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, 2012
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. ¨

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 ¨	Smaller reporting company ¨
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    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 $5,812,902,304.

The registrant had 397,963,199 common units outstanding as of February 26, 2013.

DOCUMENTS INCORPORATED BY REFERENCE

None

WILLIAMS PARTNERS L.P.

FORM 10-K

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business		4
	Website Access to Reports and Other Information		4
	General		4
	Organizational Restructuring		5
	Financial Information About Segments		5
	Business Segments		6
	Gas Pipeline		6
	Midstream Gas & Liquids		9
	Regulatory Matters		17
	Environmental Matters		18
	Competition		19
	Employees		19
	Financial Information about Geographic Areas		20
Item 1A.	Risk Factors		21
Item 1B.	Unresolved Staff Comments		46
Item 2.	Properties		46
Item 3.	Legal Proceedings		46
Item 4.	Mine Safety Disclosures		47
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		48
Item 6.	Selected Financial Data		50
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		51
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		79
Item 8.	Financial Statements and Supplementary Data		81
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		126
Item 9A.	Controls and Procedures		126
Item 9B.	Other Information		126
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		127
Item 11.	Executive Compensation		135
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		139
Item 13.	Certain Relationships and Related Transactions, and Director Independence		142
Item 14.	Principal Accountant Fees and Services		147
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		148

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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 bcf 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.

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 and which we account for as equity investments, including principally Discovery Producer Services LLC, Gulfstream Natural Gas System, L.L.C., Laurel Mountain Midstream, LLC, Aux Sable Liquid Products L.P., Caiman Energy II, LLC, and Overland Pass Pipeline Company LLC.

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

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PART I

Item 1. Business

Unless the context clearly indicates otherwise, references in this report to “we,” “our,” “us” or like terms refer to Williams 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). These reports include, among other disclosures, information on any transactions we may engage in with our general partner and its affiliates and on fees and other amounts paid or accrued to our general partner and its affiliates. 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; olefins production; and oil transportation. Williams owns an approximate 68 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.

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ORGANIZATIONAL RESTRUCTURING

Following Williams’ spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of our growth plans, Williams initiated an organizational restructuring evaluation to better align resources to support an ongoing business strategy to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. As a result of this review, management implemented a new structure, effective January 1, 2013, that generally organizes our businesses into geographically based operational areas. These operating areas, including the comprised components, are presented below in comparison to our current reportable segment presentation:

Beginning with the reporting of first-quarter 2013 results, we will change our segment reporting structure to align with the new operating areas resulting from the organizational restructuring, as this will be consistent with the manner in which our Chief Operating Decision Maker will evaluate performance and make resource allocation decisions. Our reportable segments will be Northeast G&P, Atlantic-Gulf, West, and NGL & Petchem Services, as reflected above.

Information in this report has generally been prepared consistent with the manner in which we have prepared our consolidated financial statements and presented such information to our Chief Operating Decision Maker as of December 31, 2012 and for the periods then ended which is consistent with the reportable segment presentation in our consolidated financial statements in Part II, Item 8 of this document, which reflects our segment reporting structure prior to the 2013 restructuring. These segments are discussed in further detail in the following sections.

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 olefins production 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 3,400 TBtu of natural gas and peak-day delivery capacity of approximately 14 MMdth of natural gas. Gas Pipeline consists primarily of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline). We hold interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System, LLC (Gulfstream) and a 51 percent interest in Constitution Pipeline Company, LLC (Constitution).

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, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 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, 2012, Transco’s system had a mainline delivery capacity of approximately 5.8 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 9.8 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, 2012, our customers had stored in our facilities approximately 150 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 2012 or are future significant pipeline projects for which Transco has customer commitments.

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. The capital cost of the project is estimated to be approximately $200 million. Transco placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. Transco plans to place the second phase into service in June 2013, which is expected to increase capacity by an additional 130 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. The capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d.

Northeast Supply Link

In November 2012, Transco received approval from 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 $390 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

In January 2013, Transco filed an application with the FERC for the construction of a three-mile offshore lateral to a distribution system in New York. The capital cost of the project is estimated to be approximately $180 million. Transco plans to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d.

Virginia Southside

In December 2012, Transco filed an application with the FERC to expand Transco’s existing natural gas transmission system from the Zone 6 Station 210 Pooling Point in New Jersey to Dominion Virginia Power’s proposed power station in Brunswick County, Virginia, and our Cascade Creek interconnect with East Tennessee Natural Gas and our Pleasant Hill delivery point to Piedmont Natural Gas Company, Inc. in North Carolina. The capital cost of the project is estimated to be approximately $300 million. Transco plans to place the project into service in September 2015, and is expected to increase capacity by 270 Mdth/d.

Leidy Southeast

The Leidy Southeast Project involves an expansion of Transco’s existing natural gas transmission system from the Marcellus Shale production region in Pennsylvania to a pooling point in Alabama. Transco anticipates filing an application with the FERC in the fourth quarter of 2013. The capital cost of the project is estimated to be approximately $600 million. Transco plans to place the project into service in December 2015, and it is expected to increase capacity by 469 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 Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California and Arizona directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2012, Northwest Pipeline’s system, having long-term firm transportation agreements including peaking service of approximately 3.9 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 472,000 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 14.2 MMdth of natural gas, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to certain customers.

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 80 Mdth/d and 74 Mdth/d, respectively. Northwest Pipeline estimates the expansion of the two laterals to cost between $32 million and $36 million. We placed North Seattle into service in November 2012. 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 50 percent interest in Gulfstream. Spectra Energy Corporation, through its subsidiary, and Spectra Energy Partners, LP, own the other 50 percent interest. We share operating responsibilities for Gulfstream with Spectra Energy Corporation and accounts for this using the equity method as described in Note 1 of our Notes to Consolidated Financial Statements.

Constitution Pipeline

In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. We plan to place the project into service in March 2015, with an expected capacity of 650 thousand dekatherms per day (Mdth/d). The pipeline is fully subscribed with two shippers. We expect to file a FERC application during the second quarter of 2013.

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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, Louisiana, Pennsylvania, West Virginia, New York, and Ohio. The primary businesses are: (1) natural gas gathering, treating, and processing; (2) NGL fractionation, storage, and transportation; (3) oil transportation; and (4) olefins production. 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;

• Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

• Prices impacting our commodity-based activities.

Expansion Projects

The midstream projects listed below were completed during 2012 or are future significant projects.

Northeast

Ohio Valley

In April 2012, we completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquisition provides us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320 MMcf/d of cryogenic processing capacity currently available. The Moundsville fractionator is now in service with approximately 13 Mbbls/d of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.

We also have expansions currently under construction to our natural gas gathering system, processing facilities and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility which is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d.

Caiman II

In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, through our 47.5 percent ownership, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

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Susquehanna Supply Hub

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). The gathering system is comprised of 33 miles of 16-inch natural gas pipeline and associated gathering facilities in Susquehanna County, in northeastern 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.

Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 Bcf/d of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.

Laurel Mountain Midstream

In addition, we plan expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region.

Atlantic-Gulf

Gulfstar FPS™ Deepwater Project

We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach 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. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.

Keathley Canyon Connector™

Our equity investee which we operate, Discovery Producer Services LLC (Discovery), plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area 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 the Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural 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. Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014.

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West

Parachute

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

NGL & Petchem Services

Overland Pass Pipeline

Through our equity investment in Overland Pass Pipeline Company LLC, we are participating 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.

Geismar

With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facility’s annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility to over 88 percent.

In the fourth quarter of 2012, we also completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discovery’s Paradis fractionator.

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, isobutane 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. Beginning in 2013, a portion of our fee-based processing revenues will include a share of the margins on the NGLs produced. For the year ended December 31, 2012, 63 percent of the NGL production volumes were under fee-based contracts.

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• 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 price exposure on the difference between NGL and natural gas prices. For the year ended December 31, 2012, 34 percent of the NGL production volumes were under keep-whole contracts.

• 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, 2012, 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 new 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 2012, our facilities gathered and processed gas for approximately 220 customers. Our top six gathering and processing customers accounted for approximately 54 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 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, Pennsylvania, and West Virginia. 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.

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The following table summarizes our significant operated natural gas gathering assets as of December 31, 2012:

	Natural Gas Gathering Assets
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins
West
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	(2)	Piceance
Northeast
Ohio Valley	West Virginia	101	0.8	100%	Appalachian
Pennsylvania & New York	Pennsylvania & New York	191	1.7	100%	Appalachian
Laurel Mountain (1)	Pennsylvania	2,013	0.6	51%	Appalachian
Atlantic-Gulf
Canyon Chief & Blind Faith	Deepwater Gulf of Mexico	139	0.5	100%	Eastern Gulf of Mexico
Seahawk	Deepwater Gulf of Mexico	115	0.4	100%	Western Gulf of Mexico
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	358	0.6	60%	Central Gulf of Mexico

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

(2) We own 60 percent of a gathering system in the Ryan Gulch area, which we operate, with 140 miles of pipeline and 200 MMcf/d of inlet capacity. We own and operate 100 percent of the balance of the Piceance gathering system.

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.

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The following table summarizes our significant operated natural gas processing facilities as of December 31, 2012:

	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
West
Opal	Opal, WY	1.5	70	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
Willow Creek	Rio Blanco County, CO	0.5	30	100%	Piceance
Parachute	Garfield County, CO	1.4	7	(2)	Piceance
Northeast
Fort Beeler	Marshall County, WV	0.3	37	100%	Appalachian
Atlantic-Gulf
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 jointly owned investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

(2) We own 60 percent of the Sagebrush plant, which we operate, with an inlet capacity of 35 MMcf/d and NGL handling capacity of less than 1 Mbbls/d. We own and operate 100 percent of the balance of the Parachute plant complex.

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 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, 2012:

	Crude Oil Pipelines
	Pipeline Miles	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

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The following table summarizes our production handling platforms as of December 31, 2012:

	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 jointly owned investments that we operate; however, our financial statements report equity method income from these investments based on our equity ownership percentage.

NGL & Petchem Services

Gulf Olefins

In November 2012, we purchased Williams’ 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage caverns.

Our olefins production facility has a total production capacity of 1.35 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstocks for the cracker are ethane and propane; as a result, these assets are primarily exposed to the price spread between ethane and propane, and ethylene and propylene, respectively. Ethane and propane are available for purchase from third parties and from affiliates. We own ethane and propane pipeline systems in Louisiana that provide feedstock transportation to the Geismar plant and other third-party crackers. In the fourth quarter of 2012, we placed a pipeline in service that has the capacity to supply 12 Mbbls/d of ethane from Discovery’s Paradis fractionator to the Geismar plant.

