ~~benefit~~affiliates ~~expense.~~for Atour ~~December 31,~~participation ~~2007,~~in ~~regulatory liabilities~~these ~~included~~plans. ~~prior~~We recognized ~~service~~pension ~~costs~~expense of $27.65 million ~~and~~ ~~net~~in ~~actuarial~~2009, ~~gains~~$3.5 million ofin 2008 and $6.4.0 million ~~related~~in to2007. No other postretirement benefit ~~plans~~expense was recognized in 2009, 2008 or 2007.

Defined Contribution Plan

Employees participate in a Williams’ defined contribution plan. We recognized compensation expense of $2.12 million in ~~2008~~ 2009, $2.01 million in ~~2007~~2008 and $12.80 million in ~~2006~~2007 for Williams’ company matching contributions to this plan.

Stock-Based Compensation

Plan Information

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

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

Accounting for Stock-Based Compensation

Compensation cost for share-based ~~payments~~awards is based on the grant date fair value. ~~Total~~The performance ~~stock-based~~targets ~~compensation~~for ~~expense, included~~certain inperformance ~~administrative~~based ~~and~~restricted ~~general~~stock ~~expenses,~~units ~~for~~have ~~the~~not ~~years~~been established ~~ended~~and ~~December 31~~therefore, ~~2008,~~expense ~~2007~~is ~~and~~not ~~2006~~currently ~~was $1~~recognized.~~0 million,~~ ~~$1.1 million~~Expense ~~and~~associated ~~$0.9 million,~~with these ~~respectively,~~performance-based ~~excluding~~awards ~~amounts~~will ~~allocated~~be ~~from~~recognized ~~WGP~~in ~~and~~future ~~Williams~~periods when performance targets are established.

~~Note~~ Total 6stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2009, 2008 and 2007 was $1.3 million, ~~Income~~$1.0 million ~~Taxes~~and $1.1 million, respectively, excluding amounts allocated from WGP and Williams.

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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~The~~Note ~~provision~~7. ~~(benefit)~~Income ~~for income taxes includes:~~Taxes

	Years Ended December 31,
	2008		2007			2006
	(Thousands of dollars)
Current:
Federal	$	—	$	30,888		$	2,940
State		—		3,674			350
		—		34,562			3,290
Deferred:
Federal		—		(258,459	)		24,945
State		—		(30,770	)		2,971
		—		(289,229	)		27,916
Total provision (benefit)	$	—	$	(254,667	)	$	31,206

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

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

	Years Ended December 31,
	2008			2007			2006
	2009			2008			2007
	(Thousands of dollars)
Provision at statutory Federal income tax rate of 35 percent(1)	$	—		$	52,831		$	29,984
Current:
Increase (decrease) in tax provision resulting from -
Federal	$	—		$	—		$	30,888
State income taxes net of Federal tax benefit		—			3,948			2,159
State		—			—			3,674
Book/tax basis reconciliation adjustment		—			—			(723	)
		—			—			34,562
Other — net		—			330			(214	)
Deferred:
Provision for income taxes prior to conversion from a corporation to a partnership	$	—		$	57,109		$	31,206
Federal		—			—			(258,459	)
Effective tax rate prior to conversion from a corporation to a partnership		—	%		37.83	%		36.43	%
State		—			—			(30,770	)
Provision for income taxes prior to conversion from a corporation to a partnership	$	—		$	57,109		$	31,206
		—			—			(289,229	)
Conversion from a corporation to a partnership		—			(311,776	)		—
Total benefit	$	—		$	—		$	(254,667	)
Total provision (benefit) for income taxes	$	—		$	(254,667	)	$	31,206

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


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

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

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

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

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


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

~~Prior~~ No tocash ~~our~~payments ~~conversion to a general partnership, we provided~~ for income taxes ~~using~~were ~~the~~made ~~asset~~to ~~and~~or ~~liability~~received ~~method~~from ~~as required~~Williams byin ~~SFAS 109,~~2009 ~~“Accounting~~or ~~for Income Taxes,” through September 30, 2007~~2008. ~~During 2006, as a~~Net ~~result~~cash ofpayments ~~additional~~(received ~~analysis~~from) ofmade ~~our~~to ~~tax~~Williams ~~basis~~for ~~and~~income ~~book~~taxes ~~basis assets~~were ~~and liabilities, we recorded a~~ $037.7 million ~~tax benefit~~in ~~adjustment to reduce the overall deferred income tax liabilities on the Balance Sheet~~2007. ~~Management concluded that the~~ ~~effect of this correction was not material to prior annual or interim periods, to 2006 results, or to the trend of earnings.~~

