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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K


(Mark One)
☑		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2010
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number 1-4174

The Williams Companies, Inc.

(Exact Name of Registrant as Specified in Its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		73-0569878 (IRS Employer Identification No.)

One Williams Center, Tulsa, Oklahoma (Address of Principal Executive Offices)		74172 (Zip Code)

918-573-2000

(Registrant's Telephone Number, Including Area Code)

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


		Name of Each Exchange
Title of Each Class		on Which Registered

Common Stock, $1.00 par value		New York Stock Exchange
Preferred Stock Purchase Rights		New York Stock Exchange

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

5.50% Junior Subordinated Convertible Debentures due 2033

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

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

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 ☑ No o

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 ☑ No o

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

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant's most recently completed second quarter was approximately $10,683,141,499.

The number of shares outstanding of the registrant's common stock outstanding at February 21, 2011 was 586,207,919.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's Definitive Proxy Statement for the Registrant's 2011 Annual Meeting of Stockholders to be held on May 19, 2011, are incorporated into Part III, as specifically set forth in Part III.

THE WILLIAMS COMPANIES, INC.
FORM 10-K
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			Page

PART I
	Item 1.	Business		1
		Website Access to Reports and Other Information		1
		General		1
		Change in Structure and Dividend Increase		1
		Financial Information About Segments		2
		Business Segments		2
		Williams Partners		2
		Exploration & Production		10
		Other		16
		Additional Business Segment Information		17
		Regulatory Matters		17
		Environmental Matters		19
		Competition		20
		Employees		21
		Financial Information about Geographic Areas		21
	Item 1A.	Risk Factors		21
	Item 1B.	Unresolved Staff Comments		38
	Item 2.	Properties		38
	Item 3.	Legal Proceedings		39
		Executive Officers of the Registrant		39

PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		42
	Item 6.	Selected Financial Data		43
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations		44
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		78
	Item 8.	Financial Statements and Supplementary Data		80
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		151
	Item 9A.	Controls and Procedures		151
	Item 9B.	Other Information		151

PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		151
	Item 11.	Executive Compensation		152
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		152
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		152
	Item 14.	Principal Accountant Fees and Services		152

PART IV
	Item 15.	Exhibits and Financial Statement Schedules		153
EX-10.5
EX-10.6
EX-10.7
EX-10.8
EX-24
EX-10.25
EX-12
EX-21
EX-23.1
EX-23.2
EX-23.3
EX-23.4
EX-24
EX-31.1
EX-31.2
EX-32
EX-99.1
EX-99.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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DEFINITIONS

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

Barrel - means one barrel of petroleum products that equals 42 U.S. gallons.

Bcfe - means one billion cubic feet of gas equivalent determined using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

Bcf/d - means one billion cubic feet per day.

British Thermal Unit or BTU - means a unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit.

BBtud - means one billion BTUs per day.

Dekatherms or Dth or Dt - means a unit of energy equal to one million BTUs.

Mbbls/d - means one thousand barrels per day.

Mcfe - means one thousand cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

Mdt/d - means one thousand dekatherms per day.

MMboe - means one million barrels of oil equivalent.

MMBtu - means one million Btus.

MMBtu/d - means one million Btus per day.

MMcf - means one million cubic feet.

MMcf/d - means one million cubic feet per day.

MMcfe - means one million cubic feet of gas equivalent using the ratio of one barrel of oil or condensate to six thousand cubic feet of natural gas.

MMdt - means one million dekatherms or approximately one trillion BTUs.

MMdt/d - means one million dekatherms per day.

TBtu - means one trillion BTUs.

Other definitions:

FERC - means Federal Energy Regulatory Commission.

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

LNG - means liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures.

NGL - means 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 - means NGL revenues less Btu replacement cost, plant fuel, transportation and fractionation.

Throughput - means the volume of product transported or passing through a pipeline, plant, terminal or other facility.

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PART I


Item 1.	*Business*

In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise requires, all of our subsidiaries) is at times referred to in the first person as "we," "us" or "our." We also sometimes refer to Williams as the "Company."

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, proxy statements and other documents electronically with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934, as amended (Exchange Act). You may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. You may also obtain such reports from the SEC's Internet website at http://www.sec.gov.

Our Internet website is http://www.williams.com. We make available free of charge through the Investor tab of 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 Ethics for Senior Officers, Board committee charters and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

GENERAL

We are primarily an integrated natural gas company originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. We were founded in 1908 when two Williams brothers began a construction company in Fort Smith, Arkansas. Today, we primarily find, produce, gather, process and transport natural gas. Our operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Eastern Seaboard, and the province of Alberta in Canada.

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

CHANGE IN STRUCTURE AND DIVIDEND INCREASE

On February 16, 2011, we announced that our Board of Directors approved pursuing a plan to separate the company into two standalone, publicly traded corporations. The plan calls for the separation of our exploration and production business into a publicly traded company via an initial public offering of up to 20 percent of our interest in the third quarter of 2011. We intend to complete the offering so that it preserves our ability to complete a tax-free spinoff of our remaining ownership in the exploration and production business to Williams' shareholders in 2012, after which Williams would continue as a premier natural gas infrastructure company. We retain the discretion to determine whether and when to execute the spinoff.

Additionally, we intend to increase the quarterly dividend paid to our shareholders, with an initial increase of 60 percent (to $0.20 per share), for the first quarter of 2011 payable in June 2011.

Management believes these actions will serve to enhance the growth potential and overall valuation of our assets.

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FINANCIAL INFORMATION ABOUT SEGMENTS

See " Item 8 - Financial Statements and Supplementary Data - Notes to Consolidated Financial Statements - Note 18 " for information with respect to each segment's revenues, profits or losses and total assets.

BUSINESS SEGMENTS

Substantially all our operations are conducted through our subsidiaries. To achieve organizational and operating efficiencies, our activities in 2010 were primarily operated through the following business segments:


	•	Williams Partners - comprised of our master limited partnership Williams Partners L.P. (WPZ), which includes gas pipeline and domestic midstream businesses. The gas pipeline business includes interstate natural gas pipelines and pipeline joint venture investments, and the midstream business provides natural gas gathering, treating and processing services; NGL production, fractionation, storage, marketing and transportation; deepwater production handling and crude oil transportation services and is comprised of several wholly owned and partially owned subsidiaries and joint venture investments.

	•	Exploration & Production - produces, develops, and manages natural gas and oil primarily located in the Rocky Mountain, Northeast and Mid-Continent regions of the United States and is comprised of several wholly owned and partially owned subsidiaries including Williams Production Company, LLC and Williams Production RMT Company, LLC. This segment also includes our 69 percent equity interest in Apco Oil and Gas International Inc., as well as gas marketing services which manage our natural gas commodity risk through purchases, sales and other related transactions, under our wholly owned subsidiary Williams Gas Marketing, Inc.

	•	Other - includes other business activities that are not operating segments, primarily our Canadian midstream and domestic olefins operations and a 25.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), as well as corporate operations.

This report is organized to reflect this structure.

Due to expected future growth in our Canadian midstream and domestic olefins operations, we are considering reporting these businesses as a separate segment beginning in the first quarter of 2011.

Detailed discussion of each of our business segments follows.

Williams Partners

Gas Pipeline Business

Williams Partners owns and operates a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,800 TBtu of natural gas and peak-day delivery capacity of approximately 13 MMdt of natural gas. Our gas pipeline businesses consist primarily of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline). Our gas pipeline business also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 24.5 percent interest in Gulfstream. The gas pipeline businesses contributed revenues of approximately 28 percent, 35 percent and 28 percent of Williams Partners' revenues in 2010, 2009, and 2008, respectively. During third quarter 2010, Williams Partners L.P. completed a merger with Williams Pipeline Partners L.P. (WMZ). All of WMZ's common and subordinated units have been extinguished and WMZ is wholly owned by Williams Partners. WMZ has been delisted and is no longer publicly traded.

Transco

Transco is an interstate natural gas transportation company that owns and operates a 10,000-mile natural gas pipeline system extending from Texas, Louisiana, Mississippi and the offshore Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 11 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., New York, New Jersey and Pennsylvania.

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Pipeline system and customers

At December 31, 2010, Transco's system had a mainline delivery capacity of approximately 4.9 MMdt of natural gas per day from its production areas to its primary markets. Using its Leidy Line along with market-area storage and transportation capacity, Transco can deliver an additional 3.9 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.8 MMdt 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 it owns and operates. 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 billion cubic feet of gas. At December 31, 2010, our customers had stored in our facilities approximately 154 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, a LNG storage facility with 4 billion cubic feet 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.

Transco expansion projects

The pipeline projects listed below were completed during 2010 or are future significant pipeline projects for which Transco has customer commitments.

Mobile Bay South

The Mobile Bay South Expansion Project involved the addition of compression at Transco's Station 85 in Choctaw County, Alabama, to allow Transco to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009, Transco received approval from the Federal Energy Regulatory Commission (FERC). The capital cost of the project was $32 million. The project was placed into service in May 2010 and increased capacity by 254 Mdt/d.

Mobile Bay South II

The Mobile Bay South II Expansion Project involves the addition of compression at Transco's Station 85 in Choctaw County, Alabama, and modifications to existing facilities at Transco's Station 83 in Mobile County, Alabama, to allow Transco to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In July 2010 Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $35 million, and it will increase capacity by 380 Mdt/d. Transco plans to place the project into service by May 2011.

85 North

The 85 North Expansion Project involves an expansion of Transco's existing natural gas transmission system from Station 85 in Choctaw County, Alabama, to various delivery points as far north as North Carolina. In September 2009, Transco received approval from the FERC. The capital cost of the project is estimated to be approximately $236 million, and it will increase capacity by 309 Mdt/d. The first phase for 90 Mdt/d, was placed into service in July 2010, and the second phase is expected to be placed into service in May 2011.

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Mid-South

The Mid-South Expansion Project involves an expansion of Transco's mainline from Station 85 in Choctaw County, Alabama, to markets as far downstream as North Carolina. In October 2010 Transco filed an application with the FERC. The capital cost of the project is estimated to be approximately $219 million. Transco plans to place the project into service in phases in September 2012 and June 2013, and it will increase capacity by 225 Mdt/d.

Mid-Atlantic Connector Project

The Mid-Atlantic Connector Project involves an expansion of Transco's mainline from an existing interconnection in North Carolina to markets as far downstream as Maryland. In November 2010 Transco filed an application with the FERC. The capital cost of the project is estimated to be approximately $55 million. Transco plans to place the project into service in November 2012, and it will increase capacity by 142 Mdt/d.

Rockaway Delivery Lateral Project

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to a distribution system in New York. Transco anticipates filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $159 million. Transco plans to place the project into service as early as November 2013, and its capacity will be 647 Mdt/d.

Northeast Supply Link Project

The Northeast Supply Link Project involves an expansion of Transco's 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. Transco anticipates filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $341 million. Transco plans to place the project into service in November 2013, and it will increase capacity by 250 Mdt/d.

Northwest Pipeline

Northwest Pipeline is an interstate natural gas transportation company that owns and operates a natural gas pipeline system extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in California, Arizona, New Mexico, Colorado, Utah, Nevada, Wyoming, Idaho, Oregon and Washington directly or indirectly through interconnections with other pipelines.

Pipeline system and customers

At December 31, 2010, Northwest Pipeline's system, having long-term firm transportation agreements including peaking service of approximately 3.8 Bcf of natural gas per day, was composed of approximately 3,900 miles of mainline and lateral transmission pipelines and 41 transmission compressor stations having a combined sea level-rated capacity of approximately 477,000 horsepower.

Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. Northwest Pipeline's firm transportation and storage contracts are generally long-term contracts with various expiration dates and account for the major portion of Northwest Pipeline's business. Additionally, Northwest Pipeline offers interruptible and short-term firm transportation service.

Northwest Pipeline owns a one-third interest in the Jackson Prairie underground storage facility in Washington and contracts with a third party for storage service in the Clay basin underground field in Utah. Northwest Pipeline also owns and operates an LNG storage facility in Washington. These storage facilities have an aggregate working gas storage capacity of 13.2 Bcf of natural gas, which is substantially utilized for third-party natural gas, and firm

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delivery capability of approximately 700 MMcf/d enable Northwest Pipeline to provide storage services to its customers and to balance daily receipts and deliveries.

Northwest Pipeline expansion project

Sundance Trail

In November 2009, we received approval from the FERC to construct approximately 16 miles of 30-inch pipeline between our existing compressor stations in Wyoming as well as an upgrade to an existing Vernal, Utah compressor station. The total estimated cost of the project is approximately $50 million. We placed the project in service in November 2010 with an increase in capacity of 150 Mdt/d.

Gulfstream

Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. Williams Partners owns, through a subsidiary, a 24.5 percent interest in Gulfstream while we own a 25.5 percent interest through a subsidiary. Spectra Energy Corporation, through its subsidiary, and Spectra Energy Partners, LP, own the additional 50 percent interest. Williams Partners shares operating responsibilities for Gulfstream with Spectra Energy Corporation.

Gulfstream expansion projects

The Gulfstream Phase V expansion involves the addition of compression to provide 35 Mdt/d of firm capacity by April 2011. The estimated capital cost of this expansion is approximately $44 million with Williams Partners' share being 24.5 percent of such cost.

Midstream Business

Williams Partners' midstream business, one of the nation's largest natural gas gatherers and processors, has primary service areas concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico and Pennsylvania. The primary businesses - natural gas gathering, treating, and processing; NGL fractionation, storage and transportation; and oil transportation - 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 this 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 core service areas and new step-out areas;

	•	Prices impacting commodity-based processing activities.

The midstream business revenue contributed approximately 72 percent, 66 percent and 72 percent of Williams Partners' revenues in 2010, 2009 and 2008, respectively.

One of our midstream customers, ONEOK Hydrocarbon LP, accounted for 10 percent of our consolidated revenues in 2010. These revenues were generated by our NGL marketing business. There were no customers for which our sales exceeded 10 percent of our consolidated revenues in 2009 and 2008.

Gathering, processing and treating

Williams Partners' 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. In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural

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gas stream. Processing and treating plants remove water vapor, carbon dioxide and other contaminants and extract the NGLs. NGL products include:


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

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

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

Although a significant portion of Williams Partners' gas processing services are performed for a volumetric-based fee, a portion of our gas processing agreements are commodity-based and include two distinct types of commodity exposure. The first type includes "keep-whole" processing agreements whereby we own the rights to the value from NGLs recovered at our plants and we have the obligation to replace the lost heating value with natural gas. Under these agreements, we are exposed to the spread between NGL prices and natural gas prices. The second type consists of "percent-of-liquids" agreements whereby we receive a portion of the extracted liquids with no direct exposure to the price of natural gas. Under these agreements, we are only exposed to NGL price movements. NGLs we retain in connection with both of these types of processing agreements are referred to as our equity NGL production. 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.

Williams Partners' gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding its infrastructure. During 2010, these operations gathered and processed gas for approximately 215 gas gathering and processing customers. Williams Partners' top 6 gathering and processing customers, one of which is an affiliate, accounted for approximately 50 percent of our gathering and processing revenue.

In addition to natural gas assets, Williams Partners owns and operates four deepwater crude oil pipelines and owns two production platforms serving the deepwater in the Gulf of Mexico. The crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of its marketing revenues are recognized from purchase and sale arrangements whereby the oil that Williams Partners transports is purchased and sold as a function of the same index-based price. Williams Partners' 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.

Geographically, the midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of the offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Also, the gathering and processing facilities in the San Juan and Piceance basins handle approximately 92 percent of our Exploration & Production segment's equity production in these basins. The San Juan basin, southwest Wyoming and Willow Creek systems deliver residue gas volumes into Northwest Pipeline's interstate system in addition to third-party interstate systems.

Onshore region gathering, processing and treating

Williams Partners owns and/or operates gas gathering, processing and treating assets within the states of Wyoming, Colorado, New Mexico and Pennsylvania.

In the Rocky Mountain area, the assets include:


	•	Approximately 3,500 miles of gathering pipelines with a capacity of nearly 1 Bcf/d and over 4,000 receipt points serving the Wamsutter and southwest Wyoming areas in Wyoming;

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	•	Opal and Echo Springs processing plants with a combined daily inlet capacity of over 2.2 Bcf/d and NGL processing capacity of nearly 125 Mbbls/d, including the addition of a fourth cryogenic processing train at the Echo Springs plant which began processing in the fourth quarter of 2010.

In the Four Corners area, the assets include:


	•	Approximately 3,800 miles of gathering pipelines with a capacity of nearly 2 Bcf/d and approximately 6,500 receipt points serving the San Juan basin in New Mexico and Colorado;

	•	Ignacio, Kutz and Lybrook processing plants with a combined daily inlet capacity of 765 MMcf/d and NGL processing capacity of approximately 40 Mbbls/d. The Ignacio plant also has the capacity to produce slightly more than 1 Mbbls/d of liquefied natural gas (LNG);

	•	Milagro and Esperanza natural gas treating plants, which remove carbon dioxide but do not extract NGLs, with a combined daily inlet capacity of 750 MMcf/d. At our Milagro 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.

