UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

OR

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

For the transition period from            to            

Commission file number 1-32599

WILLIAMS PARTNERS L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	20-2485124
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
One Williams Center, Tulsa, Oklahoma	74172-0172
(Address of Principal Executive Offices)	(Zip Code)

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Units	New York Stock Exchange

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

None

(Title of Class)

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

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  ¨    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  ¨

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

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

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

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

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

The aggregate market value of the registrant’s common units held by non-affiliates based on the closing sale price of such units as reported on the New York Stock Exchange, as of the last business day of the registrant’s most recently completed second quarter was approximately $3,968,507,019. This figure excludes common units beneficially owned by the directors and executive officers of Williams Partners GP LLC, our general partner.

The registrant had 305,008,540 common units outstanding as of February 23, 2012.

DOCUMENTS INCORPORATED BY REFERENCE

None

WILLIAMS PARTNERS L.P.

FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		3
	Website Access to Reports and Other Information		3
	General		3
	Recent Events		3
	Financial Information About Segments		3
	Business Segments		4
	Gas Pipeline		4
	Midstream Gas & Liquids		7
	Regulatory Matters		12
	Environmental Matters		13
	Competition		13
	Employees		14
	Financial Information about Geographic Areas		14
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		43
Item 2.	Properties		43
Item 3.	Legal Proceedings		43
Item 4.	Mine Safety Disclosures		44
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		45
Item 6.	Selected Financial Data		47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		48
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		71
Item 8.	Financial Statements and Supplementary Data		73
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		113
Item 9A.	Controls and Procedures		113
Item 9B.	Other Information		113
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		114
Item 11.	Executive Compensation		121
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		126
Item 13.	Certain Relationships and Related Transactions, and Director Independence		129
Item 14.	Principal Accounting Fees and Services		134
PART IV
Item 15.	Exhibits and Financial Statement Schedules		134

1

DEFINITIONS

We use the following oil and gas measurements and industry terms in this report:

Barrel: One barrel of petroleum products equals 42 U.S. gallons.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet of natural gas per day.

British Thermal Units (Btu): When used in terms of volumes, Btu is used to refer to the amount of natural gas required to raise the temperature of one pound of water by one degree Fahrenheit at one atmospheric pressure.

Dekatherms (Dth): A unit of energy equal to one million Btus.

Mbbls/d: One thousand barrels per day.

Mdth/d: One thousand dekatherms per day.

MMBtu: One million Btus.

MMcf/d: One million cubic feet per day.

MMdth: One million dekatherms or approximately one trillion Btus.

MMdth/d: One million dekatherms per day.

TBtu: One trillion Btus.

Other definitions:

FERC: Federal Energy Regulatory Commission.

Fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products, such as ethane, propane and butane.

LNG: Liquefied natural gas. Natural gas which has been liquefied at cryogenic temperatures.

NGLs: Natural gas liquids. Natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels and gasoline additives, among other applications.

NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation and fractionation.

Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest, including principally Discovery, Gulfstream, Laurel Mountain, Aux Sable, and Overland Pass Pipeline.

Pipeline Entities: Our regulated pipeline entities, including principally Northwest Pipeline, Transco, Gulfstream, Discovery, Overland Pass Pipeline, and Black Marlin Pipeline LLC.

Throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

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PART I

Items 1. Business

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams Partners L.P. and its subsidiaries. Unless the context clearly indicates otherwise, references to “we,” “our,” and “us” include the operations of our Partially Owned Entities in which we own interests accounted for as equity investments that are not consolidated in our financial statements. When we refer to our Partially Owned Entities by name, we are referring exclusively to their businesses and operations.

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 (the Exchange Act). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC’s Internet website at www.sec.gov.

Our Internet website is www.williamslp.com. We make available free of charge through our Internet website 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 under the “Corporate Responsibility” tab. 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 Partners L.P., One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are a publicly traded Delaware limited partnership formed by The Williams Companies, Inc. (Williams) in 2005. We were formed to own, operate and acquire a diversified portfolio of complementary energy assets. We focus on natural gas transportation; gathering, treating, and processing; storage; NGL fractionation; and oil transportation. Williams owns an approximate 70 percent limited partnership interest in us and all of our 2 percent general partner interest.

Williams is an energy infrastructure company that trades on the New York Stock Exchange (NYSE) under the symbol “WMB.”

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

RECENT EVENTS

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments and approximately 7.5 million of our common units. These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. This acquisition represents a strategic platform to enhance our expansion in the Marcellus Shale by providing our customers with both operational flow assurance and marketing flexibility. (See Results of Operations – Segments, Midstream Gas & Liquids.)

FINANCIAL INFORMATION ABOUT SEGMENTS

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

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BUSINESS SEGMENTS

Operations of our businesses are located in the United States. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments:

• Gas Pipeline — this segment includes our interstate natural gas pipelines and pipeline joint venture investments.

• Midstream Gas & Liquids — this segment includes our natural gas gathering, treating and processing business and is comprised of several wholly owned and partially owned subsidiaries.

Detailed discussion of each of our business segments follows.

Gas Pipeline

We own and operate a combined total of approximately 13,700 miles of pipelines with a total annual throughput of approximately 3,000 TBtu of natural gas and peak-day delivery capacity of approximately 13 MMdth of natural gas. Gas Pipeline consists primarily of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline). Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 49 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream).

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,800-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 11 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.

Pipeline system and customers

At December 31, 2011, Transco’s system had a mainline delivery capacity of approximately 5.6 MMdth of natural gas per day from its production areas to its primary markets, including delivery capacity from the mainline to locations on its Mobile Bay Lateral. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 4.0 MMdth of natural gas per day for a system-wide delivery capacity total of approximately 9.6 MMdth of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and an LNG storage facility. Compression facilities at sea level-rated capacity total approximately 1.5 million horsepower.

Transco’s major natural gas transportation customers are public utilities and municipalities that provide service to residential, commercial, industrial and electric generation end users. Shippers on Transco’s system include public utilities, municipalities, intrastate pipelines, direct industrial users, electrical generators, gas marketers and producers. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that we own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 200 Bcf of natural gas. At December 31, 2011, our customers had stored in our facilities approximately 164 Bcf of natural gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, an LNG storage facility with 4 Bcf of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

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Transco expansion projects

The pipeline projects listed below were completed during 2011 or are future significant pipeline projects for which Transco has customer commitments.

Mobile Bay South II

The Mobile Bay South II Expansion Project involved the addition of compression at Transco’s Station 85 in Choctaw County, Alabama, and modifications to existing facilities at Transco’s Station 83 in Mobile County, Alabama, to allow Transco to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The project was placed into service in May 2011 and provides incremental firm capacity of 380 Mdth/d.

85 North

The 85 North Expansion Project involved an expansion of Transco’s existing natural gas transmission system from Station 85 in Choctaw County, Alabama, to various delivery points as far north as North Carolina. The first phase was placed into service in July 2010 and provides incremental firm capacity of 90 Mdth/d, and the second phase was placed into service in May 2011 and provides incremental firm capacity of 219 Mdth/d.

Mid-South

The Mid-South Expansion Project involves an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama, to markets as far downstream as North Carolina. In August 2011, Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $217 million. Transco plans to place the project into service in phases in September 2012 and June 2013, and it is expected to increase capacity by 225 Mdth/d.

Mid-Atlantic Connector

The Mid-Atlantic Connector Project involves an expansion of Transco’s mainline from an existing interconnection in North Carolina to markets as far downstream as Maryland. In July 2011, Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $55 million. Transco plans to place the project into service in November 2012, and it is expected to increase capacity by 142 Mdth/d.

Northeast Supply Link

In December 2011, Transco filed an application with the FERC to expand its existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The capital cost of the project is estimated to be approximately $341 million. Transco plans to place the project into service in November 2013, and it is expected to increase capacity by 250 Mdth/d.

Rockaway Delivery Lateral

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to a distribution system in New York. Transco anticipates filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $182 million. Transco plans to place the project into service as early as April 2014, and its capacity is expected to be 647 Mdth/d.

Northeast Connector

The Northeast Connector Project involves expansion of Transco’s existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. Transco anticipates filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $39 million. Transco plans to place the project into service as early as April 2014, and it is expected to increase capacity by 100 Mdth/d.

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Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a natural gas pipeline system extending 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 Pipeline provides services for markets in California, Arizona, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon, and Washington directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2011, Northwest Pipeline’s system, having long-term firm transportation agreements including peaking service of approximately 3.8 MMdth/d, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 477,000 horsepower.

Northwest Pipeline 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 Pipeline’s firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline’s business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 13 Bcf of natural gas, which is substantially utilized for third-party natural gas, and firm delivery capability of approximately 700 MMcf/d enable Northwest Pipeline to provide storage services to its customers and to balance daily receipts and deliveries.

Northwest Pipeline expansion project

North and South Seattle Lateral Delivery Expansions

Northwest Pipeline has executed agreements with a customer to expand the North and South Seattle laterals and provide additional lateral capacity of approximately 84 Mdth/d and 74 Mdth/d, respectively. Northwest Pipeline estimates the expansion of the two laterals to cost between $28 million and $30 million. North Seattle is currently targeted for service in fall 2012 and South Seattle is currently targeted for service in fall 2013.

Gulfstream

Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. We own, through a subsidiary, a 49 percent interest in Gulfstream while Williams owns a 1 percent interest through a subsidiary. Spectra Energy Corporation, through its subsidiary, and Spectra Energy Partners, LP, owns the other 50 percent interest. We share operating responsibilities for Gulfstream with Spectra Energy Corporation.

Gulfstream Phase V

The Gulfstream Phase V expansion involved the addition of compression to provide 35 Mdth/d of incremental firm transportation capacity. The expansion was placed in service in April 2011.

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Midstream Gas & Liquids

Our Midstream Gas & Liquids segment (Midstream), one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico and Pennsylvania. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage and transportation; and (3) oil transportation. These fall within the middle of the process of taking raw natural gas and crude oil from the producing fields to the consumer.

Key variables for our business will continue to be:

• Retaining and attracting customers by continuing to provide reliable services;

• Revenue growth associated with additional infrastructure either completed or currently under construction;

• Disciplined growth in our core service areas and new step-out areas;

• Prices impacting our commodity-based activities.

Gathering, processing and treating

Our gathering systems receive natural gas from producers’ oil and natural gas wells and gather these volumes to gas processing, treating or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor, carbon dioxide and other contaminants and collect condensate, but do not extract NGLs. We are generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the BTU heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs in addition to removing water vapor, carbon dioxide and other contaminants. NGL products include:

• Ethane, primarily used in the petrochemical industry as a feedstock for ethylene production, one of the basic building blocks for plastics;

• Propane, used for heating, fuel and as a petrochemical feedstock in the production of ethylene and propylene, another building block for petrochemical-based products such as carpets, packing materials and molded plastic parts;

• Normal butane, iso-butane and natural gasoline, primarily used by the refining industry as blending stocks for motor gasoline or as a petrochemical feedstock.

  Our gas processing services generate revenues primarily from the following three types of contracts:

• Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the BTU heating value. Our customers are entitled to the NGLs produced in connection with this type of processing agreement. For the year ended December 31, 2011, 59 percent of the NGL production volumes were under fee-based contracts.

• Keep-whole: Under keep-whole contracts, we (1) process natural gas produced by customers, (2) retain some or all of the extracted NGLs as compensation for our services, (3) replace the BTU content of the retained NGLs that were extracted during processing with natural gas purchases, also known as shrink replacement gas and (4) deliver an equivalent BTU content of natural gas for customers at the plant outlet. NGLs we retain in connection with this type of processing agreement are referred to as our equity NGL production. Under these agreements, we have commodity exposure to the difference between NGL prices and natural gas prices. For the year ended December 31, 2011, 38 percent of the NGL production volumes were under keep-whole contracts.

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• Percent-of-Liquids: Under percent-of-liquids processing contracts, we (1) process natural gas produced by customers, (2) deliver to customers an agreed-upon percentage of the extracted NGLs, (3) retain a portion of the extracted NGLs as compensation for our services, and (4) deliver natural gas to customers at the plant outlet. Under this type of contract, we are not required to replace the BTU content of the retained NGLs that were extracted during processing, and are therefore only exposed to NGL price movements. NGLs we retain in connection with this type of processing agreement are also referred to as our equity NGL production. For the year ended December 31, 2011, 3 percent of the NGL production volumes were under percent-of-liquids contracts.

Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, natural gas prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Our gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2011, our facilities gathered and processed gas for approximately 210 customers. Our top 5 gathering and processing customers accounted for approximately 50 percent of our gathering and processing revenue.

Demand for our equity NGLs is affected by economic conditions and the resulting demand from industries using these commodities to produce petrochemical-based products such as plastics, carpets, packing materials and blending stocks for motor gasoline and the demand from consumers using these commodities for heating and fuel. NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks.

Geographically, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with Williams’ and our other assets. For example, most of our offshore gathering and processing assets attach, and process or condition natural gas supplies delivered, to the Transco pipeline. Our San Juan basin, southwest Wyoming and Piceance systems are capable of delivering residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems. Our gathering system in Pennsylvania delivers residue gas volumes into Transco’s pipeline in addition to third-party interstate systems.

We own and operate gas gathering, processing and treating assets within the states of Wyoming, Colorado, New Mexico and in Pennsylvania. We also own and operate gas gathering and processing assets and pipelines primarily within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama.

The following table summarizes our significant operated natural gas gathering assets as of December 31, 2011:

	Natural Gas Gathering Assets
	Location		Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins
Onshore
Rocky Mountain		Wyoming	3,587	1.1	100%		Wamsutter & SW Wyoming
Four Corners		Colorado & New Mexico	3,823	1.8	100%		San Juan
Piceance		Colorado	328	1.4	100%		Piceance
NE Pennsylvania (2)		Pennsylvania	75	0.7	100%		Appalachian
Laurel Mountain (1)		Pennsylvania	1,386	0.2	51%		Appalachian
Gulf Coast
Canyon Chief & Blind Faith		Deepwater Gulf of Mexico	139	0.4	100%		Eastern Gulf of Mexico
Seahawk		Deepwater Gulf of Mexico	115	0.4	100%		Western Gulf of Mexico

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Perdido Norte	Deepwater Gulf of Mexico	105	0.3	100%	Western Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	46	0.2	100%	Eastern Gulf of Mexico
Offshore shelf & other	Gulf of Mexico	245	0.9	100%	Western Gulf of Mexico
Discovery (1)	Gulf of Mexico	319	0.6	60%	Central Gulf of Mexico

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

(2) In the first quarter of 2012, our Springville gathering pipeline was put into service, initially providing an optional takeaway for 0.3 Bcf/d of gas gathered on our system in northeast Pennsylvania. Also in the first quarter of 2012, 0.3 Bcf/d of capacity was added from the Laser gathering system acquisition.

In addition we own and operate several natural gas treating facilities in New Mexico, Colorado, Texas, and Louisiana which bring natural gas to specifications allowable by major interstate pipelines. At our Milagro treating facility, we also use gas-driven turbines to produce approximately 60 mega-watts per day of electricity which we primarily sell into the local electrical grid.

The following table summarizes our significant operated natural gas processing facilities as of December 31, 2011:

	Natural Gas Processing Facilities
	Location		Inlet Capacity (Bcf/d)		NGL Production Capacity (Mbbls/d)		Ownership Interest			Supply Basins
Onshore
Opal		Opal, WY		1.5		67		100	%		SW Wyoming
Echo Springs		Echo Springs, WY		0.7		58		100	%		Wamsutter
Ignacio		Ignacio, CO		0.5		23		100	%		San Juan
Kutz		Bloomfield, NM		0.2		12		100	%		San Juan
Lybrook (2)		Lybrook, NM		0.1		6		100	%		San Juan
Willow Creek		Rio Blanco County, CO		0.5		30		100	%		Piceance
Parachute		Garfield County, CO		1.4		7		100	%		Piceance
Gulf Coast
Markham		Markham, TX		0.5		45		100	%		Western Gulf of Mexico
Mobile Bay		Coden, AL		0.7		30		100	%		Eastern Gulf of Mexico
Discovery (1)		Larose, LA		0.6		32		60	%		Central Gulf of Mexico

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

(2) Our Lybrook plant has been idled as of January 2012. Gas previously processed at Lybrook has been redirected to our Ignacio plant.

Crude oil transportation and production handling assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby the oil that we transport is purchased and sold as a function of the same index-based price. Our offshore floating production platforms provide centralized services to deepwater producers such as

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compression, separation, production handling, water removal and pipeline landings. Revenue sources have historically included a combination of fixed-fee, volumetric-based fee and cost reimbursement arrangements. Fixed fees associated with the resident production at our Devils Tower facility are recognized on a units-of-production basis.

The following table summarizes our significant crude oil transportation pipelines as of December 31, 2011:

	Crude Oil Pipelines
	Pipeline Miles		Handling Capacity (Mbbls/d)		Ownership Interest			Supply Basins
Mountaineer & Blind Faith		155		150		100	%		Eastern Gulf of Mexico
BANJO		57		90		100	%		Western Gulf of Mexico
Alpine		96		85		100	%		Western Gulf of Mexico
Perdido Norte		74		150		100	%		Western Gulf of Mexico

The following table summarizes our production handling platforms as of December 31, 2011:

	Production Handling Platforms
	Gas Inlet Capacity (MMcf/d)		Crude/NGL Handling Capacity (Mbbls/d)		Ownership Interest			Supply Basins
Devils Tower		210		60		100	%		Eastern Gulf of Mexico
Canyon Station		500		16		100	%		Eastern Gulf of Mexico
Discovery Grand Isle 115 (1)		150		10		60	%		Central Gulf of Mexico

(1) Statistics reflect 100 percent of the assets from the equity method investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

NGL marketing services

In addition to our gathering and processing operations, we market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets equity NGLs from the production at our processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, and the NGL volumes owned by Discovery Producer Services LLC (Discovery). The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale. Other than a long-term agreement to sell our equity NGLs transported on Overland Pass Pipeline to ONEOK Hydrocarbon L.P., the majority of sales are based on supply contracts of one year or less in duration. Sales to ONEOK Hydrocarbon L.P., accounted for 20 percent, 17 percent, and 10 percent of our consolidated revenues in 2011, 2010, and 2009, respectively.

Other operations

We own interests in and/or operate NGL fractionation and storage assets. These assets include a 50 percent interest in an NGL fractionation facility near Conway, Kansas with capacity of slightly more than 100 Mbbls/d and a 31.45 percent interest in another fractionation facility in Baton Rouge, Louisiana with a capacity of 60 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

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We own approximately 115 miles of pipelines in the Houston Shipping Channel area which transport a variety of products including ethane, propane and other products used in the petrochemical industry.

We also own a 14.6 percent equity interest in Aux Sable Liquid Products L.P. (Aux Sable) and its Channahon, Illinois gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 102 Mbbls/d of extracted liquids into NGL products. Additionally, in June 2011, Aux Sable acquired an 80 MMcf/d gas conditioning plant and a 12-inch, 83-mile gas pipeline infrastructure in North Dakota that provides additional NGLs to Channahon from the Bakken Shale in the Williston basin.

Operated Equity Investments

Discovery

We own a 60 percent equity interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and an offshore natural gas gathering and transportation system in the Gulf of Mexico.

Laurel Mountain

We own a 51 percent interest in a joint venture, Laurel Mountain Midstream, LLC (Laurel Mountain), in the Marcellus Shale located in western Pennsylvania. Laurel Mountain’s assets, which we operate, include a gathering system of nearly 1,400 miles of pipeline with a capacity of approximately 230 MMcf/d. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with some exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale. Construction is ongoing for numerous new pipeline segments and compressor stations, the largest of which is our Shamrock compressor station. The Shamrock compressor station currently has a capacity of 60 MMcf/d and is expandable to 350 MMcf/d.

Overland Pass Pipeline

We operate and own a 50 percent ownership interest in Overland Pass Pipeline Company LLC (OPPL). OPPL includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Joules basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. We plan to participate in the construction of a pipeline connection and capacity expansions expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Operating statistics

The following table summarizes our significant operating statistics for Midstream:

	2011		2010		2009
Volumes: (1)
Gathering (Tbtu)		1,377		1,262		1,370
Plant inlet natural gas (Tbtu)		1,592		1,599		1,342
NGL production (Mbbls/d) (2)		189		178		164
NGL equity sales (Mbbls/d) (2)		77		80		80
Crude oil transportation (Mbbls/d) (2)		105		94		109

(1) Excludes volumes associated with partially owned assets such as our Discovery and Laurel Mountain investments that are not consolidated for financial reporting purposes.

(2) Annual average Mbbls/d.

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REGULATORY MATTERS

Gas Pipeline. Gas Pipeline’s interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA), as amended, and under the Natural Gas Policy Act of 1978, as amended, and, as such, its rates and charges for the transportation of natural gas in interstate commerce, its accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

Each of our interstate natural gas pipeline companies establishes its rates primarily through the FERC’s ratemaking process. Key determinants in the ratemaking process are:

• Costs of providing service, including depreciation expense;

• Allowed rate of return, including the equity component of the capital structure and related income taxes;

• Contract and volume throughput assumptions.

The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

Pipeline Integrity Regulations

Transco and Northwest Pipeline have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, Transco and Northwest Pipeline have identified high consequence areas and developed baseline assessment plans. Transco and Northwest Pipeline are on schedule to complete the required assessments within required timeframes. Currently, we estimate the cost to complete the required initial assessments through 2012 and associated remediation will be primarily capital in nature and range between $25 million and $40 million for Transco and between $30 million and $35 million for Northwest Pipeline. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business, and, therefore, recoverable through our rates.

Midstream. For our Midstream segment, onshore gathering is subject to regulation by states in which we operate and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the states where Midstream gathers gas, currently only Texas actively regulates gathering activities. Texas regulates gathering primarily through complaint mechanisms under which the state commission may resolve disputes involving an individual gathering arrangement. Although offshore gathering facilities are not subject to the NGA, offshore transmission pipelines are subject to the NGA, and in recent years the FERC has taken a broad view of offshore transmission, finding many shallow-water pipelines to be jurisdictional transmission. Most offshore gathering facilities are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and nonowner shippers.”

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Midstream also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect.

Midstream owns a 50 percent interest in and is the operator of OPPL, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. OPPL provides transportation service pursuant to tariffs filed with the FERC.

See Note 15 of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

• Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities and storage tanks;

• Damage to facilities resulting from accidents during normal operations;

• Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;

• Blowouts, cratering and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, tribal or local regulatory measures on our business and specific environmental issues, please refer to “Risk Factors – We are subject to risks associated with climate change and – Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs, liabilities and expenditures and could exceed current expectations,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental” and “Environmental Matters” in Note 15 of our Notes to Consolidated Financial Statements.

COMPETITION

Gas Pipeline. The natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. More recently large reserves of shale gas have been discovered, in many cases much closer to major market centers. As a result, pipeline capacity is being used more efficiently and competition among pipeline suppliers to attach growing supply to market has increased.

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Local distribution company (LDC) and electric industry restructuring by states have affected pipeline markets. Pipeline operators are increasingly challenged to accommodate the flexibility demanded by customers and allowed under tariffs, but the changes implemented at the state level have not required renegotiation of LDC contracts. The state plans have in some cases discouraged LDCs from signing long-term contracts for new capacity.

Many states have developed energy plans that require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This has lowered the growth of residential gas demand. However, due to relatively low prices of natural gas, demand for electric power generation has increased.

These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity from traditional producing areas. Future utilization of pipeline capacity will depend on these factors and others impacting both U.S. and global demand for natural gas.

Midstream Gas & Liquids. In our Midstream segment, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, reliability, timeliness of services to be provided, pressure obligations and contract structure.

EMPLOYEES

We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2012, our general partner or its affiliates employed approximately 3,455 full-time employees, including 1,825 at Gas Pipelines and 1,630 at Midstream. Additionally, our general partner and its affiliates provide general and administrative services to us. For further information, please read “Directors, Executive Officers and Corporate Governance” and “Certain Relationships and Related Transactions, and Director Independence — Reimbursement of Expenses of our General Partner.”

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

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

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT FOR

PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES

LITIGATION REFORM ACT OF 1995

Certain matters contained in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters.

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

• Amounts and nature of future capital expenditures;

• Expansion and growth of our business and operations;

• Financial condition and liquidity;

• Business strategy;

• Cash flow from operations or results of operations;

• The levels of cash distributions to unitholders;

• Seasonality of certain business components;

• Natural gas and natural gas liquids prices and demand.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Limited partner 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. You should carefully consider the risk factors discussed below in addition to the other information in this report. If any of the following risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

• Whether we have sufficient cash from operations to enable us to maintain current levels of cash distributions or to pay cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

• Availability of supplies, market demand, volatility of prices, and the availability and cost of capital;

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

• The strength and financial resources of our competitors;

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• Ability to acquire new businesses and assets and integrate those operations and assets into our existing businesses, as well as expand our facilities;

• Development of alternative energy sources;

• The impact of operational and development hazards;

• Costs of, changes in, or the results of laws, government regulations (including safety and climate change regulation and changes in natural gas production from exploration and production areas that we serve), environmental liabilities, litigation and rate proceedings;

• Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;

• Changes in maintenance and construction costs;

• Changes in the current geopolitical situation;

• Our exposure to the credit risks of our customers and counterparties;

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

• Risks associated with future weather conditions;

• Acts of terrorism, including cybersecurity threats and related disruptions;

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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

RISK FACTORS

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

Risks Inherent in Our Business

We may not have sufficient cash from operations to enable us to make cash distributions or to maintain current levels of cash distributions following establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

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

• The prices we obtain for our services;

• The prices of, level of production of, and demand for natural gas and NGLs and our NGL margins;

• The volumes of natural gas we gather, transport, process and treat and the volumes of NGLs we fractionate and store;

• The level of our operating costs, including payments to our general partner;

• Prevailing economic conditions.

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, such as:

• The level of capital expenditures we make;

• The restrictions contained in Williams’ indentures, our indentures and Credit Facility and our debt service requirements;

• The cost of acquisitions, if any;

• Fluctuations in our working capital needs;

• Our ability to borrow for working capital or other purposes;

• The amount, if any, of cash reserves established by our general partner;

• The amount of cash that the Partially Owned Entities and our subsidiaries distribute to us.

Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by noncash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

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 expand our existing facilities to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities may not achieve profitability. In addition, the process of integrating newly acquired or constructed assets into our 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 our 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.

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Prices for NGLs, natural gas, oil, and other commodities, including oil, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain existing businesses.

Our revenues, operating results, future rate of growth and the value of certain components of our businesses depend primarily upon the prices of NGLs, natural gas, oil, or other commodities, and the differences between prices of these commodities. Price volatility can impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Any of the foregoing can also have an adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.

The markets for NGLs, natural gas and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from relatively minor changes in the supply of and demand for these commodities, market uncertainty and other factors that are beyond our control, including:

• Worldwide and domestic supplies of and demand for natural gas, NGLs, oil, petroleum, and related commodities;

• Turmoil in the Middle East and other producing regions;

• The activities of the Organization of Petroleum Exporting Countries;

• Terrorist attacks on production or transportation assets;

• Weather conditions;

• The level of consumer demand;

• The price and availability of other types of fuels;

• The availability of pipeline capacity;

• Supply disruptions, including plant outages and transportation disruptions;

• The price and quantity of foreign imports of natural gas and oil;

• Domestic and foreign governmental regulations and taxes;

• Volatility in the natural gas and oil markets;

• The overall economic environment;

• The credit of participants in the markets where products are bought and sold;

• The adoption of regulations or legislation relating to climate change and changes in natural gas production from exploration and production areas that we serve.

We might not be able to successfully manage the risks associated with selling and marketing products in the wholesale energy markets.

Our portfolio of derivative and other energy contracts may consist of wholesale contracts to buy and sell commodities, including contracts for natural gas, NGLs and other commodities that are settled by the delivery of the commodity or cash throughout the United States. If the values of these contracts change in a direction or manner that we do not anticipate or cannot manage, it could negatively affect our results of operations. In the past, certain

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marketing and trading companies have experienced severe financial problems due to price volatility in the energy commodity markets. In certain instances this volatility has caused companies to be unable to deliver energy commodities that they had guaranteed under contract. If such a delivery failure were to occur in one of our contracts, we might incur additional losses to the extent of amounts, if any, already paid to, or received from, counterparties. In addition, in our businesses, we often extend credit to our counterparties. Despite performing credit analysis prior to extending credit, we are exposed to the risk that we might not be able to collect amounts owed to us. If the counterparty to such a transaction fails to perform and any collateral that secures our counterparty’s obligation is inadequate, we will suffer a loss. Downturns in the economy or disruptions in the global credit markets could cause more of our counterparties to fail to perform than we expect.