Our refinery grade propylene splitter has a production capacity of approximately 500 million pounds per year of propylene. At our propylene splitter, we purchase refinery grade propylene and fractionate it into polymer grade propylene and propane; as a result this asset is exposed to the price spread between those commodities.

As a merchant producer of ethylene and propylene, our product sales are to customers for use in making plastics and other downstream petrochemical products destined for both domestic and export markets.

Marketing services

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. 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 14 percent, 17 percent, and 15 percent of our consolidated revenues in 2012, 2011, and 2010, respectively.

In certain situations to facilitate our gas gathering and processing activities, we buy natural gas from our producer customers for resale.

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We also market olefin products to a wide range of users in the energy and petrochemical industries. In order to meet sales contract obligations, we may purchase olefin products for resale.

Other NGL & Petchem 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.

We own approximately 178 miles of pipelines in the Houston Ship Channel area which transport a variety of products including ethane, propane, ammonia, tertiary butyl alcohol and other industrial products used in the petrochemical industry. We also own a tunnel crossing pipeline under the Houston Ship Channel which contains multiple pipelines which are leased to third parties.

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 approximately 2,000 miles of pipeline with a capacity of approximately 630 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.

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 near Conway, Kansas, along with 150—and 125-mile extensions into the Piceance and Denver-Julesberg 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 are constructing 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.

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Operating Statistics

The following table summarizes our significant operating statistics for Midstream:

	2012		2011		2010
Volumes: (1)
Gathering (Tbtu)		1,616		1,377		1,262
Plant inlet natural gas (Tbtu)		1,638		1,592		1,599
NGL production (Mbbls/d) (2)		206		189		178
NGL equity sales (Mbbls/d) (2)		77		77		80
Crude oil transportation (Mbbls/d) (2)		126		105		94
Geismar ethylene sales (millions of pounds)		1,058		1,038		981

(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.

REGULATORY MATTERS

Gas Pipeline and Midstream Gathering

FERC

Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, 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. 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.

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. 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.

We also own interests in and operate 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. In addition, Williams Partners 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.

Pipeline Safety

Our gas pipeline and midstream pipelines are 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 Jobs Creation Act of 2011 (Pipeline Safety Act), which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. The U.S. Department of Transportation (USDOT) administers federal pipeline safety laws.

Federal pipeline safety laws authorize USDOT to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. USDOT has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, USDOT performs pipeline safety inspections and has the authority to initiate enforcement actions.

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Federal pipeline safety regulations contain an exemption that applies to gathering lines in certain rural locations. A substantial portion of our gathering lines qualify for that exemption and are currently not regulated under federal law. However, USDOT is completing a congressionally-mandated review of the adequacy of the existing federal and state regulations for gathering lines and has indicated that it may apply additional safety standards to rural gas gathering lines in the future.

States are preempted by federal law from regulating pipeline safety for interstate pipelines but most are certified by USDOT to assume responsibility for enforcing intrastate pipeline safety regulations and inspecting intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, they vary considerably in their authority and capacity to address pipeline safety. Our pipelines are designed, operated, and maintained to keep the facilities in compliance with state pipeline safety requirements.

On January 3, 2012, the Pipeline Safety Act was enacted. The Pipeline Safety Act requires USDOT to complete a number of reports in preparation for potential rulemakings. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. USDOT is considering these and other provisions in the Pipeline Safety Act and has sought public comment on changes to the standards in its pipeline safety regulations.

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 completed assessment within required timeframe, with one exception which was reported to PHMSA. We estimate that the cost to complete the remediation associated with the 2012 assessments will be approximately $20 million, most of which we expect to be 2013 capital expenditures. 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 Transco’s and Northwest Pipeline’s rates.

State Gathering Regulation

Our onshore midstream gathering operations are subject to regulation by states in which we operate. Of the states where our midstream business 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.

OCSLA

Our offshore midstream gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). 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.”

Olefins

Our olefins assets are regulated by the Louisiana Department of Environmental Quality, the Texas Railroad Commission, and various other state and federal entities regarding our liquids pipelines.

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

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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 the regulation of greenhouse gas emissions. – 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 and – Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volumes of natural gas and other products that we transport, gather, process and treat” and “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.

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. 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.

Ethylene and propylene markets, and therefore our olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we expect to benefit from the lower cost position in North America versus other crude based feedstocks worldwide. The majority of North American olefins producers have significant downstream petrochemical manufacturing for plastics and other products. As such, they buy or sell ethylene and propylene as required. We operate as a merchant seller of olefins with no downstream manufacturing, and therefore can be either a supplier or a competitor at any given time to these other companies. Accordingly, we believe that we are often not considered by such companies to be a direct competitor. We compete on the basis on service, price and availability of the products we produce.

For additional information regarding competition for our services or otherwise affecting our business, please refer to “Risk Factors – 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 natural gas,” “–Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results, “and “– We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, if at all, which could affect our financial condition, the amount of cash available to pay distribution, and our ability to grow.”

EMPLOYEES

We do not have any employees. We are managed and operated by the directors and officers of our general partner. At February 1, 2013, our general partner or its affiliates employed approximately 3,658 full-time employees. 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.”

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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,” “assumes,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “guidance,” “outlook,” “in service date,” 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; and

• Natural gas, natural gas liquids and olefins 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 pay current and expected levels of cash distributions, if any 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);

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• The strength and financial resources of our competitors;

• 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 environmental regulations), 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 risk 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;

• The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

• Risks associated with future weather conditions;

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

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

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

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

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

RISK FACTORS

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

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Prices for NGLs, olefins, natural gas, oil and other commodities, are volatile and this volatility could adversely affect our financial results, cash flows, access to capital and ability to maintain our 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, olefins, 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, olefins, natural gas, oil 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, olefins, 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 or feedstock;

• 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; and

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

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 natural gas.

The development of the additional natural gas reserves that are essential for our natural 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 in which we have a limited or no

presence, 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 systems 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.

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 businesses or expand our existing facilities or businesses to capture anticipated future growth in natural gas production that does not ultimately materialize. As a result, our new or expanded facilities or businesses 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 growth activities, unitholders’ ownership interest in us may 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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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 lose all or part of our investment value or be required to contribute additional capital to support businesses or properties acquired;

• 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 operational, technical or financial problems; and

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

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

Our growth may be dependent upon the construction of new 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; and

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

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

We do not own all of the interests in the 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

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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, 2012, our investments in the Partially Owned Entities accounted for approximately 9 percent of our total consolidated assets. We expect that conflicts of interest may arise in the future between us, on the one hand, and our Partially Owned Entities, on the other hand, with regard to our Partially Owned Entities’ governance, business, and operations. If a conflict of interest arises between us and a partially owned entity, other owners may control the Partially Owned Entity’s actions with respect to such matter (subject to certain limitations), which could be detrimental to our business. 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, financial condition, results of operations, and ability to make cash distributions to unitholders.

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

We may not have sufficient available cash from operating surplus each quarter to make cash distributions or maintain current or expected 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 amount of cash that our subsidiaries and the Partially Owned Entities distribute to us;

• The amount of cash we generate from our operations, which is subject to prices we obtain for our services, the prices of natural gas, NGLs and olefins, and the volumes of gas we process and NGLs and olefins we fractionate and store, and our operating costs;

• The level of capital expenditures we make;

• The restrictions contained in our indentures and credit facility and our debt service requirements;

• The cost of acquisitions, if any;

• Fluctuations in our working capital needs; and

• Our ability to borrow.

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.

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

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.

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We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, if at all, which could affect our financial condition, the amount of cash available to pay distributions, and our ability to grow.

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts or add additional customers, each on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend, or add additional significant customer or supplier contracts on favorable terms is subject to a number of factors, some of which are beyond our control, including, but not limited to:

• The level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils, or nuclear energy.

• Natural gas, NGL, and olefins prices, demand, availability and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems.

• General economic, financial markets and industry conditions.

• The effects of regulation on us, our customers and contracting practices.

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, the fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling, 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;

• Truck and rail loading and unloading;

• Operating in a marine environment; and

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

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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 be 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, but 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), and we are an insured of OIL, an energy industry mutual insurance company, which provides coverage for damage to our property. As an insured of OIL, we are allocated a portion of shared losses and premiums in proportion to our assets. As an insured member of OIL, Williams shares in the losses among other OIL members even if its property is not damaged, and as a result, we may share in any such 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, results of operations, financial condition, cash flows and our ability to repay our debt and make cash distributions to unitholders.

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

Our assets and operations, especially those located offshore, can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. A significant disruption in operations or a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Acts of terrorism could have a material adverse effect on our business, 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 business, financial condition, results of operations, and cash flows and on our ability to make cash distributions to unitholders.

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 unauthorized gain access to information related to our assets by targeting acts of deception against individuals with authorized access to physical locations or information.

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.

We could be subject to penalties and fines if we fail to comply with laws governing our businesses.

Our businesses are regulated by numerous governmental agencies including, but not limited to, the FERC, the EPA and the PHMSA. Should we fail to comply with applicable statutes, rules, regulations and orders, our businesses 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 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, the PHMSA has civil penalty authority up to $200,000 per day, with a maximum of $2 million for any related series of violations. Any material penalties or fines under these or other statutes, rules, regulations or orders could have a material adverse impact on our business, financial condition, results of operations and cash flows, and on our ability to make cash distributions to unitholders.

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The natural gas sales, transportation and storage operations of our gas pipelines are subject to regulation by the 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 natural gas sales, transmission and storage operations of the gas pipelines 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 gas pipelines 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.

Under the NGA, the 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 the FERC. In addition, the 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.

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

We are subject to risks associated with climate change and the regulation of greenhouse gas emissions.

Climate change and the costs that may be associated with its impacts and with the regulation of emissions of greenhouse gases (“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. In 2009, the U.S. Environmental Protection Agency (“EPA”) issued a final determination that six GHG emissions are a threat to public safety and welfare and, in 2011, the EPA implemented permitting for new and/or modified large sources of GHG emissions. Increased public awareness and concern over climate change may result in additional state, regional and/or federal requirements to reduce or mitigate GHG emissions. The U.S. Congress and certain states have for some time been considering various forms of legislation related to GHG

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emissions and additional regulation of GHG emissions in our industry may be implemented under existing Clean Air Act programs, including the New Source Performance Standards program. There have also been international efforts seeking legally binding reductions in emissions of GHGs.

Regulatory actions by the EPA or the passage of new 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 and services by making our products and services 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 that 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, fractionation, transportation and storage of NGLs, processing of olefins, and crude oil transportation and production handling, and as a result, we may be required to make substantial expenditures that could exceed current expectations. Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment and the security of chemical and industrial facilities.