In the Piceance basin in Colorado, the assets include:


	•	The Willow Creek processing plant, a 450 MMcf/d cryogenic natural gas processing plant in western Colorado's Piceance basin, designed to recover 30 Mbbls/d of NGLs. The plant is currently operating at its designed inlet capacity. In the current processing arrangement with our Exploration & Production segment, Williams Partners receives a volumetric-based processing fee and a percent of the NGLs extracted.

	•	Approximately 150 miles of gathering pipeline and the Parachute Plant Complex along with three other treating facilities with a combined processing capacity of 1.2 Bcf/d, acquired in the fourth quarter of 2010 from Exploration & Production.

	•	Parachute Lateral, a 38-mile, 30-inch diameter line transporting gas from the Parachute area to the Greasewood hub and White River hub in northwest Colorado. The Willow Creek plant processes gas flowing through the Parachute Lateral.

	•	PGX pipeline delivering NGLs from our Exploration & Production segment's existing Parachute area processing plants to a major NGL transportation pipeline system.

In the Appalachian basin in Pennsylvania, the assets include:


	•	Approximately 75 miles of gathering pipelines and two compressor stations in Susquehanna County, Pennsylvania in the Marcellus Shale, acquired in the fourth quarter of 2010. Williams Partners has agreed to a new long-term dedicated gathering agreement with the seller for its production in the northeast Pennsylvania area of the Marcellus Shale. The acquired system will connect into the Transco pipeline with our 33-mile, 24-inch diameter Springville gathering pipeline. Construction on the Springville pipeline is expected to begin in the first quarter of 2011 and be completed during 2011.

Gulf region gathering, processing and treating

Williams Partners' owns and/or operates gas gathering and processing assets and crude oil pipelines primarily within the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi, and Alabama. This includes:


	•	Nearly 800 miles of onshore and offshore natural gas gathering pipelines with a combined capacity of approximately 3.7 Bcf/d, including:


	•	The 115-mile deepwater Seahawk gas pipeline in the western Gulf of Mexico, flowing into the Markham processing plant and serving the Boomvang and Nansen field areas;

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	•	The 105-mile deepwater Perdido Norte gas pipeline in the western Gulf of Mexico, which began transporting gas in the third quarter of 2010 from a third-party producers' floating production facility in to the Seahawk gathering system, which flows into Williams Partners' Markham processing plant;

	•	The 139-mile Canyon Chief gas pipeline, including the Blind Faith extension in the eastern Gulf of Mexico, flowing into the Mobile Bay processing plant and serving the Devils Tower, Triton, Goldfinger, Bass Lite and Blind Faith fields;


	•	Mobile Bay and Markham processing plants with a combined daily inlet capacity of 1.2 Bcf/d and NGL handling capacity of 75 Mbbls/d, including the 2010 expansion of the Markham plant to accommodate production volumes from the Perdido Norte gas pipeline;

	•	Canyon Station production platform, which brings natural gas to specifications allowable by major interstate pipelines but does not extract NGLs, with a daily inlet capacity of 500 MMcf/d;

	•	Four deepwater crude oil pipelines with a combined length of nearly 400 miles and capacity of 475 Mbbls/d including:


	•	BANJO pipeline running parallel to the Seahawk gas pipeline delivering production from two producer-owned spar-type floating production systems; and delivering production to the shallow-water platform at Galveston Area Block A244 (GA-A244) and then onshore through the Hoover Offshore Oil Pipeline System (HOOPS);

	•	Perdido Norte pipeline running parallel to the Perdido Norte gas pipeline which began transporting oil in the third quarter of 2010 from a third-party producers' floating production facility and then onshore through HOOPS;

	•	Alpine pipeline in the central Gulf of Mexico, serving the Gunnison field, and delivering production to GA-A244 and then onshore through HOOPS under a joint tariff agreement;

	•	Mountaineer pipeline, including the Blind Faith extension, which connects to similar production sources as our Canyon Chief pipeline, ultimately delivering production to a terminal in Plaquemines Parish, Louisiana;


	•	Devils Tower production platform located in Mississippi Canyon Block 773, approximately 150 miles south-southwest of Mobile, Alabama and serving production from the Devils Tower, Triton, Goldfinger and Bass Lite fields. Located in 5,610 feet of water, it is one of the world's deepest dry tree spars. The platform, which is operated by another party, is capable of handling 210 MMcf/d of natural gas and 60 Mbbls/d of oil.

NGL marketing services

In addition to Williams Partners' gathering and processing operations, we market NGL products to a wide range of users in the energy and petrochemical industries. The NGL marketing business transports and markets equity NGLs from the production at its processing plants, and also markets NGLs on behalf of third-party NGL producers, including some of its fee-based processing customers, and the NGL volumes owned by Discovery Producer Services LLC (Discovery). The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, Williams Partners may purchase products in the spot market for resale. The majority of sales are based on supply contracts of one year or less in duration.

Other Partially Owned Operations

Fractionation and Storage

Williams Partners owns interests in and/or operates 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

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of 60 Mbbls/d. Williams Partners also fully owns approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

Overland Pass Pipeline

In September 2010, Williams Partners completed the $424 million acquisition of an additional 49 percent ownership interest in Overland Pass Pipeline (OPPL), which increased our ownership interest to 50 percent. As long as we retain a 50 percent ownership interest in OPPL, we have the right to become operator. We have notified our partner of our intent to operate and are currently working on an early 2011 transition. OPPL includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Joules basins in Colorado, respectively. Williams Partners' 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 shipping agreement.

Discovery

Williams Partners owns a 60 percent equity interest in and operates 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

Williams Partners owns 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 1,000 miles of pipeline with a fourth quarter 2010 average throughput of approximately 125 MMcf/d. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with some exposure to natural gas prices, to gather the production of its joint venture partner's production in the northeast Pennsylvania area of the Marcellus Shale. Construction began in 2010 on numerous new pipeline segments and compressor stations, the largest of which is the Shamrock compressor station. The Shamrock compressor station will have an initial capacity of 60 MMcf/d, expandable to 350 MMcf/d, which will likely be the largest central delivery point out of the Laurel Mountain system.

Aux Sable

Williams Partners also owns a 14.6 percent equity interest in Aux Sable Liquid Products 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 92 Mbbls/d of extracted liquids into NGL products.

Operating statistics

The following table summarizes our significant operating statistics for Midstream:


	2010		2009		2008

Volumes:(1)
Gathering (Tbtu)(3)		1,262		1,370		1,361
Plant inlet natural gas (Tbtu)		1,424		1,342		1,311
NGL production (Mbbls/d)(2)		174		164		154
NGL equity sales (Mbbls/d)(2)		80		80		80
Crude oil gathering (Mbbls/d)(2)		94		109		70


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

(2)		Annual average Mbbls/d.

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(3)		Amounts have been recast to reflect the November 2010 acquisition of certain gathering and processing assets in Colorado's Piceance basin from Exploration & Production.

Exploration & Production

Our Exploration & Production segment includes natural gas and oil development, production and gas marketing activities primarily located in the Rocky Mountain (primarily Colorado, North Dakota, New Mexico, and Wyoming), Northeast (Pennsylvania), and Mid-Continent (Oklahoma and Texas) regions of the United States. We specialize in production from tight-sands and shale formations and coal bed methane (CBM) reserves in the Piceance, Appalachian, Williston, San Juan, Powder River, Fort Worth, Green River and Arkoma basins. Almost 97 percent of our domestic proved reserves are natural gas. We also have international oil and gas interests, which include a 69 percent equity interest in Apco Oil and Gas International Inc., an oil and gas exploration and production company with operations in South America. If combined with our domestic proved reserves, our international interests would make up approximately 5 percent of our total proved reserves. Considering this, the reserves information included in this section relates only to our domestic activity. The gas marketing activities include transporting, scheduling, selling and hedging equity natural gas production as well as managing various natural gas related contracts such as transportation, storage and related hedges not utilized for our equity production. Additionally, Exploration & Production's marketing group procures all fuel and shrink requirements and manages transportation and hedging activities in support of our midstream business.

Our strategy is to continue to drill our existing proved undeveloped reserves, which comprise approximately 42 percent of proved reserves, and to drill in areas of probable and possible reserves in order to add to our proved reserves. Our current proved, probable, and possible reserves inventory provides us with strong capital investment opportunities for many years into the future.

Oil and Gas Reserves

The following table outlines our estimated net proved reserves expressed on a gas equivalent basis for the reporting periods December 31, 2010, 2009 and 2008. Proved reserves for 2010 and 2009 were prepared under rules issued by the SEC on January 14, 2009. We prepare our own reserves estimates and the majority of our December 31, 2010 reserves were audited by Netherland, Sewell & Associates (NSAI) or Miller and Lents, Ltd (M&L). Proved reserves information is reported as gas equivalents, since oil volumes are insignificant in the three years shown below. Reserves for 2010 are approximately 97 percent natural gas. Reserves are more than 99 percent natural gas for 2009 and 2008. Oil reserves increased to approximately 3 percent of total proved reserves in 2010 as a result of a fourth quarter acquisition of undeveloped acreage and producing properties located in the Williston basin.

Summary of oil and gas reserves:


	December 31,
	2010		2009		2008
	(Bcfe)(1)

Proved developed reserves		2,498		2,387		2,456
Proved undeveloped reserves		1,774		1,868		1,883

Total proved reserves		4,272		4,255		4,339


(1)		Gas equivalents are calculated using a ratio of 6 mcf of gas to 1 barrel of oil.

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	Proved Reserves
Basin	December 31, 2010
	(Bcfe)

Piceance		2,927
Powder River		348
San Juan		554
Fort Worth		196
Appalachian		28
Williston		136
Other		83

Total		4,272

We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than with the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC.

The 2010 year-end proved reserves were derived using the 12-month average, first-of-the-month Henry Hub spot price of $4.38 per MMbtu, adjusted for locational price differentials. During 2010, we added 508 Bcfe of net additions to our proved reserves through drilling 1,162 gross wells at a capital cost of approximately $988 million.

Reserves estimation process

Our reserves are estimated by deterministic methods by an appropriate combination of production performance analysis and volumetric techniques. The proved reserves for economic undrilled locations are estimated by analogy or volumetrically from offset developed locations. Reservoir continuity and lateral persistence of our tight-sands, shale and CBM reservoirs is established by combinations of subsurface analysis, 2D and 3D seismic, and pressure data. Understanding reservoir quality may be augmented by core samples analysis.

The engineering staff of each basin asset team provides the reserves modeling and forecasts for their respective areas. Various departments also participate in the preparation of the year-end reserves estimate by providing supporting information such as pricing, capital costs, expenses, ownership, gas gathering and gas quality. The departments and their roles in the year-end reserves process are coordinated by our reserves analysis department. The reserves analysis department's responsibilities also include performing an internal review of reserves data for reasonableness and accuracy, working with the third-party consultants and the asset teams to successfully complete the third-party reserves audit, finalizing the year-end reserves report, and reporting reserves data to accounting.

The preparation of our year-end reserves report is a formal process. Early in the year, we begin with a review of the existing internal processes and controls to identify where improvements can be made from the prior year's reporting cycle. Later in the year, the reserves staffs from the asset teams submit their preliminary reserves data to the reserves analysis department. After review by the reserves analysis department, the data is submitted to our third party engineering consultants, NSAI and M&L, to begin their audits. After this point, reserves data, analysis and further review are conducted and iterated between the asset teams, reserves analysis department and our third party engineering consultants. In early December, reserves are reviewed with senior management. The process concludes when all parties agree upon the reserve estimates and audit tolerance is achieved.

The reserves estimates resulting from our process are subjected to both internal and external controls to promote transparency and accuracy of the year-end reserves estimates. Our internal reserves analysis team is independent and does not work within an asset team or report directly to anyone on an asset team. The reserves analysis department provides detailed independent review and extensive documentation of the year-end process. Our internal processes and controls, as they relate to the year-end reserves, are reviewed and updated. The compensation of our reserves analysis team is not linked to reserves additions or revisions.

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Approximately 93 percent of our total year-end 2010 domestic proved reserves estimates were audited by NSAI. When compared on a well-by-well basis, some of our estimates are greater and some are less than the estimates of NSAI. However, in the opinion of NSAI, the estimates of our proved reserves are in the aggregate reasonable and have been prepared in accordance with principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is satisfied with our methods and procedures in preparing the December 31, 2010 reserves estimates and future revenue, and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us. The report of NSAI is included in Exhibit 99.1 to this Form 10-K.

In addition, reserves estimates related to properties associated with the former Williams Coal Seam Gas Royalty Trust were audited by M&L. These properties represent approximately 1 percent of our total domestic proved reserves estimates. The report of M&L is included in Exhibit 99.2 to this Form 10-K.

The technical person primarily responsible for overseeing preparation of the reserves estimates and the third- party reserves audit is the Director of Reserves and Production Services. The Director's qualifications include 28 years of reserves evaluation experience, a B.S. in geology from the University of Texas at Austin, an M.S. in Physical Sciences from the University of Houston, and membership in the American Association of Petroleum Geologists and The Society of Petroleum Engineers.

Proved undeveloped reserves (PUDs)

The majority of our reserves is concentrated in unconventional tight-sands, shale and coal bed gas reservoirs. We use available geoscience and engineering data to establish drainage areas and reservoir continuity beyond one direct offset from a producing well, which provides additional proved undeveloped reserves. Inherent in the methodology is a requirement for significant well density of economically producing wells to establish reasonable certainty. In fields where producing wells are less concentrated, only direct offsets from proved producing wells were assigned the proved undeveloped reserves classification. No new technologies were used to assign proved undeveloped reserves.

At December 31, 2010, our proved undeveloped reserves were 1,774 Bcfe - a decrease of 94 Bcfe over our December 31, 2009 proved undeveloped reserves estimate of 1,868 Bcfe. During 2010, 280 Bcfe of our December 31, 2009 proved undeveloped reserves were converted to proved developed reserves. An additional 129 Bcfe was added due to the development of unproved locations. We have reclassified a net 253 Bcfe from proved to probable reserves attributable to locations not expected to be developed within five years. This amount is predominantly in the Piceance basin where the company has a large inventory of drilling locations. The downward revision has been offset by the addition of 342 Bcfe of new proved undeveloped drilling locations.

All proved undeveloped locations are scheduled to be spud within the next five years. Our five-year forecast indicates increasing capital to allow for the addition of rigs in years 2013-2015 in the Piceance basin. Our undeveloped estimate contains 91 Bcfe of aging PUDs. The majority of these are scheduled to be spud by year-end 2011.

Oil and Gas Properties and Production, Production Prices, and Production Costs

The following table summarizes our domestic sales volumes for the years indicated:


	2010		2009		2008
	(Bcfe)

Piceance		245.9		254.6		237.7
Powder River		83.8		88.9		83.6
San Juan		51.5		53.1		52.8
Fort Worth		21.5		25.2		16.6
Appalachian		1.8		0.1		-
Williston		0.1		-		-
Other		8.5		9.6		9.7

Total net production sold		413.1		431.5		400.4

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The following table summarizes our domestic price and cost information for the years indicated and has been recast for the sale of certain of our gathering and processing assets in the Piceance basin to Williams Partners in November 2010:


	2010		2009		2008
	($/Mcfe)

Average production costs excluding production taxes(1)	$	0.59	$	0.50	$	0.56

Average sales price(2)	$	4.42	$	3.42	$	6.95
Realized gain from hedging	$	0.81	$	1.43	$	0.09

Realized Average Price	$	5.23	$	4.85	$	7.04


(1)		Includes lease and other operating expense and facility operating expense.

(2)		Not reduced for gathering, processing, and transportation paid to affiliates and third parties of $1.02 in 2010, $0.79 in 2009, and $0.71 in 2008.

Drilling and Exploratory Activities

We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in each of 2010, 2009, and 2008.

The following table summarizes domestic drilling activity by number and type of well for the periods indicated:*


	2010				2009				2008
	Gross Wells		Net Wells		Gross Wells		Net Wells		Gross Wells		Net Wells

Piceance		398		360		349		303		687		624
Powder River		531		242		233		95		702		324
San Juan		43		15		77		39		95		37
Fort Worth		39		36		43		41		58		51
Appalachian		8		3		8		4		n/a		n/a
Williston		-		-		n/a		n/a		n/a		n/a
Other		138		2		165		4		240		14
Productive exploration		-		-		3		1		4		2
Nonproductive, including exploration		5		3		4		1		1		-

Total		1,162		661		882		488		1,787		1,052


*		We use the terms "gross" to refer to all wells or acreage in which we have at least a partial working interest and "net" to refer to our ownership represented by that working interest. All of the wells drilled were natural gas wells.

In 2010, there were 5 gross nonproductive development wells and 3 net nonproductive development wells. Total gross operated wells drilled were 656 in 2010, 472 in 2009, and 1,125 in 2008.