The long-term financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access, demand for those supplies in our traditional markets, and the prices of and market demand for natural gas.

The development of the additional natural gas reserves that are essential for our gas transportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, including environmental regulations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transportation and processing facilities.

Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will also naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported on or gathered through our pipeline systems and cash flows associated with the gathering and transportation of natural gas, our customers must compete with others to obtain adequate supplies of natural gas. In addition, if natural gas prices in the supply basins connected to our pipeline systems are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply areas, if natural gas supplies are diverted to serve other markets, if development in new supply basins where we do not have significant gathering or pipeline systems reduces demand for our services, or if environmental regulators restrict new natural gas drilling, the overall volume of natural gas transported, gathered and stored on our system would decline, which could have a material adverse effect on our business, financial condition and results of operations, and our ability to make cash distributions to unitholders. In addition, new LNG import facilities built near our markets could result in less demand for our gathering and transportation facilities.

Our risk management and measurement systems and hedging activities might not be effective and could increase the volatility of our results.

The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used and may in the future use fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For

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example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under generally accepted accounting principles (“GAAP”), to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.

The impact of changes in market prices for NGLs and natural gas on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for NGLs or natural gas were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss in certain circumstances, including instances in which:

• Volumes are less than expected;

• The hedging instrument is not perfectly effective in mitigating the risk being hedged;

• The counterparties to our hedging arrangements fail to honor their financial commitments.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010 federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Dodd-Frank Act on our hedging activities is uncertain at this time due to the requirement that the SEC and the Commodities Futures Trading Commission (the “CFTC”) promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should be exempt from the requirement to clear transactions through a central exchange or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.

Depending on the rules and definitions adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures or other partnership purposes. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

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We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Some of our competitors are large oil, natural gas and petrochemical companies that have greater access to supplies of natural gas and NGLs than we do. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make investments or acquisitions. Other companies with which we compete may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion or refurbishment of their facilities than we can. Similarly, a highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business, results of operations, and financial condition and our ability to make cash distributions to unitholders.

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

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

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues and cash available to pay distributions could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues.

Any temporary or permanent interruption at any key pipeline interconnect or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, results of operations, and financial condition and our ability to make cash distributions to unitholders.

Difficult conditions in the global capital markets, the credit markets and the economy in general could negatively affect our business and results of operations.

Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are reduced energy demand and lower prices for our products and services, increased difficulty in collecting amounts owed to us by our customers and a reduction in our credit ratings (either due to tighter rating standards or the negative impacts described above), which could reduce our access to credit markets, raise the cost of such access or require us to provide additional collateral to our

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counterparties. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.

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

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

Our total outstanding long-term debt (including current portion) as of December 31, 2011, was $7.2 billion.

Our debt service obligations and restrictive covenants in our Credit Facility and the indentures governing our senior unsecured notes could have important consequences. For example, they could:

• Make it more difficult for us to satisfy our obligations with respect to our senior unsecured notes and our other indebtedness, which could in turn result in an event of default on such other indebtedness or our outstanding notes;

• Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;

• Adversely affect our ability to pay cash distributions to unitholders;

• Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

• Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, general partnership purposes or other purposes;

• Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• Place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

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

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

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

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

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

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

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

Our subsidiaries are not prohibited from incurring indebtedness by their organizational documents, which may affect our ability to make distributions to unitholders.

Our subsidiaries are not prohibited by the terms of their respective organizational documents from incurring indebtedness. If they were to incur significant amounts of indebtedness, such occurrence may inhibit their ability to make distributions to us. An inability by our subsidiaries to make distributions to us would materially and adversely affect our ability to make distributions to unitholders because we expect distributions we receive from our subsidiaries to represent a significant portion of the cash available to make cash distributions to unitholders.

A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of doing business, and independent third parties outside of our control determine our credit ratings.

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

• Economic downturns;

• Deteriorating capital market conditions;

• Declining market prices for natural gas, NGLs, oil, and other commodities;

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

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

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

Our acquisition attempts may not be successful or may result in completed acquisitions that do not perform as anticipated.

We have made and may continue to make acquisitions of businesses and properties. However, suitable acquisition candidates may not continue to be available on terms and conditions we find acceptable. The following are some of the risks associated with acquisitions, including any completed or future acquisitions:

• Some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels or could have environmental, permitting or other problems for which contractual protections prove inadequate;

• We may assume liabilities that were not disclosed to us or that exceed our estimates;

• We may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operationally, technical or financial problems;

• Acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.

We are subject to risks associated with climate change.

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

In addition, legislative and regulatory responses related to GHGs and climate change creates the potential for financial risk. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.

Numerous states and other jurisdictions have announced or adopted programs to stabilize and reduce GHGs. In 2009, the U.S. Environmental Protection Agency (“EPA”) issued a final determination that six GHGs are a threat to public safety and welfare. In 2011, the EPA implemented permitting for new and/or modified large sources of GHG emissions through the existing Prevention of Signification Deterioration permitting program. Additional direct regulation of GHG emissions in our industry may be implemented under other Clean Air Act programs, including the New Source Performance Standards program.

The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

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

Substantial costs, liabilities, delays and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing and treating of natural gas and fractionation of NGLs, and as a result, we

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may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, Native American, and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

• Clean Air Act (“CAA”), and analogous state laws, which impose obligations related to air emissions;

• Clean Water Act (“CWA”), and analogous state laws, which regulate discharge of wastewaters and storm water from our facilities to state and federal waters, including wetlands;

• Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state laws, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

• Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, which impose requirements for the handling and discharge of solid and hazardous waste from our facilities;

• Endangered Species Act (“ESA”), and analogous state laws, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species;

• Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit plans to the federal government detailing how they will respond to large discharges, regulates petroleum storage tanks and related equipment, and imposes liability for spills on responsible parties.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, and the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to our handling of the products as they are gathered, transported, processed, fractionated and stored, air emissions related to our operations, historical industry operations, and waste and waste disposal practices, and the prior use of flow meters containing mercury. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA, and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes the addition of “Energy Extraction Activities” to its enforcement priorities list. To address its concerns regarding the pollution risks raised by new techniques for oil and gas extraction and coal mining, the EPA is developing an initiative to ensure that energy extraction activities are complying with federal environmental requirements. We cannot predict what the results of this initiative would be, or whether federal, state, or local laws or regulations will be enacted in this area. If regulations were imposed related to oil and gas extraction, the volumes of natural gas that we transport could decline and our results of operations could be adversely affected.

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Our business may be adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our business, financial condition, results of operations and cash flows.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

Hydraulic fracturing is exempt from federal regulation pursuant to the federal Safe Drinking Water Act (except when the fracturing fluids or propping agents contain diesel fuels). However, public concerns have been raised related to its potential environmental impact. Additional federal, state and local laws and regulations to more closely regulate hydraulic fracturing have been considered or implemented. Legislation to further regulate hydraulic fracturing has been proposed in Congress. The U.S. Department of Interior has announced plans to formalize obligations for disclosure of chemicals associated with hydraulic fracturing on federal lands. The results of a pending EPA investigation by a committee of the House of Representatives and two recent reports by the U.S. Department of Energy’s Shale Gas Subcommittee could lead to further restrictions on hydraulic fracturing. The EPA has proposed regulations under the CAA regarding certain emissions from the hydraulic fracturing of oil and natural gas wells and announced its intention to propose regulations by 2014 under the CWA regarding wastewater discharges from hydraulic fracturing and other gas production. In addition, some state and local authorities have considered or imposed new laws and rules related to hydraulic fracturing, including additional permit requirements, operational restrictions, disclosure obligations and temporary or permanent bans on hydraulic fracturing in certain jurisdictions or in environmentally sensitive areas. We cannot predict whether any additional federal, state or local laws or regulations will be enacted in this area and if so, what their provisions would be. If additional levels of reporting, regulation or permitting moratoria were required or imposed related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process and treat could decline and our results of operations could be adversely affected.

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

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

Our assets and operations, including those located offshore, 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 us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to unitholders.

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Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading either to increased investment or decreased revenues.

We depend on certain key customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. If we lost any of these key customers or producers or contracted volumes, our revenues and cash available to pay distributions could decline.

We rely on a limited number of customers for a significant portion of our revenues. Although some of these customers are subject to long-term contracts, we may be unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all, or even a portion of, the revenues from natural gas, NGLs or contracted volumes, as applicable, supplied by these customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to unitholders, unless we are able to acquire comparable volumes from other sources.

We do not own all of the interests in Partially Owned Entities, which could adversely affect our ability to operate and control these assets in a manner beneficial to us.

Because we do not control the Partially Owned Entities, we may have limited flexibility to control the operation of or cash distributions received from these entities. The Partially Owned Entities’ organizational documents require distribution of their available cash to their members on a quarterly basis; however, in each case, available cash is reduced, in part, by reserves appropriate for operating the businesses. At December 31, 2011, our investments in the Partially Owned Entities accounted for approximately 10 percent of our total consolidated assets. Any future disagreements with the other co-owners of these assets could adversely affect our ability to respond to changing economic or industry conditions, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to unitholders.

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

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

Legal and regulatory proceedings and investigations relating to the energy industry have adversely affected our business and may continue to do so. The operation of our businesses might also be adversely affected by changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations and court proceedings. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of these ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current

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legal proceedings or other matters against us including environmental matters, suits, regulatory appeals and similar matters might result in adverse decisions against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us, our facilities or our customers, and future changes in laws and regulations could have a material adverse effect on our financial condition, results of operations and ability to make cash distributions to unitholders. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed recently, including the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 enacted on January 3, 2012. This law will result in the promulgation of new regulations to be administered by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) affecting the operations of our Pipeline Entities including, but not limited to, requirements relating to pipeline inspection, installation of additional valves and other equipment and records verification. These reforms and any future changes in related laws and regulations could significantly increase our costs.

The 2010 drilling moratorium in the Gulf of Mexico and potentially more stringent regulations and permitting requirements on drilling in the Gulf of Mexico could adversely affect our operating results, financial condition and cash available to make distributions.

The drilling moratorium in the Gulf of Mexico (in force from May to October 2010) impacted our production handling, gathering and transportation operations through production delays which reduced volumes of natural gas and oil delivered to our platform, pipeline and gathering facilities in 2010. In addition, the Bureau of Ocean Energy Management, Regulation and Enforcement continues to develop more stringent drilling and permitting requirements for producers in the Gulf of Mexico which could cause delays in production or new drilling. A significant decline or delay in production volumes in the Gulf of Mexico could adversely affect our operating results, financial condition and cash available to make distributions through reduced production handling activities, gathering and transportation volumes, processing activities or other midstream services.

The Pipeline Entities’ natural gas sales, transportation and storage operations are subject to regulation by FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines, including a reasonable rate of return.

The Pipeline Entities’ natural gas sales, transmission and storage operations are subject to federal, state and local regulatory authorities. Specifically, their interstate pipeline transportation and storage service is subject to regulation by the 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 service;

• The types of services the Pipeline Entities may offer to their customers;

• Certification and construction of new interstate pipelines and storage facilities;

• Acquisition, extension, disposition or abandonment of existing interstate pipelines and storage facilities;

• Accounts and records;

• Depreciation and amortization policies;

• Relationships with affiliated companies who are involved in marketing functions of the natural gas business;

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

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

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

Unlike other interstate pipelines that own facilities in the offshore Gulf of Mexico, Transco charges its transportation customers a separate fee to access its offshore facilities. The separate charge is referred to as an “IT feeder” charge. The “IT feeder” rate is charged only when gas is actually transported on the facilities and typically it is paid by producers or marketers. Because the “IT feeder” rate is typically paid by producers and marketers, it generally results in netback prices to producers that are slightly lower than the netbacks realized by producers transporting on other interstate pipelines. This rate design disparity could result in producers bypassing Transco’s offshore facilities in favor of alternative transportation facilities.

The rates, terms and conditions for the Pipeline Entities’ interstate pipeline services are set forth in their respective FERC-approved tariffs. Any successful complaint or protest against the Pipeline Entities’ rates could have an adverse impact on their revenues associated with providing transportation services.

The Pipeline Entities could be subject to penalties and fines if they fail to comply with laws governing our business.

The Pipeline Entities’ operations are regulated by numerous governmental agencies including the FERC, the EPA and PHMSA. Should the Pipeline Entities fail to comply with all applicable statutes, rules, regulations and orders, they could be subject to substantial penalties and fines. For example, under the Energy Policy Act of 2005, the 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 and under the recently enacted Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, PHMSA has civil penalty authority up to $200,000 per day (from the prior $100,000), with a maximum of $2 million for any related series of violations (from the prior $1 million). Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on the Pipeline Entities’ business, financial condition, results of operations and cash flows, and on our ability to make cash distributions to unitholders.

The outcome of future rate cases to set the rates the Pipeline Entities can charge customers on their respective pipelines might result in rates that lower their return on the capital invested in those pipelines.

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

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

We have experienced leaks and ruptures on one of our gas pipeline systems, including a rupture near Appomattox, Virginia in 2008 and a rupture near Sweet Water, Alabama in 2011. We could experience additional unexpected leaks or ruptures on our gas pipeline systems, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. More recently, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 became law and under this statute PHMSA may issue additional regulations

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addressing such records. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines.

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

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

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

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

Our primary exposure to market risk for our gas pipelines occurs at the time the terms of existing transportation and storage contracts expire and are subject to termination. Upon expiration of the terms, we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis.

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

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

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

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

• Whether our business strategy continues to be successful;

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

• The effects of state regulation on customer contracting practices.

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

Competitive pressures could lead to decreases in the volume of natural gas contracted or transported through the Pipeline Entities’ pipeline systems.

Although most of the Pipeline Entities’ pipeline systems’ current capacity is fully contracted, FERC has taken certain actions to strengthen market forces in the interstate natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transmission provider based on considerations other than location. Other entities could construct new pipelines or expand existing pipelines that could potentially serve the same markets as our pipeline system. Any such new pipelines could offer transportation services that are more desirable to shippers because of locations, facilities, or other factors. These new pipelines could charge rates or provide service to locations that would result in greater net profit for shippers and producers and thereby force us to lower the rates charged for service on our pipeline in order to extend our existing transportation service agreements or to attract new customers. We are aware of proposals by competitors to expand pipeline capacity in certain markets we also serve which, if the proposed projects proceed, could increase the competitive pressure upon us. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our business, results of operations, and our ability to make cash distributions to unitholders.

Certain of the Pipeline Entities’ services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

The Pipeline Entities provide some services pursuant to long-term, fixed price contracts. It is possible that costs to perform services under such contracts will exceed the revenues they collect for their services. Although most of the services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

Our operations are subject to operational hazards and unforeseen interruptions for which they may not be adequately insured.

There are operational risks associated with the gathering, transporting, storage, processing and treating of natural gas and the fractionation and storage of NGLs, including:

• Hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters;

• Aging infrastructure and mechanical problems;

• Damages to pipelines and pipeline blockages or other pipeline interruptions;

• Uncontrolled releases of natural gas (including sour gas), NGLs, brine or industrial chemicals;

• Collapse or failure of storage caverns;

• Operator error;

• Damage caused by third party activity, such as operation of construction equipment;

• Pollution and other environmental risks;

• Fires, explosions, craterings and blowouts;

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• Risks related to truck and rail loading and unloading;

• Risks related to operating in a marine environment;

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

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In spite of our precautions, an event such as those described above could cause considerable harm to people or property, and could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers.

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

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

Williams currently maintains excess liability insurance with limits of $610 million per occurrence and in the annual aggregate with a $2 million per occurrence deductible. This insurance covers Williams, its subsidiaries, and certain of its affiliates, including us, for legal and contractual liabilities arising out of bodily injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations.

Although we maintain property insurance on certain physical assets that we own, lease or are responsible to insure, the policy may not cover the full replacement cost of all damaged assets or the entire amount of business interruption loss we may experience. In addition, certain perils may be excluded from coverage or sub-limited. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. We may elect to self insure a portion of our risks. We do not insure our onshore underground pipelines for physical damage, except at certain locations such as river crossings and compressor stations. Offshore assets are covered for property damage when loss is due to a named windstorm event and coverage for loss caused by a named windstorm is significantly sub-limited and subject to a large deductible. All of our insurance is subject to deductibles. If a significant accident or event occurs for which we are not fully insured it could adversely affect our operations and financial condition.

In addition to the insurance coverage described above, Williams is a member of Oil Insurance Limited (OIL), an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured of OIL, Williams shares in the losses among other OIL members even if its property is not damaged. As a result, we may share in any losses incurred by Williams.

Furthermore, any insurance company that provides coverage to us may experience negative developments that could impair their ability to pay any of our claims. As a result, we could be exposed to greater losses than anticipated and may have to obtain replacement insurance, if available, at a greater cost.

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

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

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Our growth may be dependent upon the construction of new natural gas gathering, transportation, compression, processing or treating pipelines and facilities or NGL fractionation or storage facilities, as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:

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

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

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

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

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

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

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

Our operating results for certain components of our business might fluctuate on a seasonal and quarterly basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

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

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

We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as operators and on Williams’ outsourcing relationships, and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, and financial condition and our ability to make cash distributions to unitholders.

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

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

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

Regulators and legislators continue to take a renewed look at accounting practices, financial disclosures, and companies’ relationships with their independent public accounting firms. It remains unclear what new laws or regulations will be adopted, and we cannot predict the ultimate impact that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board, the SEC or FERC could enact new accounting standards or FERC could issue rules that might impact how we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition and our ability to make cash distributions to unitholders.

Institutional knowledge residing with current employees nearing retirement eligibility or with employees going to WPX as part of the separation of our exploration and production business might not be adequately preserved.

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

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

We rely on Williams for certain services necessary for us to be able to conduct our business. Williams may outsource some or all of these services to third parties, and a failure of all or part of Williams’ relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on Williams and others as service providers and on Williams’ outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, results of operations and financial condition.

Some studies indicate a high failure rate of outsourcing relationships. A deterioration in the timeliness or quality of the services performed by the outsourcing providers or a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business. The expiration of such agreements or the transition of services between providers could lead to similar losses of institutional knowledge or disruptions.

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

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

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

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Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, plants and assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists,” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. We could also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access, physical locations, or information otherwise known as “social engineering.”

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, safety incidents, damage to the environment, potential liability or the loss of contracts, and have a material adverse effect on our operations, financial position and results of operations.

Risks Inherent in an Investment in Us

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

Williams owns and controls our general partner and appoints all of the directors of our general partner. All of the executive officers and certain directors of our general partner are officers and/or directors of Williams and certain of its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us, the directors and officers of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to Williams. Therefore, conflicts of interest may arise between Williams and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, 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. Williams’ directors and officers have a fiduciary duty to make decisions in the best interests of the owners of Williams, which may be contrary to the best interests of us and our unitholders;

• All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Williams and certain of its affiliates, 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 common units representing an approximate 70 percent limited partner interest in us, and if a vote of limited partners is required in which Williams is entitled to vote, Williams will be able to vote its units in accordance with its own interests, which may be contrary to our interests or the interests of our unitholders;

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• All of the executive officers and certain of the directors of our general partner will devote significant time to our business and/or the business of Williams, 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, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;

• Our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances and, in some instances, with the concurrence of the conflicts committee of its board of directors, 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 and to our general partner with respect to its incentive distribution rights;

• 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 incentive distributions to itself as general partner;

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

• 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 entering into additional contractual arrangements with any of these entities on our behalf;

• Our general partner has limited liability regarding our contractual and other obligations and in some circumstances is required to be indemnified by us;

• Pursuant to our partnership agreement, our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80 percent of our outstanding common units;

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

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

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

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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 and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

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• 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 affiliate 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 be “fair and reasonable” to us, as determined by our general partner in good faith. 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 respective 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 or, in the case of a criminal matter, acted with knowledge that such conduct was criminal;

• 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.

Common unitholders are bound by the provisions in our partnership agreement, including the provisions discussed above.

Affiliates of our general partner, including Williams, are not limited in their ability to compete with 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 these persons will also owe fiduciary duties to Williams.

While our relationship with Williams and its affiliates is a significant attribute, it is also a source of potential conflicts. For example, Williams is in the natural gas business and is not restricted from competing with us. Williams and its affiliates may compete with us. Williams and its affiliates may acquire, construct or dispose of natural gas industry assets in the future, some or all of which may compete with our assets, without any obligation to offer us the opportunity to purchase or construct such assets. 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 certain of its affiliates and will owe fiduciary duties to those entities as well as our unitholders and us.

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

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

Cost reimbursements due to our general partner and its affiliates will reduce cash available to pay distributions to unitholders.

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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 reimbursements in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distributions to unitholders. Furthermore, Williams, which owns our general partner, recently completed the separation of its exploration and production business into a newly formed separate publicly-traded corporation. The spin-off of Williams’ exploration and production business is expected to increase the costs of the general and administrative services provided to us. 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 have little ability to remove our general partner without its consent.

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 is chosen by Williams. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding common units is required to remove our general partner. Our general partner and its affiliates currently own approximately 71 percent of our outstanding common units and, as a result, our public unitholders cannot remove our general partner without its consent.

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 payments on our debt obligations and distributions on our common units.

We have a holding company structure, and our subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in these subsidiaries. As a result, our ability to make required payments on our debt obligations and distributions on our common units 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, applicable state partnership and limited liability company laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of our debt obligations, to repurchase our debt obligations upon the occurrence of a change of control or make distributions on our common units, we may be required to adopt one or more alternatives, such as a refinancing of our debt obligations or borrowing funds to make distributions on our common units. We cannot assure you that we would be able to borrow funds to make distributions on our common units.

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

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

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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 effectively permits a change of control without unitholder consent.

We may issue additional common units without unitholder approval, which would dilute unitholder 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 unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• Our unitholders’ proportionate ownership interest in us will decrease;

• The amount of cash available to pay distributions on each unit may decrease;

• The ratio of taxable income to distributions may decrease;

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

• The market price of the common units may decline.

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

As of December 31, 2011, Williams held 217,095,249 common units, representing an approximate 73 percent limited partnership interest in us. Williams may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common 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 unitholders to sell their common units at an undesirable time or price.

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80 percent of the common units, our general partner will have the right, 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. Our general partner may assign this right to any of its affiliates or to us. As a result, non-affiliated unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Such unitholders may also incur a tax liability upon a sale of their 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 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 under the Exchange Act, we would no longer be subject to the reporting requirements of such Act.

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, transferees of their transferees (provided that our general partner has notified such secondary transferees that the voting limitation shall not apply to them), and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. The partnership agreement also contains provisions limiting the ability of unitholders to call meetings, to acquire information about our operations and to influence the manner or direction of management.

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

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

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

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

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

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

Tax Risks

Our tax treatment depends on our status as a partnership for U.S. 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 (the “IRS”) were to treat us as a corporation for U.S. 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, then our cash available for distribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. We have not requested a ruling from the IRS on this or any other tax matter affecting us.

Failing to meet the qualifying income requirement or a change in current law may cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. 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 unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available to pay distributions to unitholders 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 unitholders, likely causing a substantial reduction in the value of the common units.

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In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distributions 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 U.S. federal, state or local income tax purposes, then the levels of distributions at which our general partner will receive increasing percentages of the cash we distribute will be adjusted to reflect the impact of that law on us.

The U.S. federal income 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 U.S. federal income 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. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. The Obama administration and members of Congress have recently considered substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or 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 common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common 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 common 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 although the U.S. Treasury Department issued proposed Treasury regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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.

An IRS contest of the U.S. federal income tax positions we take may adversely impact the market for the common units, and the costs of any 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 U.S. 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 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 U.S. federal income tax positions we take. Any contest with the IRS may materially and adversely impact the market for the 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.

Unitholders will be required to pay taxes on their share of our income even if unitholders 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, unitholders will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

If a unitholder sells its common units, it will recognize gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and its tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income that was allocated to a unitholder for a common unit, which decreased its tax basis in that common unit, will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than its tax basis in that common unit, even if the price the unitholder receives is less than the original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to the unitholder due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our non-recourse liabilities, if a unitholder sells its common units, the unitholder may incur a U.S. federal income tax liability in excess of the amount of cash it received from the sale.

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 unitholders who are organizations that are exempt from U.S. 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 U.S. federal income tax returns and pay U.S. federal income tax on their share of our taxable income.

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 the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform with 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 U.S. federal income tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to unitholder tax returns.

Unitholders will likely be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, such as state and local income 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 the unitholder does not live in any of those jurisdictions. Unitholders 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, unitholders 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 the unitholder’s responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

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

We will be considered to have terminated our partnership for U.S. 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 partners, which would result

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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 12 months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be 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. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its partners for the tax years in the fiscal year during which the termination occurs.

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 the common units.

When we issue additional common units or engage in certain other transactions, we 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 partners. 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 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 Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our general partner and certain of our partners.

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

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities are constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others.

Item 3. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings which are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.

In September 2007, the EPA requested, and our Transco subsidiary later provided, information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of Transco’s compliance with the Clean Air Act. On March 28, 2008, the EPA issued notices of violation alleging violations of Clean Air Act requirements at these compressor stations. Transco met with the EPA in May 2008 and submitted a response denying the allegations in June 2008. In May 2011, Transco provided additional information to the EPA pertaining to these compressor stations in response to a request they had made in February 2011. In August 2010, the EPA requested, and Transco provided, similar information for a compressor station in Maryland.

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In February 2012, the New Mexico Environmental Department and Williams Four Corners LLC settled alleged violations of the New Mexico Air Quality Act at five separate facilities that we own or operate for $164,000.

In September 2011, the Colorado Department of Public Health and Environment proposed a penalty of $301,000 for alleged violations of the Colorado Clean Water Act related to excavation work being done for our Crawford Trail Pipeline. Under a settlement reached with the agency in November 2011, we agreed to pay $44,300 and undertake certain supplemental environmental projects, valued at $230,700.

Other

The additional information called for by this item is provided in Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8. Financial Statements of this report, which information is incorporated by reference into this item.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Market Information, Holders and Distributions

Our common units are listed on the NYSE under the symbol “WPZ.” At the close of business on February 14, 2012, there were 297,477,159 common units outstanding, held by approximately 72,274 record holders and holders in street name, including common units held by affiliates of Williams. In addition, our general partner holds all of our 2 percent general partner interest and incentive distribution rights. On February 17, 2012, we issued an additional 7,531,381 of our common units to Delphi Midstream Partners, LLC in connection with our acquisition of the Laser Gathering System.

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported on the NYSE Composite Transactions Tape, and quarterly cash distributions paid to our unitholders.

					Cash Distribution
	High		Low		per Unit(a)
2011
Fourth Quarter	$	61.22	$	49.11	$	0.7625
Third Quarter		57.32		45.39		0.7475
Second Quarter		56.61		48.25		0.7325
First Quarter		52.00		44.81		0.7175
2010
Fourth Quarter	$	48.99	$	42.30	$	0.7025
Third Quarter		48.95		41.32		0.6875
Second Quarter		44.15		34.62		0.6725
First Quarter		42.35		30.01		0.6575

(a) Represents cash distributions attributable to the quarter and declared and paid within 45 days after quarter end. We paid cash distributions to our general partner with respect to its general partner interest and incentive distribution rights that totaled $302 million and $203 million for the 2011 and 2010 periods, respectively. The quarterly distribution with respect to the first quarter of 2010 on the Class C units and the additional general partner units issued in connection with Williams’ contribution of ownership interests in certain entities to us in February 2010 were prorated to reflect that these interests were not outstanding during the full quarterly period.

Distributions of Available Cash

Within 45 days after the end of each quarter we will distribute all of our available cash, as defined in our partnership agreement, to unitholders of record on the applicable record date. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

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

• Provide for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated credit needs);

• 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 of available cash for the quarter resulting from working capital borrowings made after the end of the quarter for which the determination is being

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made. Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions made pursuant to a credit facility or other arrangement to the extent such borrowings are required to be reduced to a relatively small amount each year for an economically meaningful period of time.

We will make distributions of available cash from operating surplus for any quarter in the following manner:

• First, 98 percent to all unitholders, pro rata, and 2 percent to our general partner, until each outstanding unit has received the minimum quarterly distribution for that quarter; and

• Thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the incentive percentages below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to any quarter exceeds specified target levels shown below:

		Marginal Percentage
	Total Quarterly Distribution	Interest in Distributions
	Target Amount	Unitholders			General Partner
Minimum Quarterly Distribution	$0.35		98	%		2	%
First Target Distribution	up to $0.4025		98	%		2	%
Second Target Distribution	above $0.4025 up to $0.4375		85	%		15	%
Third Target Distribution	above $0.4375 up to $0.5250		75	%		25	%
Thereafter	Above $0.5250		50	%		50	%

If the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

• Any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• Our general partner will have the right to convert its general partner interest and, if any, its incentive distribution rights into common units or to receive cash in exchange for those interests.