Note 8. Financial Instruments 88

Fair Value of Financial Instruments

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

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

Long-term debt — The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings. The

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Nocarrying ~~cash~~amount ~~payments~~and ~~for~~estimated ~~income~~fair ~~taxes~~value ~~were~~of ~~made~~our tolong orterm ~~received~~debt, ~~from Williams~~including incurrent ~~2008~~maturities, were $693.4 million ~~Net~~and ~~cash~~$753.2 million, ~~payments~~respectively, ~~(received~~at ~~from)~~December 31, ~~made~~2009, ~~to Williams~~and ~~for income taxes were~~ $37693.72 million and ($1572.3)0 million, inrespectively, ~~2007~~at ~~and 2006~~December 31, ~~respectively~~2008.

Note 79. ~~Financial~~Transactions ~~Instruments~~with Major Customers and Affiliates

Disclosures About the Fair Value of Financial Instruments

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

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

Long-term debt — The fair value of our publicly traded long-term debt is valued using indicative year-end traded bond market prices. Private debt is valued based on market rates and the prices of similar securities with similar terms and credit ratings. The carrying amount and estimated fair value of our long term debt, including current maturities, were $693.2 million and $572.0 million, respectively, at December 31, 2008, and $693.7 million and $710.9 million, respectively, at December 31, 2007.

Note 8. Transactions with Major Customers and Affiliates

Concentration of Off-Balance Sheet and Other Credit Risk

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

	Years Ended December 31,
	2008		2007				2006
	2009				2008				2007
	(Thousands of dollars)
Puget Sound Energy, Inc.	$~~89,988~~	94,508	$	~~85,059~~	$	89,988	$	~~64,428~~	$	85,059
Northwest Natural Gas Co.	~~(a)~~	49,256		~~48,648~~		(a	)	~~35,242~~		48,648


(a)		Under 10 percent in 2008.

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

Related Party Transactions

As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At December 31, ~~2008~~2009 and ~~2007~~2008, the advances due to us by Williams totaled approximately $66.08 million and $3966.10 million, respectively. The advances are represented by by demand notes. Historically, the interest rate on intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter, which was 7.83 percent at December 31, 2007. Beginning in 2008, the interest rate on these demand notes was based ~~upon~~ upon the overnight investment rate paid on Williams’ excess cash, which was approximately 0.05 percent and zero percent at December 31, 2009 and 2008, respectively. We received interest income from advances to Williams of $~~0.8 million~~74 thousand, $~~3.0 million~~813 thousand, and $~~3.9 million~~ 2,983 thousand during ~~2008~~2009, ~~2007~~2008 and ~~2006~~ 2007, respectively. Such interest income is included in “Other Income — net: Interest income — Affiliated” on the accompanying Consolidated Statements of ~~Statement~~Income. In accordance with Williams’ restructuring of ~~Income~~its business, our participation in the Williams’ cash management program was terminated. In February 2010, our management committee authorized a cash distribution which included the amount of our outstanding advances as of January 31, 2010. Accordingly, the balance outstanding at December 31, 2009 is reflected as a reduction of our Owners’ Equity as the advances will not be available to us as working capital. As a result of the restructuring, we will become a participant in the WPZ cash management program.

Williams’ corporate overhead expenses allocated to us were $1619.97 million, $1916.69 million and $1819.76 million for ~~2008~~2009, ~~2007~~2008 and ~~2006~~2007, respectively. Such expenses have been allocated to us by Williams primarily based on the Modified Massachusetts formula, which is a FERC -approved method ~~utilizing~~ utilizing a combination of net revenues, gross payroll and gross plant for the allocation base. In addition, Williams or an affiliate has provided executive, data processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $16.3 million, $15.8 million and $16.6 million for 2009, 2008 and 2007, respectively. These expenses are included in “General and administrative expense” on the accompanying Consolidated Statements of Income. A portion of such expenses relates to the compensation of our principal executive officer, principal financial officer and three other most highly compensated officers (our Named Executive Officers or NEOs).

During the periods presented, our revenues include transportation transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities 89totaled $9.9 million, $14.8 million and $11.8 million for 2009, 2008 and 2007, respectively.