Present Activities

At December 31, 2010, we had 27 gross (16 net) wells in the process of being drilled.

Delivery Commitments

We hold a long-term obligation to deliver on a firm basis 200,000 MMBtu/d of gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance basin. The Piceance, being our largest producing basin, holds ample reserves to fulfill this obligation without risk of nonperformance during periods of normal infrastructure and market operations. While the daily volume of gas

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is large and represents a significant percentage of our daily production, this transaction does not represent a material exposure.

Purchase Commitments

In connection with a gathering agreement entered into by Williams Partners with a third party in December 2010, we concurrently agreed to buy up to 200,000 MMBtu/d of natural gas priced at market prices from the same third party. Purchases under the 12-year contract are expected to begin in the third quarter of 2011. We expect to sell this natural gas in the open market and may utilize available transportation capacity to facilitate the sales.

Oil and Gas Properties, Wells, Operations, and Acreage

The table below summarizes 2010 productive wells by area:*


	Gas Wells		Gas Wells		Oil Wells		Oil Wells
	(Gross)		(Net)		(Gross)		(Net)

Piceance		3,923		3,587		-		-
Powder River		6,404		2,884		-		-
San Juan		3,267		881		-		-
Fort Worth		286		233		-		-
Appalachian		14		6		-		-
Williston		-		-		19		13
Other		1,340		299		-		-

Total		15,234		7,890		19		13


*		We use the term "gross" to refer to all wells or acreage in which we have at least a partial working interest and "net" to refer to our ownership represented by that working interest.

At December 31, 2010, there were 181 gross and 105 net producing wells with multiple completions.

The following table summarizes our leased acreage as of December 31, 2010:


	Developed				Undeveloped				Total
	Gross Acres		Net Acres		Gross Acres		Net Acres		Gross Acres		Net Acres

Piceance		133,428		102,835		157,017		108,165		290,445		211,000
Powder River		551,113		250,179		399,869		175,371		950,982		425,550
San Juan		237,587		119,422		2,100		1,576		239,687		120,998
Fort Worth		28,876		21,173		12,306		8,309		41,182		29,482
Appalachian		1,828		914		108,023		98,387		109,851		99,301
Williston		16,178		13,483		229,640		190,148		245,818		203,631
Other		120,538		60,559		199,077		118,734		319,615		179,293

Total		1,089,548		568,565		1,108,032		700,690		2,197,580		1,269,255

Piceance basin

The Piceance basin is located in northwestern Colorado and is our largest area of concentrated development. During 2010, we operated an average of 11 drilling rigs in the basin. This area has 1,567 undrilled proved locations in inventory. During 2010, an average of approximately 6.3 million gallons of NGLs were recovered each month at plants now owned and operated within Williams Partners, which were marketed separately from the residue natural gas.

Powder River basin

The Powder River basin is located in northeast Wyoming. The Powder River basin includes large areas with multiple coal seam potential, targeting thick coal bed methane formations at shallow depths.

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San Juan basin

The San Juan basin is located in northwest New Mexico and southwest Colorado. We provide a significant amount of equity production that is gathered and/or processed by Williams Partners' facilities in the San Juan basin.

Fort Worth basin

The Fort Worth basin is located in north central Texas where we drill horizontally into the Barnett Shale.

Appalachian basin

The Appalachian basin acreage is primarily located in northeastern Pennsylvania where we apply horizontal drilling in the Marcellus Shale. We have continued to expand our position since our entry into the basin in 2009.

Williston basin

The Williston basin acreage is located in North Dakota and Montana. Our focus in the basin is in North Dakota's Bakken/Three Forks oil play where we have a 89,420 net acreage position, of which approximately 85,800 were acquired in December 2010 and are on the Fort Berthold Indian Reservation.

Other properties

Other properties are primarily comprised of interests in the Arkoma basin in southeastern Oklahoma. Also included are exploration activity and other miscellaneous activity.

Hedging Activity

To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative contracts for a portion of our expected future production. See further discussion in Management's Discussion and Analysis of Financial Condition and Results of Operations - Exploration & Production , included in Item 7 of this Form 10-K

Acquisitions & Divestitures

During the second quarter of 2010, we entered into an agreement to acquire additional Appalachian leasehold acreage positions and a 5 percent overriding royalty interest associated with these acreage positions. These acquisitions nearly double our acreage holdings in the Marcellus Shale and closed in July for $599 million, including closing adjustments.

During 2010, we also spent a total of $164 million to acquire additional unproved leasehold acreage positions in the Marcellus Shale.

In October 2010, we exercised our right under the Williams Coal Seam Gas Royalty Trust Agreement to acquire the royalty interests for $22 million, including closing adjustments upon termination of the the Trust. Prior to the purchase, the Trust owned net profits interests in certain proved coal seam gas properties owned by Williams Production Company, LLC (WPC) and located in the San Juan basin.

In November 2010, we sold certain of our gathering and processing assets in Colorado's Piceance basin to Williams Partners for $702 million in cash and approximately 1.8 million common units. The assets include the Parachute Plant Complex, three other treating facilities with a combined processing capacity of 1.2 Bcf/d, and a gathering system with approximately 150 miles of pipeline. There are more than 3,300 wells connected to the gathering system, which includes pipelines ranging up to 30-inch trunk lines. The transaction also includes a life-of-lease dedication from Exploration & Production.

In December 2010, we acquired a company that holds a major acreage position (approximately 85,800 net acres and includes 19 producing wells) in North Dakota's Bakken Shale oil play (Williston basin) that will diversify our interests into light, sweet crude oil production. The purchase price was approximately $949 million, including closing adjustments.

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Other

Domestic olefins

In the Gulf of Mexico region, we own a 5/6 interest in and are the operator of an NGL light-feed olefins cracker in Geismar, Louisiana, with 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, we 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. Additionally, we own a refinery grade propylene splitter and associated pipeline with 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 we are 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. Our olefins business also operates an ethylene storage hub at Mont Belvieu using leased third-party underground storage wells.

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

Canadian midstream

Our Canadian operations include an oil sands off-gas processing plant located near Ft. McMurray, Alberta, and an olefin fractionation facility and a butylene/butane splitter facility, both of which are located at Redwater, Alberta, which is near Edmonton, Alberta. We operate the Ft. McMurray area processing plant, while another party operates the Redwater facilities on our behalf. The butylene/butane splitter was completed and placed into service in August 2010. Our Ft. McMurray area facilities extract liquids from the off-gas produced by a third-party oil sands bitumen upgrading process. Our arrangement with the third-party upgrader is a "keep-whole" type where we remove a mix of NGLs and olefins from the off-gas and return the equivalent heating value back in the form of natural gas. We fractionate, treat, store, terminal and sell the propane, propylene, butane, butylene and condensate recovered from this process. Our commodity price exposure is the spread between the price for natural gas and the NGL and olefin products we produce. We continue to be the only NGL/olefins fractionator in western Canada and the only treater/processor of oil sands upgrader off-gas. Our extraction of liquids from upgrader off-gas streams allows the upgraders to burn cleaner natural gas streams and reduces their overall air emissions.

The Ft. McMurray extraction plant has processing capacity of 111 MMcf/d with the ability to recover in excess of 17 Mbbls/d of olefin and NGL products. Our Redwater fractionator has a liquids handling capacity of 18 Mbbls/d. The new butylene/butane splitter, which has a production capacity of 3.7 Mbbls/d of butylene and 3.7 Mbbls/d of normal butane, further fractionates the butylene/butane mix product produced at our Redwater fractionators into separate butylene and butane products, which receive higher values and are in greater demand. Our products are sold within Canada and the United States.

Canadian expansion project

Construction began in 2010 on a 261-mile, 12-inch diameter Canadian pipeline which will transport recovered NGLs and olefins from our processing plant in Ft. McMurray to our Redwater fractionation facility. The pipeline will have sufficient capacity to transport additional NGLs and olefins from our existing operations as well as from other NGLs and olefins produced from oil sands off-gas. The project will be constructed using cash previously generated from Canadian and other international projects. We anticipate an in-service date in 2012.

Other

Considering the deteriorating circumstances in Venezuela, in 2009 we fully impaired our $75 million investment in Accroven SRL, a Venezuelan operation, which included two 400 MMcf/d NGL extraction plants, a 50 Mbbls/d NGL fractionation plant and associated storage and refrigeration facilities. (See Note 2 of Notes to Consolidated Financial Statements.) In June of 2010, we sold our 50 percent interest in Accroven to the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA) for $107 million. Of this amount, $13 million was received in cash at closing and another $30 million was received in August 2010. The remainder is due in six quarterly

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payments beginning October 31, 2010. The first quarterly payment of $11 million was received in January 2011 and will be recognized as income in 2011. We will continue to recognize the resulting gain as cash is received. Accroven was not part of our operations that were expropriated by the Venezuelan government in May 2009.

Operating statistics

The following table summarizes our significant operating statistics for Other:


	2010		2009		2008

Volumes:
Canadian NGL equity sales (Mbbls/d)		8		8		7
Olefin (ethylene and propylene) sales (millions of pounds)		1,529		1,728		1,605

Additional Business Segment Information

Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and notes to financial statements included in Part II.

Operations related to certain assets in "Discontinued Operations" have been reclassified from their traditional business segment to "Discontinued Operations" in the accompanying financial statements and notes to financial statements included in Part II.

We perform certain management, legal, financial, tax, consultation, information technology, administrative and other services for our subsidiaries.

Our principal sources of cash are from dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, interest payments from subsidiaries on cash advances and, if needed, external financings, sales of master limited partnership units to the public, and net proceeds from asset sales. The amount of dividends available to us from subsidiaries largely depends upon each subsidiary's earnings and operating capital requirements. The terms of certain of our subsidiaries' borrowing arrangements may limit the transfer of funds to us under certain conditions.

We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. In support of our energy commodity activities, primarily conducted through gas marketing services which is included within our Exploration & Production segment, our counterparties require us to provide various forms of credit support such as margin, adequate assurance amounts and pre-payments for gas supplies. Our pipeline systems are all regulated in various ways resulting in the financial return on the investments made in the systems being limited to standards permitted by the regulatory agencies. Each of the pipeline systems has ongoing capital requirements for efficiency and mandatory improvements, with expansion opportunities also necessitating periodic capital outlays.

REGULATORY MATTERS

Williams Partners

Gas Pipeline Business. Williams Partners gas pipeline's 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. Each gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, and the Pipeline Safety Improvement Act of 2002, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC Standards of Conduct govern how our interstate pipelines communicate and do business with gas marketing employees. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit gas marketing functions.

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


	•	Costs of providing service, including depreciation expense;

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

	•	Contract and volume throughput assumptions.

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

Pipeline Integrity Regulations

For Williams Partners' gas pipeline business, Transco and Northwest Pipeline have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, Transco and Northwest Pipeline have identified high consequence areas and developed baseline assessment plans. Transco and Northwest Pipeline are on schedule to complete the required assessments within required timeframes. Currently, Transco and Northwest Pipeline estimate the cost to complete the required initial assessments over the period from 2011 and 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million for Transco and between $50 million and $60 million for Northwest Pipeline. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business, and, therefore, recoverable through Transco's and Northwest Pipeline's rates.

Midstream Business. For Williams Partners' midstream business, onshore gathering is subject to regulation by states in which we operate and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA). Of the states where the 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. 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."

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

The midstream business owns an interest in, and is expected to become the operator in 2011, of Overland Pass Pipeline, which is an interstate natural gas liquids pipeline regulated by the FERC pursuant to the Interstate Commerce Act. Overland Pass provides transportation service pursuant to tariffs filed with the FERC.

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Exploration & Production

Our Exploration & Production business is subject to various federal, state and local laws and regulations on taxation and payment of royalties, and the development, production and marketing of oil and gas, and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Such laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our reserves.

Our gas marketing business is subject to a variety of laws and regulations at the local, state and federal levels, including the FERC and the Commodity Futures Trading Commission regulations. In addition, natural gas markets continue to be subject to numerous and wide-ranging federal and state regulatory proceedings and investigations.

Other

Our Canadian assets are regulated by the Energy Resources Conservation Board (ERCB) and Alberta Environment. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which noncompliance with the applicable regulations is at issue, the ERCB and Alberta Environment have implemented an enforcement process with escalating consequences.

See Note 16 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 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:


	•	From a well or drilling equipment at a drill site;

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

	•	Damage to oil and gas wells resulting from accidents during normal operations;

	•	Blowouts, cratering and explosions.

Because the requirements imposed by environmental laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business. In addition, we may be liable for environmental damage caused by former operators of our properties.

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

For a discussion of specific environmental issues, see "Environmental" under Management's Discussion and Analysis of Financial Condition and Results of Operations and "Environmental Matters" in Note 16 of our Notes to Consolidated Financial Statements.

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COMPETITION

Williams Partners

For our gas pipeline business, 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. As a result, pipeline capacity is being used more efficiently, and peaking and storage services are increasingly effective substitutes for annual pipeline capacity.

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

States are in the process of developing new energy plans that may require utilities to encourage energy saving measures and diversify their energy supplies to include renewable sources. This could lower the growth of gas demand.

These factors have increased the risk that customers will reduce their contractual commitments for pipeline capacity. Future utilization of pipeline capacity will also depend on competition from LNG imported into markets and new pipelines from the Rockies and other new producing areas.

In our midstream business, 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. We also compete in recruiting and retaining skilled employees. By virtue of the master limited partnership structure, WPZ provides us with an alternative source of capital, which helps us compete against other master limited partnerships for capital projects.

Exploration & Production

Our exploration and production business competes with other oil and gas concerns, including major and independent oil and gas companies in the development, production and marketing of natural gas. We compete in areas such as acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.

In our gas marketing services business, we compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities, and natural gas producers. We also compete with brokerage houses, energy hedge funds and other energy-based companies offering similar services.

Other

Ethylene and propylene markets, and therefore our olefins business, compete in a worldwide marketplace. Due to our NGL feedstock position at Geismar, we will 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 depending on their market balances. Generally, we are viewed primarily as a supplier to these companies and not as a direct competitor. We compete on the basis of service, price and availability of the products we produce.

Our Canadian midstream facilities continue to be the only NGL/olefins fractionator in western Canada and the only treater/processor of oil sands upgrader off-gas. Our extraction of liquids from the upgrader off-gas stream allows the upgraders to burn cleaner natural gas streams and reduce their overall air emissions. Our Canadian

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midstream business competes for the sale of its products with traditional Canadian midstream companies on the basis of operational expertise, price, service offerings and availability of the products we produce.

EMPLOYEES

At February 1, 2011, we had approximately 5,022 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

See Note 18 of our Notes to Consolidated Financial Statements for amounts of revenues during the last three fiscal years from external customers attributable to the United States and all foreign countries. Also see Note 18 of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.


Item 1A.	*Risk Factors*

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

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


	•	Amounts and nature of future capital expenditures;

	•	Expansion and growth of our business and operations;

	•	Financial condition and liquidity;

	•	Business strategy;

	•	Estimates of proved gas and oil reserves;

	•	Reserve potential;

	•	Development drilling potential;

	•	Cash flow from operations or results of operations;

	•	Seasonality of certain business segments;

	•	Natural gas, natural gas liquids and crude oil prices and demand.

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

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will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:


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

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

	•	The strength and financial resources of our competitors;

	•	Development of alternative energy sources;

	•	The impact of operational and development hazards;

	•	Costs of, changes in, or the results of laws, government regulations (including climate change legislation and/or potential additional regulation of drilling and completion of wells), environmental liabilities, litigation, and rate proceedings;

	•	Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

	•	Changes in maintenance and construction costs;

	•	Changes in the current geopolitical situation;

	•	Our exposure to the credit risk of our customers;

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

	•	Risks associated with future weather conditions;

	•	Acts of terrorism;

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

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

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

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

RISK FACTORS

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

Risks Related to Separation Plan

If our plan to separate our exploration and production business is delayed or not completed, our stock price may decline and our growth potential may not be enhanced.

On February 16, 2011, we announced that our Board of Directors approved pursuing a plan to divide our businesses into two separate, publicly traded corporations. The plan calls for a separation of our exploration and production business through an initial public offering of up to 20 percent of the corporation holding that business in 2011 and a tax-free spinoff of our remaining interest in that corporation to our shareholders in 2012. The completion and timing of each of the transactions is dependent on a number of factors including, but not limited to, the macroeconomic environment, credit markets, equity markets, energy prices, the receipt of a tax opinion from counsel and/or Internal Revenue Service rulings, final approvals from our Board of Directors and other customary matters. We may not complete the transactions at all or complete the transactions on the timeline or on the terms that we announced. If the transactions are not completed or delayed, our stock price may decline and our growth potential may not be enhanced.

Risks Inherent in our Business

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

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

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adverse effect on our business, financial condition and results of operations. In addition, new LNG import facilities built near our markets could result in less demand for our gathering and transportation facilities.