The preceding discussion is based on the assumption that our general partner maintains its 2 percent general partner interest and that we do not issue additional classes of equity securities. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Management’s Discussion and Analysis of Financial Condition and Liquidity.”

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Item 6. Selected Financial Data

The following financial data at December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011, should be read in conjunction with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. All other financial data has been prepared from our accounting records.

	2011		2010		2009		2008		2007
	(Millions, except per-unit amounts)
Revenues	$	6,729	$	5,715	$	4,602	$	5,847	$	5,684
Net income		1,378		1,101		1,036		2,108		1,462
Net income attributable to controlling interests		1,378		1,085		1,009		2,083		1,462
Net income per limited partner unit:
Common unit		3.69		2.66		2.88		3.08		1.99
Subordinated unit		N/A		N/A		N/A		N/A		1.99
Total assets at December 31		14,380		13,404		12,475		12,167		11,419
Short-term notes payable and long-term debt due within one year at December 31		324		458		15		—		75
Long-term debt at December 31 (1)		6,913		6,365		2,981		2,971		2,821
Total equity at December 31		5,228		5,076		8,103		7,867		6,215
Cash dividends declared per unit		2.900		2.653		2.540		2.435		2.045

(1) The increase in 2010 reflects borrowings entered into related to an acquisition of certain businesses from Williams.

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

General

We are primarily an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and natural gas liquids. We manage our business and analyze our results of operations on a segment basis. Our operations are divided into two business segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).

• Gas Pipeline includes Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline), which own and operate a combined total of approximately 13,700 miles of pipelines. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 49 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream), which owns an approximate 745-mile pipeline.

• Midstream includes natural gas gathering, processing and treating facilities, and crude oil gathering and transportation facilities with primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and Pennsylvania.

As of December 31, 2011, The Williams Companies, Inc. (Williams) holds an approximate 75 percent interest in us, comprised of an approximate 73 percent limited partner interest and all of our 2 percent general partner interest.

Distributions

In the months of April, July, and October of 2011, and in January 2012, our general partner’s Board of Directors approved approximately a 2 percent increase in our quarterly distribution to unitholders. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

Overview

Crude oil and NGL prices increased in 2011, while natural gas prices have remained relatively low. We have benefited from this environment as our Net Income for 2011 increased by $277 million compared to 2010, primarily due to improved natural gas liquids (NGL) margins partially offset by higher interest expense associated with increased debt levels in conjunction with the 2010 contribution of subsidiaries from our general partner. (See Results of Operations – Consolidated Overview.)

Abundant and low-cost natural gas reserves in the United States continue to drive strong demand for midstream and pipeline infrastructure. We believe that we have successfully positioned our energy infrastructure businesses for significant future growth, as highlighted by the following accomplishments during 2011 through the present:

• In October 2011, we executed an agreement with two significant producers to provide certain production handling services in the eastern deepwater Gulf of Mexico. We will design, construct and install a floating production system (Gulfstar FPS™) that will have the capacity to handle 60 thousand barrels per day (Mbbls/d) of oil, up to 200 million cubic feet per day (MMcf/d) of natural gas, and the capability to provide seawater injection services. We expect Gulfstar FPS™ to be placed into service in 2014 and to be capable of serving as a central host facility for other deepwater prospects in the area. (See Results of Operations – Segments, Midstream Gas & Liquids.)

• During 2011, we placed into service expansions of a natural gas transmission system, compression facilities, and line facilities that provide an aggregate additional 599 Mdth/d of incremental firm capacity. We also filed an application with the FERC to increase capacity by 250 Mdth/d by expanding our natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. (See Results of Operations – Segments, Gas Pipeline.)

• In January 2012, we placed into service our Springville pipeline that will allow us to initially deliver approximately 300 MMcf/d into the Transco pipeline and full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in Pennsylvania’s Marcellus Shale. (See Results of Operations – Segments, Gas Pipeline.)

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• Discovery, an equity method investee in which we own 60 percent and operate, announced in January 2012 that it signed long-term agreements with anchor customers for natural gas gathering and processing services for production from the central deepwater Gulf of Mexico. To provide these services Discovery plans to construct a new deepwater pipeline which will have the capacity to flow approximately 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. (See Results of Operations – Segments, Midstream Gas & Liquids.)

• In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit, with expected settlement on February 28, 2012. The proceeds will be used to fund capital expenditures and for other general partnership purposes.

• In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction, and approximately 7.5 million of our common units. These entities primarily own the Laser Gathering System, which is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in the Marcellus Shale in Susquehanna County, Pennsylvania, as well as 10 miles of gathering lines in southern New York. (See Results of Operations – Segments, Midstream Gas & Liquids.)

• In February 2012, we announced a new interstate gas pipeline joint venture with Cabot Oil & Gas Corporation. The new 120-mile Constitution Pipeline will connect Williams Partners’ gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We will own 75 percent of Constitution Pipeline. This project, along with the newly acquired Laser Gathering System and our Springville pipeline are key steps in Williams Partners’ strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania.

Outlook for 2012

We believe we are well-positioned to continue to execute on our 2012 business plan and to further realize our growth opportunities. Economic and commodity price indicators for 2012 and beyond reflect continued improvement in the economic environment. However, these measures can be volatile and it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting our future operating results.

Our business plan for 2012 includes planned capital and investment expenditures of more than $2.7 billion, of which we expect to fund a significant portion through debt and equity issuances. Our structure is designed to drive lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. We expect to realize our growth opportunities through these continued investments in our businesses in a way that meets customer needs and enhances our competitive position by:

• Continuing to invest in and grow our gathering and processing and interstate natural gas pipeline systems;

• Retaining the flexibility to adjust, to some extent, our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

  Potential risks and obstacles that could impact the execution of our plan include:

• Availability of capital;

• General economic, financial markets, or industry downturn;

• Lower than anticipated energy commodity margins;

• Lower than expected levels of cash flow from operations;

• Counterparty credit and performance risk;

• Decreased volumes from third parties served by our midstream business;

• Changes in the political and regulatory environments;

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• Physical damages to facilities, especially damage to offshore facilities by named windstorms.

We continue to address these risks through disciplined investment strategies, commodity hedging strategies, and maintaining ample liquidity from cash and cash equivalents and unused revolving credit facility capacity.

Williams incurs certain corporate general and administrative costs which are charged to its business segments, including us. We expect an increase in our proportionate share of these costs in 2012, due in part to Williams’ spin-off of its former exploration and production business, which was completed on December 31, 2011.

Accounting Pronouncements Issued But Not Yet Adopted

Accounting pronouncements that have been issued but not yet adopted may have an effect on our Consolidated Financial Statements in the future.

See Accounting Standards Issued But Not Yet Adopted in Note 1 of Notes to Consolidated Financial Statements for further information on recently issued accounting standards.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions, which may involve subjectivity and judgment and/or are susceptible to change. We have reviewed the subjective and judgmental accounting estimates and assumptions used in the preparation of our financial statements and determined that we have no such critical accounting estimates. We have reviewed this determination with the Audit Committee of the Board of Directors of our general partner. We believe that none of these estimates and assumptions is material to our financial condition or results of operations.

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Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2011. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Years Ended December 31,
				$ Change		% Change						$ Change		% Change
				from		from						from		from
	2011			2010*		2010*			2010			2009*		2009*			2009
	(Millions)
Revenues	$	6,729			+1,014		+18	%	$	5,715			+1,113		+24	%	$	4,602
Costs and expenses:
Costs and operating expenses		4,672			-688		-17	%		3,984			-884		-29	%		3,100
Selling, general and administrative expenses		290			-9		-3	%		281			+19		+6	%		300
Other (income) expense — net		13			-28		NM			(15	)		-19		-56	%		(34	)
General corporate expenses		112			+13		+10	%		125			-16		-15	%		109
Total costs and expenses		5,087								4,375								3,475
Operating income		1,642								1,340								1,127
Equity earnings		142			+33		+30	%		109			+28		+35	%		81
Interest accrued — net		(415	)		-51		-14	%		(364	)		-163		-81	%		(201	)
Interest income		2			-2		-50	%		4			-16		-80	%		20
Other income (expense) — net		7			-5		-42	%		12			+3		+33	%		9
Net income		1,378								1,101								1,036
Less: Net income attributable to noncontrolling interests		—			+16		+100	%		16			+11		+41	%		27
Net income attributable to controlling interests	$	1,378							$	1,085							$	1,009

* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2011 vs. 2010

The increase in revenues is primarily due to higher marketing and NGL production revenues at Midstream resulting from higher average energy commodity prices, partially offset by lower equity NGL volumes. Additionally, fee revenues increased at Midstream primarily due to higher gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired in late 2010 and the Piceance basin as a result of an agreement executed in November 2010. Gas Pipeline transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.

The increase in costs and operating expenses is primarily due to increased marketing purchases at Midstream primarily resulting from higher average energy commodity prices. Additionally, operating costs increased primarily due to higher maintenance and higher depreciation costs. These increases are partially offset by decreased costs associated with production of NGLs reflecting lower average natural gas prices and lower equity NGL volumes at Midstream.

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The unfavorable change in other (income) expense – net within operating income primarily reflects:

• $15 million of lower involuntary conversion gains in 2011 as compared to 2010 at Midstream due to insurance recoveries that are in excess of the carrying value of assets;

• The absence of a $12 million gain in 2010 on the sale of part of our ownership interest in certain Piceance gathering assets at Midstream;

• $4 million lower sales of base gas from Hester Storage Field in 2011 compared to 2010 at Gas Pipeline.

Partially offsetting the unfavorable change is $10 million related to the reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline (see Note 5 of Notes to Consolidated Financial Statements).

The decrease in general corporate expenses is primarily due to the absence of $12 million of outside services incurred in 2010 related to certain businesses acquired from our general partner.

The increase in operating income generally reflects an improved energy commodity price environment in 2011 compared to 2010 and increased fee revenues, partially offset by higher operating costs and an unfavorable change in other (income) expense – net as previously discussed.

Equity earnings increased primarily due to a $21 million increase from Gulfstream as a result of an increased ownership interest at Gas Pipeline and a $14 million increase from the 2010 acquisition of an additional interest in Overland Pass Pipeline Company LLC (OPPL) at Midstream.

The increase in interest accrued – net is primarily due to the $3.5 billion of senior notes issued in February 2010 and $600 million of senior notes issued in November 2010. In addition, 2010 project completions at Midstream contributed to a decrease in interest capitalized.

Net income attributable to noncontrolling interest decreased due to the merger with Williams Pipeline Partners L.P. (WMZ), which was completed in the third quarter of 2010.

2010 vs. 2009

The increase in revenues is primarily due to higher marketing and NGL production revenues resulting from higher average energy commodity prices and higher fee revenues primarily due to higher gathering revenue in the Piceance basin at Midstream.

The increase in costs and operating expenses is primarily due to increased marketing purchases and NGL production costs from higher average energy commodity prices at Midstream.

Other (income) expense – net within operating income in 2009 includes a $40 million gain on the sale of our Cameron Meadows NGL processing plant at Midstream.

General corporate expenses in 2010 include $12 million of outside services as discussed above.

The increase in operating income generally reflects an improved energy commodity margin environment in 2010 compared to 2009 and increased gathering-related fee revenues. The favorable change is partially offset by outside services incurred related to certain businesses acquired from our general partner and an unfavorable change in other (income) expense – net.

The increase in equity earnings is primarily due to a $10 million increase from Discovery, a $10 million increase from Aux Sable Liquid Products LP (Aux Sable) and equity earnings of $5 million from our increased investment in OPPL in 2010 at Midstream.

Interest accrued – net increased primarily due to the $3.5 billion of senior notes that were issued in February 2010 in conjunction with certain businesses acquired from our general partner.

Interest income decreased due primarily to reduced advances to affiliates and lower average interest rates in 2010 compared to 2009.

Net income attributable to noncontrolling interests decreased due to the merger with WMZ, which was completed in the third quarter of 2010.

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Results of Operations — Segments

Gas Pipeline

Overview

Gas Pipeline’s strategy to create value focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little near-term impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

Significant events of 2011 include:

Completed Expansion Projects

85 North

In September 2009, we received approval from the FERC to construct an expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. Phase I was placed into service in July 2010 and it provides 90 thousand dekatherms per day (Mdth/d) of incremental firm capacity. Phase II was placed into service in May 2011 and it provides 219 Mdth/d of incremental firm capacity.

Mobile Bay South II

In July 2010, we received approval from the FERC to construct additional compression facilities and modifications to existing Mobile Bay line facilities in Alabama allowing transportation service to various southbound delivery points. The project was placed into service in May 2011 and provides incremental firm capacity of 380 Mdth/d.

In-progress Expansion Projects

Mid-South

In August 2011, we received approval from the FERC to upgrade compressor facilities and expand our existing natural gas transmission system from Alabama to markets as far north as North Carolina. The cost of the project is estimated to be $217 million. The project is expected to be phased into service in September 2012 and June 2013, with an expected increase in capacity of 225 Mdth/d.

Mid-Atlantic Connector

In July 2011, we received approval from the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The cost of the project is estimated to be $55 million and is expected to increase capacity by 142 Mdth/d. We plan to place the project into service in November 2012.

Northeast Supply Link

In December 2011, we filed an application with the FERC to expand our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in New York and New Jersey. The cost of the project is estimated to be $341 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

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Gulfstream acquisition

In May 2011, we acquired from Williams an additional 24.5 percent interest in Gulfstream in exchange for aggregate consideration of $297 million of cash, 632,584 limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. We funded the cash consideration for this transaction through our credit facility.

Eminence Storage Field Leak

On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Mississippi. Due to the leak and related damage to the well at an adjacent cavern, both caverns are out of service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should also be retired. The event has not affected the performance of our obligations under our service agreements with our customers.

In September 2011, we filed an application with the FERC seeking authorization to abandon these four caverns. We estimate the total abandonment costs, which will be capital in nature, will be approximately $76 million which is expected to be spent through the first half of 2013. Through December 31, 2011 we have incurred approximately $38 million in abandonment costs. This estimate is subject to change as work progresses and additional information becomes known. Management considers these costs to be prudent costs incurred in the abandonment of these caverns and expects to recover these costs, net of insurance proceeds, in future rate filings. To the extent available, the abandonment costs will be funded from the ARO Trust. (See Note 14 of Notes to Consolidated Financial Statements.)

For the year ended December 31, 2011, we incurred approximately $15 million of expense related primarily to assessment and monitoring costs to ensure the safety of the surrounding area.

Outlook for 2012

In addition to the various in-progress expansion projects previously discussed, we have several other proposed projects to meet customer demands. Subject to regulatory approvals, construction of some of these projects could begin as early as 2012. We have planned capital and investment expenditures of $600 million to $700 million in 2012 mainly due to various in-progress expansion projects discussed above, as well as maintenance of existing facilities, primarily due to pipeline integrity costs and U. S. Department of Transportation mandatory requirements.

Filing of rate cases

During 2012, we expect to file rate cases for both Transco and Northwest Pipeline, which are expected to result in new transportation and storage rates beginning in 2013.

Year-Over-Year Operating Results

	Year ended December 31,
	2011		2010		2009
	(Millions)
Segment revenues	$	1,678	$	1,605	$	1,591
Segment profit	$	673	$	637	$	635

2011 vs. 2010

Segment revenues increased $73 million, or 5 percent, primarily due to a $68 million increase in transportation revenues associated with expansion projects placed in service during 2010 and 2011, and $17 million higher system management gas sales (offset in costs and operating expenses). These increases are partially offset by $4 million lower sales of base gas from Hester Storage Field.

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Costs and operating expenses increased $55 million, or 7 percent, primarily due to $17 million higher system management gas costs (offset in segment revenues), $17 million increased pipeline maintenance costs, $10 million higher depreciation expense resulting from additional assets placed in service in 2010 and 2011, and $10 million increased operations and maintenance expense related to the Eminence Storage Field leak.

Equity earnings improved $20 million primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Segment profit increased primarily due to the previously described changes.

2010 vs. 2009

Segment revenues increased primarily due to a $20 million increase in transportation revenues associated with expansion projects placed in service by Transco during 2010 and 2009 and a $9 million sale of base gas from Hester Storage Field (offset in costs and operating expenses.) Offsetting these increases is a $20 million decrease in other service revenues associated with reduced customer usage of our temporary natural gas loan and storage services.

Costs and operating expenses increased $25 million, or 3 percent, reflecting the absence of $11 million of income from an adjustment of state franchise taxes in 2009, a $9 million increase associated with the cost of selling base gas from Hester Storage Field (offset in segment revenues) and higher depreciation expense of $7 million.

Selling, general and administrative expenses decreased $13 million, or 8 percent, primarily due to lower employee-related expenses, including pension and other postretirement benefits.

Other (income) expense — net reflects increased expense of $10 million related to the over collection of certain employee-related expenses (offset in segment revenues) that will be returned to customers, partially offset by a $8 million gain on the sale of base gas from Hester Storage Field.

Segment profit increased primarily due to the previously described changes.

Midstream Gas & Liquids

Overview of 2011

Midstream’s ongoing strategy is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers.

Significant events during 2011 include the following:

Laser Northeast Gathering System Acquisition

In February 2012, we acquired the Laser Northeast Gathering System and other midstream businesses from Delphi Midstream Partners, LLC for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and approximately 7.5 million of our common units. The Laser Gathering System is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, Pennsylvania, as well as 10 miles of gathering pipeline in southern New York. The acquisition is supported by existing long-term gathering agreements that provide acreage dedications and volume commitments. As production in the Marcellus increases, the Laser system is expected to reach a capacity of 1.3 Bcf/d.

Marcellus Shale Gathering Asset Transition and Expansion

Our Springville pipeline was placed into service in January 2012, allowing us to deliver approximately 300 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 650 MMcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern

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Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. In conjunction with a long-term agreement with a significant producer, we are operating the 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline. Expansions to the Springville compression facilities in 2012 are expected to increase the capacity to approximately 625 MMcf/d.

Construction of a new noncontiguous gathering system is complete and was placed into service in October 2011. This system currently has the capacity to deliver approximately 50 MMcf/d into a third-party interstate pipeline via the newly acquired Laser gathering system.

In early 2011, we assumed the operational activities for these gathering systems in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010. The acquired business included 75 miles of gathering pipelines and two compressor stations. We expect to expand this gathering system to a planned capacity of 1.7 Bcf/d by 2015.

Keathley Canyon Connector^TM

Our equity investee, Discovery, plans to construct, own, and operate a new 215-mile 20-inch deepwater lateral pipeline for production from the Keathley Canyon Connector™, Walker Ridge, and Green Canyon areas in the central deepwater Gulf of Mexico. Discovery has signed long-term agreements with anchor customers for natural gas gathering and processing services for production from those fields. The Keathley Canyon Connector^TM lateral will originate from a third party floating production facility in the southeast portion of the Keathley Canyon Connector™ area and will connect to Discovery’s existing 30-inch offshore gas transmission system. The lateral pipeline is estimated to have the capacity to flow more than 400 MMcf/d and will accommodate the tie-in of other deepwater prospects. Construction is expected to begin in 2013, with a mid-2014 in-service date.

Gulfstar FPS™ Deepwater Project

In October 2011, we executed agreements with two significant producers to provide production handling services for the Tubular Bells discovery located in the eastern deepwater Gulf of Mexico. The operator of the Tubular Bells field will utilize our proprietary floating-production system, Gulfstar FPS™. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. We will design, construct, and install our Gulfstar FPS™ with a capacity of 60 Mbbls/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection services. The facility is a spar-based floating production system that utilizes a standard design approach that will allow customers to reduce their cycle time from discovery to first production. Construction is underway and the project is expected to be in service in 2014.

Eagle Ford Shale

We have completed construction on a pipeline segment and related modifications necessary to reverse the flow of an existing Transco pipeline segment in southwest Texas, which began to gather south Texas gas to our Markham gas processing facility in the second quarter of 2011. In addition, we connected a third-party pipeline to our Markham plant during the third quarter that is delivering Eagle Ford Shale gas to the plant. We have executed both fee-based and keep whole processing agreements which we expect will increase utilization of our Markham facility to the full gas processing capacity. Markham is subject to limited NGL take-away capacity until third-party pipeline connections are completed in early 2013.

Perdido Norte

During the fourth quarter of 2010, both oil and gas production began to flow on a sustained basis through our Perdido Norte expansion, located in the western deepwater of the Gulf of Mexico. The project included a 200 MMcf/d expansion of our Markham gas processing facility and a total of 179 miles of deepwater oil and gas lines that expand the scale of our existing infrastructure. While 2011 production volumes were significantly lower than originally expected, they have increased each quarter of 2011, as producers have resolved several technical issues. With these improvements and with the addition of a new well, we anticipate volumes in 2012 to be higher than in 2011.

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Overland Pass Pipeline

We became the operator of OPPL effective April 1, 2011. We own a 50 percent interest in OPPL which includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Julesburg basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek plant in Colorado are dedicated for transport on OPPL under a long-term shipping agreement. We plan to participate in the construction of a pipeline connection and capacity expansions, expected to be complete in early 2013, to increase the pipeline’s capacity to the maximum of 255 Mbbls/d, to accommodate new volumes coming from the Bakken Shale in the Williston basin.

Laurel Mountain

The initial phases of the Shamrock compressor station are in service, providing 60 MMcf/d of additional capacity, with further expansions planned in 2012. This compressor station is expandable to 350 MMcf/d and will likely be the largest central delivery point out of the Laurel Mountain system. Our equity investee continues to progress on further additions to the gathering infrastructure.

Volatile commodity prices

Average per-unit NGL margins in 2011 were significantly higher than in 2010, benefiting from a strong demand for NGLs resulting in higher NGL prices and slightly lower natural gas prices driven by abundant natural gas supplies.

NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.

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Outlook for 2012

The following factors could impact our business in 2012.

Commodity price changes

• We expect our average per-unit NGL margins in 2012 to be comparable to 2011 and higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude, and natural gas prices are highly volatile, difficult to predict, and are often not highly correlated. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

• As part of our efforts to manage commodity price risks on an enterprise basis, we continue to evaluate our commodity hedging strategies. To reduce the exposure to changes in market prices in 2012, we have entered into NGL swap agreements to fix the prices of approximately 5 percent of our anticipated NGL sales volumes and an approximate corresponding portion of anticipated shrink gas requirements for 2012. The combined impact of these energy commodity derivatives will provide a margin on the hedged volumes of $106 million. The following table presents our energy commodity hedging instruments as of February 15, 2012.

				Weighted
	Period	Volumes Hedged		Average  Hedge Price
Designated as hedging instruments:					(per gallon)
NGL sales - isobutane (million gallons)	Feb - Dec 2012		12.8	$	1.89
NGL sales - normal butane (million gallons)	Feb - Dec 2012		19.3	$	1.79
NGL sales - natural gasoline (million gallons)	Feb - Dec 2012		29.0	$	2.27
				(per MMbtu)
Natural gas purchases (Tbtu)	Feb - Dec 2012		6.5	$	2.76

Gathering, processing, and NGL sales volumes

• The growth of natural gas supplies supporting our gathering and processing volumes are impacted by producer drilling activities, which are influenced by natural gas prices.

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• In our onshore businesses, we anticipate significant growth in our gas gathering volumes as our infrastructure grows to support drilling activities in northeast Pennsylvania. We anticipate slight increases in gas gathering volumes in the Piceance basin and no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. We anticipate equity NGL volumes in 2012 to be comparable to 2011, as we expect little change in the volume of gas processed in the western onshore businesses. Sustained low gas prices could discourage producer drilling activities in our onshore areas and unfavorably impact the supply of natural gas available to gather and process in the long term.

• In our gulf coast businesses, we expect higher gas gathering, processing, and crude transportation volumes as production flowing through our Perdido Norte pipelines becomes consistent and other in-process drilling is completed. Increases in permitting, subsequent to the 2010 drilling moratorium, give us reason to expect gradual increased drilling activities in the Gulf of Mexico. In the Gulf Coast, our customers’ drilling activities are primarily focused on crude oil economics, rather than natural gas. We have not experienced, and do not anticipate an overall significant decline in volumes due to reduced drilling activities.

• The operator of the third-party fractionator serving our NGL production transported on Overland Pass Pipeline has notified us of an expected 20- to 25-day outage in the second quarter of 2012 to accommodate their expansion efforts. The outage could result in a reduction to our equity volumes of up to approximately 20 million to 25 million gallons, along with price impacts; however we are evaluating methods to mitigate the impact.

• We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in northeast Pennsylvania, Piceance basin, and western Gulf of Mexico.

Expansion Projects

We have planned growth capital and investment expenditures of $2,035 million to $2,215 million in 2012. We plan to pursue expansion and growth opportunities in the Marcellus Shale region, Gulf of Mexico, and Piceance basin.

As previously discussed, our ongoing major expansion projects include expansions to our gathering infrastructure in the Marcellus Shale region in northeastern Pennsylvania, including the acquisition of the Laser gathering system and related planned additions, expansions within our Laurel Mountain equity investment, also in the Marcellus Shale region, as well as our Gulfstar FPS^™ floating production system and Discovery’s Keathley Canyon Connector^TM pipeline, both located in the Gulf of Mexico.

In addition, we plan to construct a 350 MMcf/d cryogenic gas processing plant in conjunction with a new basin-wide agreement for all gathering and processing services provided by us to a customer in the Piceance basin. The Parachute TXP I plant is expected to be in service in 2014.

Year-Over-Year Operating Results

	Years ended December 31,
	2011		2010		2009
	(Millions)
Segment revenues	$	5,051	$	4,110	$	3,011
Segment profit	$	1,223	$	937	$	682

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2011 vs. 2010

The increase in segment revenues includes:

• A $589 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are substantially offset by similar changes in marketing purchases.

• A $244 million increase in revenues from our equity NGLs reflecting an increase of $272 million associated with a 25 percent increase in average NGL per-unit sales prices, partially offset by a decrease of $28 million associated with a 3 percent decrease in equity NGL volumes.

• A $103 million increase in fee revenues primarily due to higher gathering and processing fee revenues. We have fees from new volumes on our gathering assets in the Marcellus Shale in northeastern Pennsylvania, which we acquired at the end of 2010, and on our Perdido Norte gas and oil pipelines in the western deepwater Gulf of Mexico, which went into service in late 2010. In addition, higher fees in the Piceance basin are primarily a result of an agreement executed in November 2010. These increases are partially offset by a decline in gathering and transportation fees in the eastern deepwater Gulf of Mexico primarily due to natural field declines.

Segment costs and expenses increased $669 million, or 21 percent, including:

• A $574 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are offset by similar changes in marketing revenues.

• A $99 million increase in operating costs reflecting $57 million, or 17 percent, higher maintenance expenses, including maintenance expenses for our gathering assets in northeastern Pennsylvania acquired at the end of 2010, more maintenance performed on our assets in the western onshore businesses, and higher property insurance expense. In addition, depreciation expense is $33 million higher primarily due to our new Perdido Norte pipelines and our Echo Springs expansion, both of which went into service in late 2010, along with accelerated depreciation of our Lybrook plant which was idled in January 2012 when the gas was redirected to our Ignacio plant.

• The absence of $30 million in gains recognized in 2010 associated with sale of certain assets in Colorado’s Piceance basin and involuntary conversion gains due to insurance recoveries in excess of the carrying value.

• A $42 million decrease in costs associated with our equity NGLs reflecting a decrease of $21 million associated with a 5 percent decrease in average natural gas prices and a $21 million decrease reflecting lower equity NGL volumes.

The increase in Midstream’s segment profit reflects the previously described changes in segment revenues and segment costs and expenses. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The increase in Midstream’s segment profit includes:

• A $286 million increase in NGL margins reflecting:

• A $278 million increase in the onshore businesses’ NGL margins reflecting a $249 million increase from favorable commodity price changes due primarily to a 25 percent increase in average NGL prices. NGL equity volumes sold are 5 percent higher reflecting new capacity at our Echo Springs plant.

• An $8 million increase in the gulf coast business’s NGL margins related to a $39 million increase from favorable commodity price changes, partially offset by 39 percent lower NGL equity volumes sold primarily due to a change in a major contract from “keep-whole” to “percent-of-liquids” processing.