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, the issuance of injunctions limiting or preventing some or all of our operations and delays in granting permits.

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, 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, 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. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

Our business may be adversely affected by changed regulations and increased costs due to stricter pollution control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. 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 these 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.

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.

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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.

Increased regulation of energy extraction activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new oil and natural gas wells, which could decrease the volumes of natural gas and other products that we transport, gather, process and treat.

Hydraulic fracturing, a practice involving the injection of water, sand and chemicals under pressure into tight geologic formations to stimulate oil and natural gas production, is currently 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 and there have been recent initiatives at the federal, state and local levels to regulate or otherwise restrict the use of hydraulic fracturing. Several states have adopted regulations that impose permitting, disclosure and well-completion requirements on hydraulic fracturing operations. The EPA has also announced regulatory and enforcement initiatives related to hydraulic fracturing and other natural gas extraction and production activities. 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 new regulations are imposed related to oil and gas extraction, or if additional levels of reporting, regulation or permitting moratoria are 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.

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.

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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 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 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, ability to pay interest on our indebtedness and ability to make cash distributions to unitholders. For example, various legislative and regulatory reforms associated with pipeline safety and integrity have been proposed or enacted, 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 gas pipelines 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 and impact our operations. In addition, the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.

Certain of our gas pipeline 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.

Our gas pipelines 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 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.

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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.

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 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. In addition, financial markets have recently been affected by concerns over U.S. fiscal policy, including uncertainty regarding federal spending and tax policy, as well as the U.S. federal government’s debt ceiling and the federal deficit. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manners described above.

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.

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.

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, olefins, oil, and other commodities;

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

• 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. This analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as

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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.

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.

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, 2012, was $8.4 billion.

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default and our and our material subsidiaries’ ability to enter into certain affiliate transactions and certain restrictive agreements and to change the nature of our business. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Williams’ debt agreements contain similar covenants with respect to Williams and its subsidiaries, including us.

Our debt service obligations and the covenants described above could have important consequences. For example, they could:

• Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

• 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, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us;

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

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Our ability to comply with our debt covenants, 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 and may differ materially from our current assumptions. 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 comply with these covenants, meet our debt service obligations or obtain future credit on favorable terms, or 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.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. 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”.

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 existing indebtedness.

Our ability to obtain credit in the future will be affected by Williams’ credit ratings.

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.

Institutional knowledge residing with current employees nearing retirement eligibility or with former Williams employees 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 are no longer available to Williams, Williams may not be able to replace them with employees of comparable knowledge and experience. In addition, Williams may not be able to retain or recruit other qualified individuals, and 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.

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, olefins, 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 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

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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.

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 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 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; and

• 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 (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 transacted on exchanges for which cash collateral will be required. These new rules and regulations could increase the cost 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 to a large

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extent be exempt from the requirement to trade these transactions on exchanges and to clear those transactions through a central clearing house or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations that are continuing to be adopted by the Commodities Futures Trading Commission.

A number of our financial derivative transactions used for hedging purposes are currently executed on exchanges and cleared through clearing houses that already require the posting of margins based on initial and variation requirements. Final rules promulgated under the Dodd-Frank Act may require us to post additional cash or new margin to the clearing house or to our counterparties in connection with our hedging transactions. Posting 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.

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 the FERC could enact new accounting standards or the FERC could issue rules that might impact how we are required to record revenues, expenses, assets, liabilities and equity. 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.

Failure of our service providers or disruptions to 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. Certain of Williams’ accounting and information technology functions that we rely on are currently provided by third party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these agreements could be disrupted. Similarly, the expiration of such agreements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. 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.

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;

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• 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 68 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;

• 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.

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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;

• 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.

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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.

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. As of December 31, 2012, our general partner and its affiliates own approximately 69 percent of our outstanding common units and, as a result, our public unitholders cannot remove our general partner without its consent.

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

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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.

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.

The existence and eventual sale of common units held by Williams or issued in our acquisitions and eligible for future sale may adversely affect the price of our common units.

Williams holds 276,472,244 common units, representing an approximate 68 percent limited partnership interest in us. Williams may, from time to time, sell all or a portion of its common units. We have also issued additional common units in connection with our 2012 acquisitions. For example, we issued 42,778,812 common units to Williams in connection with our acquisition of Williams’ 83.3 percent undivided interest and operatorship of the olefins production facility located in Geismar, Louisiana, along with a refinery-grade propylene splitter and pipelines in the Gulf region (Geismar Acquisition) and 11,779,296 common units to Caiman Energy, LLC in connection with the Caiman Acquisition (which units are subject to restrictions on transfer without our consent for a period of 18 months). We may also issue additional common units to other unaffiliated third parties in connection with future acquisitions. Sales of substantial amounts of common units by Williams or third parties, 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.

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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.

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 rights 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 (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 with respect to our treatment as a partnership for U.S. federal income tax purposes.

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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.

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. For example, from time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that affect certain publicly traded partnerships. 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, 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 United States Department of the Treasury (Treasury) regulations, and although the Treasury issued proposed 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. 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.

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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.

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.

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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 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, our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and our 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.

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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.

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 $275,000, which was paid in November 2012.

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 January 15, 2013, there were 397,963,199 common units outstanding, held by approximately 88,248 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.

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)
2012
Fourth Quarter	$	55.48	$	45.01	$	0.8275
Third Quarter		55.90		50.50		0.8075
Second Quarter		58.26		48.28		0.7925
First Quarter		65.39		55.02		0.7775
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

(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 $413 million and $302 million for the 2012 and 2011 periods, respectively.

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 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.

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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;

• 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;

• 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. In addition, our general partner agreed to temporarily waive a portion of incentive distributions in connection with the Caiman and Geismar Acquisitions. 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, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, 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. Certain amounts have been recast as a result of the Geismar Acquisition. (See Note 1 of Notes to Consolidated Financial Statements.)

	2012		2011		2010		2009		2008
	(Millions, except per-unit amounts)
Revenues	$	7,320	$	7,714	$	6,459	$	5,149	$	6,703
Net income		1,232		1,511		1,188		1,063		2,103
Net income attributable to controlling interests		1,232		1,511		1,172		1,036		2,078
Net income per common unit (1)		1.89		3.69		2.66		2.88		3.08
Total assets at December 31 (1)		19,709		14,672		13,666		12,732		12,437
Short-term notes payable and long-term debt due within one year at December 31		-		324		458		15		-
Long-term debt at December 31 (1)(2)		8,437		6,913		6,365		2,981		2,971
Total equity at December 31 (1)		8,897		5,433		5,248		8,287		8,096
Cash distributions declared per unit		3.140		2.900		2.653		2.540		2.435

(1) The change in 2012 reflects assets acquired, as well as debt and equity issuances related to the Caiman and Laser Acquisitions.

(2) 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 (NGLs). 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 interstate natural gas pipelines. Gas Pipeline also holds interests in interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System L.L.C. (Gulfstream) and a 51 percent interest in Constitution Pipeline Company, LLC (Constitution).

• Midstream is comprised primarily of significant, large-scale operations in the Rocky Mountain and Gulf Coast regions, operations in the Marcellus Shale region, and various equity investments in domestic natural gas gathering and processing assets and NGL fractionation and transportation assets. Midstream’s assets also include substantial operations and investments in the Four Corners region, the Piceance basin, an NGL fractionator and storage facilities near Conway, Kansas as well as an interest and operatorship of an olefins production facility in Geismar, Louisiana along with a refinery grade propylene splitter and pipelines in the Gulf Coast region. Midstream’s interest and operatorship of the olefins production facility in Geismar, Louisiana and associated assets is a result of a fourth-quarter 2012 acquisition from a subsidiary of The Williams Companies, Inc. (Williams).

Williams currently holds an approximate 70 percent interest in us, comprised of an approximate 68 percent limited partner interest and all of our 2 percent general partner interest.

Acquisitions

In February 2012, we completed the acquisition of 100 percent of the ownership interests in certain entities from Delphi Midstream Partners, LLC (Laser Acquisition). 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.)

In April 2012, we completed the acquisition of 100 percent of the ownership interest in Caiman Eastern Midstream, LLC (Caiman Acquisition). The acquired entity operates a gathering and processing business in northern West Virginia, southwestern Pennsylvania and eastern Ohio. We believe the acquisition will provide us with a significant footprint and growth potential in the NGL-rich portion of the Marcellus Shale. (See Results of Operations – Segments, Midstream Gas & Liquids.)

In November 2012, we completed the acquisition of Williams’ 83.3 percent undivided interest and operatorship of the olefins production facility located in Geismar, Louisiana, along with a refinery-grade propylene splitter and pipelines in the Gulf region (Geismar Acquisition), for total consideration valued at $2.364 billion, including 42,778,812 of our limited partner units, $25 million in cash and an increase in the general partner capital account to maintain Williams’ 2 percent general partner interest. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. Prior period segment disclosures have been recast for this transaction. (See Results of Operations – Segments, Midstream Gas & Liquids.)

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Distributions

In January 2013, our general partner’s Board of Directors approved a quarterly distribution to unitholders of $0.8275 per unit, an increase of approximately 2.5 percent over the prior quarter and 8.5 percent over the same period in the prior year. (See Management’s Discussion and Analysis of Financial Condition and Liquidity.)

Overview

During the second quarter 2012, NGL margins declined sharply largely attributable to a record-warm winter, a slowing global economy, and growing NGL supplies. The downward trend of per-unit NGL margins leveled-off during the second-half of 2012. We have been impacted by this environment as our net income for 2012 decreased by $279 million compared to 2011, primarily due to lower NGL production and marketing margins, higher operating costs and selling, general, and administrative expenses (SG&A), partially offset by an increase in fee revenues and olefin production margins. See additional discussion in Results of Operations.

Our net cash provided by operating activities for 2012 decreased $272 million compared to 2011 primarily due to lower operating income.

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 2012 through the present:

Recent Events

In addition to the previously discussed acquisitions, we note the following:

• In February 2012, we announced a new interstate gas pipeline project. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. This project, along with the newly acquired Laser Gathering System and our Springville pipeline, are key steps in our strategy to create the Susquehanna Supply Hub, a major natural gas supply hub in northeastern Pennsylvania. In April 2012, we began the Federal Energy Regulatory Commission (FERC) pre-filing process for the Constitution Pipeline and expect to file a FERC application during the second quarter of 2013.