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

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

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

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

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


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

	•	Turmoil in the Middle East and other producing regions;

	•	The activities of the Organization of Petroleum Exporting Countries;

	•	Terrorist attacks on production or transportation assets;

	•	Weather conditions;

	•	The level of consumer demand;

	•	The price and availability of other types of fuels;

	•	The availability of pipeline capacity;

	•	Supply disruptions, including plant outages and transportation disruptions;

	•	The price and level of foreign imports;

	•	Domestic and foreign governmental regulations and taxes;

	•	Volatility in the natural gas and oil markets;

	•	The overall economic environment;

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

	•	The adoption of regulations or legislation relating to climate change.

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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, oil 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 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.

Significant capital expenditures are required to replace our reserves.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations and debt and equity issuances. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of natural gas and oil, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt, issue debt or equity securities or access other methods of financing on an economic basis to meet our capital expenditure budget. As a result, our capital expenditure plans may have to be adjusted.

Failure to replace reserves may negatively affect our business.

The growth of our Exploration & Production business depends upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Our proved reserves generally decline when reserves are produced, unless we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. We may not be able to find, develop or acquire additional reserves on an economic basis. If natural gas or oil prices increase, our costs for additional reserves would also increase; conversely if natural gas or oil prices decrease, it could make it more difficult to fund the replacement of our reserves.

Exploration and development drilling may not result in commercially productive reserves.

Our past success rate for drilling projects should not be considered a predictor of future commercial success. We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in wells we drill or participate in. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:


	•	Increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment, skilled labor, capital or transportation;

	•	Unexpected drilling conditions or problems;

	•	Regulations and regulatory approvals;

	•	Changes or anticipated changes in energy prices;

	•	Compliance with environmental and other governmental requirements.

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Estimating reserves and future net revenues involves uncertainties. Negative revisions to reserve estimates, oil and gas prices or assumptions as to future natural gas prices may lead to decreased earnings, losses, or impairment of oil and gas assets.

Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions, but should not be considered as a guarantee of results for future drilling projects.

The process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including many factors beyond the control of the producer. The reserve data included in this report represent estimates. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct.

Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil and gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserve estimates.

If negative revisions in the estimated quantities of proved reserves were to occur, it would have the effect of increasing the rates of depreciation, depletion and amortization on the affected properties, which would decrease earnings or result in losses through higher depreciation, depletion and amortization expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also be sufficient to trigger impairment losses on certain properties which would result in a noncash charge to earnings.

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.

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

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

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


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

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

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

	•	Whether our business strategy continues to be successful;

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

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	•	The effects of state regulation on customer contracting practices.

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

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

Although we have systems in place that use various methodologies to quantify commodity price risk associated with our businesses, these systems 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 the risk of financial loss in certain circumstances, including instances in which:


	•	Volumes are less than expected;

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

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

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

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted. The Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Among other things, the Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. The final impact of the Act on our hedging activities is uncertain at this time due to the requirement that the SEC and the Commodities Futures Trading Commission (CFTC) promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. These new rules and

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regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be impacted by position limits and should be exempt from the requirement to clear transactions through a central exchange or to post collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.

Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. 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 Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

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

Our gas pipeline and midstream businesses rely on a limited number of customers for a significant portion of their revenues. Although some of these customers are subject to long-term contracts, extensions or replacements of these contracts may not be renegotiated on favorable terms, if at all. The loss of all, or even a portion of the revenues from natural gas, NGLs or contracted volumes, as applicable, supplied by these customers, as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows, unless we are able to acquire comparable volumes from other sources.

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

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy or are required to make prepayments or provide security to satisfy credit concerns. However, our credit procedures and policies may not be adequate to fully eliminate customer credit risk. We cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers' creditworthiness. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write-down or write-off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results 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.

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. 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. 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. 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. We may not 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, financial condition, results of operations, and cash flows.

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

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


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

	•	Aging infrastructure and mechanical problems;

	•	Damages to pipelines and pipeline blockages;

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

	•	Collapse of storage caverns;

	•	Operator error;

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

	•	Pollution and environmental risks;

	•	Fires, explosions, craterings and blowouts;

	•	Risks related to truck and rail loading and unloading;

	•	Risks related to operating in a marine environment;

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

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

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

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

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

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

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

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

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

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

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

The growth in our gas pipeline and midstream businesses may be dependent upon the construction of new natural gas gathering, transportation, processing or treating pipelines and facilities or natural gas liquids fractionation or storage facilities, as well as the expansion of existing facilities. Construction or expansion of these facilities is subject to various regulatory, development and operational risks, including:


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

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

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

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

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

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

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

Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.

We have defined benefit pension plans covering substantially all of our U.S. employees and other post-retirement benefit plans covering certain eligible participants. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.

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One of our subsidiaries acts as the general partner of a publicly traded limited partnership, Williams Partners L.P. As such, this subsidiary's operations may involve a greater risk of liability than ordinary business operations.

One of our subsidiaries acts as the general partner of WPZ, a publicly-traded limited partnership. This subsidiary may be deemed to have undertaken fiduciary obligations with respect to WPZ as the general partner and to the limited partners of WPZ. Activities determined to involve fiduciary obligations to other persons or entities typically involve a higher standard of conduct than ordinary business operations and therefore may involve a greater risk of liability, particularly when a conflict of interests is found to exist. Our control of the general partner of WPZ may increase the possibility of claims of breach of fiduciary duties, including claims brought due to conflicts of interest (including conflicts of interest that may arise between WPZ, on the one hand, and its general partner and that general partner's affiliates, including us, on the other hand). Any liability resulting from such claims could be material.

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 of that any such new laws or regulations could have. In addition, the Financial Accounting Standards Board, the SEC or FERC could enact new accounting standards or FERC orders 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.

Our investments and projects located outside of the United States expose us to risks related to the laws of other countries, and the taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. These risks might delay or reduce our realization of value from our international projects.

We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic and political conditions in certain countries where we have interests or in which we might explore development, acquisition or investment opportunities present risks of delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire projects or make investments could make it more difficult to obtain nonrecourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.

Operations and investments in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain situations under which we develop or acquire projects or make investments, economic and monetary conditions and other factors could affect our ability to convert to U.S. dollars our earnings denominated in foreign currencies. In addition, risk from fluctuations in currency exchange rates can arise when our foreign subsidiaries expend or borrow funds in one type of currency, but receive revenue in another. In such cases, an adverse change in exchange rates can reduce our ability to meet expenses, including debt service obligations. We may or may not put contracts in place designed to mitigate our foreign currency exchange risks. We have some exposures that are not hedged and which could result in losses or volatility in our results of operations.

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

Revenues from certain segments 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

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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. Additionally, changes in the price of natural gas could benefit one of our businesses, but disadvantage another. For example, our Exploration & Production business may benefit from higher natural gas prices, and our midstream business, which uses gas as a feedstock, may not.

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 cash flows.

Risks Related to Strategy and Financing

Our debt agreements impose restrictions on us that may limit our access to credit and adversely affect our ability to operate our business.

Certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to grant liens to support indebtedness, merge or sell substantially all of our assets, make certain distributions during an event of default, and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired.

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

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

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

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

Adverse economic conditions could negatively affect our results of operations.

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

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

A downgrade of our credit rating might increase our cost of borrowing and could 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 rating and other disruptions. Such disruptions could include:


	•	Economic downturns;

	•	Deteriorating capital market conditions;

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

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

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

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

Risks Related to Regulations that Affect our Industry

Our gas pipelines could be subject to penalties and fines if they fail to comply with FERC regulations.

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

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

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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 their customers;

	•	Certification and construction of new facilities;

	•	Acquisition, extension, disposition or abandonment of facilities;

	•	Accounts and records;

	•	Depreciation and amortization policies;

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

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

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

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

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

The rates, terms and conditions for interstate gas pipeline services are set forth in FERC-approved tariffs. Any successful complaint or protest against the rates of the gas pipelines could have an adverse impact on their revenues associated with providing transportation services. In addition, there is a risk that rates set by FERC in future rate cases filed by the gas pipelines will be inadequate to recover increases in operating costs or to sustain an adequate return on capital investments. There is also the risk that higher rates would cause their customers to look for alternative ways to transport natural gas.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases (GHGs) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. For further information regarding risks to our business arising from climate change related legislation, please read the discussion below under "Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities and could exceed current expectations."

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

The risk of substantial environmental costs and liabilities is inherent in natural gas drilling and well completion, gathering, transportation, storage, processing and treating, and in the fractionation and storage of NGLs, and we may incur substantial environmental costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, state and local environmental laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:


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

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

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

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

Various governmental authorities, including the U.S. Environmental Protection Agency (EPA) and analogous state agencies and the U.S. Department of Homeland Security, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, and the issuance of injunctions limiting or preventing some or all of our operations.

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

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

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

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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.

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

Numerous states have announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination could lead to the direct regulation of GHG emissions in our industry under the EPA's interpretation of its authority and obligations under the CAA. The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations 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.

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

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

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 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 facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to the 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, financial condition and cash flows.

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

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

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

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

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

The recently lifted drilling moratorium in the Gulf of Mexico and potentially more stringent regulations and permitting requirements on drilling in the Gulf of Mexico could adversely affect our results of operations, financial condition and cash flows.

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

Risks Related to Employees, Outsourcing of Noncore Support Activities, and Technology

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

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

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

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

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

Risks Related to Weather, other Natural Phenomena and Business Disruption

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

Our assets and operations, including those located offshore, can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially reasonable terms, or insurance has not been available at all. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

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

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

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


Item 1B.	*Unresolved Staff Comments*

None.


Item 2.	*Properties*

We own property in 32 states plus the District of Columbia in the United States and in Argentina, Canada, Venezuela, and Colombia.

Williams Partners generally owns its facilities, although a substantial portion of the pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others. In our Exploration & Production segment, the majority of our ownership interest is held as working interests in oil and gas leaseholds. In the Gulf of Mexico region, our Other segment owns a

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5/6 interest in and is the operator of an ethane cracker at Geismar, Louisiana. It also owns ethane and propane pipeline systems and a refinery grade propylene splitter in Louisiana. Its Canadian operations include an oil sands off-gas processing plant located near Ft. McMurray, Alberta, an NGL/olefin fractionation facility at Redwater, Alberta, which is near Edmonton, Alberta, as well as a new butylene/butane splitter and hydro-treating facility.


Item 3.	*Legal Proceedings*

The information called for by this item is provided in Note 16 of the Notes to Consolidated Financial Statements of this report, which information is incorporated by reference into this item.

Executive Officers of the Registrant

The name, age, period of service, and title of each of our executive officers as of February 24, 2011, are listed below.


Alan S. Armstrong		Director, Chief Executive Officer, and President


		Age: 48

		Position held since January 2011.

		Mr. Armstrong became a director, Chief Executive Officer, and President effective January 3, 2011. From February 2002 until January 2011 he was Senior Vice President, Midstream and acted as President of our Midstream business. From 1999 to February 2002, Mr. Armstrong was Vice President, Gathering and Processing for Midstream. From 1998 to 1999 he was Vice President, Commercial Development for Midstream. Mr. Armstrong serves as Chairman of the Board and Chief Executive Officer of Williams Partners GP LLC, the general partner of WPZ, where he was formerly Senior Vice President and a director from February 2010 and February 2005, respectively.

Randall L. Barnard		Senior Vice President, Gas Pipeline
		Age: 52

		Position held since February 2011.

		Mr. Barnard acts as President of our Gas Pipeline business. Mr. Barnard served as Vice President of Natural Gas Market Development from July 2010 to February 2011. From April 2002 to July 2010, Mr. Barnard was Senior Vice President of Operations and Technical Service for Williams Gas Pipeline. From September 2000 to April 2002, he served as President of Williams International and Vice President and General Manager of Williams, and was a director and CEO of Apco Oil and Gas International Inc., formerly Apco Argentina. From June 1997 to September 2000, Mr. Barnard was General Manager of Williams International in Venezuela. Mr. Barnard is a director and Senior Vice President, Gas Pipeline, of Williams Partners GP LLC, the general partner of WPZ, Chairman of the Board of the Gas Technology Institute and is Vice Chair of the Common Ground Alliance.

James J. Bender		Senior Vice President and General Counsel
		Age: 54

		Position held since December 2002.

		Prior to joining us, Mr. Bender was Senior Vice President and General Counsel with NRG Energy, Inc., a position held since June 2000, prior to which he was Vice President, General Counsel and Secretary of NRG Energy Inc. NRG Energy, Inc. filed a voluntary bankruptcy

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		petition during 2003 and its plan of reorganization was approved in December 2003. Mr. Bender has served as the General Counsel of Williams Partners GP LLC, the general partner of WPZ since February 2005 and was General Counsel of Williams Pipeline GP LLC, the general partner of WMZ from August 2007 until its merger with WPZ in August 2010.

Donald R. Chappel		Senior Vice President and Chief Financial Officer
		Age: 59

		Position held since April 2003.

		Prior to joining us, Mr. Chappel held various financial, administrative and operational leadership positions. Mr. Chappel also serves as Chief Financial Officer and a director of Williams Partners GP LLC, the general partner of WPZ. He was Chief Financial Officer from August 2007 and a director from January 2008 of Williams Pipeline GP LLC, the general partner of WMZ until its merger with WPZ in August 2010. Mr. Chappel is a director of SUPERVALU, Inc., Energy Insurance Mutual Limited, the Children's Hospital Foundation at St. Francis and the Family & Children Services of Oklahoma.

Robyn L. Ewing		Senior Vice President and Chief Administrative Officer
		Age: 55

		Position held since April 2008.

		From 2004 to 2008 Ms. Ewing was Vice President of Human Resources. Prior to joining Williams, Ms. Ewing worked at MAPCO, which merged with Williams in April 1998. She began her career with Cities Service Company in 1976.

Ralph A. Hill		Senior Vice President, Exploration & Production
		Age: 51

		Position held since December 1998.

		Mr. Hill acts as President of our Exploration & Production business unit. He was Vice President of the Exploration & Production business from 1993 to 1998 as well as Senior Vice President Petroleum Services from 1998 to 2003. Mr. Hill serves as a director of Apco Oil and Gas International Inc. and Petrolera Entre Lomas S.A.

Rory L. Miller		Senior Vice President, Midstream
		Age: 50

		Position held since January 2011.

		Mr. Miller acts as President of the Williams Partners midstream business. He was a Vice President of the Williams Partners midstream business from May 2004 to December 2011. Mr. Miller also serves as a director and Senior Vice President, Midstream of Williams Partners GP LLC, the general partner of WPZ.

Ted T. Timmermans		Vice President, Controller, and Chief Accounting Officer
		Age: 54

		Position held since July 2005.

		Mr. Timmermans has served as Vice President, Controller & Chief Accounting Officer of Williams since July 2005. He served as Assistant Controller of Williams from April 1998 to July 2005. Mr. Timmermans is also Vice President, Controller & Chief

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		Accounting Officer of Williams Partners GP LLC, the general partner of WPZ and served as Chief Accounting Officer of Williams Pipeline Partners GP LLC, the general partner of WMZ from January 2008 until its merger with WPZ in August 2010.

Phillip D. Wright		Senior Vice President, Corporate Development
		Age: 55

		Position held since February 2011.

		Mr. Wright has served as Senior Vice President, Corporate Development since February 2011. He served as Senior Vice President, Gas Pipeline and acted as President of our Gas Pipeline business from January 2005 to February 2011. From October 2002 to January 2005, he served as Chief Restructuring Officer. From September 2001 to October 2002, Mr. Wright served as President and Chief Executive Officer of our subsidiary, Williams Energy Services, LLC. From 1996 until September 2001, he was Senior Vice President, Enterprise Development and Planning for our energy services group. Mr. Wright served as a director and Chief Operating Officer of Williams Pipeline GP LLC, the general partner of WMZ until its merger with WPZ in August 2010 and was a director and Senior Vice President, Gas Pipeline, of Williams Partners GP LLC, the general partner of WPZ from January 2010 to February 2011.

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PART II


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

Our common stock is listed on the New York Stock Exchange under the symbol "WMB." At the close of business on February 21, 2011, we had approximately 10,032 holders of record of our common stock. The high and low sales price ranges (New York Stock Exchange composite transactions) and dividends declared by quarter for each of the past two years are as follows:


	2010						2009
Quarter	High		Low		Dividend		High		Low		Dividend

1st	$	23.76	$	19.51	$	0.11	$	16.87	$	9.52	$	0.11
2nd	$	24.66	$	18.16	$	0.125	$	17.99	$	11.30	$	0.11
3rd	$	21.00	$	17.53	$	0.125	$	19.21	$	13.59	$	0.11
4th	$	24.89	$	18.88	$	0.125	$	21.54	$	16.57	$	0.11

Some of our subsidiaries' borrowing arrangements may limit the transfer of funds to us. These terms have not impeded, nor are they expected to impede, our ability to pay dividends.