• A $103 million increase in fee revenues as previously discussed.

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• A $15 million increase in margins related to the marketing of NGLs and crude.

• A $13 million increase in equity earnings primarily due to higher OPPL equity earnings as a result of our purchase of an increased ownership interest in September 2010.

• A $99 million increase in operating costs as previously discussed.

• A $30 million unfavorable change primarily related to gains recognized in 2010 as previously discussed.

2010 vs. 2009

The increase in segment revenues includes:

• A $699 million increase in marketing revenues primarily due to higher average NGL and crude prices. These changes are more than offset by similar changes in marketing purchases.

• A $330 million increase in revenues associated with the production of NGLs reflecting an increase of $335 million associated with a 41 percent increase in average NGL per-unit sales prices.

• A $56 million increase in fee revenues primarily due to higher gathering revenue in the Piceance basin as a result of permitted increases in the cost-of-service gathering rate in 2010 and to new fees for processing natural gas production at Willow Creek. These increases are partially offset by reduced fees from lower deepwater gathering and transportation volumes and lower gathering rates and volumes in the Four Corners area.

Segment costs and expenses increased $861 million, or 36 percent, including:

• A $721 million increase in marketing purchases primarily due to higher average NGL and crude prices. These changes are offset by similar changes in marketing revenues.

• A $107 million increase in costs associated with the production of NGLs reflecting an increase of $101 million associated with a 30 percent increase in average natural gas prices.

• A $19 million increase in operating costs including $12 million higher depreciation primarily due to our new Perdido Norte pipelines and a full year of depreciation on our Willow Creek facility which was placed into service in the latter part of 2009.

• The absence of a $40 million gain on the sale of our Cameron Meadows processing plant in 2009, partially offset by smaller gains in 2010 including involuntary conversion gains due to insurance recoveries in excess of the carrying value of our gulf assets which were damaged by Hurricane Ike in 2008 and our Ignacio plant, which was damaged by a fire in 2007 and gains associated with sales of certain assets in Colorado’s Piceance basin.

The increase in Midstream’s segment profit reflects the previously described changes in segment revenues and segment costs and expenses and higher equity earnings. A more detailed analysis of the segment profit of certain Midstream operations is presented as follows.

The increase in Midstream’s segment profit includes:

• A $223 million increase in NGL margins reflecting:

• A $194 million increase in the onshore businesses’ NGL margins reflecting a 43 percent increase in average NGL prices, partially offset by an increase in production costs reflecting a 31 percent increase in average natural gas prices. NGL equity volumes were slightly higher due primarily to a full year of production at Willow Creek in 2010 and new production capacity at Echo Springs in the fourth quarter of 2010, partially offset by the absence of favorable customer contractual changes in 2009 and decreasing inventory levels in 2009.

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• A $30 million increase in the gulf coast businesses’ NGL margins reflecting a $40 million increase related to commodity price changes including a 34 percent increase in average NGL prices, partially offset by a 27 percent increase in average natural gas prices. NGL equity volumes sold were slightly lower driven by a 15 percent decrease in non-ethane volumes sold. Unfavorable impacts include natural field declines and an isolated sub-sea mechanical issue that reduced the Boomvang gas production flow, partially offset by low recoveries, primarily of ethane, in the first quarter of 2009 driven by unfavorable NGL economics.

• A $25 million increase in equity earnings, primarily due to

• A $10 million increase from Discovery due primarily to higher processing margins and new volumes from the Tahiti pipeline lateral expansion completed in 2009.

• A $10 million increase from Aux Sable primarily due to higher processing margins.

• A $5 million increase from our new investment in Overland Pass Pipeline.

• A $56 million increase in fee revenues as previously discussed.

• A $19 million increase in operating costs as previously discussed.

• A $14 million unfavorable change related to the disposal of assets as previously discussed.

• A $22 million decrease in margins related to the marketing of NGLs and crude primarily due to lower favorable changes in pricing while product was in transit in 2010 as compared to 2009.

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2011, we continued to focus upon growth through disciplined investments in our natural gas businesses. Examples of this growth included:

• Expansion of Gas Pipeline’s interstate natural gas pipeline system and increased ownership in Gulfstream to meet the demand of growth markets.

• Continued investment in Midstream’s gathering and processing capacity and infrastructure in the Marcellus Shale area, western United States, and deepwater Gulf of Mexico.

These investments were primarily funded through cash flow from operations and debt offerings.

Outlook

For 2012, we expect continued strong operating results and cash flows due to the combination of continued strong energy commodity margins and the start-up of certain expansion capital projects. However, energy commodity prices are volatile and difficult to predict. Although our cash flows are impacted by fluctuations in energy commodity prices, that impact is somewhat mitigated by certain of our cash flow streams that are not directly impacted by short-term commodity price movements, as follows:

• Firm demand and capacity reservation transportation revenues under long-term contracts at Gas Pipeline;

• Fee-based revenues from certain gathering and processing services at Midstream.

We believe we have, or have access to, the financial resources and liquidity necessary to meet our requirements for working capital, capital and investment expenditures, unitholder distributions and debt service payments while maintaining a sufficient level of liquidity. In particular, we note the following for 2012:

• We increased our per-unit quarterly distribution with respect to the fourth quarter of 2011 from $0.7475 to $0.7625. We expect to increase quarterly limited partner cash distributions by approximately 6 percent to 10 percent annually.

• We have $325 million of debt maturing in 2012. We anticipate funding this maturity with a new debt issuance.

• We expect to fund capital and investment expenditures, debt service payments, distributions to unitholders and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, cash proceeds from common unit and/or long-term debt issuances and utilization of our revolving credit facility as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.775 billion and $2.25 billion in 2012.

• In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit, with expected settlement on February 28, 2012.

• As previously discussed, on February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and approximately 7.5 million common units.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2012. Our internal and external sources of liquidity include:

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• Cash and cash equivalents on hand;

• Cash generated from operations, including cash distributions from our equity-method investees;

• Cash proceeds from offerings of our common units and/or long-term debt;

• Use of our credit facility, as needed and available.

We anticipate our more significant uses of cash to be:

• Maintenance and expansion capital expenditures;

• Payment of debt maturities (pursuant to expected issuances of new long-term debt);

• Contributions to our equity-method investees to fund their expansion capital expenditures;

• Interest on our long-term debt;

• Quarterly distributions to our unitholders and/or general partner.

Potential risks associated with our planned levels of liquidity and the planned capital and investment expenditures discussed above include:

• Lower than expected levels of cash flow from operations;

• Limited availability of capital due to a change in our financial condition, interest rates, market or industry conditions;

• Sustained reductions in energy commodity margins from expected 2012 levels;

• Physical damages to facilities, especially damage to offshore facilities by named windstorms.

Available Liquidity	December 31, 2011
	(Millions)
Cash and cash equivalents	$	163
Capacity available under our $2 billion five-year senior unsecured revolving credit facility (expires June 3, 2016) (1)		2,000
	$	2,163

(1) In June 2011, we replaced our existing $1.75 billion unsecured revolving credit facility agreement with a new $2 billion five-year senior unsecured revolving credit facility agreement. The full amount of the new credit facility is available to us, to the extent not otherwise utilized by Transco and Northwest Pipeline, and may, under certain conditions, be increased by up to an additional $400 million. Transco and Northwest Pipeline are each able to borrow up to $400 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2011, we are in compliance with the financial covenants associated with this new credit facility agreement. (See 10 of Notes to Consolidated Financial Statements.)

Shelf Registration

In February 2012, we filed a shelf registration statement as a well-known seasoned issuer that allows us to issue an unlimited amount of registered debt and limited partnership unit securities.

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Distributions from Equity Method Investees

Our equity method investees’ organizational documents require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. Our more significant equity method investees include: Aux Sable, Discovery, Gulfstream, Laurel Mountain, and OPPL.

Debt Offerings

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. A portion of the proceeds were used to retire Transco’s $300 million 7 percent senior unsecured notes that matured on August 15, 2011.

In November 2011, we completed a public offering of $500 million of our 4 percent senior notes due 2021. We used the net proceeds primarily to repay outstanding borrowings on our senior unsecured revolving credit facility.

Credit Ratings

The table below presents our current credit ratings and outlook on our senior unsecured long-term debt.

			Senior Unsecured
Rating Agency	Date of Last Change	Outlook	Debt Rating
Standard & Poor’s	January 12, 2010	Positive	BBB-
Moody’s Investor Service	February 27, 2012	Stable	Baa2
Fitch Ratings	February 9, 2012	Positive	BBB-

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 Moody’s, a rating of “Baa” or above indicates an investment grade rating. A rating below “Baa” is considered to have speculative elements. 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 Fitch, a rating of “BBB” or above indicates an investment grade rating. A rating below “BBB” is considered speculative grade. Fitch may add a “+” or a “-” sign to show the obligor’s relative standing within a major rating category.

Credit rating agencies perform independent analyses when assigning credit ratings. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their current criteria for investment grade ratios. A downgrade of our credit rating might increase our future cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. As of December 31, 2011, we estimate that a downgrade to a rating below investment grade could require us to post up to $134 million in additional collateral with third parties.

Capital Expenditures

Each of our businesses is capital-intensive, requiring investment to upgrade or enhance existing operations and comply with safety and environmental regulations. The capital requirements of these businesses consist primarily of:

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• Maintenance capital expenditures, which are generally not discretionary, including (1) capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of our assets and to extend their useful lives, (2) expenditures which are mandatory and/or essential to comply with laws and regulations and maintain the reliability of our operations, and (3) certain well connection expenditures.

• Expansion capital expenditures, which are generally more discretionary than maintenance capital expenditures, including (1) expenditures to acquire additional assets to grow our business, to expand and upgrade plant or pipeline capacity and to construct new plants, pipelines and storage facilities and (2) well connection expenditures which are not classified as maintenance expenditures.

The following table provides summary information related to our expected capital expenditures for 2012:

	Maintenance						Expansion
Segment	Low		Midpoint		High		Low		Midpoint		High
	(Millions)
Gas Pipeline	$	330	$	355	$	380	$	270	$	295	$	320
Midstream		115		125		135		2,035		2,125		2,215
Total	$	445	$	480	$	515	$	2,305	$	2,420	$	2,535

See Results of Operations – Segments, Gas Pipeline and Midstream for discussions describing the general nature of these expenditures.

Cash Distributions to Unitholders

We have paid quarterly distributions to unitholders and our general partner after every quarter since our initial public offering on August 23, 2005. However, Williams waived its incentive distribution rights related to the 2009 distribution periods. We have increased our quarterly distribution from $0.7475 to $ 0.7625 per unit, which resulted in a fourth- quarter 2011 distribution of approximately $311 million that was paid on February 10, 2012, to the general and limited partners of record at the close of business on February 3, 2012.

Sources (Uses) of Cash

	Years Ended December 31,
	2011			2010			2009
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,166		$	1,816		$	1,483
Financing activities		(818	)		3,517			(544	)
Investing activities		(1,372	)		(5,299	)		(919	)
Increase (decrease) in cash and cash equivalents	$	(24	)	$	34		$	20

Operating activities

Net cash provided by operating activities increased $350 million in 2011 as compared to 2010 primarily due to higher operating income.

Net cash provided by operating activities increased $333 million in 2010 as compared to 2009 primarily due to higher operating income and changes in working capital.

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Financing activities

Significant transactions include:

2011

• $1.1 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $500 million received from our public offering of senior unsecured notes in November 2011 primarily used to repay borrowings on our revolving credit facility mentioned below;

• $375 million received from Transco’s issuance of senior unsecured notes in August 2011;

• $300 million paid to retire Transco’s senior unsecured notes that matured in August 2011;

• $300 million received in revolver borrowings from our $1.75 billion unsecured credit facility used to acquire a 24.5 percent interest in Gulfstream from Williams in May 2011. This obligation was transferred to our new $2 billion unsecured credit facility at its inception in June 2011;

• $150 million paid to retire senior unsecured notes that matured in June 2011;

• $123 million distributed to Williams related to the excess purchase price over the contributed basis of Gulfstream in May 2011;

• $425 million in net borrowings and payments related to our revolving credit facility in 2011.

2010

• $3.5 billion of net proceeds from the issuance of senior unsecured notes;

• $660 million related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $600 million received from our public offering of senior notes in November 2010 primarily used to fund a portion of the cash consideration paid for our Piceance acquisition;

• $437 million received from our September and October 2010 equity offering primarily used to reduce revolver borrowings;

• $430 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used to fund our increased ownership in OPPL, a transaction that closed in September 2010;

• $369 million received from our December 2010 equity offering used to reduce revolver borrowings and to fund a portion of our acquisition of certain midstream assets in Pennsylvania’s Marcellus Shale in December 2010;

• $250 million received from revolver borrowings on our $1.75 billion unsecured credit facility in February 2010 to repay a term loan outstanding under our credit agreement which expired at the closing of certain businesses we acquired from Williams;

• $244 million distributed to Williams related to the excess purchase price over the contributed basis of the gathering and processing assets acquired in Colorado’s Piceance basin;

• $200 million received in revolver borrowings from our $1.75 billion unsecured credit facility primarily used for general partnership purposes and to fund a portion of the cash consideration paid for our acquisition of certain gathering and processing assets in Colorado’s Piceance basin;

• $152 million in distributions to Williams primarily related to the Contributed Entities prior to the closing of certain businesses we acquired from Williams.

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2009

• $384 million in distributions to Williams related to the Contributed Entities prior to the closing of certain businesses we acquired from Williams;

• $144 million related to quarterly cash distributions paid to limited partner unitholders and our general partner.

Investing activities

Significant transactions include:

2011

• $991 million in capital expenditures;

• $174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (see Results of Operations – Segments, Gas Pipeline);

• $137 million contribution to our Laurel Mountain equity investment.

2010

• $3.4 billion related to the cash consideration paid for certain businesses we acquired from Williams;

• $837 million in capital expenditures;

• $458 million related to our Piceance acquisition;

• $424 million cash payment for our September 2010 acquisition of an increased interest in OPPL;

• $150 million paid for the purchase of a business in December 2010, consisting primarily of midstream assets in Pennsylvania’s Marcellus Shale.

2009

• $907 million in capital expenditures;

• $108 million cash payment for our 51 percent ownership interest in our Laurel Mountain equity investment;

• $73 million of cash received as a distribution from Gulfstream following its debt offering.

Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments

We have various other guarantees and commitments which are disclosed in Notes 8, 10, 14, and 15 of Notes to Consolidated Financial Statements. We do not believe these guarantees or the possible fulfillment of them will prevent us from meeting our liquidity needs.

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Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2011:

			2013 -		2015 -
	2012		2014		2016		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal	$	325	$	—	$	1,125	$	5,803	$	7,253
Interest		411		764		698		3,045		4,918
Operating leases (1)		33		49		44		145		271
Purchase obligations (2)		1,340		441		381		1,292		3,454
Other long-term obligations		—		1		1		—		2
Total	$	2,109	$	1,255	$	2,249	$	10,285	$	15,898

(1) Includes a right-of-way agreement with the Jicarilla Apache Nation, which is considered an operating lease. We are required to make a fixed annual payment of $7.5 million and an additional annual payment, which varies depending on per-unit NGL margins and the volume of gas gathered by our gathering facilities subject to the right-of-way agreement. The table above for years 2013 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable.

(2) Includes an estimated $2.2 billion long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31,2011 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator in Conway, Kansas, and we are subsequently obligated to purchase ethane volumes at Mont Belvieu. The purchased ethane volumes may be utilized or resold at comparable prices in the Mont Belvieu market.

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 63 percent of our gross property, plant, and equipment is at Gas Pipeline. Gas Pipeline is subject to regulation, which limits recovery to historical cost. While amounts in excess of historical cost are not recoverable under current FERC practices, we anticipate being allowed to recover and earn a return based on increased actual cost incurred to replace existing assets. Cost-based regulations, along with competition and other market factors, may limit our ability to recover such increased costs. For Midstream, operating costs are influenced to a greater extent by both competition for specialized services and specific price changes in crude oil and natural gas and related commodities than by changes in general inflation. Crude oil, natural gas, and NGL prices are particularly sensitive to the Organization of the Petroleum Exporting Countries (OPEC) production levels and/or the market perceptions concerning the supply and demand balance in the near future, as well as general economic conditions. However, our exposure to these price changes is reduced through the fee-based nature of certain of our services.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and/or remedial processes at certain sites, some of which we currently do not own (see Note 15 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $18 million, all of which are included in other accrued liabilities and regulatory liabilities, deferred income and other on the Consolidated Balance Sheet at December 31, 2011. We will seek recovery of approximately $10 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2011, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $4 million in 2012 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. At December 31, 2011, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

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We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone, we have installed air pollution controls on existing sources at certain facilities in order to reduce ozone emissions.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. In September 2011, the EPA announced it would not move forward with the proposed 2010 ozone NAAQS. Instead, the EPA will implement the 2008 ozone NAAQS that was stayed during the reconsideration process. The EPA is expected to designate ozone nonattainment areas under the 2008 NAAQS in second quarter 2012 and we are unable at this time to estimate the cost of additions that may be required to meet this new regulation. However, designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment – net on the Consolidated Balance Sheet.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include capital costs in the range of $24 million to $32 million through 2013, the compliance date.

In June 2010, the EPA promulgated a final rule establishing a new one-hour sulfur dioxide (SO₂) NAAQS. The effective date of the new SO₂ standard was August 23, 2010. This new standard is subject to challenge in federal court. EPA has not adopted final modeling guidance. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

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

Our interstate natural gas pipelines consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facilities could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 10 of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2011 and 2010. Long-term debt in the tables represents principal cash flows, net of (discount) premium, and weighted-average interest rates by expected maturity dates. 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.

	2012		2013		2014		2015		2016		Thereafter(1)		Total		Fair Value December 31, 2011
	(Millions)
Long-term debt, including current portion:
Fixed rate	$	325	$	—	$	—	$	750	$	375	$	5,787	$	7,237	$	8,170
Interest rate		5.6%		5.5%		5.5%		5.6%		5.7%		5.9%
	2011		2012		2013		2014		2015		Thereafter(1)		Total		Fair Value December 31, 2010
	(Millions)
Long-term debt, including current portion:
Fixed rate	$	458	$	325	$	—	$	—	$	750	$	5,290	$	6,823	$	7,283
Interest rate		5.9%		5.7%		5.7%		5.7%		5.8%		6.1%

(1) Includes unamortized discount and premium.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas and NGLs, as well as other market factors, such as market volatility and energy commodity price correlations. We are exposed to these risks in connection with our owned energy-related assets and our long-term energy-related contracts, and limited proprietary trading activities. Our management of the risks associated with these market fluctuations includes maintaining a conservative capital structure and significant liquidity, as well as using various derivatives and non derivative energy-related contracts. The fair value of derivative contracts is subject to many factors, including changes in energy commodity market prices, the liquidity and volatility of the markets in which the contracts are transacted, and changes in interest rates. (See Note 14 of Notes to Consolidated Financial Statements.)

We measure the risk in our portfolio using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolio. Value-at-risk requires a number of key assumptions and is not necessarily representative of actual losses in fair value that could be incurred from the portfolio. Our value-at-risk model uses a Monte Carlo method to simulate hypothetical movements in future market prices and assumes that, as a result of changes in commodity prices, there is a 95 percent probability that the one-day loss in fair value of the portfolio will not exceed the value-at-risk. The simulation method uses historical correlations and market forward prices and volatilities. In applying the value-at-risk methodology, we do not consider that the simulated hypothetical movements affect the positions or would cause any potential liquidity issues, nor do we consider that

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changing the portfolio in response to market conditions could affect market prices and could take longer than a one-day holding period to execute. While a one-day holding period has historically been the industry standard, a longer holding period could more accurately represent the true market risk given market liquidity and our own credit and liquidity constraints.

We segregate our derivative contracts into trading and nontrading contracts, as defined in the following paragraphs. We calculate value-at-risk separately for these two categories. Contracts designated as normal purchases or sales and nonderivative energy contracts have been excluded from our estimation of value-at-risk.

Trading

Our limited trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of less than $0.1 million at December 31, 2011. The value-at-risk for contracts held for trading purposes was less than $0.1 million at December 31, 2011 and zero at December 31, 2010.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL sale activities.

The fair value of our nontrading derivatives was a net asset of $1 million at December 31, 2011.

The value at risk for derivative contracts held for nontrading purposes was zero at December 31, 2011 and 2010. During the year ended December 31, 2011, our value-at-risk for these contracts ranged from a high of $1 million to a low of zero.

Certain of the derivative contracts held for nontrading purposes in 2011 were accounted for as cash flow hedges but realized during the year. Of the total fair value on nontrading derivatives, cash flow hedges had a net asset value of zero as of December 31, 2011. Though these contracts would be included in our value-at-risk calculation, any changes in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Trading Policy

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER

FINANCIAL REPORTING

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

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

Under the supervision and with the participation of our management, including our general partner’s Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2011, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment we concluded that, as of December 31, 2011, our internal control over financial reporting was effective.

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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Board of Directors of Williams Partners GP LLC

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

We have audited Williams Partners L.P.’s (the Partnership) internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Williams 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 Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’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.

In our opinion, Williams Partners L.P. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of Williams Partners L.P. as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011, and our report dated February 27, 2012 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP        

Tulsa, Oklahoma

February 27, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors of Williams Partners GP LLC

General Partner of Williams Partners L.P.

and the Limited Partners of Williams Partners L.P.

We have audited the accompanying consolidated balance sheets of Williams Partners L.P. (the Partnership) as of December 31, 2011 and 2010, and the related consolidated statements of income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. 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 did not audit the financial statements of Gulfstream Natural Gas System, L.L.C. (Gulfstream) (a limited liability corporation in which the Partnership has a 49 percent interest). The Partnership’s investment in Gulfstream constituted three percent of the Partnership’s assets as of December 31, 2011 and the Partnership’s equity in the net income of Gulfstream constituted four percent of the Partnership’s net income for the year ended December 31, 2011. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the 2011 consolidated financial statements, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit 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, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Williams Partners L.P. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Williams Partners L.P.’s internal control over financial reporting as of December 31, 2011, 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 27, 2012 expressed an unqualified opinion thereon.

/s/    Ernst & Young LLP        

Tulsa, Oklahoma

February 27, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2011, and the related statements of operations, cash flows, and members’ equity and comprehensive income for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2011, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 23, 2011

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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF INCOME

	Years Ended December 31,
	2011			2010			2009
	(Millions, except per-unit amounts)
Revenues:
Gas Pipeline	$	1,678		$	1,605		$	1,591
Midstream Gas & Liquids		5,051			4,110			3,011
Total revenues		6,729			5,715			4,602
Segment costs and expenses:
Costs and operating expenses		4,672			3,984			3,100
Selling, general, and administrative expenses		290			281			300
Other (income) expense — net		13			(15	)		(34	)
Segment costs and expenses		4,975			4,250			3,366
General corporate expenses		112			125			109
Operating income:
Gas Pipeline		615			599			600
Midstream Gas & Liquids		1,139			866			636
General corporate expenses		(112	)		(125	)		(109	)
Total operating income		1,642			1,340			1,127
Equity earnings		142			109			81
Interest accrued — third-party		(425	)		(392	)		(207	)
Interest accrued — affiliate		(1	)		(1	)		(52	)
Interest capitalized		11			29			58
Interest income — third-party		2			1			1
Interest income — affiliate		—			3			19
Other income (expense) — net		7			12			9
Net income		1,378			1,101			1,036
Less: Net income attributable to noncontrolling interests		—			16			27
Net income attributable to controlling interests	$	1,378		$	1,085		$	1,009
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests	$	1,378		$	1,085		$	1,009
Allocation of net income to general partner and Class C units (a)		308			517			857
Allocation of net income to common units	$	1,070		$	568		$	152
Basic and diluted net income per common unit	$	3.69		$	2.66		$	2.88
Weighted average number of common units outstanding (thousands) (a)		290,255			213,539			52,777
Cash distributions per common unit	$	2.96		$	2.72		$	2.54

(a) Calculated as discussed in Note 2.

See accompanying notes.

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WILLIAMS PARTNERS L.P.

CONSOLIDATED BALANCE SHEET

	December 31, 2011			December 31, 2010
	(Millions)
ASSETS
Current assets:
Cash and cash equivalents	$	163		$	187
Accounts and notes receivable:
Trade		484			404
Affiliate		9			8
Inventories		148			195
Regulatory assets		40			51
Other current assets		70			53
Total current assets		914			898
Investments		1,383			1,045
Property, plant, and equipment – net		11,627			11,001
Regulatory assets, deferred charges, and other		456			460
Total assets	$	14,380		$	13,404
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	554		$	322
Affiliate		57			154
Accrued interest		105			105
Asset retirement obligations		66			35
Other accrued liabilities		166			139
Long-term debt due within one year		324			458
Total current liabilities		1,272			1,213
Long-term debt		6,913			6,365
Asset retirement obligations		503			460
Regulatory liabilities, deferred income, and other		464			290
Contingent liabilities and commitments (Note 15)
Equity:
Common units (290,477,159 units outstanding at December 31, 2011 and 289,844,575 units outstanding at December 31, 2010)		6,810			6,564
General partner		(1,580	)		(1,485	)
Accumulated other comprehensive income (loss)		(2	)		(3	)
Total equity		5,228			5,076
Total liabilities and equity	$	14,380		$	13,404

See accompanying notes.

78

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

	Williams Partners L.P.
										Accumulated Other
	Limited Partners						General			Comprehensive			Noncontrolling			Total
	Common			Class C			Partner			Income (Loss)			Interests			Equity
	(Millions)
Balance – December 31, 2008	$	1,620		$	—		$	5,901		$	4		$	342		$	7,867
Comprehensive income:
Net income		145			—			864			—			27			1,036
Other comprehensive income (loss):
Net unrealized change in cash flow hedges, net of reclassification adjustments		—			—			—			(2	)		—			(2	)
Total other comprehensive income (loss)																	(2	)
Total comprehensive income																	1,034
Cash distributions		(134	)		—			(10	)		—			—			(144	)
Dividends paid to noncontrolling interests		—			—			—			—			(23	)		(23	)
Distributions to The Williams Companies, Inc. – net		—			—			(384	)		—			—			(384	)
Reclassification of notes receivable		—			—			(253	)		—			—			(253	)
Other		—			—			5			—			1			6
Balance – December 31, 2009	$	1,631		$	—		$	6,123		$	2		$	347		$	8,103
Comprehensive income:
Net income		558			156			371			—			16			1,101
Other comprehensive income (loss):
Net unrealized change in cash flow hedges, net of reclassification adjustments		—			—			—			(5	)		—			(5	)
Total other comprehensive income (loss)																	(5	)
Total comprehensive income																	1,096
Cash distributions		(432	)		(87	)		(141	)		—			—			(660	)
Dividends paid to noncontrolling interests		—			—			—			—			(18	)		(18	)
Issuance of units (203,000,000 Class C units)		—			6,946			(6,946	)		—			—			—
Distributions to The Williams Companies, Inc. – net		—			(3,357	)		(679	)		—			—			(4,036	)
Excess of purchase price over contributed basis of business purchase from affiliate		—			—			(244	)		—			—			(244	)
Conversion of Class C units to Common (203,000,000 units)		3,658			(3,658	)		—			—			—			—
Issuance of units due to Williams Pipeline Partners L.P. merger (13,580,485 common units)		343			—			—			—			(343	)		—
Issuance of units to public (18,637,500 common units)		806			—			—			—			—			806
Contributions from general partner		—			—			29			—			—			29
Other		—			—			2			—			(2	)		—
Balance – December 31, 2010	$	6,564		$	—		$	(1,485	)	$	(3	)	$	—		$	5,076
Comprehensive income:
Net income		1,088			—			290			—			—			1,378
Other comprehensive income (loss):
Net unrealized change in cash flow hedges, net of reclassification adjustments		—			—			—			1			—			1
Total other comprehensive income (loss)																	1
Total comprehensive income																	1,379
Cash distributions		(842	)		—			(282	)		—			—			(1,124	)
Excess of purchase price over contributed basis of investment purchase from affiliate		—			—			(123	)		—			—			(123	)
Contributions from general partner		—			—			31			—			—			31
Other		—			—			(11	)		—			—			(11	)
Balance – December 31, 2011	$	6,810		$	—		$	(1,580	)	$	(2	)	$	—		$	5,228

See accompanying notes.