• In April 2012, we completed an equity issuance of 10 million common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. Also in April 2012, we sold 16,360,133 common units to Williams for $1 billion. The net proceeds of these transactions were used for general partnership purposes, including funding a portion of the cash purchase price of the Caiman Acquisition.

• In July 2012, Transco issued $400 million of 4.45 percent senior unsecured notes due 2042 to investors in a private debt placement. A portion of these proceeds was used to repay Transco’s $325 million 8.875 percent senior unsecured notes that matured on July 15, 2012. 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 November 2012 and completed in December 2012.

• In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

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• Following Williams’ spin-off of WPX Energy, Inc. (WPX) at the end of 2011 and in consideration of the growth plans of the ongoing business, Williams initiated an organizational restructuring evaluation to better align resources to support an ongoing business strategy to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. This effort has resulted in changes in our organizational structure effective January 1, 2013 and, thus, how our underlying businesses will be managed. As a result, our segment reporting structure will change beginning in 2013.

• In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit. Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of these transactions were primarily used to repay outstanding borrowings on our senior unsecured revolving credit facility (revolver).

• In August 2012, we completed a public offering of $750 million of 3.35 percent senior unsecured notes due 2022. We used the net proceeds to repay outstanding borrowings on our revolver and for general partnership purposes.

• In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction.

Outlook for 2013

Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas, natural gas products, and crude oil that exists in North America. We seek to accomplish this through further developing our scale positions in current key markets and basins and entering new growth markets and basins where we can become the large-scale service provider. We will maintain a strong commitment to operational excellence and customer satisfaction. We believe that accomplishing these goals will position us to deliver an attractive return to our unitholders.

Fee-based businesses are a significant component of our portfolio. As we continue to transition to an overall business mix that is increasingly fee-based, the influence of commodity price fluctuations on our operating results and cash flows is expected to become somewhat less significant.

In light of the above, our business plan for 2013 continues to reflect both significant capital investment and growth in distributions. Our planned capital investments for 2013 total approximately $3.75 billion, of which we expect to fund a significant portion through debt and equity issuances. We expect to maintain an attractive cost of capital and reliable access to capital markets, both of which will allow us to pursue development projects and acquisitions.

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

• General economic, financial markets, or industry downturn;

• Availability of capital;

• Lower than expected levels of cash flow from operations;

• Counterparty credit and performance risk;

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

• Unexpected significant increases in capital expenditures or delays in capital project execution;

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• Lower than anticipated energy commodity prices and margins;

• Changes in the political and regulatory environments;

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

We continue to address these risks through maintaining a strong financial position and ample liquidity, as well as managing a diversified portfolio of energy infrastructure assets.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have reviewed the selection, application, and disclosure of these critical accounting estimates with our general partner’s Audit Committee. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Goodwill and Intangible Assets

At December 31, 2012, our Consolidated Balance Sheet includes $649 million of goodwill and $1.7 billion in intangible assets related to the Laser and Caiman Acquisitions, which were completed earlier in the year.

Goodwill

We performed our annual assessment of goodwill for impairment as of October 1. All of our goodwill is allocated to our Northeast gathering and processing businesses (the reporting unit). In our evaluation, our estimate of the fair value of the reporting unit exceeded its carrying value, including goodwill, and thus no impairment was recognized. If the carrying value of the reporting unit had exceeded its fair value, a computation of the implied fair value of the goodwill would have been compared with its related carrying value. If the carrying value of the reporting unit goodwill had exceeded the implied fair value of that goodwill, an impairment loss would have been recognized in the amount of the excess.

The fair value of the reporting unit was estimated using an income approach (discounted cash flows). Significant estimates and assumptions in this determination included our estimate of the expected future cash flows associated with the underlying operations. These assumptions include projections of future production volumes and timing, certain energy commodity prices, capital expenditures and recovery provisions, gathering fees, and operating expenses.

Judgments and assumptions are inherent in our estimate of future cash flows used to evaluate these assets. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of an impairment charge in the consolidated financial statements. Our calculation of fair value used a discount rate of 11.25 percent. We estimate that an increase of approximately 250 basis points in the discount rate could result in a fair value of the reporting unit below its carrying value, all other variables held constant.

Other intangible assets

We evaluate other intangible assets for both changes in the expected remaining useful lives and impairment when events or changes in circumstances indicate, in our management’s judgment, that the estimated useful lives have changed or the carrying value of such assets may not be recoverable. Changes in an estimated remaining useful life would be reflected prospectively through amortization over the revised remaining useful life. When an indicator of impairment has occurred, we compare our management’s estimate of undiscounted future cash flows attributable to the intangible 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. If an impairment of the carrying value has occurred, we determine the amount of the impairment

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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. Indicators of potential impairment may include:

• Laws prohibiting the production of reserves in the areas where our assets from the Laser and Caiman Acquisitions operate;

• The development of alternative energy sources that would halt the production of reserves in these areas; or

• The loss of or failure to renew customer contracts. A significant portion of the value allocated to these contracts in our purchase price allocation was based on our assumptions regarding our ability and intent to renew or renegotiate existing customer contracts. (See Note 2 of Notes to Consolidated Financial Statements.)

We have not evaluated our intangible assets for impairment as of December 31, 2012, as there were no indicators of potential impairment.

Equity-method Investments

At December 31, 2012, our Consolidated Balance Sheet includes approximately $1.8 billion of investments that are accounted for under the equity method of accounting. We evaluate these 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. We generally estimate the fair value of our investments using an income approach where significant judgments and assumptions include expected future cash flows and the appropriate discount rate. In some cases, we may utilize a form of market approach to estimate the fair value of our investments.

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 fair value is recognized in the consolidated financial statements as an impairment charge. Events or changes in circumstances that may be indicative of an other-than-temporary decline in value will vary by investment, but may include:

• Lower than expected cash distributions from investees;

• Significant asset impairments or operating losses recognized by investees;

• Significant delays in or lack of producer development or significant declines in producer volumes in markets served by investees; and,

• Significant delays in or failure to complete significant growth projects of investees.

No impairments of investments accounted for under the equity method have been recorded for the year ended December 31, 2012.

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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, 2012. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Years Ended December 31,
	2012			$ Change from 2011*		% Change from 2011*		2011			$ Change from 2010*		% Change from 2010*		2010
	(Millions)
Revenues:
Service revenues	$	2,709			+192		+8%	$	2,517			+171		+7%	$	2,346
Product sales		4,611			-586		-11%		5,197			+1,084		+26%		4,113
Total revenues		7,320							7,714							6,459
Costs and expenses:
Product costs		3,526			+425		+11%		3,951			-728		-23%		3,223
Operating and maintenance expenses		987			-39		-4%		948			-111		-13%		837
Depreciation and amortization expenses		714			-93		-15%		621			-43		-7%		578
Selling, general, and administrative expenses		553			-147		-36%		406			+2		-		408
Other (income) expense – net		23			-10		-77%		13			-27		NM		(14	)
Total costs and expenses		5,803							5,939							5,032
Operating income		1,517							1,775							1,427
Equity earnings (losses)		111			-31		-22%		142			+33		+30%		109
Interest expense		(405	)		+10		+2%		(415	)		-51		-14%		(364	)
Interest income		3			+1		+50%		2			-2		-50%		4
Other income (expense) – net		6			-1		-14%		7			-5		-42%		12
Net income		1,232							1,511							1,188
Less: Net income attributable to noncontrolling interests		-			-		-		-			+16		+100%		16
Net income attributable to controlling interests	$	1,232						$	1,511						$	1,172

* + = 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.

2012 vs. 2011

The increase in service revenues is primarily due to Midstream’s higher fee revenues resulting from increased gathering and processing fee revenues from higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses and higher volumes in the western deepwater Gulf of Mexico and in the Piceance basin. Additionally, Gas Pipeline’s transportation revenues increased from expansion projects placed into service in 2011 and 2012.

The decrease in product sales is primarily due to Midstream’s lower NGL and olefin production revenues reflecting an overall decrease in average per-unit sales prices. Marketing revenues also decreased primarily due to significant decreases in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

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The decrease in product costs is primarily due to lower olefins feedstock costs reflecting a decrease in average per-unit prices and lower costs associated with the production of NGLs primarily due to a decrease in average natural gas prices at Midstream. Midstream’s marketing purchases also decreased primarily resulting from significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

The increase in operating and maintenance expenses is primarily due to Gas Pipeline’s increased employee-related benefit costs and increased pipeline maintenance as well as Midstream’s increased maintenance expenses primarily associated with its new assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

The increase in depreciation and amortization expenses is primarily associated with Midstream’s new assets acquired in 2012 (see Note 2 of Notes to Consolidated Financial Statements).

The increase in SG&A is primarily due to an increase of $71 million at Midstream reflecting $23 million of acquisition and transition-related costs as well as higher employee-related and information technology expenses driven by general growth within Midstream’s business operations. Also, general corporate expenses increased $66 million in 2012 related to our higher proportionate share of these costs as a result of Williams’ spin-off of WPX, which was completed on December 31, 2011. This increase in general corporate expenses includes $25 million of reorganization-related costs in 2012 primarily relating to Williams’ engagement of a consulting firm to assist in better aligning resources to support our business strategy following Williams’ spin-off of WPX.

The decrease in operating income generally reflects lower NGL production and marketing margins, as well as previously described increases in operating and maintenance expenses, depreciation and amortization expenses, and SG&A. Higher fee revenues and olefin production margins partially offset these decreases.

Equity earnings (losses) decreased primarily due to lower Laurel Mountain Midstream, LLC (Laurel Mountain), Aux Sable Liquid Products L.P. (Aux Sable) and Discovery Producer Services LLC (Discovery) equity earnings at Midstream primarily reflecting lower operating results of these investees and the impairment of two minor NGL processing plants at Laurel Mountain, partially offset by an increase in equity earnings at Gas Pipeline primarily resulting from the acquisition of an additional 24.5 percent interest in Gulfstream in May 2011.

Interest expense decreased due to an increase in interest capitalized related to construction projects primarily at Midstream, partially offset by an increase in interest incurred related to increased borrowings (see Note 11 of Notes to Consolidated Financial Statements).

2011 vs. 2010

The increase in service revenues is primarily due to higher Midstream gathering and processing fee revenue in the Marcellus Shale related to gathering assets acquired at the end of 2010, in the western deepwater Gulf of Mexico related to assets placed into service in late 2010, and in the Piceance basin as a result of an agreement executed in November 2010. These increases are partially offset by a decline in fee revenue in the eastern deepwater Gulf of Mexico primarily due to natural field declines. Gas Pipeline’s transportation revenues increased primarily due to expansion projects placed in service in 2010 and 2011.