Performance Graph

Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index and the Bloomberg U.S. Pipeline Index for the period of five fiscal years commencing January 1, 2006. The Bloomberg U.S. Pipeline Index is composed of El Paso, Enbridge, Spectra Energy, TransCanada Corp. and Williams. The graph below assumes an investment of $100 at the beginning of the period.

Cumulative Total Shareholder Return


	2005		2006		2007		2008		2009		2010
The Williams Companies, Inc.		100.0		114.4		158.6		65.3		97.8		117.4
S&P 500 Index		100.0		115.8		122.1		77.0		97.3		112.0
Bloomberg U.S. Pipelines Index		100.0		115.9		137.4		84.0		119.0		146.3

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Item 6.	*Selected Financial Data*

The following financial data at December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, should be read in conjunction with the other financial information included in 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.


	2010			2009			2008		2007		2006
	(Millions, except per-share amounts)

Revenues	$	9,616		$	8,255		$	11,890	$	10,239	$	9,144
Income (loss) from continuing operations(1)		(916	)		584			1,467		910		366
Income (loss) from discontinued operations(2)		(6	)		(223	)		125		170		(17	)
Amounts attributable to The Williams Companies, Inc.:
Income (loss) from continuing operations		(1,091	)		438			1,306		829		332
Income (loss) from discontinued operations		(6	)		(153	)		112		161		(23	)
Diluted earnings (loss) per common share:
Income (loss) from continuing operations		(1.87	)		.75			2.21		1.37		.55
Income (loss) from discontinued operations		(0.01	)		(0.26	)		0.19		0.26		(0.04	)
Total assets at December 31		24,972			25,280			26,006		25,061		25,402
Short-term notes payable and long-term debt due within one year at December 31		508			17			18		108		358
Long-term debt at December 31		8,600			8,259			7,683		7,580		7,410
Stockholders' equity at December 31		7,288			8,447			8,440		6,375		6,073
Cash dividends declared per common share		0.485			.44			.43		.39		.345


(1)		Loss from continuing operations for 2010 includes $648 million of pre-tax costs associated with our restructuring, as well as approximately $1.7 billion of impairment charges related to goodwill and certain properties at Exploration & Production. See Note 4 of Notes to Consolidated Financial Statements for further discussion of asset sales, impairments, and other accruals in 2010, 2009, and 2008. Income from continuing operations for 2006 includes a $73 million charge for a litigation contingency and a $167 million charge for a securities litigation settlement and related costs.

(2)		See Note 2 of Notes to Consolidated Financial Statements for the analysis of the 2010, 2009, and 2008 income (loss) from discontinued operations. The discontinued operations results for 2007 includes our former power business and our discontinued Venezuela operations. The discontinued operations results for 2006 includes our former power business, discontinued Venezuela operations, as well as amounts associated with our former chemical fertilizer business, a former exploration business, our former Alaska refinery, and our former distributive power business.

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

General

We are primarily an integrated natural gas company engaged in finding, producing, gathering, processing, and transporting natural gas. Our operations are located principally in the United States and are organized into the following segments as of December 31, 2010: Williams Partners, Exploration & Production, and Other. (See Note 1 of Notes to Consolidated Financial Statements and Part I, Item 1 for further discussion of these segments.)

Unless indicated otherwise, the following discussion and analysis of critical accounting estimates, results of operations, and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this document.

Change in Structure and Dividend Increase

Additionally, we intend to increase the quarterly dividend paid to our shareholders, with an initial increase of 60 percent (to $0.20 per share), for the first quarter of 2011 payable in June 2011.

Management believes these actions will serve to enhance the growth potential and overall valuation of our assets.

Overview of 2010

The effects of the severe economic recession during late 2008 and 2009 have eased during 2010. Crude oil and NGL prices have returned to attractive levels, but natural gas prices have remained low. Natural gas prices have remained low and forward natural gas prices have declined, primarily as a result of significant increases in near- and long-term supplies, which have outpaced near-term demand growth. The decline in forward natural gas prices contributed significantly to impairments recorded by our Exploration & Production segment in the third quarter of 2010. However, lower natural gas prices, along with strong NGL prices and ethane demand, contributed to improved results in our midstream businesses. Abundant and low-cost natural gas reserves in the United States are

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driving strong demand for midstream and pipeline infrastructure. Objectives and highlights of our plan for 2010 include:


Objectives			Highlights
Continuing to invest in our gathering and processing and interstate natural gas pipeline systems.			We invested $1 billion in capital and investment expenditures in our midstream businesses and also invested $473 million in capital expenditures in our gas pipelines during 2010.
Continuing to invest in our natural gas production development.			We invested $2.8 billion in drilling activity and acquisitions in Exploration & Production, including $1.7 billion related to acquisitions in the Bakken and Marcellus Shale areas.
Retaining the flexibility to adjust our planned levels of capital and investment expenditures in response to changes in economic conditions, as well as seizing attractive opportunities.			During 2010, our Williams Partners and Exploration & Production segments seized growth opportunities to expand in the Marcellus Shale, while Exploration & Production further diversified into oil production with an acquisition in North Dakota's Bakken Shale. (See further discussion in Other Significant 2010 Events.) These expenditures were funded through cash flow from operations, debt and equity offerings at WPZ, and cash on hand, while maintaining our desired level of liquidity of at least $1 billion from cash and cash equivalents and unused revolving credit facilities.

Our 2010 income (loss) from continuing operations attributable to The Williams Companies, Inc. changed unfavorably by $1.5 billion compared to 2009. This decrease is primarily reflective of a $1 billion full impairment charge related to goodwill at Exploration & Production and $678 million of pre-tax charges associated with impairments of certain producing properties and acquired unproved reserves at Exploration & Production during the third quarter of 2010. Additionally, we had $648 million of pre-tax costs associated with our 2010 restructuring, including $606 million of early debt retirement costs. Partially offsetting these costs is the impact of an improved energy commodity price environment in 2010 compared to 2009. See additional discussion in Results of Operations.

Our net cash provided by operating activities for 2010 increased $79 million compared to 2009, primarily due to the improvement in the energy commodity price environment during the year. See additional discussion in Management's Discussion and Analysis of Financial Condition and Liquidity.

Other Significant 2010 Events

On February 17, 2010, we completed a strategic restructuring that involved contributing certain of our wholly and partially owned subsidiaries to WPZ, our consolidated master limited partnership, and restructuring our debt (see Note 11 of Notes to Consolidated Financial Statements).

In May 2010, Exploration & Production announced a major acreage acquisition in the Marcellus Shale located in northeast Pennsylvania. In July 2010, the purchase was completed for $599 million, including closing adjustments. (See Results of Operations - Segments, Exploration & Production.)

On May 24, 2010, WPZ and WMZ entered into a merger agreement providing for the merger of WMZ and WPZ. On August 31, 2010, the WMZ unitholders approved the proposed merger between the two master limited partnerships and the merger was completed.

In July 2010, we notified our partner in the Overland Pass Pipeline Company LLC (OPPL) of our election to exercise our option to purchase an additional ownership interest, which provides us with a 50 percent ownership

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interest in OPPL, for approximately $424 million. This transaction was completed on September 9, 2010, primarily with proceeds from WPZ's credit facility. (See Results of Operations - Segments, Williams Partners.) Additionally, WPZ completed an equity offering resulting in net proceeds of $437 million, which were used to reduce the borrowing under WPZ's credit facility.

In October 2010, we filed an application with the Federal Energy Regulatory Commission (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 $219 million. The project is expected to be phased into service in September 2012 and June 2013, with an increase in capacity of 225 Mdt/d.

In November 2010, WPZ acquired a business from Exploration & Production represented by certain gathering and processing assets in Colorado's Piceance basin, for $702 million in cash, approximately 1.8 million of WPZ common units and an increase in the capital account of its general partner to allow us to maintain our 2 percent general partner interest. (See Note 1 of Notes to Consolidated Financial Statements.)

In November 2010, WPZ completed a public offering of $600 million of its 4.125 percent senior notes due 2020. WPZ used the net proceeds from the offering to fund a portion of the cash consideration paid for the previously described gathering and processing assets in the Piceance basin. (See further discussion in Results of Operations - Segments, Williams Partners.)

In December 2010, WPZ acquired a midstream business in Pennsylvania's Marcellus Shale for $150 million. (See further discussion in Results of Operations - Segments, Williams Partners.)

In December 2010, Exploration & Production acquired a company that holds a major acreage position (approximately 85,800 net acres) in North Dakota's Bakken Shale oil play that will diversify our interests into light, sweet crude oil production. The purchase price was approximately $949 million, including closing adjustments.

In December 2010, WPZ completed a public offering of 8 million of its common units, representing limited-partner interests. WPZ used the net proceeds from the common unit public offering for repayment of a $200 million borrowing under the partnership's credit facility, as well as funding a portion of the consideration for the acquisition of midstream assets in Pennsylvania's Marcellus Shale. We made a cash contribution to WPZ in order to maintain our 2 percent general partner interest in the partnership. As a result of the offering, our limited partner interest in the partnership was reduced to 73 percent. See additional discussion in Management's Discussion and Analysis of Financial Condition and Liquidity.

Outlook for 2011

We believe we are well positioned to execute on our 2011 business plan and to capture attractive growth opportunities. Economic and commodity price indicators for 2011 and beyond reflect continued improvement in the economic environment. However, given the potential volatility of these measures, it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of long-lived assets.

As a result of our 2010 restructuring, as previously discussed, we are better positioned to drive additional organic growth and aggressively pursue value-adding growth opportunities. Our structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions.

We continue to operate with a focus on increasing Economic Value Added ® (EVA ® ) 1 and invest in our businesses in a way that meets customer needs and enhances our competitive position by:


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

1 Economic Value Added ® (EVA ® ) is a registered trademark of Stern, Stewart & Co. This tool considers both financial earnings and a cost of capital in measuring performance. We look for opportunities to improve EVA ® because we believe there is a strong correlation between EVA ® improvement and creation of shareholder value.

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

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


	•	Lower than anticipated energy commodity prices;

	•	Lower than expected levels of cash flow from operations;

	•	Availability of capital;

	•	Counterparty credit and performance risk;

	•	Decreased drilling success at Exploration & Production;

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

	•	General economic, financial markets, or industry downturn;

	•	Changes in the political and regulatory environments;

	•	Physical damages to facilities, especially damage to offshore facilities by named windstorms for which our aggregate insurance policy limit is $75 million in the event of a material loss.

We continue to address these risks through utilization of commodity hedging strategies, disciplined investment strategies, and maintaining at least $1 billion in consolidated liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties to reduce credit risk and liquidity requirements.

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 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.

Impairments of Goodwill and Long-Lived Assets

We have assessed goodwill for impairment annually as of the end of the year and we have performed interim assessments of goodwill if impairment triggering events or circumstances were present. One such triggering event is a significant decline in forward natural gas prices. During the first and second quarter of 2010, we evaluated the impact of declines in forward gas prices across all future production periods and determined that the impact was not significant enough to warrant a full impairment review. Forward natural gas prices through 2025 used in these prior analyses had declined less than 10 percent, on average, from December 31, 2009 through March 31, 2010 and June 30, 2010. During the third quarter of 2010, these forward natural gas prices through 2025 declined an additional 19 percent for a total year-to-date decline of more than 22 percent on average through September 30, 2010. Based on forward prices as of September 30, 2010, we evaluated the impact of this decline across all future production periods and determined that a full impairment review was warranted.

As a result, we evaluated our goodwill of approximately $1 billion resulting from a 2001 acquisition at Exploration & Production related to its domestic natural gas production operations (the reporting unit). Our impairment evaluation of goodwill first considered our management's estimate of the fair value of the reporting unit compared to its carrying value, including goodwill. If the carrying value of the reporting unit exceeded its fair value, a computation of the implied fair value of the goodwill was compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeded the implied fair value of that goodwill, an impairment loss was recognized in the amount of the excess. Because quoted market prices were not available for the reporting unit, management applied reasonable judgments (including market supported assumptions when available) in estimating the fair value for the reporting unit. We estimated the fair value of the reporting unit on a stand-alone basis and also

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considered our market capitalization and third party estimates in corroborating our estimate of the fair value of the reporting unit.

The fair value of the reporting unit was estimated primarily by valuing proved and unproved reserves. We use an income approach (discounted cash flows) for valuing reserves. The significant inputs into the valuation of proved and unproved reserves include reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves, income taxes, and appropriate discount rates. To estimate the fair value of the reporting unit and the implied fair value of goodwill under a hypothetical acquisition of the reporting unit, we assumed a tax structure where a buyer would obtain a step-up in the tax basis of the net assets acquired.

In our assessment as of September 30, 2010, the carrying value of the reporting unit, including goodwill, exceeded its fair value. We then determined that the implied fair value of the goodwill was zero. As a result, we recognized a full $1 billion impairment charge related to Exploration & Production's goodwill. See Note 4 and Note 14 of Notes to Consolidated Financial Statements for additional discussion and significant inputs into the fair value determination.

We evaluate our long-lived assets for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value. Our computations utilize judgments and assumptions that include the estimated fair value of the asset, undiscounted future cash flows, discounted future cash flows, and the current and future economic environment in which the asset is operated.

As a result of significant declines in forward natural gas prices during the third quarter of 2010, we assessed Exploration & Production's natural gas producing properties and acquired unproved reserve costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and our estimate of an applicable discount rate commensurate with risk of the underlying cash flow estimates. The assessment performed at September 30, 2010 identified certain properties with a carrying value in excess of their calculated fair values. As a result, we recognized a $678 million impairment charge. See Note 4 and Note 14 of Notes to Consolidated Financial Statements for additional discussion and significant inputs into the fair value determination.

In addition to those long-lived assets described above for which impairment charges were recorded, certain others were reviewed for which no impairment was required. These reviews included Exploration & Production's other domestic producing properties and acquired unproved reserve costs, and utilized inputs generally consistent with those described above. 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 the recognition of different levels of impairment charges in the consolidated financial statements. For Exploration & Production's other producing assets reviewed, but for which impairment charges were not recorded, we estimate that approximately 10 percent could be at risk for impairment if forward prices across all future periods decline by approximately 8 to 11 percent, on average, as compared to the forward prices at December 31, 2010. A substantial portion of the remaining carrying value of these other assets (primarily related to Exploration & Production's assets in the Piceance basin) could be at risk for impairment if forward prices across all future periods decline by at least 30 percent, on average, as compared to the prices at December 31, 2010.

Accounting for Derivative Instruments and Hedging Activities

We review our energy contracts to determine whether they are derivatives or contain derivatives. We further assess the appropriate accounting method for any derivatives identified, which could include:


	•	Qualifying for and electing cash flow hedge accounting, which recognizes changes in the fair value of the derivative in other comprehensive income (to the extent the hedge is effective) until the hedged item is recognized in earnings;

	•	Qualifying for and electing accrual accounting under the normal purchases and normal sales exception; or

	•	Applying mark-to-market accounting, which recognizes changes in the fair value of the derivative in earnings.

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If cash flow hedge accounting or accrual accounting is not applied, a derivative is subject to mark-to-market accounting. Determination of the accounting method involves significant judgments and assumptions, which are further described below.

The determination of whether a derivative contract qualifies as a cash flow hedge includes an analysis of historical market price information to assess whether the derivative is expected to be highly effective in offsetting the cash flows attributed to the hedged risk. We also assess whether the hedged forecasted transaction is probable of occurring. This assessment requires us to exercise judgment and consider a wide variety of factors in addition to our intent, including internal and external forecasts, historical experience, changing market and business conditions, our financial and operational ability to carry out the forecasted transaction, the length of time until the forecasted transaction is projected to occur, and the quantity of the forecasted transaction. In addition, we compare actual cash flows to those that were expected from the underlying risk. If a hedged forecasted transaction is not probable of occurring, or if the derivative contract is not expected to be highly effective, the derivative does not qualify for hedge accounting.

For derivatives designated as cash flow hedges, we must periodically assess whether they continue to qualify for hedge accounting. We prospectively discontinue hedge accounting and recognize future changes in fair value directly in earnings if we no longer expect the hedge to be highly effective, or if we believe that the hedged forecasted transaction is no longer probable of occurring. If the forecasted transaction becomes probable of not occurring, we reclassify amounts previously recorded in other comprehensive income into earnings in addition to prospectively discontinuing hedge accounting. If the effectiveness of the derivative improves and is again expected to be highly effective in offsetting the cash flows attributed to the hedged risk, or if the forecasted transaction again becomes probable, we may prospectively re-designate the derivative as a hedge of the underlying risk.

Derivatives for which the normal purchases and normal sales exception has been elected are accounted for on an accrual basis. In determining whether a derivative is eligible for this exception, we assess whether the contract provides for the purchase or sale of a commodity that will be physically delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In making this assessment, we consider numerous factors, including the quantities provided under the contract in relation to our business needs, delivery locations per the contract in relation to our operating locations, duration of time between entering the contract and delivery, past trends and expected future demand, and our past practices and customs with regard to such contracts. Additionally, we assess whether it is probable that the contract will result in physical delivery of the commodity and not net financial settlement.