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WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF CASH FLOWS

	Years Ended December 31,
	2011			2010			2009
	(Millions)
OPERATING ACTIVITIES:
Net income	$	1,378		$	1,101		$	1,036
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization		611			568			553
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		(80	)		(23	)		(93	)
Inventories		47			(66	)		17
Other assets and deferred charges		(8	)		37			8
Accounts payable		163			28			2
Accrued liabilities		56			72			(73	)
Affiliate accounts receivable and payable – net		(98	)		72			16
Other, including changes in noncurrent assets and liabilities		97			27			17
Net cash provided by operating activities		2,166			1,816			1,483
FINANCING ACTIVITIES:
Proceeds from long-term debt		1,596			5,029			—
Payments of long-term debt		(1,184	)		(1,203	)		(2	)
Payment of debt issuance costs		(16	)		(66	)		—
Proceeds from sales of common units		—			806			—
General partner contributions		31			29			—
Dividends paid to noncontrolling interests		—			(18	)		(23	)
Distributions to limited partners and general partner		(1,124	)		(660	)		(144	)
Excess of purchase price over contributed basis of business and investment		(123	)		(244	)		—
Distributions to The Williams Companies, Inc. – net		—			(152	)		(384	)
Other – net		2			(4	)		9
Net cash provided (used) by financing activities		(818	)		3,517			(544	)
INVESTING ACTIVITIES:
Purchase of business and investments from affiliates		(174	)		(3,884	)		—
Property, plant and equipment:
Capital expenditures		(991	)		(837	)		(907	)
Net proceeds from dispositions		5			64			46
Purchases of business and investments		(228	)		(626	)		(131	)
Purchase of ARO trust investments		(41	)		(47	)		(46	)
Proceeds from sale of ARO trust investments		56			31			41
Other – net		1			—			78
Net cash used by investing activities		(1,372	)		(5,299	)		(919	)
Increase (decrease) in cash and cash equivalents		(24	)		34			20
Cash and cash equivalents at beginning of period		187			153			133
Cash and cash equivalents at end of period	$	163		$	187		$	153

See accompanying notes.

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Organization, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

Organization

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us,” or similar language refer to Williams Partners L.P. and its subsidiaries.

We are a publicly traded Delaware limited partnership. Williams Partners GP LLC, a Delaware limited liability company wholly owned by The Williams Companies, Inc. (Williams), serves as our general partner. As of December 31, 2011, Williams owns an approximate 73 percent limited partner interest, a 2 percent general partner interest and incentive distribution rights (IDRs) in us. All of our activities are conducted through Williams Partners Operating LLC (OLLC), an operating limited liability company (wholly owned by us).

Description of Business

Our operations are located in the United States and are organized into the following reporting segments: Gas Pipeline and Midstream Gas & Liquids (Midstream).

Gas Pipeline is comprised primarily of the following interstate natural gas pipeline assets:

• Transcontinental Gas Pipe Line Company, LLC (Transco), an interstate natural gas pipeline extending from the Gulf of Mexico region to the northeastern United States;

• Northwest Pipeline GP (Northwest Pipeline), an interstate natural gas pipeline extending from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington;

• A 49 percent equity interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), an interstate natural gas pipeline extending from the Mobile Bay area in Alabama to markets in Florida.

Midstream is comprised primarily of:

• Large-scale natural gas gathering, processing, and treating facilities in the Rocky Mountain, Four Corners, Piceance basin, and Pennsylvania’s Marcellus Shale regions;

• Offshore deepwater oil and natural gas production platforms, gathering, and transportation facilities in the Gulf of Mexico, as well as significant natural gas gathering, processing, and treating facilities on the Gulf Coast;

• A natural gas liquid (NGL) fractionator and storage facilities near Conway, Kansas;

• Various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets.

Basis of Presentation

In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream from a subsidiary of Williams in exchange for aggregate consideration of $297 million of cash, 632,584 of our limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest. As the acquired equity interest was purchased from a subsidiary of Williams, the transaction was accounted for as a combination of entities under common control whereby the investment acquired is combined with ours at its

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

historical amount as of the date of transfer. The excess of the cash purchase price over the historical carrying amount is recognized as a reduction of general partner equity. This investment is reported in our Gas Pipeline segment.

In February 2010, we closed a transaction (the Dropdown) with our general partner, our operating company, Williams and certain of its subsidiaries, pursuant to which Williams contributed to us the ownership interests in the entities that made up its gas pipeline and midstream businesses to the extent not already owned by us, including Williams’ limited and general partner interests in Williams Pipeline Partners L.P. (WMZ), but excluding its Canadian, Venezuelan, and olefins operations, and 25.5 percent of Gulfstream, collectively defined as the Contributed Entities.

Accounting standards issued but not yet adopted

In June 2011, the FASB issued Accounting Standards Update No. 2011-5, “Comprehensive Income (Topic 220) Presentation of Comprehensive Income” (ASU 2011-5). ASU 2011-5 requires presentation of net income and other comprehensive income either in a single continuous statement or in two separate, but consecutive, statements. ASU 2011-5 requires separate presentation in both net income and other comprehensive income of reclassification adjustments for items that are reclassified from other comprehensive income to net income. The new guidance does not change the items reported in other comprehensive income, nor affect how earnings per share is calculated and presented. We currently report net income in the Consolidated Statement of Operations and report other comprehensive income in the Consolidated Statement of Changes in Equity. In December 2011, The FASB issued Accounting Standards Update No. 2011-12, “Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12). ASU 2011-12 defers the effective date for only the presentation requirements related to reclassifications in ASU 2011-5. During this deferral period, ASU 2011-12 states that we should continue to report reclassifications out of accumulated other comprehensive income consistent with the presentation requirements in effect before ASU 2011-05. All other requirements in ASU 2011-05 are not affected by ASU 2011-12, including the requirement to report comprehensive income either in a single continuous financial statement or in two separate but consecutive financial statements. Both standards are effective beginning the first quarter of 2012, with retrospective application to prior periods. We will apply the new guidance for both standards beginning in 2012.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of Williams Partners L.P., OLLC, and our other wholly owned subsidiaries. We apply the equity method of accounting for investments in unconsolidated companies in which we and our subsidiaries own 20 percent to 50 percent of the voting interest or otherwise exercise significant influence over operating and financial policies of the company. We also apply the equity method of accounting for investments where our majority ownership does not provide us with control due to the significant participatory rights of other owners.

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 consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Significant estimates and assumptions include:

• Impairment assessments of investments and long-lived assets;

• Litigation-related contingencies;

• Environmental remediation obligations;

• Asset retirement obligations.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC). Their rates established by the FERC are designed to recover the costs of providing the regulated services, and their competitive environment makes it probable that such rates can be charged and collected. Therefore, our management has determined that it is appropriate to account for and report regulatory assets and liabilities related to these operations consistent with the economic effect of the way in which their rates are established. Accounting for these businesses that are regulated can differ from the accounting requirements for non-regulated businesses. The components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, asset retirement obligations, fuel cost differentials, levelized incremental depreciation, negative salvage, and postretirement benefits.

Cash and cash equivalents

Cash and cash equivalents 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 maturities of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts based on existing economic conditions, the financial condition of our customers, and the amount and age of past due accounts. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. The allowance for doubtful accounts at December 31, 2011 and 2010 was insignificant.

Inventory valuation

All inventories are stated at the lower of cost or market. We determine the cost of certain natural gas inventories held by Transco using the last-in, first-out (LIFO) cost method. We determine the cost of the remaining inventories primarily using the average-cost method. There was no LIFO inventory at December 31, 2011. LIFO inventory at December 31, 2010 was $9 million.

Property, plant, and equipment

Property, plant, and equipment is recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply a declining balance method. (See Note 8.)

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Gains or losses from the ordinary sale or retirement of property, plant and equipment for regulated pipelines are credited or charged to accumulated depreciation; other gains or losses are recorded in other (income) expense — net included in operating income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant and equipment.

We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO) at the time the liability is initially incurred, typically when the asset is acquired or constructed. The ARO asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. As regulated entities, Northwest Pipeline and Transco record the ARO asset depreciation offset to a regulatory asset. We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in costs and operating expenses, except for regulated entities, for which the liability is offset by a regulatory asset as management expects to recover amounts in future rates. The regulatory asset is amortized commensurate with the collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Cash flows from revolving credit facilities

Proceeds and payments related to borrowings under our credit facility are reflected in the financing activities of the Consolidated Statement of Cash Flows on a gross basis.

Derivative instruments and hedging activities

We may utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swap agreements and forward contracts involving short- and long-term purchases and sales of physical energy commodities. We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in other current assets; regulatory assets, deferred charges, and other; other accrued liabilities; or regulatory liabilities, deferred income, and other. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades. We report these amounts on a gross basis. Additionally, we report cash collateral receivables and payables with our counterparties on a gross basis.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected on the balance sheet after the initial election of the exception.

We have also designated a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in revenues or costs and operating expenses.

For commodity derivatives designated as a cash flow hedge, the effective portion of the change in fair value of the derivative is reported in accumulated other comprehensive income (loss) (AOCI) and reclassified into earnings in the period in which the hedged item affects earnings. Any ineffective portion of the derivative’s change in fair value is recognized currently in revenues or costs and operating expenses. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in revenues or costs and operating expenses at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by management.

For commodity derivatives that are not designated in a hedging relationship, and for which we have not elected the normal purchases and normal sales exception, we report changes in fair value currently in revenues or costs and operating expenses.

Certain gains and losses on derivative instruments included in the Consolidated Statement of Income are netted together to a single net gain or loss, while other gains and losses are reported on a gross basis. Gains and losses recorded on a net basis include:

• Unrealized gains and losses on all derivatives that are not designated as hedges and for which we have not elected the normal purchases and normal sales exception;

• The ineffective portion of unrealized gains and losses on derivatives that are designated as cash flow hedges;

• Realized gains and losses on all derivatives that settle financially other than natural gas derivatives for NGL processing activities;

• Realized gains and losses on derivatives entered into as a pre-contemplated buy/sell arrangement.

Realized gains and losses on derivatives that require physical delivery, as well as natural gas derivatives for NGL processing activities and which are not held for trading purposes nor were entered into as a pre-contemplated buy/sell arrangement, are recorded on a gross basis. In reaching our conclusions on this presentation, we considered whether we act as principal in the transaction; whether we have the risks and rewards of ownership, including credit risk; and whether we have latitude in establishing prices.

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Gas Pipeline revenues

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

In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided for in our FERC tariffs. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances.

As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks.

Midstream revenues

Natural gas gathering and processing services are performed under volumetric-based fee contracts, keep-whole agreements and percent-of-liquids arrangements. Revenues under volumetric-based fee contracts are recorded when services have been performed. Under keep-whole and percent-of-liquid processing contracts, we retain the rights to all or a portion of the NGLs extracted from the producers’ natural gas stream and recognize revenues when the extracted NGLs are sold and delivered.

We also market NGLs that we purchase from our producer customers as part of the overall service provided to producers. Revenues from marketing NGLs are recognized when the products have been sold and delivered.

Oil gathering and transportation revenues and offshore production handling fees are recognized when the services have been performed. Certain offshore production handling contracts contain fixed payment terms that result in the deferral of revenues until such services have been performed.

Storage revenues under prepaid contracted storage capacity contracts are recognized evenly over the life of the contract as services are provided.

Impairment of long-lived assets and investments

We evaluate our long-lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value.

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when events or changes in circumstances indicate, in our 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 charge.

Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least three months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The later is included in other income (expense) – net below operating income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on the average interest rate on debt.

Income taxes

We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by individual partners. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregated difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available to us.

Earnings per unit

We use the two-class method to calculate basic and diluted earnings per unit whereby net income, adjusted for items specifically allocated to our general partner, is allocated on a pro-rata basis between unitholders and our general partner. Basic and diluted earnings per unit are based on the average number of common and subordinated units outstanding. Additionally, subsequent to April 1, 2010 we consider Class C units as common units for purposes of the calculation. Basic and diluted earnings per unit are equivalent as there are no dilutive securities outstanding.

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WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 2. Allocation of Net Income and Distributions

The allocation of net income among our general partner, limited partners, and noncontrolling interests, as reflected in the Consolidated Statement of Changes in Equity, for the years ended 2011, 2010, and 2009, is as follows:

	Years Ended December 31,
	2011			2010			2009
	(Millions)
Allocation of net income to general partner:
Net income	$	1,378		$	1,101		$	1,036
Net income applicable to pre-partnership operations allocated to general partner		—			(223	)		(857	)
Net income applicable to noncontrolling interests		—			(16	)		(27	)
Net reimbursable costs charged directly to general partner		(2	)		(4	)		3
Income subject to 2% allocation of general partner interest		1,376			858			155
General partner’s share of net income		2	%		2	%		2	%
General partner’s allocated share of net income before items directly allocable to general partner interest		28			17			3
Incentive distributions paid to general partner (a)		260			127			7
Net reimbursable costs charged directly to general partner		2			4			(3	)
Pre-partnership net income allocated to general partner interest		—			223			857
Net income allocated to general partner	$	290		$	371		$	864
Net income	$	1,378		$	1,101		$	1,036
Net income allocated to general partner		290			371			864
Net income allocated to Class C limited partners		—			156			—
Net income allocated to noncontrolling interests		—			16			27
Net income allocated to common limited partners	$	1,088		$	558		$	145

(a) In the calculation of basic and diluted net income per limited partner unit, the net income allocated to the general partner includes IDRs pertaining to the current reporting period, but paid in the subsequent period. The net income allocated to the general partner’s capital account reflects IDRs paid during the current reporting period.

The net reimbursable costs charged directly to general partner may include the net of both income and expense items. Under the terms of omnibus agreements, we are reimbursed by our general partner for certain expense items and are required to distribute certain income items to our general partner.

For purposes of calculating the year-to-date 2010 basic and diluted net income per common unit, the weighted average number of common units outstanding are calculated considering Class C units as common units effective April 1, 2010, and net income allocated to the Class C units prior to that date is based on the distributed earnings paid to the Class C units for first-quarter 2010. For the allocation of 2010 net income for the Consolidated Statement of Changes in Equity, net income was allocated based on the number of days the Class C units were outstanding as Class C units during 2010.

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The following table sets forth the partnership cash distributions paid on the dates indicated (in millions, except for per unit amounts):

		53333336		53333336		53333336		53333336		53333336		53333336
							General Partner
Payment Date	Per Unit Distribution		Common Units		Class C Units		2%		Incentive Distribution Rights		Total Cash Distribution
2/13/2009	$	0.6350	$	33	$	—	$	1	$	8	$	42
5/15/2009	$	0.6350	$	33	$	—	$	1	$	—	$	34
8/14/2009	$	0.6350	$	33	$	—	$	1	$	—	$	34
11/13/2009	$	0.6350	$	33	$	—	$	1	$	—	$	34
2/12/2010	$	0.6350	$	33	$	—	$	1	$	—	$	34
5/14/2010 (b)	$	0.6575	$	35	$	87	$	3	$	30	$	155
8/13/2010	$	0.6725	$	172	$	—	$	4	$	45	$	221
11/12/2010	$	0.6875	$	192	$	—	$	5	$	53	$	250
2/11/2011	$	0.7025	$	204	$	—	$	5	$	59	$	268
5/13/2011	$	0.7175	$	208	$	—	$	5	$	63	$	276
8/12/2011	$	0.7325	$	213	$	—	$	6	$	67	$	286
11/11/2011	$	0.7475	$	217	$	—	$	6	$	71	$	294
2/10/2012 (c)	$	0.7625	$	227	$	—	$	6	$	78	$	311

(b) Distributions on the Class C units and the additional general partner units issued in connection with the closing of the Dropdown, as well as the related incentive distribution rights payments, were prorated to reflect the fact that they were not outstanding during the first full quarter period of 2010.

(c) On February 10, 2012, we paid a cash distribution of $0.7625 per unit on our outstanding common units to unitholders of record at the close of business on February 3, 2012.

Note 3. Related Party Transactions

The employees of our operated assets are employees of Williams. Williams directly charges us for the payroll and benefit costs associated with operations employees and carries the obligations for many employee-related benefits in its financial statements, including the liabilities related to employee retirement, medical plans and paid time off. Our share of those costs is charged to us through affiliate billings and reflected in costs and operating expenses in the accompanying Consolidated Statement of Income.

In addition, employees of Williams provide general and administrative services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. Our share of direct administrative expenses is reflected in selling, general, and administrative expenses, and our share of allocated administrative expenses is reflected in general corporate expenses in the accompanying Consolidated Statement of Income. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams.

In connection with Williams’ contribution of ownership interests in certain entities to us in February 2010, we entered into an omnibus agreement with Williams. Under this agreement, Williams is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries for certain U.S. Department of Transportation projects, up to a maximum of $50 million, and

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(iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received by Williams prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform. In addition, we will be obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement. Net amounts received under this agreement for the years ended December 31, 2011 and December 31, 2010 were $31 million and $2 million, respectively.

We have a contribution receivable from our general partner of $7 million and $8 million at December 31, 2011 and December 31, 2010, respectively, for amounts reimbursable to us under omnibus agreements. We net this receivable against equity on the Consolidated Balance Sheet.

On December 31, 2011, Williams spun-off its former exploration and production business, WPX Energy, Inc. (WPX). We were affiliated with WPX prior to this separation so transactions between us and WPX are included below.

Gas Pipeline revenues include revenues from transportation and exchange services and rental of communication facilities with WPX. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly-situated nonaffiliated customers.

Midstream Gas & Liquids revenues include revenues from the following types of transactions with affiliates:

• Sales of feedstock commodities to Williams Olefins, LLC (Williams Olefins), a wholly owned subsidiary of Williams, for use in their facilities. These sales are generally made at market prices at the time of sale.

• Gathering, treating and processing services for WPX under several contracts. We believe that the rates charged to provide these services are reasonable as compared to those that are charged to similarly-situated nonaffiliated customers.

Costs and operating expenses also include charges for the following types of transactions with affiliates and equity method investees:

• Our Midstream segment purchases NGLs for resale from WPX, Discovery Producer Services LLC (Discovery), and Williams Olefins at market prices at the time of purchase.

• Our Midstream segment purchased natural gas for shrink replacement and fuel from WPX at market prices at the time of purchase or contract execution.

• Our Midstream segment pays Overland Pass Pipeline Company LLC (OPPL) for transportation of NGLs from certain natural gas processing plants.

• We transferred a transportation capacity agreement to WPX in a prior year. To the extent that WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs.

Historically, we periodically entered into derivative contracts with WPX to hedge forecasted NGL sales and natural gas purchases. These contracts were priced based on market rates at the time of execution.

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Below is a summary of the related party transactions discussed above.

	Years Ended December 31,
	2011		2010		2009
	(Millions)
Gas Pipeline revenues	$	42	$	25	$	29
Midstream revenues
Product sales		114		121		75
Gathering and processing		270		225		143
Costs and operating expenses
Product purchases		923		863		602
Employee costs		208		191		206
Other		55		53		39
Selling, general and administrative expense
Employee and other allocated costs		232		208		234
General corporate expense		112		125		109

The accounts and notes receivable — affiliate and accounts payable — affiliate on the Consolidated Balance Sheet represent the receivable and payable positions that result from the transactions with affiliates discussed above. Included in the Consolidated Balance Sheet are certain obligations of $12 million at December 31, 2011 related to the WPX spin-off. In addition, we have $1 million and $2 million accounts receivable and $23 million and $20 million accounts payable with our equity method investees at December 31, 2011 and December 31, 2010, respectively.

We also have operating agreements with certain equity method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to certain equity method investees. The total gross charges to equity method investees for these fees are $57 million, $38 million, and $23 million for the years ended 2011, 2010, and 2009, respectively.

Mr. H. Michael Krimbill, a member of our Board of Directors, has served as the Chief Executive Officer of NGL Energy Partners LP, formerly Silverthorne Energy Partners LP, and as a director of its general partner since 2010. We recorded $62 million in revenues from NGL Energy Partners LP primarily for the sale of propane at market prices and $9 million in costs and expenses for the purchase of propane at market prices for the year ended December 31, 2011. We have $2 million in accounts receivables and $1 million in accounts payable with NGL Energy Partners LP at December 31, 2011. We also recorded $20 million in revenue from Silverthorne Energy Partners LP primarily for the sale of propane at market prices and $5 million in costs and expenses from the purchase of propane at market prices for the year ended December 31, 2010 and have $1 million in accounts receivable at December 31, 2010.

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Note 4. Investments

Investments accounted for using the equity method include:

	December 31,
	2011		2010
	(Millions)
OPPL—50%	$	433	$	429
Gulfstream—49%		355		185
Laurel Mountain Midstream, LLC (Laurel Mountain)—51% (1)		291		170
Discovery—60% (1)		182		181
Other		122		80
	$	1,383	$	1,045

(1) We account for these investments under the equity method due to the significant participatory rights of our partners such that we do not control the investments.

The difference between the carrying value of our equity investments and the underlying equity in the net assets of the investees is $62 million at December 31, 2011, primarily related to impairments we previously recognized. These differences are amortized over the expected remaining life of the investees’ underlying assets.

In May 2011, we acquired a 24.5 percent interest in Gulfstream from a subsidiary of Williams. (See Note 1.) We also invested $30 million in Aux Sable Liquid Products LP (Aux Sable) in 2011. In September 2010, we purchased an additional 49 percent ownership interest in OPPL for $424 million. In June 2009, we purchased a 51 percent ownership interest in Laurel Mountain for $133 million and invested $137 million and $43 million in Laurel Mountain in 2011 and 2010, respectively.

Dividends and distributions, including those presented below, received from companies accounted for by the equity method were $169 million, $133 million, and $168 million in 2011, 2010, and 2009, respectively. These transactions reduced the carrying value of our investments. These dividends and distributions primarily included:

	Years Ended December 31,
	2011		2010		2009
	(Millions)
Gulfstream	$	60	$	39	$	109
Discovery		40		44		32
Aux Sable		35		28		15
OPPL		19		—		—

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Summarized Financial Position and Results of Operations of Equity Method Investments (Unaudited)

	December 31,
	2011		2010
	(Millions)
Current assets	$	293	$	235
Noncurrent assets		4,409		3,976
Current liabilities		235		156
Noncurrent liabilities		1,257		1,294

	Years Ended December 31,
	2011		2010		2009
	(Millions)
Gross revenue	$	1,242	$	1,050	$	785
Operating income		623		566		359
Net income		460		402		295

Note 5. Asset Sales, Impairments and Other Accruals

The following table presents significant gains or losses reflected in other (income) expense – net within segment costs and expenses.

	Years Ended December 31,
	2011			2010			2009
	(Millions)
Gas Pipeline
Capitalization of project feasibility costs previously expensed	$	(10	)	$	—		$	—
Accrual of regulatory liability related to overcollection of certain employee expenses		9			10			—
Midstream
Involuntary conversion gains		(3	)		(18	)		(4	)
Gains on sales of certain assets		—			(12	)		(40	)
Impairments of certain gathering assets		4			9			—

The reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline is associated with a natural gas pipeline expansion project. This reversal was made upon determining that the related project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.

In 2009, we sold our Cameron Meadows plant, which had a carrying value of $16 million and recognized a $40 million gain at Midstream.

Additional Item

We detected a leak in an underground cavern at our Eminence Storage Field in Mississippi on December 28, 2010. We recorded $15 million and $5 million of charges to costs and operating expenses at Gas Pipeline during 2011 and 2010, respectively, primarily related to assessment and monitoring costs incurred to ensure the safety of the surrounding area.

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Note 6. Benefit Plans

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

Pension plans

Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension expense charged to us by Williams for 2011, 2010 and 2009 totaled $30 million, $30 million and $37 million, respectively. At the total Williams plan level, the pension plans had a projected benefit obligation of $1.4 billion and $1.3 billion at December 31, 2011 and 2010, respectively. The plans were underfunded by $476 million and $296 million at December 31, 2011 and 2010, respectively.

Postretirement benefits other than pensions

Williams provides certain retiree health care and life insurance benefits for eligible participants that generally were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries. The allocation of cost 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. We recognized a net periodic postretirement benefit credited to us by Williams of $2 million and $4 million for 2011 and 2010, respectively, and a net periodic postretirement benefit charged to us by Williams of $4 million for 2009. At the total Williams plan level, the postretirement benefit plans had a projected benefit obligation of $339 million and $289 million at December 31, 2011 and 2010, respectively. The plans were underfunded by $180 million and $127 million at December 31, 2011 and 2010, respectively.

Any differences between the annual expense and amounts currently being recovered in rates by our FERC-regulated gas pipelines are recorded as an adjustment to revenues and collected or refunded through future rate adjustments. A regulatory asset can be recorded only to the extent it is currently funded.

Defined contribution plan

Williams charged us compensation expense of $15 million, $13 million and $14 million in 2011, 2010 and 2009, respectively, for Williams’ matching contributions to this plan.

Employee Stock-Based Compensation Plan information

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

Williams bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards.

Total stock-based compensation expense, included in administrative and general expenses, for the years ended December 31, 2011, 2010 and 2009 was $9 million, $11 million and $11 million, respectively.

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Note 7. Inventories

	December 31,
	2011		2010
	(Millions)
Natural gas liquids	$	79	$	61
Natural gas in underground storage		1		62
Materials, supplies, and other		68		72
	$	148	$	195

Note 8. Property, Plant and Equipment

	Estimated			Depreciation
	Useful Life (a)			Rates (a)			December 31,
	(Years)			(%)			2011			2010
							(Millions)
Nonregulated:
Natural gas gathering and processing facilities		5 -40					$	5,769		$	5,486
Construction in progress		(b	)					318			100
Other		3 -45						485			456
Regulated:
Natural gas transmission facilities					.01 - 6.67			9,593			9,066
Construction in progress					(b	)		199			240
Other					.01 - 33.33			1,391			1,359
Total property, plant, and equipment, at cost							$	17,755		$	16,707
Accumulated depreciation and amortization								(6,128	)		(5,706	)
Property, plant, and equipment—net							$	11,627		$	11,001

(a) Estimated useful life and depreciation rates are presented as of December 31, 2011. Depreciation rates for regulated assets are prescribed by the FERC.

(b) Construction in progress balances not yet subject to depreciation.

Depreciation and amortization expense for property, plant and equipment – net was $608 million, $567 million and $548 million in 2011, 2010 and 2009, respectively.

Regulated property, plant and equipment – net includes approximately $865 million and $906 million at December 31, 2011 and 2010, respectively, related to amounts in excess of the original cost of the regulated facilities within Gas Pipeline as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset retirement obligations

Our accrued obligations relate to underground storage caverns, offshore platforms, fractionation and compression facilities, gas gathering well connections and pipelines, and gas transmission facilities. At the end of

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the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to restore land and remove surface equipment at gas processing, fractionation and compression facilities, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground.

The following table presents the significant changes to our asset retirement obligations. The current portion included in asset retirement obligations at December 31, 2011 and 2010, respectively, is $66 million and $35 million:

	December 31,
	2011			2010
	(Millions)
Beginning balance	$	495		$	497
Accretion		39			36
New obligations		3			1
Revisions(1)		78			(22	)
Property dispositions/obligations settled		(46	)		(17	)
Ending balance	$	569		$	495

(1) The revision in 2011 is primarily due to increases in the inflation rate and estimated removal costs, which are among several factors considered for revision in the annual review process. The revision in 2010 is primarily due to a decrease in the inflation rate. The 2011 and 2010 revisions include increases of $39 million and $31 million, respectively, related to changes in the timing and method of abandonment on certain of Transco’s natural gas storage caverns that were associated with a leak in 2010.

Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected rates into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations. Transco is also required to make annual deposits into the trust through 2012. (See Note 14.)

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Note 9. Regulatory Assets and Liabilities

The regulatory assets and regulatory liabilities included in the Consolidated Balance Sheet at December 31, 2011 and 2010 are as follows:

	December 31,
	2011		2010
	(Millions)
Regulatory assets:
Grossed-up deferred taxes on equity funds used during construction	$	103	$	105
Asset retirement obligations		122		108
Fuel cost		26		33
Levelized incremental depreciation		33		32
Other		24		32
	$	308	$	310
Regulatory liabilities:
Negative salvage	$	158	$	100
Postretirement benefits other than pension		39		30
Other		9		5
	$	206	$	135

Regulatory assets are included in regulatory assets and regulatory assets, deferred charges and other. Regulatory liabilities are included in other accrued liabilities and regulatory liabilities, deferred income and other. Our regulatory asset and liability balances are recoverable or reimbursable over various periods.

Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the periods the gas pipelines were taxable entities. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long lived asset to which they relate.

Asset retirement obligations: We record an asset and a liability equal to the present value of each expected future ARO. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and is offset by a regulatory asset. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates.

Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel filing periods.

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

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Negative salvage: Transco’s rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs. Current year amount includes an adjustment for salvage proceeds from previously retired assets.

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

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Note 10. Debt, Banking Arrangements, and Leases

Long- Term Debt

	December 31,
	2011			2010
	(Millions)
Unsecured:
Transco:
7% Notes due 2011	$	—		$	300
8.875% Notes due 2012		325			325
6.4% Notes due 2016		200			200
6.05% Notes due 2018		250			250
7.08% Debentures due 2026		8			8
7.25% Debentures due 2026		200			200
5.4% Notes due 2041		375			—
Northwest Pipeline:
7% Notes due 2016		175			175
5.95% Notes due 2017		185			185
6.05% Notes due 2018		250			250
7.125% Debentures due 2025		85			85
Williams Partners L.P.:
7.5% Notes due 2011		—			150
3.8% Notes due 2015		750			750
7.25% Notes due 2017		600			600
5.25% Notes due 2020		1,500			1,500
4.125% Notes due 2020		600			600
4% Notes due 2021		500			—
6.3% Notes due 2040		1,250			1,250
Other		—			9
Unamortized debt discount		(16	)		(14	)
Total long-term debt, including current portion		7,237			6,823
Long-term debt due within one year		(324	)		(458	)
Long-term debt	$	6,913		$	6,365

The terms of our senior unsecured notes are governed by indentures that contain covenants that, among other things, limit: (1) our ability and the ability of our subsidiaries to create liens securing indebtedness and (2) mergers, consolidations, and sales of assets. The indentures also contain customary events of default, upon which the trustee or the holders of the senior unsecured notes may declare all outstanding senior unsecured notes to be due and payable immediately.

Credit Facility

In June 2011, we entered into a new $2 billion five-year senior unsecured revolving credit facility agreement with Transco and Northwest Pipeline as co-borrowers. The new agreement is considered a modification for accounting purposes. It replaced our existing $1.75 billion credit facility agreement that was scheduled to expire on February 17, 2013. At the closing, we refinanced $300 million outstanding under the existing facility via a non-cash

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transfer of the obligation to the new credit facility. The new credit facility may, under certain conditions, be increased up to an additional $400 million. The full amount of the credit facility is available to us to the extent not otherwise utilized by Transco and Northwest Pipeline. Transco and Northwest Pipeline each have access to borrow up to $400 million under the credit facility to the extent not otherwise utilized by the other co-borrowers. Significant financial covenants include:

• Our ratio of debt to EBITDA (each as defined in the credit facility) must be no greater than 5 to 1. For the fiscal quarter and the two following fiscal quarters in which one or more acquisitions for a total aggregate purchase price equal to or greater than $50 million has been executed, we are required to maintain a ratio of debt to EBITDA of no greater than 5.5 to 1;

• The ratio of debt to capitalization (defined as net worth plus debt) must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2011, we are in compliance with these financial covenants.

Each time funds are borrowed, a borrower may choose from two methods of calculating interest: a fluctuating base rate equal to Citibank N.A.’s alternate base rate plus an applicable margin, or a periodic fixed rate equal to LIBOR plus an applicable margin. We are required to pay a commitment fee (currently 0.25 percent) based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower’s senior unsecured long-term debt ratings. The credit facility contains various covenants that may limit, among other things, a borrower’s and its respective material subsidiaries’ ability to grant certain liens supporting indebtedness, a borrower’s ability to merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, make investments, and allow any material change in the nature of its business.

The new credit facility includes customary events of default. If an event of default with respect to a borrower occurs under the 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 and exercise other rights and remedies.

Letter of credit capacity under our new credit facility is $1.3 billion. At December 31, 2011, no letters of credit have been issued and no loans are outstanding under the credit facility.

Issuances and Retirements

Utilizing cash on hand, we retired $150 million of 7.5 percent senior unsecured notes that matured on June 15, 2011.

In August 2011, Transco issued $375 million of 5.4 percent senior unsecured notes due 2041 to investors in a private debt placement. A portion of these proceeds was used to repay Transco’s $300 million 7 percent senior unsecured notes that matured on August 15, 2011. As part of the new issuance, Transco entered into a registration rights agreement with the initial purchasers of the unsecured notes. An offer to exchange these unregistered notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended, was commenced in February 2012 and is expected to be completed in March 2012. If Transco fails to complete the exchange within certain time periods required by the registration rights agreement, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-day period thereafter. Following the cure of any registration defaults, the accrual of additional interest will cease.

In November 2011, we completed a public offering of $500 million of our 4 percent senior unsecured notes due 2021. We used the net proceeds primarily to repay outstanding borrowings on our senior unsecured revolving credit facility.

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Other Debt Disclosures

As of December 31, 2011, aggregate minimum maturities of long-term debt (excluding unamortized discount) for each of the next five years are as follows:

	(Millions)
2012	$	325
2013	$	—
2014	$	—
2015	$	750
2016	$	375

Cash payments for interest (net of amounts capitalized) were $398 million in 2011, $310 million in 2010, and $193 million in 2009.

Leases-Lessee

The future minimum annual rentals under non-cancelable operating leases as of December 31, 2011, are payable as follows:

	(Millions)
2012	$	33
2013		25
2014		24
2015		22
2016		21
Thereafter		145
Total	$	270

Under our right-of-way agreement with the Jicarilla Apache Nation (JAN), we make annual payments of approximately $8 million and an additional annual payment which varies depending on the prior year’s per-unit NGL margins and the volume of gas gathered by our midstream gathering facilities subject to the agreement. Depending primarily on the per-unit NGL margins for any given year, the additional annual payments could exceed the fixed amount. This agreement expires March 31, 2029.

Total rent expense was $37 million in 2011, $34 million in 2010, and $34 million in 2009.

Note 11. Partners’ Capital

At December 31, 2011 and 2010, the public held 25 percent of our total units outstanding, and affiliates of Williams held the remaining units. Transactions which occurred during 2010 and 2011 are summarized below.

In February 2010, we closed the Dropdown with our general partner, our operating company, Williams and certain subsidiaries. (See Note 1.) In connection with this transaction, we issued 203 million Class C limited partnership units to Williams. The Class C units were identical to our common limited partnership units except that for the first quarter of 2010 they received a prorated quarterly distribution since they were not outstanding during the full quarterly period. The Class C units automatically converted into our common limited partnership units on May 10, 2010.

101

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On August 31, 2010, WMZ unitholders approved the merger between WMZ and us. As a result of the merger, effective September 1, 2010, WMZ unitholders, other than its general partner, received 0.7584 WPZ common units for each WMZ common unit they owned at the effective time of the merger, for a total issuance of 13,580,485 common units.

On September 28, 2010, we completed an equity issuance of 9,250,000 common units representing limited partner interests in us at a price of $42.40 per unit. The proceeds of approximately $380 million, net of the underwriters’ discount and fees of approximately $12 million, were used to repay borrowings incurred to fund a portion of our additional $424 million investment in OPPL. This additional investment increased our ownership interest in OPPL to 50 percent.

On October 8, 2010, we sold an additional 1,387,500 common units to the underwriters upon the underwriters’ exercise of their option to purchase additional common units pursuant to our common unit offering in September 2010. The proceeds of $57 million, net of the underwriters’ discount and fees of approximately $2 million, were used for general partnership purposes.

On December 17, 2010, we completed an equity issuance of 8,000,000 common units representing limited partner interests in us at $47.55 per unit. The proceeds of approximately $369 million, net of the underwriters’ discount and fees of approximately $11 million, were used primarily to repay borrowings incurred to fund acquisitions.

In May 2011, we closed the acquisition of a 24.5 percent interest in Gulfstream from a subsidiary of Williams. (See Note 1.) In connection with this transaction, we issued 632,584 of our limited partner units.

Limited Partners’ Rights

Significant rights of the limited partners include the following:

• Right to receive distributions of available cash within 45 days after the end of each quarter.

• No limited partner shall have any management control over our business and affairs; the general partner shall conduct, direct and manage our activities.

• The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units voting as a single class, including units held by our general partner and its affiliates.

Incentive Distribution Rights

Our general partner is entitled to incentive distributions if the amount we distribute to unitholders with respect to any quarter exceeds specified target levels shown below:

Quarterly Distribution Target Amount (per unit)	Unitholders			General Partner
Minimum quarterly distribution of $0.35		98	%		2	%
Up to $0.4025		98			2
Above $0.4025 up to $0.4375		85			15
Above $0.4375 up to $0.5250		75			25
Above $0.5250		50			50

102

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

In April 2009, Williams waived the IDRs related to 2009 distribution periods.

In the event of liquidation, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and our general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Issuances of Additional Partnership Securities

Our partnership agreement allows us to issue additional partnership securities for any partnership purpose at any time and from time to time for consideration and on terms and conditions as our general partner determines, all without the approval of any limited partners. See Note 17 for information about our recent equity issuances.

Note 12. Long-Term Incentive Plan

Our general partner maintains the Williams Partners GP LLC Long-Term Incentive Plan (the Plan) for employees, consultants, and directors of our general partner and its affiliates who perform services for us. Initially, the Plan permitted granting of awards covering an aggregate of 700,000 common units, in the form of options, restricted units, phantom units, or unit appreciation rights. At December 31, 2011, 686,597 securities were available for future issuance under the Plan.

To date, the only grants under the Plan have been grants of restricted units to members of our general partner’s Board of Directors who are not officers or employees of us or our affiliates. No awards were granted under the plan in 2011, 2010, or 2009, and no awards are outstanding at December 31, 2011 or 2010. We recognized compensation expense of $20,000 associated with the Plan in 2009 based on the market price of our common units at the date of grant for awards granted prior to 2009.

Note 13. Fair Value Measurements

The following table presents, by level within the fair value hierarchy, our assets that are measured at fair value on a recurring basis.

	December 31, 2011								December 31, 2010
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(Millions)
ARO Trust investments (see Note 14)	$	25	$	—	$	—	$	25	$	40	$	—	$	—	$	40
Energy derivatives		1		—		—		1		—		—		—		—
Total assets	$	26	$	—	$	—	$	26	$	40	$	—	$	—	$	40

ARO Trust investments: Transco deposits a portion of its collected rates into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations pursuant to its 2008 rate case settlement. The ARO Trust invests in a portfolio of actively traded mutual funds.

Energy derivatives: Energy derivatives include commodity based exchange-traded contracts, which consist of swaps that are valued based on quoted prices in active markets. The tenure of our energy derivatives portfolio is relatively short with all of our derivatives expiring by March 31, 2013.

103

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents assets measured on a nonrecurring basis within Level 3 of the fair value hierarchy as of December 31, 2010.

	Fair Value Measurement		Total Impairments
	(Millions)
Certain gathering assets—Midstream	$	3	$	9

Note 14. Financial Instruments, Derivatives, Guarantees and Concentration of Credit Risk

Financial Instruments

Fair-value methods

We use the following methods and assumptions in estimating our fair-value disclosures for financial instruments:

Cash and cash equivalents: The carrying amounts reported in the Consolidated Balance Sheet approximate fair value due to the short-term maturity of these instruments.

ARO Trust investments: Pursuant to its 2008 rate case settlement, Transco deposits a portion of its collected rates into the ARO Trust. The ARO Trust invests in a portfolio of mutual funds that are reported at fair value, based on quoted net asset values, in regulatory assets, deferred charges, and other in the Consolidated Balance Sheet and are classified as available-for-sale. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Long-term debt: The fair value of our publicly traded long-term debt is determined using indicative period-end traded bond market prices. The fair value of our private debt is based on market rates and the prices of similar securities with similar terms and credit ratings. At December 31, 2011 and December 31, 2010, approximately 95 percent and 100 percent, respectively, of our long-term debt was publicly traded.

Other: Includes current and noncurrent notes receivable, customer margin deposits payable, and margin deposits.

Energy derivatives: Energy derivatives include forwards and swaps. These are carried at fair value in the Consolidated Balance Sheet. See Note 13 for a discussion of the valuation of our energy derivatives.

Carrying amounts and fair values of our financial instruments

	December 31, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Asset (Liability)	(Millions)
Cash and cash equivalents	$	163		$	163		$	187		$	187
ARO Trust investments	$	25		$	25		$	40		$	40
Long-term debt, including current portion	$	(7,237	)	$	(8,170	)	$	(6,823	)	$	(7,283	)
Other	$	10		$	10		$	—		$	—
Energy derivatives	$	1		$	1		$	—		$	—

104

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Energy Commodity Derivatives

Risk management activities

We are exposed to market risk from changes in energy commodity prices within our operations. We may utilize derivatives to manage our exposure to the variability in expected future cash flows from forecasted purchases of natural gas and forecasted sales of NGLs attributable to commodity price risk. Certain of these derivatives utilized for risk management purposes have been designated as cash flow hedges, while other derivatives have not been designated as cash flow hedges or do not qualify for hedge accounting despite hedging our future cash flows on an economic basis.

We sell NGL volumes received as compensation for certain processing services at different locations throughout the United States. We also buy natural gas to satisfy the required fuel and shrink needed to generate NGLs. To reduce exposure to a decrease in revenues from fluctuations in NGL market prices or increases in costs and operating expenses from fluctuations in natural gas market prices, we may enter into NGL or natural gas swap agreements, financial or physical forward contracts, and financial option contracts to mitigate the price risk on forecasted sales of NGLs and purchases of natural gas. Those designated as cash flow hedges are expected to be highly effective in offsetting cash flows attributable to the hedged risk during the term of the hedge. However, ineffectiveness may be recognized primarily as a result of locational differences between the hedging derivative and the hedged item.

Volumes

Our energy commodity derivatives are comprised of both contracts to purchase commodities (long positions) and contracts to sell commodities (short positions). Derivative transactions are categorized into two types:

• Central hub risk: Financial derivative exposures to Henry Hub for natural gas and Mont Belvieu for NGLs;

• Basis risk: Financial derivative exposures to the difference in value between the central hub and another specific delivery point.

The following table depicts the notional quantities of the net long (short) positions in our commodity derivatives portfolio as of December 31, 2011. NGLs are presented in barrels.

Derivative Notional Volumes	Unit of Measurement		Central Hub Risk		Basis Risk
Not Designated as Hedging Instruments
Midstream    Risk Management		Barrels		45,000		240,000

Fair values and gains (losses)

At December 31, 2011, the fair value of our energy commodity derivatives was an asset of $1 million. These derivative contracts were not designated as hedging instruments. Our derivatives are included in other current assets in our Consolidated Balance Sheet. Derivatives are classified as current or noncurrent based on the contractual timing of expected future net cash flows of individual contracts. The expected future net cash flows for derivatives classified as current are expected to occur within the next 12 months. The fair value amount is on a gross basis and does not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amount does not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions.

105

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents gains and losses for our energy commodity derivatives designated as cash flow hedges, as recognized in AOCI, revenues, or costs and operating expenses.

	Years ended December 31,
	2011			2010			Classification
	(Millions)
Net gain (loss) recognized in other comprehensive income (loss) (effective portion)	$	(18	)	$	(12	)	AOCI
Net gain (loss) reclassified from accumulated other comprehensive income (loss) into income (effective portion)	$	(18	)	$	(13	)	Revenues or Costs and Operating Expenses
Gain (loss) recognized in income (ineffective portion)	$	—		$	—		Revenues or Costs and Operating Expenses

There were no gains or losses recognized in income as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges.

We recognized losses of less than $1 million and $1 million in revenues for the years ended December 31, 2011 and 2010, respectively, on our energy commodity derivatives not designated as hedging instruments.

The cash flow impact of our derivative activities is presented in the Consolidated Statement of Cash Flows as changes in other assets and deferred charges and changes in accrued liabilities.

Credit-risk-related features

Certain of our derivative contracts contain credit-risk-related provisions that would require us, in certain circumstances, to post additional collateral in support of our net derivative liability positions. These credit-risk-related provisions require us to post collateral in the form of cash or letters of credit when our net liability positions exceed an established credit threshold. The credit thresholds are typically based on our senior unsecured debt ratings from Standard and Poor’s and/or Moody’s Investors Service. Under these contracts, a credit ratings decline would lower our credit thresholds, thus requiring us to post additional collateral. We also have contracts that contain adequate assurance provisions giving the counterparty the right to request collateral in an amount that corresponds to the outstanding net liability.

As of December 31, 2011 and December 31, 2010, we did not have any collateral posted, either in the form of cash or letters of credit, to derivative counterparties since we had respective net derivative asset positions with all of our counterparties.

Cash flow hedges

Changes in the fair value of our cash flow hedges, to the extent effective, are deferred in AOCI and reclassified into earnings in the same period or periods in which the hedged forecasted purchases or sales affect earnings, or when it is probable that the hedged forecasted transaction will not occur by the end of the originally specified time period. As of December 31, 2011, we have realized all of our hedged portions of future cash flows associated with anticipated energy commodity purchases. Based on recorded values at December 31, 2011, no net gains or losses will be reclassified into earnings within the next year.

106

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Guarantees

We are required by our revolving credit agreement to indemnify lenders for any taxes required to be withheld from payments due to the lenders and for any tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

At December 31, 2011, we do not expect these guarantees to have a material impact on our future liquidity or financial position. However, if we are required to perform on these guarantees in the future, it may have an adverse effect on our results of operations.

Concentration of Credit Risk

Cash equivalents

Our cash equivalents are primarily invested in funds with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government.

Accounts and notes receivable

The following table summarizes concentration of receivables, net of allowances, by product or service at December 31, 2011 and 2010:

	December 31,
	2011		2010
	(Millions)
Receivables by product or service:
Sale of NGLs and related products and services	$	324	$	255
Transportation of natural gas and related products		160		149
Total	$	484	$	404

Natural gas and NGL customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the central, eastern and northwestern United States, Rocky Mountains and the Gulf Coast. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly.

Revenues

In 2011, 2010 and 2009, we had one customer in our Midstream segment that accounted for 20 percent, 17 percent, and 10 percent of our consolidated revenues, respectively.

107

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Note 15. Contingent Liabilities and Commitments

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations and remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), and other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2011, we have accrued liabilities totaling $18 million for these matters, as discussed below. Our accrual reflects the most likely costs of cleanup, which are generally based on completed assessment studies, preliminary results of studies or our experience with other similar cleanup operations. Certain assessment studies are still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Any incremental amount in excess of amounts currently accrued cannot be reasonably estimated at this time due to uncertainty about the actual number of contaminated sites ultimately identified, the actual amount and extent of contamination discovered and the final cleanup standards mandated by the EPA and other governmental authorities.

The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. These new rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, new air quality standards for ground level ozone, and one hour nitrogen dioxide emission limits. We are unable to estimate the costs of asset additions or modifications necessary to comply with these new regulations due to uncertainty created by the various legal challenges to these regulations and the need for further specific regulatory guidance.

Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyl, mercury contamination, and other hazardous substances. These activities have involved the EPA, various state environmental authorities and identification as a potentially responsible party at various Superfund waste sites. At December 31, 2011, we have accrued liabilities of $10 million for these costs. We expect that these costs will be recoverable through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2011, we have accrued liabilities totaling $8 million for these costs.

Rate Matters

On August 31, 2006, Transco submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing (Docket No. RP06-569) principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.

The one issue reserved for litigation or further settlement relates to Transco’s proposal to change the design of the rates for service under one of its storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that Transco’s proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Certain parties have sought rehearing of the FERC’s order. If the FERC were to reverse their opinion on rehearing, we believe any refunds would not be material to our results of operations.

Other

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

108

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Summary

We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties. We disclose all significant matters for which we are unable to reasonably estimate a range of possible loss.

Commitments

Commitments for construction and acquisition of property, plant and equipment are approximately $762 million at December 31, 2011.

Note 16. Segment Disclosures

Our reportable segments are strategic business units that offer different products and services. The segments are managed separately because each segment requires different technology, marketing strategies, and industry knowledge. (See Note 1.)

Performance Measurement

We currently evaluate segment operating performance based on segment profit from operations, which includes segment revenues from external customers, segment costs and expenses, and equity earnings. The accounting policies of the segments are the same as those described in Note 1. Intersegment sales, which are insignificant for all periods presented, are generally accounted for at the current market prices as if the sales were to unaffiliated third parties.

The primary types of costs and operating expenses by segment can be generally summarized as follows:

• Gas Pipeline — depreciation and operation and maintenance expenses;

• Midstream — commodity purchases (primarily for NGL and crude marketing, shrink, and fuel), depreciation, and operation and maintenance expenses.

109

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table reflects the reconciliation of segment profit to operating income as reported in the Consolidated Statement of Income. It also presents other financial information related to long-lived assets.

		$00000000		$00000000		$00000000
	Gas Pipeline		Midstream		Total
	(Millions)
2011
Segment revenues	$	1,678	$	5,051	$	6,729
Segment profit	$	673	$	1,223	$	1,896
Less equity earnings		58		84		142
Segment operating income	$	615	$	1,139		1,754
General corporate expenses						(112	)
Total operating income					$	1,642
Other financial information:
Additions to long-lived assets (a)	$	661	$	591	$	1,252
Depreciation and amortization	$	351	$	260	$	611
2010
Segment revenues	$	1,605	$	4,110	$	5,715
Segment profit	$	637	$	937	$	1,574
Less equity earnings		38		71		109
Segment operating income	$	599	$	866		1,465
General corporate expenses						(125	)
Total operating income					$	1,340
Other financial information:
Additions to long-lived assets (a)	$	476	$	432	$	908
Depreciation and amortization	$	340	$	228	$	568
2009
Segment revenues	$	1,591	$	3,011	$	4,602
Segment profit	$	635	$	682	$	1,317
Less equity earnings		35		46		81
Segment operating income	$	600	$	636		1,236
General corporate expenses						(109	)
Total operating income					$	1,127
Other financial information:
Additions to long-lived assets (a)	$	518	$	505	$	1,023
Depreciation and amortization	$	334	$	219	$	553

(a) Excludes additions acquired in the transactions accounted for as a combination of entities under common control, and also excludes purchases of investments.

110

WILLIAMS PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table reflects total assets and investments by reporting segment.

	Total Assets at December 31,						Investments at December 31,
	2011			2010			2011		2010
	(Millions)
Gas Pipeline	$	8,348		$	8,033		$	413	$	229
Midstream Gas & Liquids		6,591			5,291			970		816
Other corporate assets		226			404			—		—
Eliminations (1)		(785	)		(324	)		—		—
Total	$	14,380		$	13,404		$	1,383	$	1,045

(1) Primarily relates to the elimination of intercompany accounts receivable generated by our cash management program.

Note 17. Subsequent Events

In January 2012, we completed an equity issuance of 7 million common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, the underwriters exercised their option to purchase an additional 1.05 million common units for $62.81 per unit.

On February 17, 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC in exchange for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and approximately 7.5 million of our common units valued at $465 million. Our valuation of the assets acquired and liabilities assumed has not been completed because the acquisition is very recent. We expect the significant components of the valuation to include property, plant and equipment, intangible contract assets and goodwill. The goodwill relates primarily to enhancing our strategic platform for expansion in the area. Revenues and earnings for the acquired companies are insignificant for the periods presented primarily because the Laser Gathering System began operations in October 2011.

111

WILLIAMS PARTNERS, L.P.

QUARTERLY FINANCIAL DATA

(Unaudited)

Summarized quarterly financial data are as follows:

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Millions, except per-unit amounts)
2011
Revenues	$	1,579	$	1,671	$	1,673	$	1,806
Costs and operating expenses		1,105		1,163		1,169		1,235
Net income		307		338		342		391
Net income attributable to controlling interests		307		338		342		391
Basic and diluted net income per common unit		0.81		0.91		0.91		1.05
2010
Revenues	$	1,490	$	1,400	$	1,327	$	1,498
Costs and operating expenses		1,033		1,002		923		1,026
Net income		322		240		253		286
Net income attributable to controlling interests		316		235		248		286
Basic and diluted net income per common unit		0.61		0.66		0.63		0.76

The sum of earnings per unit for the four quarters may not equal the total earnings per unit for the year due to changes in the average number of common units outstanding and rounding.

Net income for first-quarter 2011 includes $10 million related to the reversal of project feasibility costs from expense to capital at Gas Pipeline. (See Note 5 of Notes to Consolidated Financial Statements.)

Net income for third-quarter 2010 includes a $12 million gain on the sale of certain assets at Midstream. (See Note 5.)

Net income for second-quarter 2010 includes $11 million of involuntary conversion gains due to insurance recoveries that are in excess of the carrying value of assets at Midstream. (See Note 5.)

112

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

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

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

Management’s Annual Report on Internal Control over Financial Reporting

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

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

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

Changes in Internal Controls Over Financial Reporting

There have been no changes during the fourth quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our Internal Controls over financial reporting.

Item 9B. Other Information

None.

113

PART III

Item 10. Directors, Executive Officers and Corporate Governance

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

All of the senior officers of our general partner are also senior officers of Williams and spend a sufficient amount of time overseeing the management, operations, corporate development and future acquisition initiatives of our business. Our non-executive directors devote as much time as is necessary to prepare for and attend Board of Directors and committee meetings.

The following table shows information for the directors and executive officers of our general partner as of February 24, 2012.

Name	Age	Position with Williams Partners GP LLC
Alan S. Armstrong	49	Chairman of the Board and Chief Executive Officer
Donald R. Chappel	60	Chief Financial Officer and Director
Rory L. Miller	51	Senior Vice President - Midstream and Director
Randall Barnard	53	Senior Vice President - Gas Pipeline and Director
Craig L. Rainey	59	General Counsel
Ted T. Timmermans	55	Vice President, Controller, and Chief Accounting Officer
H. Michael Krimbill	58	Director
H. Brent Austin	57	Director and Member of Audit and Conflicts Committees
Alice M. Peterson	59	Director and Member of Audit and Conflicts Committees
Laura A. Sugg	50	Director and Member of Audit Committee

Officers serve at the discretion of the Board of Directors of our general partner. There are no family relationships among any of the directors or executive officers of our general partner. The directors of our general partner are elected for one-year terms and hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. In addition to independence and financial literacy for members of our general partner’s Board of Directors who serve on the Audit Committee and Conflicts Committee, our general partner considers the following qualifications relevant to service on its Board of Directors in the context of our business and structure:

• Industry Experience in the natural gas business.

• Financial Experience with which to evaluate our financial statements and capital investments.

• Corporate Governance Experience to support our goals of transparency, accountability for management and the Board of our general partner, and protection of unitholder interests.

• Regulatory Experience to oversee our regulatory compliance.

• Public Policy and Government Experience because we operate in a highly regulated industry.

• Operating Experience to understand our operating plan.

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Certain information about each of our general partner’s directors and executive officers is set forth below, including qualifications relevant to service on our general partner’s Board of Directors.

Alan S. Armstrong has served as a director of our general partner since 2005 and has served as the Chairman of the Board of Directors and the Chief Executive Officer of our general partner since January 3, 2011. Mr. Armstrong has served as the Chief Executive Officer, President, and a director of Williams since January 3, 2011. From February 2010 to January 2011, Mr. Armstrong served as Senior Vice President – Midstream of our general partner. From 2005 to February 2010, Mr. Armstrong served as the Chief Operating Officer of our general partner. From 2002 to January 2011, Mr. Armstrong served as a Senior Vice President of Williams and acted as President of Williams’ midstream business. From 1999 to 2002, Mr. Armstrong was Vice President, Gathering and Processing in Williams’ midstream business and from 1998 to 1999 was Vice President, Commercial Development, in Williams’ midstream business. Mr. Armstrong also serves as Chairman of the Board of Directors of Junior Achievement of Oklahoma, Inc., President of the Gas Processors Association, a member of the Board for the Natural Gas Supply Association, and Chairman of the University of Oklahoma College of Engineering Board of Visitors.

Mr. Armstrong’s qualifications include industry, financial, public policy and government, and operating experience.

Donald R. Chappel has served as the Chief Financial Officer and a director of our general partner since 2005. Mr. Chappel has served as Senior Vice President and Chief Financial Officer of Williams since 2003. Mr. Chappel served as Chief Financial Officer from 2007 and a director from 2008 of the general partner of Williams Pipeline Partners L.P. (WMZ), a limited partnership formed by Williams to own and operate natural gas transportation and storage assets, until WMZ merged with us in 2010. Mr. Chappel also serves as a director of SUPERVALU Inc., a grocery and pharmacy company, and as Chairman of its Finance Committee.

Mr. Chappel’s qualifications include industry and financial experience.

Rory L. Miller has served as Senior Vice President—Midstream and a director of our general partner since January 3, 2011. Mr. Miller has served as a Senior Vice President of Williams and acted as President of Williams midstream business since January 3, 2011. From 2004 to 2010, Mr. Miller was a Vice President of Williams’ midstream business.