The increase in product sales is primarily due to higher marketing and NGL and olefin production revenues at Midstream as a result of higher average energy commodity prices, partially offset by a decrease in NGL production volumes.

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

The increase in operating and maintenance expenses is primarily due to increased maintenance expenses and higher property insurance expenses at Midstream.

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The increase in depreciation and amortization expenses is primarily due to assets placed in service late in 2010, along with increased depreciation of a facility, which was idled in 2012, at Midstream.

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 $8 million related to the net reversal of project feasibility costs from expense to capital in 2011 at Gas Pipeline (see Note 6 of Notes to Consolidated Financial Statements).

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 (losses) changed favorably 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 expense 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 interests decreased due to the merger with Williams Pipeline Partners L.P., 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 2012 include:

Expansion projects

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 capital cost of the project was approximately $60 million. The project was placed into service in the first quarter of 2013, increasing capacity by 142 Mdth/d.

Virginia Southside

In December 2012, we filed an application with the FERC to expand our existing natural gas transmission system from New Jersey to a proposed power station in Virginia and a delivery point in North Carolina. The capital cost of the project is estimated to be approximately $300 million. We plan to place the project into service in September 2015, which is expected to increase capacity by 270 Mdth/d.

Constitution Pipeline

In April 2012, we began the FERC pre-filing process for a new interstate gas pipeline project. We currently own 51 percent of Constitution Pipeline with two other parties holding 25 percent and 24 percent, respectively. We will be the operator of Constitution Pipeline. The new 120-mile Constitution Pipeline will connect our gathering system in Susquehanna County, Pennsylvania, to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems. The total cost of the entire project is estimated to be $680 million. We plan to place the project into service in March 2015, with an expected capacity of 650 Mdth/d. The pipeline is fully subscribed with two shippers. We expect to file a FERC application during the second quarter of 2013.

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 $200 million. We placed the first phase of the project into service in September 2012, which increased capacity by 95 Mdth/d. We plan to place the second phase of the project into service in June 2013, which is expected to increase capacity by an additional 130 Mdth/d.

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Rockaway Delivery Lateral

In January 2013, we filed an application with the FERC to construct a three-mile offshore lateral to a distribution system in New York. The capital cost of the project is estimated to be approximately $180 million. We plan to place the project into service during the second half of 2014, with an expected capacity of 647 Mdth/d.

Northeast Supply Link

In November 2012, we received approval from 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 $390 million and is expected to increase capacity by 250 Mdth/d. We plan to place the project into service in November 2013.

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. In February 2013, the FERC issued an order approving the abandonment. We estimate the total abandonment costs, which will be capital in nature, will be approximately $92 million, which is expected to be spent through the end of 2013. As of December 31, 2012, we have incurred approximately $69 million in cumulative 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 13 of Notes to Consolidated Financial Statements.)

Outlook for 2013

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 2013. We have planned capital and investment expenditures of $725 million to $825 million in 2013 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

On August 31, 2012, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2012, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2013, subject to refund and the outcome of a hearing. We expect that our new rates, although still subject to refund until the rate case is resolved, will contribute to a modest increase in revenue in 2013. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2012 and will not be subject to refund. The impact of these specific new rates that became effective October 1, 2012 is expected to reduce revenues by approximately $2 million for the period from January 1, 2013 until the remaining rates that are currently suspended become effective on March 1, 2013.

During the first quarter of 2012, Northwest Pipeline filed a Stipulation and Settlement Agreement with the FERC for an increase in their rates. Northwest Pipeline received FERC approval during the second quarter of 2012. The new rates, which as filed are 7.4 percent higher than the formerly applicable rates, became effective January 1, 2013.

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Year-Over-Year Operating Results

	Year ended December 31,
	2012		2011		2010
	(Millions)
Segment revenues	$	1,674	$	1,678	$	1,605
Segment profit	$	677	$	673	$	637

2012 vs. 2011

Segment revenues decreased $4 million primarily due to $39 million lower system management gas sales (offset in product costs) and $4 million lower sales of base gas from Hester Storage Field. These decreases are substantially offset by a $40 million increase in transportation revenues associated with expansion projects placed in service during 2011 and 2012.

Segment costs and expenses increased $6 million, or 1 percent, primarily due to an $18 million increase in employee-related benefit costs charged to us by Williams, $13 million increased pipeline maintenance costs, an $11 million increase in project feasibility costs, $10 million higher depreciation expense resulting from additional assets placed in service in 2011, and $9 million higher selling, general and administrative costs, including increases in information technology services and rental cost. These increases were partially offset by $39 million lower system management gas costs (offset in segment revenues), $12 million lower operations and maintenance expense associated with the Eminence Storage Field leak, and an $8 million increase in the reversal of project feasibility costs from expense to capital associated with expansion projects.

Segment profit increased primarily due to the previously described changes and a $14 million increase in equity earnings primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

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 product costs). These increases are partially offset by $4 million lower sales of base gas from Hester Storage Field.

Segment costs and expenses increased $57 million, or 6 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.

Segment profit increased primarily due to the previously described changes and a $20 million increase in equity earnings primarily due to the acquisition of an additional interest in Gulfstream in May 2011.

Midstream Gas & Liquids

Overview of 2012

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.

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Significant events during 2012 include the following:

Gulf Olefins production facilities acquisition

In November 2012, we purchased Williams’ 83.3 percent undivided interest and operatorship of the olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf region. The acquisition is expected to bring more certainty to cash flows that are currently exposed to volatile ethane prices by shifting the commodity price exposure to ethylene. Located south of Baton Rouge, Louisiana, the Geismar facility is a light-end NGL cracker with current feedstock volumes of 39,000 barrels per day (bpd) of ethane and 3,000 bpd of propane and annual production of 1.35 billion pounds of ethylene. With the benefit of a $350-$400 million expansion under way and scheduled for completion by late 2013, the facility’s annual ethylene production capacity will grow by 600 million pounds to 1.95 billion pounds. Along with ethane, propane and ethylene, the Geismar facility also produces propylene, butadiene, and debutanized aromatic concentrate (DAC). Prior periods have been recast for this transaction.

In the fourth quarter of 2012, we also completed the construction of a pipeline which is capable of supplying 12 Mbbls/d of ethane to our Geismar olefins production facility from Discovery’s Paradis fractionator.

Caiman Acquisition

In April 2012, we completed the Caiman Acquisition for consideration valued at approximately $2.3 billion. The transition of operations is complete.

The acquisition provides us with a significant footprint and growth potential in the natural gas liquids-rich Ohio River Valley area of the Marcellus Shale. The existing physical assets that we acquired include a gathering system, two processing facilities and a fractionator located in northern West Virginia and establish our new Ohio Valley Midstream business. In addition to the acquisition cost, we committed a large portion of our 2012 capital expenditures and continue to commit planned capital expenditures in 2013 and beyond for ongoing expansions to the gathering system, processing facilities, and fractionator, which are currently under construction. NGL pipelines are also planned. The assets are anchored by long-term contracted commitments, including 236,000 dedicated gathering acres from 10 producers in West Virginia, Ohio, and Pennsylvania.

Several projects were completed in the fourth quarter of 2012 increasing our gathering, processing and fractionating capacities. The Fort Beeler plant complex has 320 million cubic feet per day (MMcf/d) of cryogenic processing capacity currently available with another 200 MMcf/d expected during the first quarter of 2013. The Moundsville fractionator is now in service with approximately 13 thousand barrels per day (Mbbls/d) of NGL handling capacity. An NGL pipeline, connecting the Fort Beeler plant to the Moundsville fractionator has also been completed and is in service.

Utica Shale infrastructure project

In July 2012, we formed Caiman Energy II, LLC with Caiman Energy, LLC and others to develop large-scale natural gas gathering and processing and the associated liquids infrastructure serving oil and gas producers in the Utica shale, primarily in Ohio and northwest Pennsylvania. As a result, through our 47.5 percent ownership, we plan to contribute $380 million through 2014 to fund a portion of Blue Racer Midstream, a joint project formed in December 2012 between Caiman Energy II, LLC and another party.

Susquehanna Supply Hub, northeastern Pennsylvania

In February 2012, we completed the Laser Acquisition for $325 million in cash, net of cash acquired in the transaction and subject to certain closing adjustments, and 7,531,381 of our common units valued at $441 million. The 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.

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Our Springville pipeline, a 33-mile, 24-inch diameter natural gas gathering pipeline, connecting a portion of our gathering assets into the Transco pipeline, was placed into service in January 2012, and expansions were completed in the third quarter of 2012 allowing us to deliver approximately 625 MMcf/d into the Transco pipeline. This new take-away capacity allows full use of approximately 1.6 billion cubic feet per day (Bcf/d) of capacity from various compression and dehydration expansion projects to our gathering business in northeastern Pennsylvania’s Marcellus Shale which we acquired at the end of 2010.

As production in the Marcellus increases and expansion projects are completed, the Susquehanna Supply Hub is expected to reach a natural gas take away capacity of 3 Bcf/d by 2015, including capacity contributions from the Constitution Pipeline.

Volume impacts in 2012

Due to third-party NGL pipeline capacity restrictions from our Four Corners plants beginning in late September and to unfavorable ethane economics in December, we reduced our recoveries of ethane in our onshore plants, which resulted in 7 percent lower NGL equity sales volumes in the fourth quarter of 2012 compared to the third quarter of 2012.

Our NGL equity sales volumes for the third quarter of 2012 were modestly impacted by maintenance on the Overland Pass Pipeline for approximately 5 days. As a result of the NGL pipeline maintenance, NGL takeaway capacity from our western plants on the Overland Pass Pipeline was reduced, which forced our western plants to reduce NGL recoveries.

In the Gulf Coast, our Mobile Bay plant was shut down for 10 days due to Hurricane Isaac. The plant and offshore platforms were evacuated during the storm. Afterwards, the plant remained shut down due to flooding issues on a third-party pipeline limiting the NGL takeaway capacity. In addition, production into Devils Tower was shut-in for various time periods due to third-party hurricane related issues. These events related to Hurricane Isaac did not have a material impact to our overall NGL production or NGL equity sales.

Volatile commodity prices

Driven primarily by a sharp decline in NGL prices during the second quarter of 2012, followed by increasing natural gas prices in the latter half of 2012, average per-unit NGL margins declined during 2012 and were approximately 23 percent lower in 2012 than in 2011. Because we typically realize lower per-unit margins for ethane versus other NGLs, if we had produced the same mix of ethane and non-ethane NGLs during the fourth quarter of 2012 as we generally have in prior periods, the average per-unit margin in the fourth quarter of 2012 would have been lower. Key factors in the NGL market weakness have been high propane inventories caused by the extremely warm winter and the effect of the propane oversupply on ethane inventories and pricing. Despite an increase in natural gas prices during the latter half of 2012, we have benefited from lower natural gas prices in 2012 than in 2011, driven by abundant natural gas supplies.