Since our energy derivative contracts could be accounted for in three different ways, two of which are elective, our accounting method could be different from that used by another party for a similar transaction. Furthermore, the accounting method may influence the level of volatility in the financial statements associated with changes in the fair value of derivatives, as generally depicted below:


	Consolidated Statement of Operations		Consolidated Balance Sheet
Accounting Method	Drivers	Impact	Drivers	Impact

Accrual Accounting	Realizations	Less Volatility	None	No Impact
Cash Flow Hedge Accounting	Realizations & Ineffectiveness	Less Volatility	Fair Value Changes	More Volatility
Mark-to-Market Accounting	Fair Value Changes	More Volatility	Fair Value Changes	More Volatility

Our determination of the accounting method does not impact our cash flows related to derivatives.

Additional discussion of the accounting for energy contracts at fair value is included in Notes 1 and 15 of Notes to Consolidated Financial Statements.

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Oil- and Gas-Producing Activities

We use the successful efforts method of accounting for our oil- and gas-producing activities. Estimated natural gas and oil reserves and forward market prices for oil and gas are a significant part of our financial calculations. Following are examples of how these estimates affect financial results:


	•	An increase (decrease) in estimated proved oil and gas reserves can reduce (increase) our unit-of-production depreciation, depletion, and amortization rates.

	•	Changes in oil and gas reserves and forward market prices both impact projected future cash flows from our oil and gas properties. This, in turn, can impact our periodic impairment analyses.

The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering, and economic data. After being estimated internally, approximately 94 percent of our domestic reserve estimates are audited by independent experts. (See Part I, Item 1 for further discussion.) The data may change substantially over time as a result of numerous factors, including additional development cost and activity, evolving production history, and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates could occur from time to time. Such changes could trigger an impairment of our oil and gas properties and have an impact on our depreciation, depletion, and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion, and amortization expense between approximately $77 million and $94 million. The actual impact would depend on the specific basins impacted and whether the change resulted from proved developed, proved undeveloped, or a combination of these reserve categories.

Forward market prices, which are utilized in our impairment analyses, include estimates of prices for periods that extend beyond those with quoted market prices. This forward market price information is consistent with that generally used in evaluating our drilling decisions and acquisition plans. These market prices for future periods impact the production economics underlying oil and gas reserve estimates. The prices of natural gas and oil are volatile and change from period to period, thus impacting our estimates. Significant unfavorable changes in the forward price curve could result in an impairment of our oil and gas properties.

Contingent Liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. Revisions to contingent liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions with respect to the likelihood or amount of loss. Liabilities for contingent losses are based upon our assumptions and estimates and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matter. Areas of significance include certain royalty-related and other litigated matters, as well as environmental matters. As new developments occur or more information becomes available, our assumptions and estimates of these liabilities may change. Changes in our assumptions and estimates or outcomes different from our current assumptions and estimates could materially affect future results of operations for any particular quarterly or annual period. See Note 16 of Notes to Consolidated Financial Statements.

Valuation of Deferred Tax Assets and Tax Contingencies

We have deferred tax assets resulting from certain investments and businesses that have a tax basis in excess of the book basis and from tax carry-forwards generated in the current and prior years. We must evaluate whether we will ultimately realize these tax benefits and establish a valuation allowance for those that may not be realizable. This evaluation considers tax planning strategies, including assumptions about the availability and character of future taxable income. When assessing the need for a valuation allowance, we consider forecasts of future company performance, the estimated impact of potential asset dispositions, and our ability and intent to execute tax planning strategies to utilize tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets, including the impact of organizational or structural changes.

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We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. We evaluate the liability associated with our various filing positions by applying the two step process of recognition and measurement. The ultimate disposition of these contingencies could have a significant impact on operating results and net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.

See Note 5 of Notes to Consolidated Financial Statements for additional information.

Pension and Postretirement Obligations

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit expense and obligations for these plans are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements.

The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.


	Benefit Expense						Benefit Obligation
	One-Percentage-			One-Percentage-			One-Percentage-			One-Percentage-
	Point Increase			Point Decrease			Point Increase			Point Decrease
	(Millions)

Pension benefits:
Discount rate	$	(10	)	$	11		$	(133	)	$	158
Expected long-term rate of return on plan assets		(10	)		10			-			-
Rate of compensation increase		3			(3	)		14			(12	)
Other postretirement benefits:
Discount rate		(3	)		3			(35	)		43
Expected long-term rate of return on plan assets		(2	)		2			-			-
Assumed health care cost trend rate		5			(4	)		39			(32	)

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on the average rate of return expected on the funds invested in the plans. We determine our long-term expected rate of return on plan assets using our expectations of capital market results, which includes an analysis of historical results as well as forward-looking projections. These capital market expectations are based on a long-term period of at least ten years and consider our investment strategy and mix of assets, which is weighted toward domestic and international equity securities. We develop our expectations using input from several external sources, including consultation with our third-party independent investment consultant. The forward-looking capital market projections are developed using a consensus of economists' expectations for inflation, GDP growth, and dividend yield along with expected changes in risk premiums. The capital market return projections for specific asset classes in the investment portfolio are then applied to the relative weightings of the asset classes in the investment portfolio. The resulting rate is an estimate of future results and, thus, likely to be different than actual results.

The capital markets continued to improve in 2010 and the benefit plans' assets reflect this improvement. While the 2010 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans had been 7.75 percent since 2006. In 2010, we reduced our expected long-term rate of return on pension plan assets to 7.5 percent. This reduction was implemented due to changes in long-term capital market expectations and our intent to slightly reduce the equity exposure and increase the fixed income exposure in

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the investment portfolio. The 2010 actual return on plan assets for our pension plans was a gain of approximately 12.9 percent. The ten-year average rate of return on pension plan assets through December 2010 was approximately 3.3 percent and is largely affected by the approximately 34.1 percent loss experienced in 2008.

The discount rates are used to measure the benefit obligations of our pension and other postretirement benefit plans. The objective of the discount rates is to determine the amount, if invested at the December 31 measurement date in a portfolio of high-quality debt securities, that will provide the necessary cash flows when benefit payments are due. Increases in the discount rates decrease the obligation and, generally, decrease the related expense. The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans and their respective expected benefit cash flows as described in Note 7 of Notes to Consolidated Financial Statements. Our discount rate assumptions are impacted by changes in general economic and market conditions that affect interest rates on long-term high-quality debt securities as well as by the duration of our plans' liabilities.

The expected rate of compensation increase represents average long-term salary increases. An increase in this rate causes the pension obligation and expense to increase.

The assumed health care cost trend rates are based on national trend rates adjusted for our actual historical cost rates and plan design. An increase in this rate causes the other postretirement benefit obligation and expense to increase.

Fair Value Measurements

A limited amount of our energy derivative assets and liabilities trade in markets with lower availability of pricing information requiring us to use unobservable inputs and are considered Level 3 in the fair value hierarchy. At December 31, 2010, less than 1 percent of our energy derivative assets and liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.

The determination of fair value for our energy derivative assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our energy derivative liabilities. The determination of the fair value of our energy derivative liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2010, the credit reserve is less than $1 million on both our net derivative assets and net derivative liabilities. Considering these factors and that we do not have significant risk from our net credit exposure to derivative counterparties, the impact of credit risk is not significant to the overall fair value of our derivatives portfolio.

At December 31, 2010, 89 percent of the fair value of our derivatives portfolio expires in the next 12 months and more than 99 percent expires in the next 24 months. Our derivatives portfolio is largely comprised of exchange-traded products or like products where price transparency has not historically been a concern. Due to the nature of the markets in which we transact and the relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.

The instruments included in Level 3 at December 31, 2010, consist of natural gas index transactions that are used to manage the physical requirements of our Exploration & Production segment. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices.

Exploration & Production has an unsecured credit agreement through December 2015 with certain banks that, so long as certain conditions are met, serves to reduce our usage of cash and other credit facilities for margin requirements related to instruments included in the facility.

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For the years ended December 31, 2010 and 2009, we recognized impairments of certain assets that were measured at fair value on a nonrecurring basis. These impairment measurements are included in Level 3 as they include significant unobservable inputs, such as our estimate of future cash flows and the probabilities of alternative scenarios. (See Note 14 of Notes to Consolidated Financial Statements.)

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, 2010. The results of operations by segment are discussed in further detail following this consolidated overview discussion.


	Years Ended December 31,
				$ Change		% Change						$ Change		% Change
				from		from						from		from
	2010			2009*		2009*			2009			2008*		2008*			2008
	(Millions)

Revenues	$	9,616			+1,361		+16	%	$	8,255			− 3,635		−31	%	$	11,890
Costs and expenses:
Costs and operating expenses		7,185			−1,104		−18	%		6,081			+ 2,695		+31	%		8,776
Selling, general and administrative expenses		498			+14		+3	%		512			−8		−2	%		504
Impairments of goodwill and long-lived assets		1,692			−1,672		NM			20			+ 133		+87	%		153
Other (income) expense - net		(24	)		+21		NM			(3	)		−222		−99	%		(225	)
General corporate expenses		221			−57		−35	%		164			−15		−10	%		149

Total costs and expenses		9,572								6,774								9,357

Operating income (loss)		44								1,481								2,533
Interest accrued - net		(581	)		+4		+1	%		(585	)		−8		−1	%		(577	)
Investing income - net		209			+163		NM			46			−143		−76	%		189
Early debt retirement costs		(606	)		−605		NM			(1	)		-		-			(1	)
Other income (expense) - net		(12	)		−14		NM			2			+ 2		NM			-

Income (loss) from continuing operations before income taxes		(946	)							943								2,144
Provision (benefit) for income taxes		(30	)		+389		NM			359			+ 318		+47	%		677

Income (loss) from continuing operations		(916	)							584								1,467
Income (loss) from discontinued operations		(6	)		+217		+97	%		(223	)		−348		NM			125

Net income (loss)		(922	)							361								1,592
Less: Net income attributable to noncontrolling interests		175			−99		−130	%		76			+ 98		+56	%		174

Net income (loss) attributable to The Williams Companies, Inc.	$	(1,097	)						$	285							$	1,418


*		+ = 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.

2010 vs. 2009

The increase in revenues is primarily due to higher marketing and NGL production revenues due to higher average energy commodity prices at Williams Partners. Additionally, Exploration & Production gas management and production revenues increased reflecting an increase in average natural gas prices, partially offset by a decrease in production volumes sold. NGL and olefin production revenues at Other also increased due to higher average per-unit prices.

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The increase in costs and operating expenses is primarily due to increased marketing purchases and NGL production costs at Williams Partners, reflecting higher average energy commodity prices. Exploration & Production costs increased primarily due to increased average natural gas prices associated with gas management activities. Additionally, NGL and olefin production costs at Other increased due to higher average per-unit feedstock costs.

Impairments of goodwill and long-lived assets in 2010 primarily includes a $1 billion impairment of goodwill and $678 million of impairments of certain producing properties and acquired unproved reserves at Exploration & Production.

Impairments of goodwill and long-lived assets in 2009 includes $20 million impairment of certain producing properties and acquired unproved reserves at Exploration & Production.

Other (income) expense - net within operating income (loss) in 2010 includes:


	•	$18 million of involuntary conversion gains at Williams Partners due to insurance recoveries that are in excess of the carrying value of assets;

	•	A $12 million gain on the sale of certain assets at Williams Partners;

	•	A $10 million accrual of a regulatory liability related to overcollection of certain employee expenses at Williams Partners.

Other (income) expense - net within operating income (loss) in 2009 includes:


	•	A $40 million gain on the sale of our Cameron Meadows NGL processing plant at Williams Partners;

	•	$32 million of penalties from the early termination of certain drilling rig contracts at Exploration & Production.

General corporate expenses in 2010 includes $45 million of transaction costs associated with our strategic restructuring transaction.

The unfavorable change in operating income (loss) is primarily due to $1.7 billion of impairment charges in 2010 at Exploration & Production and $45 million of transaction costs in 2010 associated with our strategic restructuring transaction. The unfavorable change is partially offset by an improved energy commodity price environment in 2010 compared to 2009 and the favorable change in other (income) expense - net .

The increase in investing income - net is primarily due to the absence of a $75 million impairment charge in 2009 and a $43 million gain in 2010 on the sale of our 50 percent interest in Accroven at Other, a $27 million increase in equity earnings, primarily at Williams Partners, and the absence of an $11 million impairment charge in 2009 of a cost-based investment at Exploration & Production.

Early debt retirement costs in 2010 reflect costs related to corporate debt retirements associated with our first quarter strategic restructuring transaction, including premiums of $574 million.

Provision (benefit) for income taxes changed favorably primarily due to the pre-tax loss in 2010 compared to pre-tax income in 2009. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.

See Note 2 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations .

Net income attributable to noncontrolling interests increased reflecting higher results, primarily at WPZ, due to an improved energy commodity price environment in 2010 compared to 2009 as well as the impact of the first-quarter 2009 impairments and related charges associated with our discontinued Venezuela operations.

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2009 vs. 2008

Our consolidated results in 2009 declined significantly compared to 2008. These results reflect a rapid decline in energy commodity prices that began in the fourth quarter of 2008 as a result of the weakened economy. Energy commodity prices generally improved during 2009, but not to levels experienced early in 2008.

The decrease in revenues is primarily due to decreased gas management and production revenues at Exploration & Production, reflecting a decrease in average natural gas prices, partially offset by an increase in production volumes sold. NGL production and marketing revenues at Williams Partners, as well as NGL and olefin production revenues at Other, also decreased reflecting lower average prices.

The decrease in costs and operating expenses is primarily due to decreased costs at Exploration & Production reflecting a decrease in average natural gas prices associated with gas management activities, as well as decreased marketing purchases and decreased costs associated with our NGL production businesses at Williams Partners. In addition, NGL and olefin production costs at Other decreased primarily due to lower average per-unit feedstock costs.

Impairments of goodwill and long-lived assets in 2008 includes $143 million of impairments of certain producing properties at Exploration & Production and $10 million of impairments of certain gathering and transportation assets at Williams Partners.

Other (income) expense - net within operating income (loss) in 2008 includes:


	•	Gain of $148 million on the sale of our Peru interests at Exploration & Production;

	•	Net gains of $39 million on foreign currency exchanges at Other;

	•	Income of $32 million related to the partial settlement of our Gulf Liquids litigation at Other;

	•	Gain of $10 million on the sale of certain south Texas assets at Williams Partners;

	•	Income of $17 million resulting from involuntary conversion gains at Williams Partners;

	•	Expense of $23 million related to project development costs at Williams Partners.

General corporate expenses increased primarily due to an increase in employee-related expenses, partially offset by a decrease in outside services.

The decrease in operating income (loss) generally reflects an overall unfavorable energy commodity price environment in 2009 compared to 2008 and other changes as previously discussed.

The decrease in investing income - net is primarily due to a $75 million impairment charge in 2009 of our 50 percent interest in Accroven at Other and an $11 million impairment charge in 2009 of a cost-based investment at Exploration & Production. (See Note 3 of Notes to Consolidated Financial Statements.) A decrease in interest income, primarily due to lower average interest rates in 2009 compared to 2008, also contributed to the decrease in investing income - net.

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rates compared to the federal statutory rate for both years.

See Note 2 of Notes to Consolidated Financial Statements for a discussion of the items in income (loss) from discontinued operations .

Net income attributable to noncontrolling interests decreased reflecting the first-quarter 2009 impairments and related charges associated with our discontinued Venezuela operations (see Note 2 of Notes to Consolidated Financial Statements) and the decline in WPZ's operating results primarily driven by lower NGL margins.

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Results of Operations - Segments

Williams Partners

Our Williams Partners segment includes WPZ, our consolidated master limited partnership, which includes two interstate natural gas pipelines, as well as investments in natural gas pipeline-related companies, which serve regions from the San Juan basin in northwestern New Mexico and southwestern Colorado to Oregon and Washington and from the Gulf of Mexico to the northeastern United States. WPZ also includes natural gas gathering and processing and treating facilities and oil gathering and transportation facilities located primarily in the Rocky Mountain and Gulf Coast regions of the United States. As of December 31, 2010, we currently own approximately 75 percent of the interests in WPZ, including the interests of the general partner, which is wholly owned by us, and incentive distribution rights.

Williams Partners' ongoing strategy is to safely and reliably operate large-scale, interstate natural gas transmission and midstream infrastructures 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 and utilizing our low cost-of-capital to invest in growing markets, including the deepwater Gulf of Mexico, the Marcellus Shale, the western United States, and areas of increasing natural gas demand.

Williams Partners' interstate transmission and related 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.