Mr. Miller’s qualifications include industry, financial, public policy and government, and operating experience.

Randall L. Barnard has served as Senior Vice President – Gas Pipeline and a director of our general partner since February 24, 2011. Mr. Barnard has served as a Senior Vice President of Williams and acted as President of Williams gas pipeline business since February 2011. From July 2010 to February 2011, Mr. Barnard served as Vice President of Natural Gas Market Development of Williams. From 2002 to July 2010, Mr. Barnard was Senior Vice President of Operations and Technical Service for Williams’ gas pipeline business. From 2000 to 2002, Mr. Barnard served as President of Williams International and Vice President and General Manager of Williams and was a director of Apco Oil and Gas International Inc., formerly Apco Argentina (Apco). Mr. Barnard also served as Chief Executive Officer of Apco from 2001 to 2002. From 1997 to 2000, Mr. Barnard was General Manager of Williams International in Venezuela.

Mr. Barnard’s qualifications include industry, financial, regulatory, public policy and government, and operating experience.

H. Brent Austin has served as a director of our general partner since 2010. Mr. Austin has been Managing Director and Chief Investment Officer of Alsamora L.P., a Houston-based private limited partnership with real estate and diversified equity investments, since 2003. Mr. Austin served as a director of the general partner of WMZ from October 2008 until WMZ merged with us in 2010. From 2002 to 2003, Mr. Austin was President and Chief Operating Officer of El Paso Corporation, where he managed all non-regulated operations as well as all financial functions.

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Mr. Austin’s qualifications include industry, financial, corporate governance, regulatory, public policy and government, and operating experience.

H. Michael Krimbill has served as a director of our general partner since 2007. Mr. Krimbill has served as the Chief Executive Officer of NGL Energy Partners LP and as a director of its general partner since 2010. Mr. Krimbill has served as a director of Pacific Commerce Bank since February 2011. Mr. Krimbill served as a director of Seminole Energy Services, LLC, a privately held natural gas marketing company, from 2007 to 2010. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 to 2007. Mr. Krimbill joined Heritage Propane Partners, L.P. (the predecessor of Energy Transfer Partners) as Vice President and Chief Financial Officer in 1990. Mr. Krimbill served as President of Heritage from 1999 to 2004 and as President and Chief Executive Officer of Heritage from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, from 2000 to 2007.

Mr. Krimbill’s qualifications include industry, financial, corporate governance, and operating experience.

Alice M. Peterson has served as a director of our general partner since 2005. Ms. Peterson served as the Chief Ethics Officer of SAI Global from 2009 to 2010 and presently acts as a special advisor to SAI Global. Since 2000, Ms. Peterson has served as a director of RIM Finance, LLC, a wholly owned subsidiary of Research in Motion, Ltd., the maker of the Blackberry^tm handheld device. Since July 2011, Ms. Peterson has served as a director of Patina Solutions, which provides professionals on a flexible basis to help companies achieve their business objectives. Ms. Peterson served as a director of Navistar Financial Corporation, a wholly owned subsidiary of Navistar International, from 2006 to 2010. Ms. Peterson founded and served as the president of Syrus Global, a provider of ethics, compliance, and reputation management solutions from 2002 to April 2009, when it was acquired by SAI Global. Ms. Peterson served as a director of Hanesbrands Inc., an apparel company, from 2006 to 2009. Ms. Peterson served as a director of TBC Corporation, a marketer of private branded replacement tires, from July 2005 to November 2005, when it was acquired by Sumitomo Corporation of America. From 1998 to 2004, she served as a director of Fleming Companies. From 2000 to 2001, Ms. Peterson served as President and General Manager of RIM Finance, LLC. From 1998 to 2000, Ms. Peterson served as Vice President of Sears Online and from 1993 to 1998, as Vice President and Treasurer of Sears, Roebuck and Co. Ms. Peterson serves on the faculty of the Practicing Law Institute and the National Association of Corporate Directors.

Ms. Peterson’s qualifications include financial and corporate governance experience.

Laura A. Sugg has served as a director of our general partner since December 2011. Ms. Sugg has served as a director of Williams since 2010 and has served as a director of Denbury Resources, Inc., an oil and natural gas exploration and production company, since January 2012. Ms. Sugg retired from ConocoPhillips in 2010, having served as President, Australasia Division, a position responsible for the profit and loss and growth responsibility of ConocoPhillip’s operations in Australia and East Timor. Ms. Sugg began her career in 1983 at Sohio Petroleum and joined Phillips Petroleum, now ConocoPhillips, in 1986 and performed various business development, human resources and operations roles. From 2003 to 2005, Ms. Sugg was ConocoPhillip’s General Manager E&P Human Resources, with responsibility for global compensation and benefits, leadership succession planning, and all human resource functions for 10,000 worldwide employees in 16 countries. From 2002 to 2003, Ms. Sugg was a ConocoPhillip’s midstream executive responsible for profit and loss, health, safety and environment, and operations for its gas gathering, processing, and fractionation business in the U.S., Canada, and Trinidad. From 2000 to 2002, Ms. Sugg was Vice President Worldwide Gas for Phillips with responsibility for its global liquefied natural gas and coal bed methane business development and the profit and loss for its North American gas marketing operations. Ms. Sugg was a director of Mariner Energy, Inc., an independent oil and gas exploration and production company, from 2009 until its merger with Apache Corporation in 2010. She is a member of the National Association of Corporate Directors and the Oklahoma State University Engineering Advisory Board.

Ms. Sugg’s qualifications include industry, financial, and operating experience.

Craig L. Rainey has served as the General Counsel of our general partner since December 31, 2011. From 2001 to December 2011, Mr. Rainey served as an Assistant General Counsel of Williams, primarily supporting Williams’ midstream business and former exploration and production business. He joined Williams in 1999 as a senior counsel.

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Ted T. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of our general partner since 2005. Mr. Timmermans has served as Vice President, Controller, and Chief Accounting Officer of Williams since 2005. Mr. Timmermans served as an Assistant Controller of Williams from 1998 to 2005. Mr. Timmermans served as Chief Accounting Officer of the general partner of WMZ from 2008 until WMZ merged with us in 2010.

Governance

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

Director Independence

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

Our general partner’s Board of Directors has adopted director independence standards, which are included in our governance guidelines. Our governance guidelines are available on our website at www.williamslp.com at the Corporate Responsibility/Corporate Governance Guidelines tab.

Our general partner’s Board of Directors has affirmatively determined that each of Mesdames Peterson and Sugg and Mr. Austin is an “independent director” under the current listing standards of the NYSE and our director independence standards. In so doing, the Board of Directors determined that each of these individuals met the “bright line” independence standards of the NYSE. In addition, there were no transactions or relationships between each director and any member of his or her immediate family on one hand, and us or any affiliate of us on the other, that were identified and considered by the Board of Directors. Accordingly, the Board of Directors of our general partner affirmatively determined that all of the directors mentioned above are independent. Because Messrs. Armstrong, Barnard, Chappel, Miller, Phillip D. Wright (who served as a director of our general partner until February 24, 2011), and Steven J. Malcolm (who served as a director of our general partner until January 3, 2011) are or were employees, officers and/or directors of Williams, they are not independent under these standards. Mr. Krimbill is not independent due to business relationships between us and NGL Energy Partners L.P.

Mesdames Peterson and Sugg and Mr. Austin do not serve as an executive officer of any non-profit organization to which we or our affiliates (the Partnership Group) made contributions within any single year of the preceding three years that exceeded the greater of $1.0 million or 2 percent of such organization’s consolidated gross revenues. Further, in accordance with our director independence standards, there were no discretionary contributions made by any member of the Partnership Group to a non-profit organization with which such director, or such director’s spouse, has a relationship that impact the director’s independence.

Meeting Attendance and Preparation

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

Executive Sessions of Non-Management Directors

Our general partner’s non-management Board members periodically meet outside the presence of our general partner’s executive officers. The Chairman of the Audit Committee serves as the presiding director for executive sessions of non-management Board members. The current Chairman of the Audit Committee and the presiding director is Ms. Alice M. Peterson.

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Communications with Directors

Interested parties wishing to communicate with our general partner’s non-management directors, individually or as a group, may do so by contacting our general partner’s Corporate Secretary or the presiding director. The contact information is maintained at the corporate responsibility/corporate governance guidelines tab of our website at www.williamslp.com.

The current contact information is as follows:

Williams Partners L.P.

c/o Williams Partners GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Presiding Director

Williams Partners L.P.

c/o Williams Partners GP LLC

One Williams Center, Suite 4700

Tulsa, Oklahoma 74172

Attn: Corporate Secretary

Board Committees

The Board of Directors of our general partner has a separately-designated standing Audit Committee established in accordance with Section 3(a)(58)(A) of the Securities Exchange Act of 1934 and a Conflicts Committee. The following is a description of each of the committees and committee membership as of February 24, 2012.

Board Committee Membership

	Audit Committee	Conflicts Committee
H. Brent Austin	ü	•
Alice M. Peterson	•	ü
Laura A. Sugg	ü

ü = committee member

• = chairperson

Audit Committee

Our general partner’s Board of Directors has determined that all members of the Audit Committee meet the heightened independence requirements of the NYSE for audit committee members and that all members are financially literate as defined by the rules of the NYSE. The Board of Directors has further determined that Ms. Alice M. Peterson and Mr. H. Brent Austin qualify as “audit committee financial experts” as defined by the rules of the SEC. Biographical information for each of these persons is set forth above. The Audit Committee is governed by a written charter adopted by the Board of Directors. For further information about the Audit Committee, please read the “Report of the Audit Committee” below and “Principal Accountant Fees and Services.”

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Conflicts Committee

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

Code of Business Conduct and Ethics

Our general partner has adopted a Code of Business Conduct and Ethics for directors, officers and employees. We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our general partner’s Chief Executive Officer, Chief Financial Officer, Controller and persons performing similar functions on our website at www.williamslp.com under the Corporate Responsibility tab, promptly following the date of any such amendment or waiver.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our general partner’s executive officers and directors and persons who own more than 10% of a registered class of our equity securities to file with the SEC and the NYSE reports of ownership of our securities and changes in reported ownership. Executive officers and directors of our general partner and greater than 10% unitholders are required to by SEC rules to furnish to us copies of all Section 16(a) reports that they file. Based solely on a review of reports furnished to our general partner, or written representations from reporting persons that all reportable transactions were reported, we believe that during the fiscal year ended December 31, 2011 our general partner’s officers, our directors and our greater than 10% common unitholders filed all reports they were required to file under Section 16(a) on a timely basis.

Transfer Agent and Registrar

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

Computershare Trust Company, N.A.

P.O. Box 43069

Providence, Rhode Island 02940-3069

Phone: (781) 575-2879 or toll-free, (877) 498-8861

Hearing impaired: (800) 952-9245

Internet: www.computershare.com/investor

Send overnight mail to:

Computershare

250 Royall St.

Canton, Massachusetts 02021

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REPORT OF THE AUDIT COMMITTEE

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

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

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

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

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

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

• Based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2011, for filing with the SEC.

This report has been furnished by the members of the Audit Committee of the Board of Directors:

— Alice M. Peterson—Chair

— H. Brent Austin

— Laura A. Sugg

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

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Item 11. Executive Compensation

Compensation Discussion and Analysis

We and our general partner, Williams Partners GP LLC, were formed in February 2005. We are managed by the executive officers of our general partner who are also executive officers of Williams. Neither we nor our general partner have a compensation committee. The executive officers of our general partner are compensated directly by Williams. All decisions as to the compensation of the executive officers of our general partner who are involved in our management are made by the Compensation Committee of Williams. Therefore, we do not have any policies or programs relating to compensation of the executive officers of our general partner and we make no decisions relating to such compensation. None of the executive officers of our general partner have employment agreements with us or are otherwise specifically compensated for their service as an executive officer of our general partner. A full discussion of the policies and programs of the Compensation Committee of Williams will be set forth in the proxy statement for Williams’ 2012 annual meeting of stockholders which will be available upon its filing on the SEC’s website at www.sec.gov and on Williams’ website at www.williams.com at the “Investors—SEC Filings” tab (Williams’ 2012 Proxy Statement). We reimburse our general partner for direct and indirect general and administrative expenses attributable to our management (which expenses include the share of the compensation paid to the executive officers of our general partner attributable to the time they spend managing our business). Please read “Certain Relationships and Related Transactions, and Director Independence—Reimbursement of Expenses of Our General Partner” for more information regarding this arrangement.

Executive Compensation

The following table summarizes the compensation attributable to services performed for us in 2011 for our general partner’s named executive officers (NEOs), consisting of our principal executive officer, principal financial officer, three other most highly compensated executive officers serving as executive officers at the end of 2011, a former executive officer who served as our principal executive officer for a portion of 2011, and a former executive officer who would have been one of our general partner’s three most highly compensated executive officers (other than the principal executive and financial officers) if he had been serving as an executive officer at the end of 2011.

Further information regarding compensation of our principal executive officer, Mr. Armstrong, who also serves as the President and Chief Executive Officer of Williams, our principal financial officer, Mr. Chappel, who also serves as the Chief Financial Officer of Williams, Mr. Wright, who until February 24, 2011 served as our Senior Vice President – Gas Pipeline and who also serves as a Senior Vice President of Williams, and Mr. Malcolm, who until January 3, 2011 served as our principal executive officer and also served as Chairman of the Board, President, and Chief Executive Officer of Williams, will be set forth in Williams’ 2012 Proxy Statement. Compensation amounts set forth in Williams’ 2012 Proxy Statement will include all compensation paid by Williams, including the amounts in the table below attributable to services performed for us.

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2011 Summary Compensation Table

The following table sets forth certain information with respect to Williams’ compensation of our general partner’s NEOs attributable to us during fiscal years 2011, 2010, and 2009.

Name and Principal Position(1)	Year		Salary(2)		Bonus		Stock Awards(3)		Option Awards(4)		Non-Equity Incentive Plan Compensation(5)		Change in Pension Value and Nonqualified Deferred Compensation Earnings(6)		All Other Compensation(7)		Total
Alan S. Armstrong		2011	$	548,550	$	—	$	1,545,849	$	277,298	$	997,943	$	409,057	$	34,722	$	3,813,419
Chairman &		2010		370,596		—		917,705		260,423		319,581		205,368		12,252		2,085,925
Chief Executive Officer		2009		135,987		—		268,430		133,658		153,173		79,325		4,393		774,966
Donald R. Chappel		2011		383,865		—		986,533		233,883		462,091		297,698		11,313		2,375,383
Chief Financial Officer		2010		333,144		—		784,538		222,628		305,242		123,144		8,911		1,777,607
		2009		55,180		—		86,991		43,315		53,553		26,837		1,143		267,019
Phillip D. Wright		2011		327,063		—		836,863		198,400		385,836		408,502		12,277		2,168,941
Former Senior Vice President		2010		431,531		—		1,036,540		294,146		323,903		225,704		13,878		2,325,702
Gas Pipeline		2009		—		—		—		—		—		—		—		—
Rory L. Miller		2011		344,933		—		968,722		229,652		306,233		238,837		13,253		2,101,630
Senior Vice President,		2010		—		—		—		—		—		—		—		—
Midstream		2009		—		—		—		—		—		—		—		—
Randall L. Barnard		2011		380,084		—		1,100,795		260,962		323,128		393,398		21,071		2,479,438
Senior Vice President,		2010		—		—		—		—		—		—		—		—
Gas Pipeline		2009		—		—		—		—		—		—		—		—
James J. Bender		2011		293,758		—		602,339		142,800		271,096		240,747		20,707		1,571,447
Former General Counsel		2010		247,724		—		484,079		137,367		186,133		97,662		8,423		1,161,388
		2009		42,991		—		56,544		28,155		36,548		17,548		1,865		183,651
Steven J. Malcolm		2011		94,476		—		—		—		75,291		—		—		169,767
Former Chairman &		2010		580,470		—		1,549,477		1,004,111		673,545		392,834		23,114		4,223,551
Chief Executive Officer		2009		86,310		—		148,180		199,248		133,235		97,986		4,978		669,937

(1) Name and Principal Position. On January 3, 2011, Mr. Malcolm retired as Chairman of the Board and Chief Executive Officer of our general partner. Mr. Armstrong, our general partner’s former Senior Vice President – Midstream, succeeded Mr. Malcolm as Chairman of the Board and Chief Executive Officer on January 3, 2011. Mr. Wright served as a director of our general partner and our general partner’s Senior Vice President – Gas Pipeline from February 2010 to February 24, 2011.

(2) Salary. The amount paid to Mr. Malcolm in 2011 consisted primarily of accrued vacation/paid time off. Mr. Malcolm did not receive a salary increase in 2009 or 2010. All other NEOs did not receive a salary increase in 2009 and received a 2 percent increase in 2010.

(3) Stock Awards. The stock awards represent equity grants related to Williams’ common stock. The NEOs do not receive any equity awards from us. Awards were granted under the terms of Williams’ 2007 Incentive Plan and include time-based and performance-based restricted stock units (RSUs). Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the stock awards can be found in the Williams Annual Report on Form 10-K for the year-ended December 31, 2011. Mr. Malcolm had no outstanding time-based RSUs.

The potential maximum values attributable to us of the performance-based RSUs, subject to changes in performance outcomes of Williams, are as follows:

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	2011 Performance-Based RSU Maximum Potential
Alan S. Armstrong	$	2,173,116
Donald R. Chappel		1,069,169
Phillip D. Wright		906,960
Rory L. Miller		1,049,866
Randall L. Barnard		1,193,001
James J. Bender		652,793
Steven J. Malcolm		—

(4) Option Awards. Awards are granted under the terms of Williams’ 2007 Incentive Plan and include non-qualified stock options. Amounts shown are the grant date fair value of awards attributable to us computed in accordance with FASB ASC Topic 718. The assumptions used by Williams to determine the grant date fair value of the option awards can be found in the Williams Annual Report on Form 10-K for the year-ended December 31, 2011. The options may be exercised to acquire Williams’ common stock. The NEOs do not receive any option awards from us.

(5) Non-Equity Incentive Plan. Williams provides an annual incentive program to the NEOs and payments are based on the financial performance of Williams. The maximum annual incentive pool funding for NEOs is 250 percent of target. The NEOs also have a previously funded reserve balance that has been eliminated, beginning in 2009; however, Mr. Miller and Mr. Barnard were not executive officers in 2009 and did not have reserve balances. Threshold performance was met in 2009, 2010, and 2011 and a portion of the respective reserve balance was paid to each NEO each year. We do not sponsor any non-equity incentive plans.

(6) Change in Pension Value and Nonqualified Deferred Compensation Earnings. The amount shown is the aggregate change from December 31, 2010 to December 31, 2011 in the actuarial present value of the accrued benefit under the qualified pension and supplemental retirement plans sponsored by Williams that is attributable to us. Williams’ 2012 Proxy Statement will provide more detail regarding “Pension Benefits” including further details regarding the calculation of the present value of the accrued benefit. We do not sponsor any qualified pension or supplemental retirement plans.

(7) All Other Compensation. Amounts shown represent payments made by Williams on behalf of the NEOs and attributable to us. These amounts include life insurance premium, a 401(k) matching contribution, and perquisites (if applicable). None of these amounts were provided directly by us. Perquisites include financial planning services, mandated annual physical exam, and personal use of Williams aircraft. Effective in 2011, Williams no longer requires its CEO to use Williams’ aircraft for all air travel. The incremental cost method was used to calculate the personal use of Williams’ aircraft. The incremental cost calculation includes such items as fuel, maintenance, weather and airport services, pilot meals, pilot overnight expenses, aircraft telephone, and catering. The amounts of perquisites for Mr. Armstrong and Mr. Bender are included because the aggregate amount attributable to us exceeds $10,000.

	Financial Planning		Annual Physical Exam		Company Aircraft Personal Usage
Alan S. Armstrong	$	3,048	$	3,450	$	18,482
James J. Bender		9,054		2,023		—

We have not included tables with information about grants of plan-based awards, outstanding equity awards at fiscal year-end, option exercises and stock vested, pension benefits, and non-qualified deferred compensation because we do not currently sponsor such plans or grant awards to our NEOs under our general partner’s long-term incentive plan, which is the only compensation plan sponsored by our general partner. Information related to Williams’ sponsorship of any such plans will be set forth in Williams’ 2012 Proxy Statement. In addition, our NEOs are not entitled to any compensation as a result of a change-in-control of us or the termination of their service as an NEO of our general partner.

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Compensation Committee Interlocks and Insider Participation

As previously discussed, our general partner’s Board of Directors is not required to maintain, and does not maintain, a compensation committee. Until January 3, 2011, Steven J. Malcolm, served as our general partner’s Chief Executive Officer and Chairman of the Board of Directors and also served as the Chairman of the Board and Chief Executive Officer of Williams. From January 3, 2011, Alan S. Armstrong has served as our general partner’s Chief Executive Officer and Chairman of the Board of Directors and has also served as the President and Chief Executive Officer of Williams. Also during 2011, Randall L. Barnard, Donald R. Chappel, Rory L. Miller and Phillip D. Wright, who were directors of our general partner, also served as executive officers of Williams. However, all compensation decisions with respect to each of these persons are made by Williams and none of these individuals receive any compensation directly from us or our general partner. Please read “Certain Relationships and Related Transactions, and Director Independence” below for information about relationships among us, our general partner and Williams.

Compensation Policies and Practices as They Relate to Risk Management

We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Williams perform services on our behalf. We do not have any compensation policies or practices that need to be assessed or evaluated for the effect on our operations. Please read “Compensation Discussion and Analysis,” “Employees,” and “Certain Relationships and Related Transactions, and Director Independence” for more information about this arrangement. For an analysis of any risks arising from Williams’ compensation policies and practices, please read Williams’ 2012 Proxy Statement.

Board Report on Compensation

Neither we nor our general partner has a compensation committee. The Board of Directors of our general partner has reviewed and discussed with management the Compensation Discussion and Analysis set forth above and based on this review and discussion has approved it for inclusion in this Form 10-K.

The Board of Directors of Williams Partners GP LLC:

Alan S. Armstrong,

Randall L. Barnard,

H. Brent Austin,

Donald R. Chappel,

H. Michael Krimbill,

Rory L. Miller,

Alice M. Peterson

Laura A. Sugg

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Compensation of Directors

We are managed by the Board of Directors of our general partner. Members of the Board of Directors who are also officers or employees of Williams or an affiliate of us or Williams do not receive additional compensation for serving on the Board of Directors. Please read “Compensation Discussion and Analysis,” “Executive Compensation,” and “Certain Relationships and Related Transactions, and Director Independence—Reimbursement of Expenses of Our General Partner” for information about how we reimburse our general partner for direct and indirect general and administrative expenses attributable to our management. Non-employee directors receive a bi-annual compensation package consisting of the following, which amounts are paid on September 1 and March 1: (a) $45,000 cash retainer; and (b) $2,500 cash retainer each for service on the Conflicts Committee or Audit Committee of the Board of Directors. If a non-employee director’s service on the Board of Directors commenced after September 1 and prior to the final day of February, or between March 1 and August 31, the non-employee director receives a prorated bi-annual compensation package. In addition to the bi-annual compensation package, each non-employee director who was first elected to the Board of Directors receives a one-time cash payment of $25,000 on the date of such election. Also, each non-employee director serving as a member of the Conflicts Committee receives $1,250 cash for each Conflicts Committee meeting attended by such director. Fees for attendance at meetings of the Conflicts Committee are paid on March 1 and September 1 for meetings held during the preceding months.

Each non-employee director is also reimbursed for out-of-pocket expenses in connection with attending meetings of the Board of Directors or its committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Delaware law. We also reimburse non-employee directors for the costs of education programs relevant to their duties as Board members.

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For their service, non-management directors were paid the following compensation in 2011:

Director Compensation Fiscal Year 2011

Name	Fees Earned or Paid in Cash (1)			Unit Awards		Option Awards		Non-Equity Incentive Plan Compensation		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
H. Brent Austin	$	126,250			—		—		—		—		—	$	126,250
H. Michael Krimbill		126,250			—		—		—		—		—		126,250
Alice M. Peterson		125,000			—		—		—		—		—		125,000
Laura A. Sugg		32,917	(2)		—		—		—		—		—		32,917

(1) Bi-annual compensation retainer fees and Conflicts Committee meeting fees earned in 2011 are reflected in this column.

(2) Ms. Sugg joined the Board of Directors of our General Partner on December 12, 2011. The amount in this column reflects the one-time cash payment of $25,000 for new directors on the date of her election and the portion of Ms. Sugg’s prorated bi-annual retainer and committee fee for December 2011. On March 1, 2012, Ms. Sugg will be paid the prorated bi-annual retainer and committee fee for her service between December 2011 and February 2012.

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

The following table sets forth information as of February 23, 2012, concerning beneficial ownership by holders of 5 percent or more of our common units. Unless otherwise indicated by footnote, the companies named in the table have sole voting and investment power with respect to the common units listed.

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Total Common Units Beneficially Owned
The Williams Companies, Inc.(a)		217,095,249		71.18	%
Williams Gas Pipeline Company, LLC(a)		120,564,984		39.53	%

Percentage of common units beneficially owned is based on 305,008,540 common units outstanding. Our general partner, Williams Partners GP LLC, also owns all of our 2 percent general partner interest and IDRs.

(a) The Williams Companies, Inc. (Williams) is the parent company of Williams Partners GP LLC (the General Partner), Williams Discovery Pipeline LLC (Discovery Pipeline), and Williams Gas Pipeline Company, LLC (WGP) and is the ultimate parent company of Williams Energy, L.L.C. (WE), Williams Partners Holdings LLC (Holdings), and WGP Gulfstream Pipeline LLC (Gulfstream), and may, therefore, be deemed to beneficially own the common units held by each of these companies. Williams’ common stock is listed on the NYSE under the symbol “WMB.” Williams files information with, or furnishes information to, the Securities and Exchange Commission pursuant to the information requirements of the Securities Exchange Act of 1934 (the Act). Gulfstream is the record holder of 4,875,284 common units. WGP is the record holder of 115,689,700 common units, and, as the sole member of Gulfstream, may, pursuant to Rule 13d-3, be deemed to beneficially own the common units owned by Gulfstream. Discovery Pipeline is the record holder of 1,425,466 common units. Holdings is the record holder of 2,826,378 common units. The General Partner is the record holder of 3,363,527 common units. WE is the record owner of 2,952,233 common units. Williams is record holder of 85,962,661

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common units and, as the sole member of Discovery Pipeline, WGP, and the General Partner, and the indirect owner of WE, Holdings and Gulfstream may, pursuant to Rule 13d-3, be deemed to beneficially own the units beneficially owned by Discovery Pipeline, WGP, the General Partner, WE, Holdings, and Gulfstream. The address of these companies is One Williams Center, Tulsa, Oklahoma 74172.

The following table sets forth, as of February 1, 2012, the number of shares of common stock of The Williams Companies, Inc. beneficially owned by each of the directors of our general partner, by the NEOs of our general partner, and by all directors and executive officers of our general partner as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Shares of Common Stock Owned Directly or Indirectly(a)		Shares Underlying Options Exercisable Within 60 Days(b)		Total		Percent of Class
Alan S. Armstrong		394,789		352,115		746,904		*
H. Brent Austin		—		—		—		*
Randall L. Barnard		113,607		23,589		137,196		*
James J. Bender (c)		346,819		344,854		691,673		*
Donald R. Chappel		466,199		694,925		1,161,124		*
H. Michael Krimbill		50,000		—		50,000		*
Steven J. Malcolm (d)		1,238,867		900,002		2,138,869		*
Rory L. Miller		111,457		78,491		189,948		*
Alice M. Peterson		—		—		—		*
Laura A. Sugg		8,710		—		8,710		*
Phillip D. Wright (e)		485,250		328,190		813,440		*
All current directors and executive officers as a group (10 persons)		1,192,841		1,265,853		2,508,694		*

Percentage of shares beneficially owned is based on 592,141,595 shares outstanding on February 1, 2012.

* Less than 1%.

(a) Includes shares held under the terms of Williams incentive and investment plans as follows: Mr. Armstrong, 318,049 restricted stock units and 76,740 beneficially owned shares; Mr. Barnard, 106,868 restricted stock units and 6,739 beneficially owned shares; Mr. Bender, 314,312 restricted stock units and 32,507 beneficially owned shares; Mr. Chappel, 331,936 restricted stock units and 134,263 beneficially owned shares; Mr. Malcolm, 1,173 shares in The Williams Companies Investment Plus Plan, 526,848 restricted stock units, and 710,846 beneficially owned shares; Mr. Miller, 80,958 restricted stock units and 30,499 beneficially owned shares; and Mr. Wright, 270,492 restricted stock units and 214,758 beneficially owned shares of which 14,388 shares were held in the Vicky L. Wright Trust dated February 12, 2004. Williams restricted stock units do not provide the holder with voting or investment power.