NGL margins are defined as NGL revenues less any applicable British thermal unit (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 2013

The following factors, among others, could impact our business in 2013.

Commodity price changes

• We expect a decline in ethane and propane prices and an increase in natural gas prices such that our full year 2013 NGL margins are expected to be lower than our rolling five-year average and 2012 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.

• While per-unit ethylene margins are volatile and highly dependent upon continued demand within the global economy, we believe that our average per-unit ethylene margin will improve over 2012 levels, benefiting from higher ethylene prices and lower ethane and propane feedstock prices. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.

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.

• We anticipate significant growth in our natural gas gathering volumes as our infrastructure grows to support drilling activities in the Marcellus Shale region.

• We anticipate equity NGL volumes in 2013 to be lower than 2012 due in part to a change in a customer’s contract in the onshore business from percent-of-liquids to fee-based processing, with a portion of the fee

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representing a share of the associated NGL margins. We also expect lower equity NGL volumes due to periods when we expect it will not be economical to recover ethane. Our expectations of sustained low natural gas prices are expected to discourage producer drilling activities in the western onshore area and unfavorably impact the supply of natural gas available to gather and process in 2013.

• In our businesses in the Gulf Coast, we expect lower production handling and crude transportation volumes compared to 2012, as production flowing through our Devils Tower facility declines.

• We anticipate higher general and administrative, operating, and depreciation expense supporting our growing operations in the Marcellus Shale area.

Olefin production volumes

• We expect lower ethylene volumes in 2013 as compared to 2012 primarily due to major maintenance planned for 2013. With the completion of our Geismar expansion in the latter part of 2013, as discussed below, we expect growth in production volumes in the fourth quarter of 2013.

Expansion Projects

We expect to invest total capital of $2.8 billion to $ 3.1 billion in 2013. We plan to continue pursuing expansion and growth opportunities in the Marcellus Shale region, Gulf of Mexico, and Piceance basin.

Our ongoing major expansion projects include the following:

• Expansion of our Susquehanna Supply Hub in northeastern Pennsylvania, as previously discussed.

• Expansions currently under construction to our natural gas gathering system, processing facilities and fractionator in our Ohio Valley Midstream business of the Marcellus Shale including a third turbo-expander at our Fort Beeler facility which is expected to add 200 MMcf/d of processing capacity in the first quarter of 2013. By the end of 2013, we expect our first turbo-expander at our Oak Grove facility to add 200 MMcf/d of processing capacity and additional fractionation capacity at our Moundsville fractionators bringing the NGL handling capacity to approximately 43 Mbbls/d.

• Expansions to our gathering system infrastructure through capital to be invested within our Laurel Mountain equity investment, also in the Marcellus Shale region.

• We will design, construct, and install our Gulfstar FPS™, a spar-based floating production system that utilizes a standard design approach 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. We expect Gulfstar FPS™ to be capable of serving as a central host facility for other deepwater prospects in the area. Construction is underway and the project is expected to be in service in 2014. In January 2013, we agreed to sell a 49 percent ownership interest in our Gulfstar FPS™ project to a third party. The transaction is expected to close in second-quarter 2013, at which time we expect the third party will contribute $225 million to fund its proportionate share of the project costs, following with monthly capital contributions to fund its share of ongoing construction. 

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

• An expansion of our Geismar olefins production facility is under way which is expected to increase the facility’s ethylene production capacity by 600 million pounds per year to a new annual capacity of 1.95 billion pounds. The additional capacity will be wholly owned by us and is expected to increase our share of the Geismar production facility to over 88 percent. We expect to complete the expansion in the latter part of 2013.

• Our equity investee which we operate, Discovery, plans to construct, own, and operate a new 215-mile, 20-inch deepwater lateral pipeline from a third-party floating production facility located in the Keathley Canyon production area 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 the

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Keathley Canyon and Green Canyon areas. The Keathley Canyon Connector™ lateral will originate from a third-party floating production facility in the southeast portion of the Keathley Canyon area and will connect to Discovery’s existing 30-inch offshore natural 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. Pre-construction activities have begun; the pipeline is expected to be laid in 2013 and in service in mid-2014.

• Through our equity investment in OPPL, we are participating 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.

Year-Over-Year Operating Results

	Years ended December 31,
	2012		2011		2010
	(Millions)
Segment revenues	$	5,646	$	6,036	$	4,854
Segment profit	$	1,135	$	1,362	$	1,029

2012 vs. 2011

The decrease in segment revenues includes:

• A $366 million decrease in revenues from our equity NGLs primarily reflecting a decrease of $354 million associated with an overall 26 percent decrease in average NGL per-unit sales prices. Average ethane and non-ethane per-unit prices decreased by 49 percent and 15 percent, respectively.

• A $77 million decrease in olefin sales revenues including $42 million lower ethylene production sales revenues primarily due to 10 percent lower average per-unit sales prices and $26 million lower propylene production sales revenues primarily due to 17 percent lower average per-unit sales prices.

• Marketing revenues are $93 million lower primarily due to a significant decrease in NGL and olefin prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities.

• A $163 million increase in fee revenues primarily due to higher volumes in the Marcellus Shale, including new volumes on our recently acquired gathering and processing assets in our Ohio Valley Midstream and Susquehanna Supply Hub businesses; higher volumes in the western deepwater Gulf of Mexico, including higher volumes on our Perdido Norte natural gas and oil pipelines; and higher volumes in the Piceance basin.

Segment costs and expenses decreased $208 million, or 4 percent, including:

• A $183 million decrease in olefin feedstock costs including $130 million lower ethylene feedstock costs driven by 38 percent lower average per-unit feedstock costs and $28 million lower propylene feedstock costs primarily due to 20 percent lower per-unit feedstock costs.

• A $137 million decrease in costs associated with our equity NGLs primarily due to a 31 percent decrease in average natural gas prices.

• A $46 million decrease in marketing purchases primarily due to significantly lower average NGL prices, partially offset by higher NGL and crude volumes, as well as new volumes from natural gas marketing activities. The changes in natural gas marketing purchases are more than offset by similar changes in natural gas marketing revenues.

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• A $101 million increase in operating costs including higher depreciation and amortization of assets and intangibles, along with maintenance costs associated with assets acquired in 2012, partially offset by lower costs in our Four Corners area related to the consolidation of certain operations.

• A $71 million increase in general and administrative expenses including $23 million of Caiman and Laser acquisition and transition-related costs, as well as increases in employee-related and information technology expenses driven by general growth within our business operations.

The decrease 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 decrease in Midstream’s segment profit includes:

• A $229 million decrease in NGL margins driven primarily by commodity price changes including lower NGL prices, partially offset by lower natural gas prices.

• A $101 million increase in operating costs as previously discussed.

• A $71 million increase in general and administrative expenses as previously discussed.

• A $47 million decrease in margins related to the marketing of NGLs primarily due to the impact of a significant and rapid decline in NGL prices, primarily during the second quarter of 2012, while product was in transit and a $7 million unfavorable change in write-downs of inventories to lower of cost or market. These unfavorable variances compare to periods of increasing prices during 2011.

• A $45 million decrease in equity earnings primarily due to $19 million lower Laurel Mountain equity earnings driven by lower gathering rates indexed to natural gas prices, higher operating costs, including depreciation, and the impairment of two minor NGL processing plants, partially offset by higher gathered volumes; $12 million lower Aux Sable equity earnings primarily due to lower NGL margins; and $12 million lower Discovery equity earnings primarily due to lower NGL margins and volumes.

• A $163 million increase in fee revenues as previously discussed.

• A $106 million increase in olefin product margins including $88 million higher ethylene production margins primarily due to 38 percent lower average per-unit feedstock prices, partially offset by 10 percent lower average per-unit sales prices. DAC production margins were also $13 million higher, primarily resulting from higher average per-unit margins primarily driven by lower average per-unit feedstock prices.

2011 vs. 2010

The increase in segment revenues includes:

• A $657 million increase in marketing revenues primarily due to higher average NGL, crude and propylene 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 $167 million increase in olefin sales revenues including $126 million higher ethylene production sales revenues due to 28 percent higher average per-unit sales prices on 6 percent higher volumes primarily resulting from the absence of a four-week plant maintenance outage in 2010; and $30 million higher butadiene and DAC production sales revenues primarily due to higher average per-unit sales prices.

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• A $107 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 $862 million, or 22 percent, including:

• A $641 million increase in marketing purchases primarily due to higher average NGL, crude and propylene prices. These changes are offset by similar changes in marketing revenues.

• A $117 million increase in olefin feedstock costs including $93 million higher ethylene feedstock costs resulting from higher average per-unit feedstock costs and 6 percent higher volumes and $11 million higher butadiene and DAC feedstock costs primarily due to higher per-unit feedstock costs.

• A $104 million increase in operating costs reflecting $63 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 increased 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 of certain Gulf Coast assets which were damaged by Hurricane Ike in 2008 and our Ignacio plant which was damaged by a fire in 2007.

• 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 businesses’ 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 $107 million increase in fee revenues as previously discussed.

• A $50 million increase in olefin product margins including $33 million higher ethylene production margins due to 27 percent higher per-unit margins on 6 percent higher volumes and $19 million higher butadiene and DAC production margins primarily resulting from higher average per-unit margins.

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• A $16 million increase in margins related to the marketing of NGLs, crude and propylene.

• 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 $104 million increase in operating costs as previously discussed.

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

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Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2012, we continued to focus upon growth through disciplined investments. Examples of this growth included:

• Expansion of Gas Pipeline’s interstate natural gas pipeline system to meet the demand of growth markets.

• Laser, Caiman, and Geismar Acquisitions, as well as 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 and equity offerings.

Outlook

We seek to manage our businesses with a focus on applying conservative financial policy and maintaining investment-grade credit metrics. Our plan for 2013 reflects our ongoing transition to an overall business mix that is increasingly fee-based. 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 also note that the addition of the Geismar olefins-production facility is expected to result in a favorable shift in our commodity exposure from ethane to ethylene.

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 2013:

• We increased our per-unit quarterly distribution with respect to the fourth quarter of 2012 from $0.8075 to $0.8275. We expect to increase quarterly limited partner cash distributions by approximately 9 percent annually.

• 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 revolver as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $1.925 billion and $2.325 billion in 2013. In addition, we retain the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions or business opportunities.