From January 2008 through July 2009, we leased the Parachute Lateral facilities from an affiliate. Under the terms of the operating lease, we paid monthly rent equal to the revenues collected from transportation services on the lateral, less 3 percent to cover costs related to the operation of the lateral. This lease expense, totaling $5.9 million and $10.1 million for the years ended December 31, 2009 and 2008, respectively, is included in “Operation and maintenance expense” on the accompanying Consolidated Statements of Income. The lease was terminated on August 1, 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

processing, legal, accounting, internal audit, human resources and other administrative services to us on a direct charge basis, which totaled $15.8 million, $16.6 million and $16.6 million for 2008, 2007 and 2006, respectively. These expenses are included in General and Administrative Expense on the accompanying Statement of Income.

During the periods presented, our revenues include transportation and exchange transactions and rental of communication facilities with subsidiaries of Williams. Combined revenues for these activities totaled $14.8 million, $11.8 million and $3.4 million for 2008, 2007 and 2006, respectively. The increase from 2006 to 2007 is primarily due to capacity reservation revenues of $6.7 million related to the Parachute Lateral facility which was placed into service in May 2007.

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

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

Note 910. Asset Retirement Obligations

During ~~2008~~2009 and ~~2007~~2008, we adjusted the ARO liability and Property, Plant and Equipment for a change in the inflation and discount rates.

During ~~2008~~2009 and ~~2007~~2008, our overall asset retirement obligation changed as follows (in thousands):

	2008			2007
	2009			2008
Beginning balance	$	5082,~~423~~666		$	4850,~~020~~423
Accretion		46,~~341~~068			34,~~673~~341
New obligations		~~116~~2,594			~~1,912~~116
Obligations transferred to an affiliate		—			~~(1,996~~—	)
Changes in estimates of existing obligations		27(4,~~790~~579	)		(127,~~186~~790	)
Obligation settled		(4—	)		—(4	)
Ending Balance	$	8286,~~666~~749		$	5082,~~423~~666

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

Note 1011. Regulatory Assets and Liabilities

Our regulatory assets and liabilities result from our application of the provisions of ~~SFAS 71~~Topic 980 and are reflected on our balance sheet. Current regulatory assets are included in prepayments and other. Regulatory liabilities are included in deferred credits and other noncurrent liabilities. ~~These~~ These balances are presented on our balance sheet on a gross basis and are recoverable over various periods. Below are the details of our regulatory assets and liabilities as of December 31, 2009 and 2008:


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

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

Total noncurrent regulatory assets		57,032		55,582

Total regulatory assets	$	59,232	$	57,782

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

Total regulatory liabilities	$	15,134	$	14,652

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

	2008		2007
	(Thousands of dollars)
Current regulatory assets — environmental costs	$	2,200	$	2,200
Non-current regulatory assets
Environmental costs		5,790		4,841
Grossed-up deferred taxes on equity funds used during construction		19,234		20,122
Levelized incremental depreciation		28,397		25,780
Asset retirement obligations, net		1,189		—
Other postemployment benefits		972		1,329
Total non-current regulatory assets		55,582		52,072
Total regulatory assets	$	57,782	$	54,272
Non-current regulatory liabilities
Asset retirement obligations, net	$	—	$	10
Postretirement benefits		2,888		17,806
Total regulatory liabilities	$	2,888	$	17,816

Note 11. Accumulated Other Comprehensive Loss

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

	2008			2007
	(Thousands of dollars)
Cash flow hedges	$	462		$	523
Pension Benefits		(60,098	)		(20,668	)
Accumulated other comprehensive loss before taxes		(59,636	)		(20,145	)
Deferred income taxes		—			—
Total accumulated other comprehensive loss	$	(59,636	)	$	(20,145	)

Note 12. Quarterly Information (Unaudited)

The following is a summary of unaudited quarterly financial data for ~~2008~~2009 and ~~2007~~2008:

Quarter of 2008

Quarter of 2009

First

Second

Third

Fourth

(Thousands of dollars)

~~(Thousands of dollars)~~

Operating revenues

~~107~~111,~~405~~548

~~106~~107,~~450~~756

~~108~~106,~~452~~615

~~112~~108,~~457~~460

Operating income

4953,~~166~~152

4647,~~676~~013

5349,~~042~~145

5251,~~294~~199

Net income

3840,~~158~~908

35,~~685~~162

4138,~~236~~260

4039,~~292~~321


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

NORTHWEST PIPELINE GP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

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

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

None.

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

Disclosure Controls and Procedures

Our management, including our general partner’s Chief Executive Officer and Chief Financial

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Filing Compare · WILLIAMS PIPELINE PARTNERS L.P.