(b) The shares indicated represent stock options granted under Williams’ current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 1, 2012. Shares subject to options cannot be voted.

(c) Mr. Bender resigned as General Counsel of our general partner, effective December 31, 2011.

(d) Mr. Malcolm retired as Chairman of the Board and Chief Executive Officer of our general partner, effective January 3, 2011.

(e) Mr. Wright resigned as Senior Vice President – Gas Pipeline and Director of our general partner, effective February 24, 2011.

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The following table sets forth, as of February 22, 2012, the number of common units beneficially owned by each of the directors of our general partner, by the NEOs of our general partner, and by all directors and executive officers of our general partner as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned
Alan S. Armstrong (a)	20,000		*
H. Brent Austin (b)	10,336		*
Randall L. Barnard	2,337		*
James J. Bender (c)	17,000		*
Donald R. Chappel	22,584		*
H. Michael Krimbill	57,151		*
Steven J. Malcolm (d)	32,684		*
Rory L. Miller	—		*
Alice M. Peterson	4,524		*
Laura A. Sugg	—		*
Phillip D. Wright (e)	12,084		*
All current directors and executive officers as a group (10 persons)	125,678		*

Percentage of common units beneficially owned is based on 305,008,540 common units outstanding.

* Less than 1%.

(a) Mr. Armstrong is the trustee of the Alan Stuart Armstrong Trust dated June 16, 2010, who has the power to vote or to direct the vote of, the right to receive or the power to direct the receipt of distributions from, the power to dispose or direct the dispositions of, and the right to receive the proceeds from the sale of, 10,000 Common Units held by the Trust. Mr. Armstrong’s spouse is the trustee of the Shelly Stone Armstrong Trust dated June 16, 2010, who has the power to vote or to direct the vote of, the right to receive or the power to direct the receipt of dividends from, the power to dispose or direct the disposition of, and the right to receive the proceeds from the sale of, 10,000 Common Units held by the Trust.

(b) Mr. Austin holds 9,000 common units in a joint tenants-in-common account with his spouse.

(c) Represents units beneficially owned by Mr. Bender that are held by the James J. Bender Revocable Trust dated July 8, 2009. Mr. Bender resigned as General Counsel of our general partner, effective December 31, 2011.

(d) Mr. Malcolm retired as Chairman of the Board and Chief Executive Officer of our general partner, effective January 3, 2011.

(e) Mr. Wright resigned as Senior Vice President – Gas Pipeline and Director of our general partner, effective February 24, 2011. Includes 2,425 common units held in the Vicky L. Wright Trust dated February 12, 2004.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information concerning common units that were potentially subject to issuance under the Williams Partners GP LLC Long-Term Incentive Plan as of December 31, 2011. For more information about this plan, which did not require approval by our limited partners, please read Note 12, of Notes to Consolidated Financial Statements.

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Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plan (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by security holders	—	—	—
Equity compensation plans not approved by security holders	—	—	686,597
Total	—	—	686,597

Item 13. Certain Relationships and Related Transactions, and Director Independence

Transactions with Related Persons

Our general partner and its affiliates own 217,095,249 common units representing a 70 percent limited partner interest in us. Williams also indirectly owns 100 percent of our general partner, which allows it to control us. Certain officers and directors of our general partner also serve as officers and/or directors of Williams. In addition, our general partner owns a 2 percent general partner interest and incentive distribution rights in us.

In addition to the related transactions and relationships discussed below, information about such transactions and relationships is included in Note 3 of our Notes to Consolidated Financial Statements and is incorporated herein by reference in its entirety.

On December 31, 2011, Williams completed the tax-free spin-off of its 100 percent interest in WPX to their shareholders. WPX was formed in April 2011 to hold Williams’ former exploration and production business. The spin-off was completed by means of a special stock dividend. We were affiliated with WPX until this separation, so transactions between us and WPX are included below.

Distributions and Payments to Our General Partner and Its Affiliates

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

	Operational Stage
Distributions of available cash to our general partner and its affiliates	We will generally make cash distributions 98 percent to unitholders, including our general partner and its affiliates as holders of an aggregate of 217,095,249 common units and the remaining 2 percent to our general partner.
	In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our general partner will be entitled to increasing percentages of the distributions, up to 50 percent of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” For further information about distributions, please read “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.”
Reimbursement of expenses to our general partner and its affiliates	Our general partner does not receive a management fee or other compensation for the management of our partnership. Our general partner and its affiliates are reimbursed, however, for all direct and indirect expenses incurred on our behalf. Our general partner determines the amount of these expenses.

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Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
	Liquidation Stage
Liquidation	Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Reimbursement of Expenses of Our General Partner

Our general partner does not receive any management fee or other compensation for its management of our business. However, we reimburse our general partner for expenses incurred on our behalf, including expenses incurred in compensating employees of an affiliate of our general partner who perform services on our behalf. These expenses include all allocable expenses necessary or appropriate to the conduct of our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no minimum or maximum amount that may be paid or reimbursed to our general partner for expenses incurred on our behalf.

For the fiscal year ended December 31, 2011, our general partner allocated approximately $12 million of expense to us for the services performed on our behalf by our executive officers, who are also employees of Williams, and those of our directors, who are also employees of Williams. This allocated expense included our allocable share of salaries, non-equity incentive plan compensation, and other employment-related expenses, including Williams restricted stock unit and stock option awards, retirement plans, health and welfare plans, employer-related payroll taxes, matching contributions made under a Williams 401(k) plan and premiums for life insurance.

Williams affiliates charge us for the costs associated with the employees that operate our assets. These costs totaled $208 million for the year ended December 31, 2011.

In addition, general and administrative services are provided to us by employees of Williams, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to their operations. Direct charges are for goods and services provided by Williams at their request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. These costs totaled $344 million for the year ended December 31, 2011. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of their costs of doing business incurred by Williams.

Commodity Purchase Contracts

We purchased natural gas for shrink replacement and fuel for processing plants from WPX and we purchased for resale from WPX, Discovery Producer Services LLC, and Williams Olefins, LLC (Williams Olefins), a wholly owned subsidiary of Williams, substantially all of the NGLs to which those entities take title. We conduct these purchases at market prices at the time of purchase. We also purchased natural gas for Gas Pipeline’s merchant gas sales program from WPX at contract or market prices. These purchases totaled $923 million for the year ended December 31, 2011.

In addition, through an agency agreement, WPX managed Transco’s jurisdictional merchant gas sales. WPX was authorized to make gas sales on Transco’s behalf in order to manage its gas purchase obligations. WPX receives all margins associated with jurisdictional merchant gas sales business and, as Transco’s agent, assumes all market and credit risk associated with such sales. Consequently, Transco’s merchant gas sales service has no impact on its operating income or results of operations.

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Gathering, Processing and Treating Contracts

We provided gathering, treating and processing services for WPX under several contracts. Revenues from these services were $270 million for the year ended December 31, 2011. The rates charged to provide these services are considered reasonable as compared to those that are charged to similarly-situated nonaffiliated customers.

Transportation and Exchange Contracts

We purchase transportation services from Overland Pass Pipeline Company LLC for NGLs from certain of our natural gas processing plants. These transportation costs were $45 million for the year ended December 31, 2011.

We provided natural gas transportation and exchange services and rental of communication facilities to WPX. These revenues were $42 million for the year ended December 31, 2011. The rates charged to provide sales and services to affiliates are comparable to those that are charged to similarly-situated nonaffiliated customers.

Commodity Sales Contracts

We sell feedstock commodities to Williams Olefins for use in its facilities and natural gas purchased for shrink replacement and fuel at our processing plants in excess of their requirements to WPX. Revenues from these product sales were $114 million for the year ended December 31, 2011. These sales are generally made at market prices at the time of sale.

We transferred a transportation capacity contract to WPX in a previous year. To the extent WPX did not utilize this transportation capacity for its needs (primarily transporting third-party gas volumes), we reimbursed WPX for these transportation costs. These cost reimbursements totaled approximately $11 million in 2011.

Operating Agreements with Equity Method Investees

We are party to operating agreements with unconsolidated companies where our investment is accounted for using the equity method. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies and other charges and also for management services. Williams supplied a portion of these services, primarily those related to employees since we do not have any employees, to the equity method investees. The following amounts were billed to the equity method investments we operate:

	Year Ended December 31, 2011
	(Millions)
Cardinal Pipeline Company LLC	$	3
Discovery Producer Services LLC	$	14
Gulfstream Natural Gas System, L.L.C.	$	9
Laurel Mountain Midstream, LLC	$	21
Overland Pass Pipeline Company LLC	$	8
Pine Needle LNG Company, LLC	$	2
	$	57

Summary of Other Transactions with Williams

For the year ended December 31, 2011, we distributed approximately $911 million to affiliates of Williams as quarterly distributions on its common units, 2 percent general partner interest, and incentive distribution rights.

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Initial Omnibus Agreement

Upon the closing of our initial public offering, we entered into an omnibus agreement with Williams and its affiliates that was not the result of arm’s-length negotiations. The omnibus agreement governs our relationship with Williams regarding the following matters:

• Reimbursement of certain general and administrative expenses;

• Indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;

• Reimbursement for certain expenditures;

• A license for the use of certain software and intellectual property.

Total amounts received under this agreement for the year ended December 31, 2011, were $0.3 million.

Intellectual Property License

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

Piceance Omnibus Agreement

Under an omnibus agreement entered into in connection with our acquisition of certain gathering and processing assets in the Piceance basin in November 2010, a subsidiary of WPX is obligated to reimburse us for (i) amounts incurred by us or our subsidiaries for any cost required to complete the pipeline and compression projects known collectively as the Ryan Gulch Expansion Project, (ii) amounts incurred by us or our subsidiaries prior to January 31, 2011, related to the development of a cryogenic processing arrangement with a subsidiary of Williams, up to $20 million, and (iii) amounts incurred by us or our subsidiaries for notice of violation or enforcement actions related to compression station land use permits or other losses, costs and expenses related to surface lease use agreements. In addition, we are obligated to reimburse a subsidiary of WPX for any costs related to the pipeline and compression projects known collectively as the Kokopelli Expansion irrespective of whether othose costs were incurred prior to the effective date of the acquisition. We received approximately $1 million and paid $0.4 million under this agreement for the year ended December 31, 2011.

February 2010 Omnibus Agreement

In connection with Williams’ contribution of ownership interests in certain entities to us in February 2010, we entered into an omnibus agreement with Williams. Pursuant to this omnibus agreement, Williams is obligated to indemnify us from and against or reimburse us for (i) amounts incurred by us or our subsidiaries for repair or abandonment costs for damages to certain facilities caused by Hurricane Ike, up to a maximum of $10 million, (ii) maintenance capital expenditure amounts incurred by us or our subsidiaries in respect of certain U.S. Department of Transportation projects, up to a maximum aggregate amount of $50 million, and (iii) an amount based on the amortization over time of deferred revenue amounts that relate to cash payments received prior to the closing of the contribution transaction for services to be rendered by us in the future at the Devils Tower floating production platform located in Mississippi Canyon Block 773. In addition, we are obligated to pay to Williams the proceeds of certain sales of natural gas recovered from the Hester storage field pursuant to the FERC order dated March 7, 2008, approving a settlement agreement in Docket No. RP06-569. Net amounts received under this agreement for the year ended December 31, 2011, were $31 million.

Gulfstream Acquisition

In May 2011, we acquired from Williams an additional 24.5 percent interest in Gulfstream in exchange for aggregate consideration of $297 million of cash, 632,584 limited partner units, and an increase in the capital account of our general partner to allow it to maintain its 2 percent general partner interest.

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Review, Approval or Ratification of Transactions with Related Persons

Our partnership agreement contains specific provisions that address potential conflicts of interest between our general partner and its affiliates, including Williams, on one hand, and us and our subsidiaries, on the other hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is not required to, seek the approval of such resolution from the Conflicts Committee of the Board of Directors of our general partner, which is comprised of independent directors. The partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if the resolution of the conflict is:

• Approved by the Conflicts Committee;

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

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

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

If our general partner does not seek approval from the Conflicts Committee and the Board of Directors of our general partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the Conflicts Committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires. See “Directors, Executive Officers and Corporate Governance —Governance — Board Committees — Conflict Committee.”

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

Director Independence

Please read “Directors, Executive Officers and Corporate Governance — Governance — Director Independence” and “ — Board Committees” in Item 10 above for information about the independence of our general partner’s Board of Directors and its committees, which information is incorporated into this Item 13 by reference in its entirety.

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Item 14. Principal Accounting Fees and Services

Fees for professional services provided by our independent auditors for each of the last two fiscal years were as follows:

	2011		2010
	(Thousands)
Audit Fees	$	5,057	$	7,309
Audit-Related Fees		—		—
Tax Fees		45		30
All Other Fees		—		—
	$	5,102	$	7,339

Fees for audit services in 2011 and 2010 include fees associated with the annual audit, the reviews of our quarterly reports on Form 10-Q, the audit of our assessment of internal controls as required by Section 404 of the Sarbanes-Oxley Act of 2002 and services provided in connection with other filings with the SEC. The fees for audit services do not include audit costs for stand-alone audits for equity investees. Tax fees for 2011 and 2010 include fees for review of our federal tax return. Ernst & Young LLP does not provide tax services to our general partner’s executive officers.

The Audit Committee of our general partner’s Board of Directors is responsible for appointing, setting compensation for and overseeing the work of Ernst & Young LLP, our independent auditors. The Audit Committee has established a policy regarding pre-approval of all audit and non-audit services provided by Ernst & Young LLP. On an ongoing basis, our general partner’s management presents specific projects and categories of service to the Audit Committee to request advance approval. The Audit Committee reviews those requests and advises management if the Audit Committee approves the engagement of Ernst & Young LLP. On a quarterly basis, the management of our general partner reports to the Audit Committee regarding the services rendered by, including the fees of, the independent accountant in the previous quarter and on a cumulative basis for the fiscal year. The Audit Committee may also delegate the ability to pre-approve audit and permitted non-audit services, excluding services related to our internal control over financial reporting, to any two committee members, provided that any such pre-approvals are reported at a subsequent Audit Committee meeting. In 2011 and 2010, 100 percent of Ernst & Young LLP’s fees were pre-approved by the Audit Committee.

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

	Page
Covered by reports of independent auditors:
Consolidated balance sheets at December 31, 2011 and 2010		78
Consolidated statements of income for each of the three years ended December 31, 2011		77
Consolidated statement of changes in equity for each of the three years ended December 31, 2011		79
Consolidated statements of cash flows for each of the three years ended December 31, 2011		80
Notes to consolidated financial statements		81
Not covered by reports of independent auditors:
Quarterly financial data (unaudited)		112

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

(a) 3 and (b). The following documents are included as exhibits to this report:

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Exhibit Number		Description
§Exhibit 2.1	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
Exhibit 3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
Exhibit 3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6 and 7 (filed on February 24, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. (File No. 001-32599)) and incorporated herein by reference.
Exhibit 3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.1	—	Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
Exhibit 4.2	—	Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
Exhibit 4.3	—	Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.4	—	Form of 7 1/4% Senior Note due 2017 (filed on December 19, 2006 as Exhibit 1 to Rule 144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.5	—	Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

135

Exhibit Number		Description
Exhibit 4.6	—	Registration Rights Agreement, dated as of February 9, 2010, among Williams Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., each acting on behalf of themselves and the initial purchasers listed on Schedule I thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.7	—	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File. No. 001-07414)) and incorporated herein by reference.
Exhibit 4.8	—	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File No. 001-07414)) and incorporated herein by reference.
Exhibit 4.9	—	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K File No. 001-07414)) and incorporated herein by reference.
Exhibit 4.10	—	Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-3 (File No. 333-02155)) and incorporated herein by reference.
Exhibit 4.11	—	Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee with regard to Northwest Pipeline’s 7.125% debentures due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form S-3 (File No. 033-62639)) and incorporated herein by reference.
Exhibit 4.12	—	Indenture, dated as of August 27, 2001, between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-4 (File No. 333-72982)) and incorporated herein by reference.
Exhibit 4.13	—	Indenture, dated as of July 3, 2002, between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.’s Form 10-Q (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.14	—	Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.

136

Exhibit Number		Description
Exhibit 4.15	—	Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.16	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.17	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.18	—	Form of 4.125% Senior Notes due 2020 (filed November 12, 2010 as Exhibit A of Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.19		Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.20		Registration Rights Agreement, dated August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC, BNP Paribas Securities Corp., RBC Capital markets, LLC, and RBS Securities Inc., each acting on behalf of themselves and the initial purchasers listed on Schedule I thereto (filed on August 12, 2011 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.21	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.22		Form of 4.00% Senior Notes due 2021 (filed November 18, 2011 as Exhibit A of Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.1	—	Omnibus Agreement, among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (filed on August 26, 2005 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

137

Exhibit Number		Description
Exhibit 10.2	—	Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (filed on April 20, 2009 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.3	—	Omnibus Agreement, dated as of February 17, 2010, by and between The Williams Companies, Inc. and Williams Partners L.P. (filed on February 22, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.4	—	Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating LLC (filed on February 22, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.5	—	Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.6	—	Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.7	—	Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.8	—	Director Compensation Policy dated November 29, 2005, as revised November 30, 2010 (filed on February 24, 2011 as Exhibit 10.8 to Williams Partners L.P.’s annual report on Form 10-K (File No. (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.9	—	Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917)) and incorporated herein by reference.
Exhibit 10.10	—	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

138

Exhibit Number		Description
Exhibit 10.11	—	Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on August 4, 2011 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File no. 001-32599)) and incorporated herein by reference.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges
*Exhibit 21	—	List of subsidiaries of Williams Partners L.P.
*Exhibit 23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
*Exhibit 23.2	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
*Exhibit 24	—	Power of attorney.
*Exhibit 31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*Exhibit 31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**Exhibit 32	—	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*101.INS	—	XBRL Instance Document
*101.SCH	—	XBRL Taxonomy Extension Schema
*101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	—	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	—	XBRL Taxonomy Extension Label Linkbase
*101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith.

** Furnished herewith.

§ Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

# Management contract or compensatory plan or arrangement.

139

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

WILLIAMS PARTNERS L.P.

(Registrant)

By: Williams Partners GP LLC, its general partner

/s/ Ted T. Timmermans

Ted T. Timmermans

Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal

Accounting Officer)

February 27, 2012

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

Signature	Title	Date
/s/ ALAN S. ARMSTRONG	Chief Executive Officer and	February 27, 2012
Alan S. Armstrong	Chairman of the Board (Principal Executive Officer)
/s/ DONALD R. CHAPPEL	Chief Financial Officer and Director	February 27, 2012
Donald R. Chappel	(Principal Financial Officer)
/s/ TED T. TIMMERMANS	Vice President, Controller, and Chief Accounting Officer	February 27, 2012
Ted T. Timmermans	(Principal Accounting Officer)
/s/ H. BRENT AUSTIN*	Director	February 27, 2012
H. Brent Austin
/s/ RORY L. MILLER*	Director	February 27, 2012
Rory L. Miller
/s/ ALICE M. PETERSON*	Director	February 27, 2012
Alice M. Peterson
/s/ H. MICHAEL KRIMBILL*	Director	February 27, 2012
H. Michael Krimbill

Signature		Title	Date
	/s/ RANDALL L. BARNARD*	Director	February 27, 2012
	Randall L. Barnard
	/s/ LAURA A. SUGG *	Director	February 27, 2012
	Laura A. Sugg
*By:	/s/ WILLIAM H. GAULT		February 27, 2012
	William H. Gault
	Attorney-in-fact

EXHIBIT INDEX

Exhibit Number		Description
§Exhibit 2.1	—	Contribution Agreement, dated as of January 15, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P., Williams Partners Operating LLC and, for a limited purpose, The Williams Companies, Inc, including exhibits thereto (filed on January 19, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 3.1	—	Certificate of Limited Partnership of Williams Partners L.P. (filed on May 2, 2005 as Exhibit 3.1 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
Exhibit 3.2	—	Certificate of Formation of Williams Partners GP LLC (filed on May 2, 2005 as Exhibit 3.3 to Williams Partners L.P.’s registration statement on Form S-1 (File No. 333-124517)) and incorporated herein by reference.
Exhibit 3.3	—	Amended and Restated Agreement of Limited Partnership of Williams Partners L.P. (including form of common unit certificate), as amended by Amendments Nos. 1, 2, 3, 4, 5, 6 and 7 (filed on February 24, 2011 as Exhibit 3.3 to Williams Partners L.P.’s annual report on Form 10-K (File No. (File No. 001-32599)) and incorporated herein by reference.
Exhibit 3.4	—	Amended and Restated Limited Liability Company Agreement of Williams Partners GP LLC (filed on August 26, 2005 as Exhibit 3.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.1	—	Certificate of Incorporation of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.5 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
Exhibit 4.2	—	Bylaws of Williams Partners Finance Corporation (filed on September 22, 2006 as Exhibit 4.6 to Williams Partners L.P.’s registration statement on Form S-3 (File No. 333-137562)) and incorporated herein by reference.
Exhibit 4.3	—	Indenture, dated December 13, 2006, by and among Williams Partners L.P., Williams Partners Finance Corporation and The Bank of New York (filed on December 19, 2006 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.4	—	Form of 7 1/4% Senior Note due 2017 (filed on December 19, 2006 as Exhibit 1 to Rule 144A/Regulation S Appendix of Exhibit 4.1 attached to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.5	—	Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit Number		Description
Exhibit 4.6	—	Registration Rights Agreement, dated as of February 9, 2010, among Williams Partners L.P. and Barclays Capital Inc. and Citigroup Global Markets Inc., each acting on behalf of themselves and the initial purchasers listed on Schedule I thereto (filed on February 10, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.7	—	Indenture, dated as of June 22, 2006, between Northwest Pipeline Corporation and JPMorgan Chase Bank, N.A., as Trustee, with regard to Northwest Pipeline’s $175 million aggregate principal amount of 7.00% Senior Notes due 2016 (filed on June 23, 2006 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File. No. 001-07414)) and incorporated herein by reference.
Exhibit 4.8	—	Indenture, dated as of April 5, 2007, between Northwest Pipeline Corporation and The Bank of New York (filed on April 5, 2007 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form 8-K (File No. 001-07414)) and incorporated herein by reference.
Exhibit 4.9	—	Indenture, dated May 22, 2008, between Northwest Pipeline GP and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Northwest Pipeline GP’s Form 8-K File No. 001-07414)) and incorporated herein by reference.
Exhibit 4.10	—	Senior Indenture, dated as of July 15, 1996 between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-3 (File No. 333-02155)) and incorporated herein by reference.
Exhibit 4.11	—	Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank Trustee with regard to Northwest Pipeline’s 7.125% debentures due 2025 (filed September 14, 1995 as Exhibit 4.1 to Northwest Pipeline Corporation’s Form S-3 (File No. 033-62639)) and incorporated herein by reference.
Exhibit 4.12	—	Indenture, dated as of August 27, 2001, between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on November 8, 2001 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form S-4 (File No. 333-72982)) and incorporated herein by reference.
Exhibit 4.13	—	Indenture, dated as of July 3, 2002, between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed August 14, 2002 as Exhibit 4.1 to The Williams Companies Inc.’s Form 10-Q (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.14	—	Indenture, dated as of April 11, 2006, between Transcontinental Gas Pipe Line Corporation and JPMorgan Chase Bank, N.A., as Trustee with regard to Transcontinental Gas Pipe Line’s $200 million aggregate principal amount of 6.4% Senior Note due 2016 (filed on April 11, 2006 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.

Exhibit Number		Description
Exhibit 4.15	—	Indenture, dated May 22, 2008, between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A., as Trustee (filed on May 23, 2008 as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.16	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.17	—	First Supplemental Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.18	—	Form of 4.125% Senior Notes due 2020 (filed November 12, 2010 as Exhibit A of Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.19		Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.20		Registration Rights Agreement, dated August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC, BNP Paribas Securities Corp., RBC Capital markets, LLC, and RBS Securities Inc., each acting on behalf of themselves and the initial purchasers listed on Schedule I thereto (filed on August 12, 2011 as Exhibit 10.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584)) and incorporated herein by reference.
Exhibit 4.21	—	Second Supplemental Indenture, dated as of November 17, 2011, between Williams Partners L.P. and The  Bank of New York Mellon Trust Company, N.A., as trustee (filed November 18, 2011 as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 4.22		Form of 4.00% Senior Notes due 2021 (filed November 18, 2011 as Exhibit A of Exhibit 4.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.1	—	Omnibus Agreement, among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (filed on August 26, 2005 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit Number		Description
Exhibit 10.2	—	Amendment No. 1 to Omnibus Agreement among Williams Partners L.P., Williams Energy Services, LLC, Williams Energy, L.L.C., Williams Partners Holdings LLC, Williams Discovery Pipeline LLC, Williams Partners GP LLC, Williams Partners Operating LLC and (for purposes of Articles V and VI thereof only) The Williams Companies, Inc. (filed on April 20, 2009 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.3	—	Omnibus Agreement, dated as of February 17, 2010, by and between The Williams Companies, Inc. and Williams Partners L.P. (filed on February 22, 2010 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.4	—	Conveyance, Contribution and Assumption Agreement, dated as of February 17, 2010, by and among Williams Energy Services, LLC, Williams Gas Pipeline Company, LLC, WGP Gulfstream Pipeline Company, L.L.C., Williams Partners GP LLC, Williams Partners L.P. and Williams Partners Operating LLC (filed on February 22, 2010 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.5	—	Williams Partners GP LLC Long-Term Incentive Plan (filed on August 26, 2005 as Exhibit 10.2 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.6	—	Amendment to the Williams Partners GP LLC Long-Term Incentive Plan, dated November 28, 2006 (filed on December 4, 2006 as Exhibit 10.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.
#Exhibit 10.7	—	Amendment No. 2 to the Williams Partners GP LLC Long-Term Incentive Plan, dated December 2, 2008 (filed on February 26, 2009, as Exhibit 10.4 to Williams Partners L.P.’s annual report on Form 10-K (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.8	—	Director Compensation Policy dated November 29, 2005, as revised November 30, 2010 (filed on February 24, 2011 as Exhibit 10.8 to Williams Partners L.P.’s annual report on Form 10-K (File No. (File No. 001-32599)) and incorporated herein by reference.
Exhibit 10.9	—	Administrative Services Agreement between Northwest Pipeline Services LLC and Northwest Pipeline GP, dated October 1, 2007 (filed on January 30, 2008 as Exhibit 10.1 to Williams Pipeline Partners L.P.’s Form 8-K (File No. 001-33917)) and incorporated herein by reference.
Exhibit 10.10	—	Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed on February 22, 2010 as Exhibit 10.3 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599)) and incorporated herein by reference.

Exhibit Number		Description
Exhibit 10.11	—	Credit Agreement, dated as of June 3, 2011, by and among Williams Partners L.P., Northwest Pipeline GP and Transcontinental Gas Pipe Line Company, LLC, as co-borrowers, the lenders named therein, and Citibank N.A., as Administrative Agent (filed on August 4, 2011 as Exhibit 10.1 to Williams Partners L.P.’s quarterly report on Form 10-Q (File no. 001-32599)) and incorporated herein by reference.
*Exhibit 12	—	Computation of Ratio of Earnings to Fixed Charges
*Exhibit 21	—	List of subsidiaries of Williams Partners L.P.
*Exhibit 23.1	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
*Exhibit 23.2	—	Consent of Independent Registered Public Accounting Firm, Deloitte & Touche LLP.
*Exhibit 24	—	Power of attorney.
*Exhibit 31.1	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
*Exhibit 31.2	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
**Exhibit 32	—	Section 1350 Certifications of Chief Executive Officer and Chief Financial Officer.
*101.INS	—	XBRL Instance Document
*101.SCH	—	XBRL Taxonomy Extension Schema
*101.CAL	—	XBRL Taxonomy Extension Calculation Linkbase
*101.DEF	—	XBRL Taxonomy Extension Definition Linkbase
*101.LAB	—	XBRL Taxonomy Extension Label Linkbase
*101.PRE	—	XBRL Taxonomy Extension Presentation Linkbase

* Filed herewith.

** Furnished herewith.

§ Pursuant to item 601(b) (2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

# Management contract or compensatory plan or arrangement.