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 2013. Our internal and external sources of liquidity include:

• 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 revolver as needed and available.

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We anticipate our more significant uses of cash to be:

• Maintenance and expansion capital expenditures;

• 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 2013 levels;

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

As of December 31, 2012, we had a working capital deficit (current liabilities in excess of current assets) of $499 million. However, we note the following about our available liquidity.

Available Liquidity	December 31, 2012
	(Millions)
Cash and cash equivalents	$	20
Capacity available under our $2.4 billion five-year revolver (expires June 3, 2016) (1)		2,025
	$	2,045

(1) The full amount of the revolver 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 revolver to the extent not otherwise utilized by the other co-borrowers. As of February 25, 2013, $975 million of loans are outstanding under this revolver. At December 31, 2012, we are in compliance with the financial covenants associated with this revolver. (See Note 11 of Notes to Consolidated Financial Statements.)

Shelf Registration

In February 2012, we filed a shelf registration statement as a well-known seasoned issuer to facilitate unlimited issuances of registered debt and limited partnership unit securities.

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.

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Debt Offerings

In August 2012, we completed a public offering of $750 million of our 3.35 percent senior unsecured notes due in 2022. We used the $745 million net proceeds to repay outstanding borrowings under our revolver and for general partnership purposes.

In July 2012, Transco received net proceeds of $395 million from the issuance of $400 million of 4.45 percent senior unsecured notes due in 2042. These proceeds were used to repay Transco’s $325 million 8.875 percent notes and for general corporate purposes, including capital expenditures.

Equity Offerings

In August 2012, we completed an equity issuance of 8,500,000 common units representing limited partner interests in us at a price of $51.43 per unit. Subsequently, we sold an additional 1,275,000 common units for $51.43 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $488 million were used to repay outstanding borrowings under our revolver and for general partnership purposes.

In April 2012, we completed an equity issuance of 10,000,000 common units representing limited partner interests in us at a price of $54.56 per unit. Subsequently, we sold an additional 973,368 common units for $54.56 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $581 million were used for general partnership purposes, including the funding of a portion of the cash purchase price of the Caiman Acquisition.

In April 2012, we also issued 16,360,133 common units to Williams for $1 billion, which was used to fund a portion of the cash purchase price of the Caiman Acquisition.

In January 2012, we completed an equity issuance of 7,000,000 common units representing limited partner interests in us at a price of $62.81 per unit. In February 2012, we sold an additional 1,050,000 common units for $62.81 per unit to the underwriters upon the underwriters’ exercise of their option to purchase additional common units. The net proceeds of $490 million were used to fund capital expenditures and for general partnership purposes.

Additionally, we issued equity to the sellers for acquisitions as discussed below.

Acquisitions

In November 2012, we completed the Geismar Acquisition in exchange for aggregate consideration valued at $2.364 billion, including $25 million in cash and 42,778,812 of our common units.

In April 2012, we completed the Caiman Acquisition in exchange for aggregate consideration of $1.72 billion in cash, net of purchase price adjustments, and 11,779,296 of our common units.

In February 2012, we completed the Laser Acquisition in exchange for $325 million in cash, net of cash acquired in the transaction, and 7,531,381 of our common units.

Credit Ratings

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

Rating Agency	Date of Last Change	Outlook	Senior Unsecured Debt Rating
Standard & Poor’s	March 5, 2012	Stable	BBB
Moody’s Investors Service	February 27, 2012	Stable	Baa2
Fitch Ratings	February 9, 2012	Positive	BBB-

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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, 2012, we estimate that a downgrade to a rating below investment grade could require us to post up to $429 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:

• 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 2013:

	Maintenance						Expansion
Segment	Low		Midpoint		High		Low		Midpoint		High
	(Millions)
Gas Pipeline	$	225	$	250	$	275	$	500	$	525	$	550
Midstream		90		100		110		2,735		2,875		3,015
Total	$	315	$	350	$	385	$	3,235	$	3,400	$	3,565

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

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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. We have increased the fourth quarter 2012 distribution to $ 0.8275 per unit, from the third quarter 2012 distribution of $0.8075, which resulted in a fourth-quarter 2012 cash distribution of approximately $442 million that was paid on February 8, 2013, to the general and limited partners of record at the close of business on February 1, 2013.

Williams has agreed to temporarily waive its incentive distribution rights related to the common units issued to Williams and the seller of Caiman Eastern Midstream, LLC, in connection with our acquisition of that entity, through 2013. In connection with the Geismar Acquisition, Williams also agreed to waive $16 million per quarter of incentive distribution rights until the later of December 31, 2013 or 30 days after the Geismar plant expansion is operational. The incentive distribution rights waived relative to distributions paid in 2012 were $24 million.

Sources (Uses) of Cash

	Years Ended December 31,
	2012			2011			2010
	(Millions)
Net cash provided (used) by:
Operating activities	$	2,018		$	2,290		$	1,922
Financing activities		2,412			(918	)		3,418
Investing activities		(4,573	)		(1,396	)		(5,306	)
Increase (decrease) in cash and cash equivalents	$	(143	)	$	(24	)	$	34

Operating activities

Net cash provided by operating activities decreased $272 million in 2012 as compared to 2011 primarily due to lower operating income.

Net cash provided by operating activities increased $368 million in 2011 as compared to 2010 primarily due to higher operating income.

Financing activities

Significant transactions include:

2012

• $1.559 billion received from our equity offerings;

• $1.44 billion related to quarterly cash distributions paid to limited partner unitholders and our general partner;

• $1 billion received from Williams for common units issued, used for the funding of a portion of the cash purchase price of the Caiman Acquisition;

• $1.49 billion received in revolver borrowings for general partnership purposes, including capital expenditures;

• $745 million net proceeds received from our August 2012 public offering of $750 million of senior unsecured notes due in 2022;

• $395 million net proceeds received from Transco’s July 2012 issuance of $400 million of senior unsecured notes due in 2042;

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• $1.115 billion of revolver borrowings paid;

• $325 million paid to retire Transco’s 8.875 percent notes upon their maturity on July 15, 2012.

2011

• $1.12 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 revolver 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.

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 the Piceance Acquisition (See Note 1 of Notes to Consolidated Financial Statements.);

• $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 the Piceance Acquisition;

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• $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 the Piceance Acquisition;

• $152 million in distributions to Williams primarily related to the Contributed Entities prior to the closing of the Dropdown. (See Note 1 of Notes to Consolidated Financial Statements.)

Investing activities

Significant transactions include:

2012

• $2.1 billion in capital expenditures;

• $1.72 billion paid, net of purchase price adjustments, for the Caiman Acquisition in April 2012;

• $325 million paid, net of cash acquired in the transaction, for the Laser Acquisition in March 2012;

• $471 million contributed to our equity method investments.

2011

• $1 billion in capital expenditures;

• $174 million related to our acquisition of a 24.5 percent interest in Gulfstream from Williams in May 2011 (See Note 1 of Notes to Consolidated Financial Statements.);

• $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;

• $844 million in capital expenditures;

• $458 million related to the 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.

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

We have various other guarantees and commitments which are disclosed in Notes 9, 11, 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, 2012:

	2013		2014 -   2015		2016 -   2017		Thereafter		Total
	(Millions)
Long-term debt, including current portion:
Principal	$	-	$	750	$	1,535	$	6,168	$	8,453
Interest		426		825		710		3,323		5,284
Operating leases (1)		40		66		53		136		295
Purchase obligations (2)		1,569		196		177		495		2,437
Other long-term obligations		1		1		-		1		3
Total	$	2,036	$	1,838	$	2,475	$	10,123	$	16,472

(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 2014 and thereafter does not include such variable amounts related to this agreement as the variable amount is not yet determinable. The variable portion to be paid in 2013 based on 2012 gathering volumes is $7.3 million and is included in the table for year 2013.

(2) Includes approximately $1.2 billion in open property, plant and equipment purchase orders. Larger projects include Gulfstar and the Geismar plant expansion. Also includes an estimated $579 million long-term ethane purchase obligation with index-based pricing terms that is reflected in this table at December 31, 2012 prices. This obligation is part of an overall exchange agreement whereby volumes we transport on OPPL are sold at a third-party fractionator near 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. In addition, we have not included certain natural gas life-of-lease contracts for which the future volumes are indeterminable. We have not included commitments, beyond purchase orders, for the acquisition or construction of property, plant and equipment or expected contributions to our jointly owned investments (See Results of Operations – Segments).

Effects of Inflation

Our operations have historically not been materially affected by inflation. Approximately 56 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 certain of these price changes is reduced through the use of hedging instruments and 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

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others. Current estimates of the most likely costs of such activities are approximately $17 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, 2012. 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 2012, we paid approximately $4 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $5 million in 2013 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, 2012, certain assessment studies were still in process for which the ultimate outcome may yield 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.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. 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 nonattainment 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 that it was proceeding with required actions to implement the 2008 ozone standard and area designations. In May 2012, the EPA completed designation of new eight-hour ozone non-attainment areas. Several Transco facilities are located in 2008 ozone nonattainment areas; however, each facility has been previously subjected to federal and/or state emission control requirements implemented to address preceding ozone standards. To date, no new federal or state actions have been proposed to mandate additional emission controls at these facilities. At this time, it is unknown whether future federal or state regulatory actions associated with implementation of the 2008 ozone standard will impact our operations and increase the cost of additions to property, plant and equipment-net on the Consolidated Balance Sheet. Until any additional federal or state regulatory actions are proposed, we are unable to estimate the cost of additions that may be required to meet this new regulation. Additionally, several non-attainment areas exist in or near areas where we have operating assets. States are required to develop implementation plans to bring these areas into compliance. Implementing regulations are expected to result in impacts to our operations and increase the cost of additions to property, plant and equipment-net on the Consolidated Balance Sheet for both new and existing facilities in affected areas.

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 $11 million to $13 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. The 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.

On January 22, 2010, the EPA set a new one-hour nitrogen dioxide (NO₂) NAAQS. The effective date of the new NO₂ standard was April 12, 2010. This standard is subject to challenge in federal court. On January 20, 2012, the EPA determined pursuant to available information that no area in the country is violating the 2010 NO₂ NAAQS and thus designated all areas of the country as “unclassifiable/attainment.” Also, at that time the EPA noted its plan to deploy an expanded NO₂ monitoring network beginning in 2013. However on October 5, 2012, the EPA proposed a graduated implementation of the monitoring network between January 1, 2014 and January 1, 2017. Once three years of data is collected from the new monitoring network, the EPA will reassess attainment status with the one-hour NO₂ NAAQS. Until that time, the EPA or states may require ambient air quality modeling on a case by case basis to demonstrate compliance with the NO₂ standard. Because we are unable to predict the outcome of the EPA’s or states’ future assessment using the new monitoring network, we are unable to estimate the cost of additions that may be required to meet this 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 primarily 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 11 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, 2012 and 2011. 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.