Overview of 2010

Significant events during 2010 include the following:

Echo Springs Plant Expansion

New capacity from our expansion of the Echo Springs facility began service in the fourth quarter of 2010. The addition of the fourth cryogenic processing train added approximately 350 MMcf/d of processing capacity and 30 Mbbls/d of NGL production capacity, nearly doubling Echo Spring's capacities in both cases. Approximately 70 MMcf/d of production from Exploration & Production in the Piceance basin is currently being processed at the Echo Springs facility for a volumetric-based fee. While a slow-down in Wamsutter area drilling has resulted in some unused capacity, we are exploring ways to bring more natural gas to this facility in the coming year.

Marcellus Shale Gathering Asset Acquisition

In the fourth quarter of 2010 we acquired a gathering business in Pennsylvania's Marcellus Shale in the Appalachian basin for $150 million. The business includes 75 miles of gathering pipelines and two compressor stations which currently gathers approximately 235 MMcf/d. We have agreed to a new long-term dedicated gathering agreement with the seller for its production in the northeast Pennsylvania area of the Marcellus Shale. The acquired system will connect into the Transco pipeline through our Springville gathering pipeline, currently under construction in the Appalachian basin.

Piceance Acquisition

During the fourth quarter of 2010, we completed the purchase of certain gathering and processing assets in the Piceance basin from Exploration & Production as discussed in Note 1 of Notes to Consolidated Financial Statements. In conjunction with this purchase, we entered into a gathering and processing agreement with Exploration & Production, such that future gathering and processing revenues will be at a higher, market-based rate. Prior periods reflect gathering and processing revenues at an internal cost of service rate.

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Perdido Norte

Our Perdido Norte project, in the western deepwater of the Gulf of Mexico, began start-up of operations late in the first quarter of 2010. The project includes a 200 MMcf/d expansion of our onshore Markham gas processing facility and a total of 179 miles of deepwater oil and gas lines that expand the scale of our existing infrastructure. Shortly after an initial startup, during the second quarter, production was suspended by the operator of the deepwater producing platforms to address facility issues and the third quarter was impacted by further delays. While these issues have been resolved and both oil and gas production is currently flowing, production has been impacted in part by the drilling moratorium and the producer's technical issues, and has not increased as quickly as expected. We anticipate volumes to increase significantly, however, during 2011.

Impact of Gulf Oil Spill

Our transportation and processing assets in the Gulf of Mexico were not physically impacted by the Deepwater Horizon oil spill. Operations are normal at all facilities, and we did not experience any operational or logistical issues that hindered the safety of our employees or facilities. The drilling moratorium, in force from May to October, in the Gulf of Mexico impacted the financial performance of our operations through production delays which reduced natural gas and oil growth volumes in 2010. Protracted delays in permitting and drilling could continue to impact our future growth volumes. While we continue to carefully monitor the events and business environment in the Gulf of Mexico for potential negative impacts, we also continue to pursue major expansion and growth opportunities in that region.

Overland Pass Pipeline

In September 2010, we completed the $424 million acquisition of an additional 49 percent ownership interest in OPPL, which increased our ownership interest to 50 percent. In 2006, we entered into an agreement to develop new pipeline capacity for transporting NGLs from production areas in the Rocky Mountain area to central Kansas. Our partner reimbursed us for the development costs we had incurred for the proposed pipeline and acquired 99 percent of the pipeline. We retained a 1 percent interest and the option to increase our ownership to 50 percent within two years of the pipeline becoming operational in November of 2008. As long as we retain a 50 percent ownership interest in OPPL, we have the right to become operator. We have notified our partner of our intent to operate and are currently working on an early 2011 transition. Work is also under way to determine optimal expansions to serve producers in the OPPL corridor. OPPL includes a 760-mile NGL pipeline from Opal, Wyoming, to the Mid-Continent NGL market center in Conway, Kansas, along with 150- and 125-mile extensions into the Piceance and Denver-Joules basins in Colorado, respectively. Our equity NGL volumes from our two Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term shipping agreement.

Volatile commodity prices

Average per-unit NGL margins in 2010 are significantly higher than in 2009, benefiting from a period of increasing average NGL prices while abundant natural gas supplies limited the increase in natural gas prices. Benefits from favorable natural gas price differentials in the Rocky Mountain area have narrowed since the second quarter of 2009 such that our realized per-unit margins are only slightly greater than that of the industry benchmarks for natural gas processed in the Henry Hub area and for liquids fractionated and sold at Mont Belvieu, Texas.

NGL margins are defined as NGL revenues less any applicable BTU replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants.

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Gathering and Processing Per Unit NGL Margin
with Production and Sales Volumes by Quarter
(excludes partially owned plants)

Williams Pipeline Partners L.P.

During the third quarter, WPZ consummated its merger with WMZ. As a result, WMZ is wholly owned by WPZ and is no longer publicly traded.

Mobile Bay South project

In May 2010, a compression facility in Alabama allowing natural gas pipeline transportation service to various southbound delivery points was placed into service. The cost of the project was $32 million and increased capacity by 254 thousand dekatherms per day (Mdt/d).

Sundance Trail project

In November 2009, approval was received from the FERC to construct approximately 16 miles of 30-inch pipeline between existing compressor stations in Wyoming. The project also includes an upgrade to the existing compressor station. The total estimated cost of the project is approximately $50 million. The project was placed in service in November 2010 with an increase in capacity of 150 Mdt/d.

Outlook for 2011

The following factors could impact our business in 2011.

Commodity price changes


	•	We expect our average per-unit NGL margins in 2011 to be higher than our rolling five-year average per-unit NGL margins. NGL price changes have historically tracked somewhat with changes in the price of crude oil, although NGL, crude and natural gas prices are highly volatile and difficult to predict. NGL margins are highly dependent upon continued demand within the global economy. However, NGL products are currently the preferred feedstock for ethylene and propylene production, which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets.

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Gathering, processing, and NGL sales volumes


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

	•	We anticipate growth in our onshore businesses' gas gathering and processing volumes as our infrastructure grows to support drilling activities in the Piceance and Appalachian basins. However, we anticipate no change or slight declines in basins in the Rocky Mountain and Four Corners areas due to reduced drilling activity. Due to the high proportion of fee-based processing agreements in the Piceance basin, we anticipate only a slight increase in NGL equity sales volumes.

	•	In our Gulf Coast businesses, we expect higher gas gathering, processing and crude transportation volumes as our Perdido Norte pipelines move into a full year of operation and other in-process drilling is completed. However, permitting and production delays related to the drilling moratorium which was in force from May to October, 2010 continue to hamper growth. While we expect an overall increase in processed gas volumes in 2011, NGL equity volumes are expected to be lower as we anticipate a major contract to change from keep-whole to fee-based processing.

Expansion projects

We have planned capital and investment expenditures of $1,090 million to $1,370 million in 2011 including expenditures related to our newly acquired gathering system in the Marcellus Shale as well as our Laurel Mountain Midstream, LLC (Laurel Mountain) equity investment. We also plan to pursue major expansion and growth opportunities in the Gulf of Mexico, as well as in the Piceance basin in conjunction with both Exploration & Production's and third-party drilling programs. The ongoing major expansion projects include:

85 North

An expansion of our existing natural gas transmission system from Alabama to various delivery points as far north as North Carolina. The cost of the project is estimated to be approximately $236 million. Phase I service was placed into service in July 2010 and increased capacity by 90 Mdt/d. Phase II service is anticipated to begin in May 2011 and will increase capacity by 219 Mdt/d.

Mobile Bay South II

Additional compression facilities and modifications to existing facilities in Alabama allowing natural gas transportation service to various southbound delivery points. In July 2010, we received approval from the U.S. Federal Energy Regulatory Commission. Construction began in October 2010 and is estimated to cost $35 million. The estimated project in-service date is May 2011 and will increase capacity by 380 Mdt/d.

Mid-South

In October 2010, we filed an application with 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 $219 million. The project is expected to be phased into service in September 2012 and June 2013, with an increase in capacity of 225 Mdt/d.

Mid-Atlantic Connector

In November 2010, we filed an application with the FERC to expand our existing natural gas transmission system from North Carolina to markets as far downstream as Maryland. The cost of the project is estimated to be $55 million and will increase capacity by 142 Mdt/d. We plan to place the project into service in November 2012.

Marcellus Shale

In the Appalachian basin, $150 million was added to our planned expansion capital to fund the 2011 construction phase of additional gathering assets, including compression and dehydration. In conjunction with a

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long-term agreement with a significant producer, we will construct and operate a 33-mile natural gas gathering pipeline in the Marcellus Shale region which will connect our recently acquired gathering assets in Pennsylvania's Marcellus Shale into the Transco pipeline. In order to pursue future opportunities, the project has been increased from a 20-inch diameter to a 24-inch diameter pipeline. Construction on the pipeline is expected to begin in the first quarter of 2011 and be completed during 2011.

Laurel Mountain

Capital to be invested within our Laurel Mountain Midstream, LLC (Laurel Mountain) equity investment to enable the rapid expansion of our gathering system including the initial stages of projects that are planned to provide approximately 1.5 Bcf/d of gathering capacity and 1,400 miles of gathering lines, including 400 new miles of 6-inch to 24-inch diameter pipeline. Construction has begun on our Shamrock compressor station with an initial capacity of 60 MMcf/d, expandable to 350 MMcf/d, which will likely be the largest central delivery point out of the Laurel Mountain system.

We have several other proposed projects to meet customer demands in addition to the various in-progress expansion projects previously discussed. Subject to regulatory approvals, construction of some of these projects could begin in 2011.

Year-Over-Year Operating Results


	Year Ended December 31,
	2010		2009*		2008*
	(Millions)

Segment revenues	$	5,715	$	4,602	$	5,847

Segment profit	$	1,574	$	1,317	$	1,425


*		Recast as discussed in Note 1 of Notes to Consolidated Financial Statements

2010 vs. 2009

The increase in segment revenues includes:


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

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

	•	A $56 million increase in fee revenues primarily due to higher gathering revenue in the Piceance basin as a result of permitted increases in the cost-of-service gathering rate in 2010.

The increase in s egment costs and expenses of $884 million includes:


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

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

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

	•	A $14 million unfavorable change related to the disposal of assets reflecting the absence of a $40 million gain on the sale of our Cameron Meadows processing plant in 2009, partially offset by smaller gains in 2010. Gains recognized in 2010 include involuntary conversion gains due to insurance recoveries in excess of the carrying value of our Gulf assets which were damaged by Hurricane Ike in 2008 and our

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		Ignacio plant, which was damaged by a fire in 2007, as well as gains associated with sales of certain assets in Colorado's Piceance basin.

The increase in William Partners' segment profit includes:


	•	$223 million of higher NGL production margins reflecting higher NGL prices, partially offset by increased production costs associated with higher natural gas prices. NGL equity volumes were slightly higher due primarily to new production at Willow Creek, partially offset by the absence of favorable customer contractual changes and decreasing inventory levels in 2009.

	•	$28 million increase in equity earnings, including a $10 million increase from Discovery primarily due to higher processing margins and new volumes from the Tahiti pipeline lateral expansion completed in 2009. In addition, equity earnings from Aux Sable Liquid Products LP (Aux Sable) are $10 million higher primarily due to higher processing margins, and equity earnings from our increased investment in OPPL were $5 million.

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

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

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

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

2009 vs. 2008

The decrease in segment revenues includes:


	•	A $716 million decrease in revenues associated with the production of NGLs primarily due to lower average NGL prices.

	•	A $513 million decrease in marketing revenues primarily due to lower average NGL and crude prices, partially offset by higher NGL volumes.

	•	A $53 million decrease in revenues from lower transportation imbalance settlements in 2009 compared to 2008 ( offset in costs and operating expenses ).

	•	A $65 million increase in fee revenues primarily due to higher volumes resulting from connecting new supplies in the deepwater Gulf of Mexico in the latter part of 2008 and new fees for processing the Exploration & Production segment's natural gas production at Willow Creek.

	•	A $17 million increase in transportation revenues associated with expansion projects placed into service in 2009.

The decrease in s egment costs and expenses of $1,132 million includes:


	•	A $643 million decrease in marketing purchases primarily due to lower average NGL and crude prices, including the absence of a $9 million charge in 2008 to write down the value of NGL inventories, partially offset by higher NGL volumes.

	•	A $435 million decrease in costs associated with the production of NGLs primarily due to lower average natural gas prices.

	•	A $53 million decrease in costs associated with lower transportation imbalance settlements in 2009 compared to 2008 ( offset in segment revenues ).

	•	A $40 million gain on the 2009 sale of our Cameron Meadows processing plant.

	•	The absence of $17 million of charges in 2008 related to an impairment, asset abandonments, and asset retirement obligations.

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The decrease in William Partners' segment profit includes:


	•	$281 million of lower NGL production margins reflecting a decrease in energy commodity prices in 2009 compared to 2008.

	•	$124 million in higher margins related to the marketing of NGLs primarily due to favorable changes in pricing while product was in transit during 2009 as compared to significant unfavorable changes in pricing while product was in transit in 2008 and the absence of a $9 million charge in 2008 to write down the value of NGL inventories.

	•	A $40 million gain in 2009 on the sale of our Cameron Meadows processing plant, partially offset by the absence of a $5 million involuntary conversion gain in 2008 related to our Cameron Meadows plant.

Exploration & Production

Exploration & Production includes the natural gas development, production and gas management activities primarily in the Rocky Mountain and Mid-Continent regions of the United States, natural gas development activities in the northeastern portion of the United States, oil and natural gas interests in South America, and more recently, oil development activities in the northern United States. The gas management activities include procuring fuel and shrink gas for our midstream businesses and providing marketing services to third parties, such as producers. Additionally, gas management activities include the managing of various natural gas related contracts such as transportation, storage and related hedges.

Overview of 2010

Domestic production revenues for 2010 were higher than 2009 primarily due to higher realized average prices on our natural gas production, partially offset by lower production volumes. Segment profit (loss) for 2010 includes approximately $1.7 billion in impairments of natural gas properties and goodwill (see further discussion below), while 2009 included expense of $32 million associated with contractual penalties from the early termination of drilling rig contracts. Highlights of the comparative periods, primarily related to our production activities, include:


	Years Ended December 31,
	2010			2009		% Change

Average daily domestic production (MMcfe)		1,132			1,182		−4	%
Average daily total production (MMcfe)		1,185			1,236		−4	%
Domestic production realized average price ($/Mcfe)(1)	$	5.23		$	4.85		+8	%
Capital expenditures and acquisitions($ millions)	$	2,823		$	1,291		+119	%
Domestic production revenues ($ millions)	$	2,160		$	2,093		+3	%
Segment revenues ($ millions)	$	4,042		$	3,684		+10	%
Segment profit (loss) ($ millions)	$	(1,343	)	$	391		NM


(1)		Realized average prices include market prices, net of fuel and shrink and hedge gains and losses. The realized hedge gain per Mcfe was $0.81 and $1.43 for 2010 and 2009, respectively.

During the second quarter of 2010, we entered into an agreement to acquire additional leasehold acreage positions and a 5 percent overriding royalty interest associated with these acreage positions. These acquisitions nearly double our acreage holdings in the Marcellus Shale and closed in July for $599 million, including closing adjustments. During 2010, we also spent a total of $164 million to acquire additional unproved leasehold acreage in the Marcellus Shale.

During the fourth quarter of 2010, we acquired a company that holds a major acreage position (approximately 85,800 net acres, most of which is undeveloped) in North Dakota's Bakken Shale oil play (Williston basin) that will diversify our interests into light, sweet crude oil production. The purchase price was approximately $949 million, including closing adjustments.

During the fourth quarter of 2010, we completed the sale of certain gathering and processing assets in the Piceance basin to WPZ for consideration of $702 million in cash and approximately 1.8 million common units. See

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Note 1 in Notes to Consolidated Financial Statements. In conjunction with this sale, we entered into a gathering and processing agreement with WPZ. Gathering and processing costs prior to the sale reflect an internal cost-of-service rate. Subsequent to the closing date of the sale, gathering and processing costs will be at a higher, market-based rate.

As a result of significant declines in forward natural gas prices during third quarter 2010, we performed an interim assessment of our capitalized costs related to property and goodwill. As a result of these assessments, we recorded a $503 million impairment charge related to the capitalized costs of our Barnett Shale properties and a $175 million impairment charge related to capitalized costs of acquired unproved reserves in the Piceance Highlands, which were acquired in 2008. Additionally, we fully impaired our goodwill in the amount of $1 billion. These impairments were based on our assessment of estimated future discounted cash flows and other information. See Notes 4 and 14 of Notes to Consolidated Financial Statements for a further discussion of the impairments.

Outlook for 2011

We have the following expectations for 2011:


	•	Natural gas prices to remain at levels similar to 2010.

	•	Increase capital expenditures in 2011 over levels (before acquisitions) in 2010 to develop positions that were acquired in the Appalachian and Williston basins in 2010.

	•	Continuation of our development drilling program in the Appalachian, Piceance, Fort Worth, Powder River, and San Juan basins. Our total capital expenditures for 2011 are projected to be between $1.15 billion and $1.75 billion. We expect to maintain three to five drilling rigs in our newly acquired Williston basin properties with related capital expenditures expected to be between $200 million and $300 million.