	2013			2014			2015			2016			2017			Thereafter(1)			Total		Fair Value December 31, 2012
													(Millions)
Long-term debt, including current portion:
Fixed rate	$	-		$	-		$	750		$	375		$	785		$	6,152		$	8,062	$	9,249
Interest rate		5.3	%		5.3	%		5.3	%		5.4	%		5.3	%		5.6	%
Variable rate	$	-		$	-		$	-		$	375		$	-		$	-		$	375	$	375
Interest rate (2)
	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	%

(1) Includes unamortized discount.

(2) The weighted average interest rate at December 31, 2012 was 2.7 percent.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of NGLs, olefins, and natural gas, 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, 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 nonderivative 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.)

79

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 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. At December 31, 2012, we had no trading derivatives in our portfolio. The fair value of our trading derivatives at December 31, 2011, was a net asset of less than $0.1 million. The value at risk for contracts held for trading purposes was zero at December 31, 2012, and less than $0.1 million at December 31, 2011.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from natural gas purchase and NGL purchase and sale activities. The fair value of our nontrading derivatives was a net asset of $4 million and $1 million at December 31, 2012 and 2011, respectively. The value-at-risk for derivative contracts held for nontrading purposes was less than $0.1 million at December 31, 2012 and zero at December 31, 2011. During the year ended December 31, 2012, our value at risk for these contracts ranged from a high of $2.3 million to a low of zero.

Certain of the derivative contracts held for nontrading purposes in 2012 were accounted for as cash flow hedges but realized during the year. As of December 31, 2012, the energy derivative contracts in our portfolio have not been designated as cash flow hedges.

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.

80

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, 2012, 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, 2012, 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.

81

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, 2012, 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, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Williams Partners L.P. as of December 31, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012, and our report dated February 27, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2013

82

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, 2012 and 2011, and the related consolidated statements of comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. 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 50 percent interest). The Partnership’s investment in Gulfstream constituted two percent of the Partnership’s assets as of December 31, 2012 and 2011 and the Partnership’s equity earnings in the net income of Gulfstream constituted five and four percent of the Partnership’s net income for the years ended December 31, 2012 and 2011, respectively. Gulfstream’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion on the 2011 and 2012 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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, 2012, 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, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2013

83

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the balance sheets of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2012 and 2011, and the related statements of operations, comprehensive income, members’ equity and cash flows for each of the two years in the period ended December 31, 2012. 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 audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide 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, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 25, 2013

84

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

	Years Ended December 31,
	2012			2011			2010
	(Millions, except per-unit amounts)
Revenues:
Service revenues	$	2,709		$	2,517		$	2,346
Product sales		4,611			5,197			4,113
Total revenues		7,320			7,714			6,459
Costs and expenses:
Product costs		3,526			3,951			3,223
Operating and maintenance expenses		987			948			837
Depreciation and amortization expenses		714			621			578
Selling, general, and administrative expenses		553			406			408
Other (income) expense — net		23			13			(14	)
Total costs and expenses		5,803			5,939			5,032
Operating income		1,517			1,775			1,427
Equity earnings (losses)		111			142			109
Interest incurred		(441	)		(426	)		(393	)
Interest capitalized		36			11			29
Interest income		3			2			4
Other income (expense) — net		6			7			12
Net income		1,232			1,511			1,188
Less: Net income attributable to noncontrolling interests		-			-			16
Net income attributable to controlling interests	$	1,232		$	1,511		$	1,172
Allocation of net income for calculation of earnings per common unit:
Net income attributable to controlling interests	$	1,232		$	1,511		$	1,172
Allocation of net income to general partner and Class C units		587			441			604
Allocation of net income to common units	$	645		$	1,070		$	568
Basic and diluted net income per common unit	$	1.89		$	3.69		$	2.66
Weighted average number of common units outstanding (thousands)		341,981			290,255			213,539
Cash distributions per common unit	$	3.205		$	2.960		$	2.720
Other comprehensive income (loss):
Net unrealized gain (loss) from derivative instruments	$	30		$	(17	)	$	(17	)
Reclassifications into earnings of net derivative instruments (gain) loss		(30	)		18			12
Other comprehensive income (loss)		-			1			(5	)
Comprehensive income		1,232			1,512			1,183
Less: Comprehensive income attributable to noncontrolling interests		-			-			16
Comprehensive income attributable to controlling interests	$	1,232		$	1,512		$	1,167

See accompanying notes.

85

WILLIAMS PARTNERS L.P.

CONSOLIDATED BALANCE SHEET

	December 31,     2012		December 31,     2011
ASSETS	(Millions)
Current assets:
Cash and cash equivalents	$	20	$	163
Trade accounts and notes receivable		562		564
Inventories		173		169
Regulatory assets		39		40
Other current assets		56		72
Total current assets		850		1,008
Investments		1,800		1,383
Property, plant, and equipment – net		14,287		11,822
Goodwill		649		-
Other intangibles		1,702		43
Regulatory assets, deferred charges, and other		421		416
Total assets	$	19,709	$	14,672
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	851	$	623
Affiliate		117		68
Accrued interest		110		105
Asset retirement obligations		68		66
Other accrued liabilities		203		172
Long-term debt due within one year		-		324
Total current liabilities		1,349		1,358
Long-term debt		8,437		6,913
Asset retirement obligations		508		504
Regulatory liabilities, deferred income, and other		518		464
Contingent liabilities and commitments (Note 15)
Equity:
Partners’ equity:
Common units (397,963,199 units outstanding at December 31, 2012 and 290,477,159 units outstanding at December 31, 2011)		10,372		6,810
General partner		(1,487)		(1,375)
Accumulated other comprehensive income (loss)		(2)		(2)
Total partners’ equity		8,883		5,433
Noncontrolling interests in consolidated subsidiaries		14		-
Total equity		8,897		5,433
Total liabilities and equity	$	19,709	$	14,672

See accompanying notes.

86

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, 2009	$	1,631	$	-	$	6,307	$	2	$	347	$	8,287
Net income		558		156		458		-		16		1,188
Other comprehensive income (loss)		-		-		-		(5)		-		(5)
Cash distributions (Note 3)		(432)		(87)		(141)		-		-		(660)
Distributions to The Williams Companies, Inc. - net		-		(3,357)		(778)		-		-		(4,135)
Excess of purchase price over contributed basis of business purchase from affiliate		-		-		(244)		-		-		(244)
Dividends paid to noncontrolling interests		-		-		-		-		(18)		(18)
Issuance of Class C units		-		6,946		(6,946)		-		-		-
Conversion of Class C units to Common		3,658		(3,658)		-		-		-		-
Issuance of units due to Williams Pipeline Partners L.P. merger		343		-		-		-		(343)		-
Sales of common units		806		-		-		-		-		806
Contributions from general partner		-		-		29		-		-		29
Other		-		-		2		-		(2)		-
Balance – December 31, 2010	$	6,564	$	-	$	(1,313)	$	(3)	$	-	$	5,248
Net income		1,088		-		423		-		-		1,511
Other comprehensive income (loss)		-		-		-		1		-		1
Cash distributions (Note 3)		(842)		-		(282)		-		-		(1,124)
Distributions to The Williams Companies, Inc. - net		-		-		(99)		-		-		(99)
Excess of purchase price over contributed basis of investment purchase from affiliate		-		-		(123)		-		-		(123)
Contributions from general partner		-		-		31		-		-		31
Other		-		-		(12)		-		-		(12)
Balance – December 31, 2011	$	6,810	$	-	$	(1,375)	$	(2)	$	-	$	5,433
Net income		672		-		560		-		-		1,232
Cash distributions (Note 3)		(1,056)		-		(384)		-		-		(1,440)
Distributions to The Williams Companies, Inc. - net		-		-		(42)		-		-		(42)
Sales of common units (Note 12)		2,559		-		-		-		-		2,559
Issuances of common units related to acquisitions (Note 12)		1,044		-		-		-		-		1,044
Issuances of common units in common control transactions (Note 12)		345		-		(338)		-		-		7
Contributions from general partner		-		-		93		-		-		93
Contributions to Constitution Pipeline Company, LLC (Note 1)		-		-		-		-		14		14
Other		(2)		-		(1)		-		-		(3)
Balance – December 31, 2012	$	10,372	$	-	$	(1,487)	$	(2)	$	14	$	8,897

See accompanying notes.

87

WILLIAMS PARTNERS L.P.

CONSOLIDATED STATEMENT OF CASH FLOWS

	Years  Ended December 31,
	2012		2011		2010
	(Millions)
OPERATING ACTIVITIES:
Net income	$	1,232	$	1,511	$	1,188
Adjustments to reconcile to net cash provided by operations:
Depreciation and amortization		714		621		578
Cash provided (used) by changes in current assets and liabilities:
Accounts and notes receivable		19		(92)		(33)
Inventories		7		56		(67)
Other current assets and deferred charges		25		(7)		35
Accounts payable		(89)		138		35
Accrued liabilities		(8)		60		105
Affiliate accounts receivable and payable – net		49		(97)		81
Other, including changes in noncurrent assets and liabilities		69		100		-
Net cash provided by operating activities		2,018		2,290		1,922
FINANCING ACTIVITIES:
Proceeds from long-term debt		2,639		1,596		5,029
Payments of long-term debt		(1,440)		(1,184)		(1,203)
Payment of debt issuance costs		(12)		(16)		(66)
Proceeds from sales of common units		2,559		-		806
General partner contributions		93		31		29
Dividends paid to noncontrolling interests		-		-		(18)
Distributions to limited partners and general partner		(1,440)		(1,124)		(660)
Excess of purchase price over contributed basis of business and investment		-		(123)		(244)
Distributions to The Williams Companies, Inc. – net		(17)		(99)		(251)
Other – net		30		1		(4)
Net cash provided (used) by financing activities		2,412		(918)		3,418
INVESTING ACTIVITIES:
Purchase of businesses and investments from affiliates		(25)		(174)		(3,884)
Property, plant and equipment:
Capital expenditures		(2,112)		(1,005)		(844)
Net proceeds from dispositions		22		5		64
Purchases of businesses		(2,049)		(41)		(150)
Purchases of and contributions to equity method investments		(471)		(197)		(476)
Purchase of ARO trust investments		(34)		(41)		(47)
Proceeds from sale of ARO trust investments		43		56		31
Other – net		53