	•	Annual average daily domestic production expected to increase approximately 9 percent over 2010.

Risks to achieving our expectations include unfavorable energy commodity price movements which are impacted by numerous factors, including weather conditions, domestic natural gas, oil and NGL production levels and demand. A significant decline in natural gas, oil and NGL prices would impact these expectations for 2011, although the impact would be somewhat mitigated by our hedging program, which hedges a significant portion of our expected production. In addition, changes in laws and regulations may impact our development drilling program.

Purchase Commitments

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Commodity Price Risk Strategy

To manage the commodity price risk and volatility of owning producing gas and oil properties, we enter into derivative contracts for a portion of our future production. For 2011, we have the following contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:


	2011 Natural Gas
			Price ($/Mcf)
	Volume		Floor-Ceiling for
	(MMcf/d)		Collars

Collar agreements - Rockies		45		$5.30 - $7.10
Collar agreements - San Juan		90		$5.27 - $7.06
Collar agreements - Mid-Continent		80		$5.10 - $7.00
Collar agreements - Southern California		30		$5.83 - $7.56
Collar agreements - Appalachia		30		$6.50 - $8.14
Fixed price at basin swaps		368		$5.21


	2011 Crude Oil
	Volume
	(Bbls/d)
	(Feb-Dec)		Price ($/Bbl)

WTI Crude Oil fixed-price (entered into first-quarter 2011)		3,073		95.13

The following is a summary of our agreements and contracts for daily domestic production shown at weighted average volumes and basin-level weighted average prices for the years ended December 31, 2010, 2009 and 2008:


	2010			2009		2008
			Price ($/Mcf)		Price ($/Mcf)		Price ($/Mcf)
	Volume		Floor-Ceiling	Volume	Floor-Ceiling	Volume	Floor-Ceiling
	(MMcf/d)		for Collars	(MMcf/d)	for Collars	(MMcf/d)	for Collars

Collars - Rockies		100	$6.53 - $8.94	150	$6.11 -$9.04	170	$6.16 - $9.14
Collars - San Juan		233	$5.75 - $7.82	245	$6.58 - $9.62	202	$6.35 - $8.96
Collars - Mid-Continent		105	$5.37 - $7.41	95	$7.08 -$9.73	63	$7.02 - $9.72
Collars - Southern California		45	$4.80 - $6.43	-	-	-	-
Collars - Other		28	$5.63 - $6.87	-	-	-	-
NYMEX and basis fixed-price		120	$4.40	106	$3.67	70	$3.97

Additionally, we utilize contracted pipeline capacity to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We hold a long-term obligation to deliver on a firm basis 200,000 MMbtu per day of gas to a buyer at the White River Hub (Greasewood-Meeker, CO), which is the major market hub exiting the Piceance basin. Our interests in the Piceance basin hold sufficient reserves to meet this obligation.

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Year-Over-Year Operating Results


	Years Ended December 31,
	2010			2009*		2008*
	(Millions)

Segment revenues:
Domestic production revenues	$	2,160		$	2,093	$	2,819
Gas management revenues		1,743			1,456		3,244
Net forward unrealized mark-to-market gains and ineffectiveness		27			18		29
Other revenues		112			117		103

Total segment revenues	$	4,042		$	3,684	$	6,195

Segment profit (loss)	$	(1,343	)	$	391	$	1,253


*		Recast as discussed in Note 1 of Notes to Consolidated Financial Statements.

2010 vs. 2009

The increase in total segment revenues is primarily due to the following:


	•	The increase in domestic production revenues reflects an increase of $156 million associated with an 8 percent increase in realized average prices including the effect of hedges, partially offset by a decrease of $89 million associated with a 4 percent decrease in production volumes sold. Production revenues in 2010 and 2009 include approximately $202 million and $93 million, respectively, related to NGLs and approximately $57 million and $38 million, respectively, related to condensate. The increase related to NGLs is primarily due to higher volumes in the Piceance basin processed by Williams Partners' Willow Creek facility, which was placed into service in the latter part of 2009;

	•	The increase in gas management revenues is primarily due to an increase in physical natural gas revenue as a result of a 21 percent increase in average prices on physical natural gas sales. This is primarily related to gas sales associated with our transportation and storage contracts and is offset by a similar increase in segment costs and expenses ;

Total segment costs and expenses increased $2,094 million, primarily due to the following:


	•	$1,684 million due to 2010 impairments of property and goodwill as previously discussed. In 2009, $20 million of impairments were recorded in the Fort Worth and Arkoma basins;

	•	$278 million increase in gas management expenses, primarily due to an 19 percent increase in average prices on physical natural gas purchases. This increase is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is more than offset by a similar increase in segment revenues . Gas management expenses in 2010 and 2009 include $48 million and $21 million, respectively, related to charges for unutilized pipeline capacity;

	•	$76 million higher gathering, processing, and transportation expenses primarily as a result of processing natural gas liquids at Williams Partners' Willow Creek plant, which began processing in August 2009, and higher rates charged on gathering and processing associated with certain gathering and processing assets in the Piceance basin that were sold to WPZ in the fourth quarter of 2010;

	•	$44 million higher severance and ad valorem taxes primarily due to higher average market prices, excluding the impact of hedges;

	•	$30 million higher lease and other operating expenses primarily due to increased workover and maintenance activity;

	•	$27 million higher depreciation, depletion, and amortization expenses primarily due to a change in prior production volumes and higher depreciable costs used in the calculation of depreciation, depletion, and amortization expenses.

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Partially offsetting the increased costs is a decrease due to the absence of $32 million of expenses in 2009 related to penalties from the early release of drilling rigs as previously discussed.

The $1,734 million decrease in s egment profit (loss) is primarily due to the impairments, partially offset by an 8 percent increase in realized average domestic prices on production and the other previously discussed changes in segment revenues and segment costs and expenses.

2009 vs. 2008

The decrease in total segment revenues is primarily due to the following:


	•	$726 million, or 26 percent, decrease in domestic production revenues reflecting $946 million associated with a 31 percent decrease in realized average prices, partially offset by an increase of $220 million associated with an 8 percent increase in production volumes sold. Production revenues in 2009 and 2008 include approximately $93 million and $85 million, respectively, related to NGLs and approximately $38 million and $62 million, respectively, related to condensate. While NGL volumes were significantly higher than the prior year, NGL prices were significantly lower;

	•	$1,788 million, or 55 percent, decrease in gas management revenues primarily due to a decrease in physical natural gas revenue as a result of a 56 percent decrease in average prices on physical natural gas sales, slightly offset by a 2 percent increase in natural gas sales volumes. This is primarily related to gas sales associated with our transportation and storage contracts and is substantially offset by a similar decrease in segment costs and expenses .

The decrease in net forward unrealized mark-to-market gains (losses) and ineffectiveness is primarily related to the absence of a $10 million favorable impact in 2008 for the initial consideration of our own nonperformance risk in estimating the fair value of our derivative liabilities.

Total segment costs and expenses decreased $1,651 million, primarily due to the following:


	•	$1,752 million decrease in gas management expenses, primarily due to a 55 percent decrease in average prices on physical natural gas purchases, slightly offset by a 2 percent increase in natural gas purchase volumes. This decrease is primarily related to the gas purchases associated with our previously discussed transportation and storage contracts and is more than offset by a similar decrease in segment revenues . Gas management expenses in 2009 and 2008 include $21 million and $8 million, respectively, related to charges for unutilized pipeline capacity. Gas management expenses in 2009 and 2008 also include $7 million and $35 million, respectively, related to adjustments to the carrying value of natural gas inventories in storage;

	•	$166 million lower operating taxes due primarily to 56 percent lower average market prices (excluding the impact of hedges), partially offset by higher production volumes sold. The lower operating taxes include a net decrease of $39 million reflecting a $34 million charge in 2008 and $5 million of favorable revisions in 2009 relating to Wyoming severance and ad valorem tax issues;

	•	$143 million due to the absence of property impairments recorded in 2008 in the Arkoma basin;

	•	$6 million lower SG&A expenses, which include lower bad debt expense related to the partial recovery of certain receivables previously reserved for in 2008 resulting from a bankrupt counterparty.

Partially offsetting the decreased costs are increases due to the following:


	•	The absence of a $148 million gain recorded in 2008 associated with the sale of our Peru interests;

	•	$145 million higher depreciation, depletion, and amortization expense primarily due to the impact of higher capitalized drilling costs from prior years and higher production volumes compared to the prior year. Also, we recorded an additional $17 million of depreciation, depletion, and amortization in the

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		fourth quarter of 2009 primarily due to new SEC reserves reporting rules. Our proved reserves decreased primarily due to the new SEC reserves reporting rules and the related price impact;


	•	$57 million higher gathering, processing and transportation expense primarily due to higher production volumes and the processing fees for natural gas liquids at Williams Partners' Willow Creek plant, which began processing in August 2009;

	•	$32 million of expense related to penalties from the early release of drilling rigs as previously discussed;

	•	$31 million higher exploratory expense in 2009, primarily related to $20 million of increased seismic costs and $12 million related to higher amortization and the write-off of lease acquisition costs. Dry hole costs for 2009 and 2008 were $11 million and $12 million, respectively. As of December 31, 2009, we have approximately $14 million of capitalized drilling costs and $24 million of undeveloped leasehold costs related to continuing exploratory activities in the Paradox basin;

	•	$20 million of impairment costs in the Fort Worth and Arkoma basins. We recorded a $15 million impairment in 2009 related to costs of acquired unproved reserves resulting from a 2008 acquisition in the Fort Worth basin. This impairment was based on our assessment of estimated future discounted cash flows and additional information obtained from drilling and other activities in 2009. We also recorded a $5 million impairment in the Arkoma basin in 2009 related to facilities.

The $862 million decrease in segment profit is primarily due to the 31 percent decrease in realized average domestic prices and the other previously discussed changes in segment revenues and segment costs and expenses.

Other

Other includes other business activities that are not operating segments, primarily our Canadian midstream and domestic olefins operations and a 25.5 percent interest in Gulfstream, as well as corporate operations. Segment profit (loss) for the year ended December 31, 2010, has improved compared to the prior year primarily due to $139 million higher NGL and olefins production margins resulting from significantly higher average per-unit margins on lower volumes and the net impact of recognizing $43 million in gains on the Accroven investment in 2010 while recording a $75 million impairment charge on that investment in 2009.

Significant events for 2010 include the following:

Sale of Accroven

Considering the deteriorating circumstances in Venezuela, in 2009 we fully impaired our $75 million investment in Accroven SRL, a Venezuelan operation. (See Note 2 of Notes to Consolidated Financial Statements.) In June of 2010, we sold our 50 percent interest in Accroven to the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA) for $107 million. Of this amount, $13 million was received in cash at closing and another $30 million was received in August 2010. The remainder is due in six quarterly payments beginning October 31, 2010. The first quarterly payment of $11 million was received in January 2011 and will be recognized as income in 2011. We will continue to recognize the resulting gain as cash is received. Accroven was not part of our operations that were expropriated by the Venezuelan government in May 2009.

Completion of the butylene/butane splitter facility in Canada

The new butylene/butane splitter and hydro-treating facility was placed into service in August 2010. The butylene/butane splitter further fractionates the butylene/butane mix product produced at our Redwater fractionators near Edmonton, Alberta, into separate butylene and butane products, which receive higher values and are in greater demand. The source of the product fractionated at Redwater is our oil sands off-gas extraction facility near Ft. McMurray, Alberta.

Outlook for 2011

The following factors could impact our business in 2011.

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Commodity price changes

We anticipate average per-unit margins in 2011 will be consistent with the 2010 levels. Margins in our Canadian midstream and domestic olefins business are highly dependent upon continued demand within the global economy. NGL products are currently the preferred feedstock for ethylene and propylene production which has been shifting away from the more expensive crude-based feedstocks. Bolstered by abundant long-term domestic natural gas supplies, we expect to benefit from these dynamics in the broader global petrochemical markets because of our NGL-based olefins production.

Allocation of capital to projects

We expect to spend $380 million to $480 million in 2011 on capital projects. The major expansion projects include a 12-inch diameter pipeline in Canada, which will transport recovered NGLs and olefins from our extraction plant in Ft. McMurray to our Redwater fractionation facility. The pipeline will have sufficient capacity to transport additional recovered liquids in excess of those from our current agreements. Construction has begun and we anticipate an in-service date in 2012.

Year-Over-Year Operating Results


	Year Ended December 31,
	2010		2009			2008
	(Millions)

Segment revenues	$	1,057	$	780		$	1,257

Segment profit (loss)	$	240	$	(2	)	$	142

2010 vs. 2009

Segment revenues increased primarily due to:


	•	$307 million higher NGL and olefins production revenues resulting from higher average per-unit prices. The new butylene/butane splitter began producing and selling both butylene and butane in August 2010 and resulted in $22 million additional sales revenues over the 2009 butylene/butane mix product sold.

	•	$27 million higher marketing revenues due to general increases in energy commodity prices on slightly higher volumes. The higher marketing revenues were more than offset by similar changes in marketing purchases described below.

Partially offsetting the increased revenue was a $57 million decrease from lower sales volumes primarily due to:


	•	11 percent lower Gulf ethylene sales volumes, including the impact of a four-week plant maintenance outage at our Geismar plant during the fourth quarter of 2010.

	•	12 percent lower propylene volumes sold primarily due to the absence of certain large 2009 propylene inventory sales and lower volumes available for processing at our Gulf propylene splitter.

Segment costs and expenses increased $150 million primarily as a result of:


	•	$156 million higher NGL and olefins production product costs resulting from higher average per-unit feedstock costs.

	•	$29 million increased marketing purchases due to general increases in energy commodity prices on slightly higher volumes. The increased marketing purchases more than offset similar changes in marketing revenues.

	•	$7 million higher operating and general and administrative costs in our Canadian midstream and domestic olefins operations.

Partially offsetting the increased costs are decreases due to:


	•	$45 million of reduced product costs resulting from the lower sales volumes described above.

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	•	$6 million favorable customer settlement in 2010.

The favorable change in segment profit (loss) is primarily due to $139 million higher NGL and olefins production margins resulting from significantly higher average per-unit margins on lower volumes and the net impact of recognizing $43 million in gains on the Accroven investment in 2010 while recording a $75 million impairment charge on that investment in 2009.

2009 vs. 2008

Segment revenues decreased primarily due to:


	•	A $457 million decrease in NGL and olefins production revenues resulting from lower average product prices, partially offset by higher volumes.

	•	A $19 million decrease in marketing revenues primarily due to lower average NGL and olefin prices, partially offset by higher NGL and olefin volumes.

Segment costs and expenses decreased $413 million primarily as a result of:


	•	A $445 million decrease in costs in our NGL and olefins production business primarily due to lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin inventories, partially offset by higher volumes.

	•	A $34 million decrease in marketing purchases primarily due to lower average NGL and olefin prices, including the absence of an $11 million charge in 2008 to write-down the value of our NGL inventories, partially offset by higher volumes.

These decreases were partially offset by:


	•	A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•	The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation (see Note 16 of Notes to Consolidated Financial Statements).

The unfavorable change in segment profit (loss) was primarily due to:


	•	A $75 million loss from investment related to the 2009 impairment of our investment in Accroven.

	•	A $39 million unfavorable change primarily due to foreign currency exchange gains in 2008 related to the revaluation of current assets held in U.S. dollars within our Canadian operations.

	•	The absence of $32 million of income in 2008 related to the partial settlement of our Gulf Liquids litigation.

	•	A $12 million decrease in NGL and olefins production margins primarily due to lower average prices, partially offset by lower per-unit feedstock costs, including the absence of an $11 million charge in 2008 to write-down the value of olefin production inventories, and higher volumes in 2009 related to the impact of third-party operational issues in 2008 that reduced off-gas supplies to our plant in Canada.

	•	The absence of an $8 million gain recognized in 2008 related to a final earn-out payment on a 2005 asset sale.

These decreases were partially offset by $15 million higher marketing margins in our NGL and olefins production business primarily due to the absence of an $11 million charge in 2008 to write-down the value of NGL inventories.

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Management's Discussion and Analysis of Financial Condition and Liquidity

Overview

In 2010, we continued to focus upon growth through disciplined investments in our businesses. Examples of this growth included:


	•	Continued investment in Exploration & Production's development drilling programs, as well as acquisitions that expanded our presence in the Marcellus Shale and provided our initial entry into the Bakken Shale areas.

	•	Expansion of Williams Partners' interstate natural gas pipeline system to meet the demand of growth markets.

	•	Continued investment in Williams Partners' deepwater Gulf expansion projects, gas processing capacity in the western United States, infrastructure in the Marcellus Shale area and increased ownership in OPPL.

These investments were funded through cash flow from operations, debt and equity offerings at WPZ and cash on hand.

During 2010, the overall economic recession has impacted us. In consideration of our liquidity under these conditions, we note the following:


	•	As of December 31, 2010, we have approximately $800 million of cash and cash equivalents and approximately $2.7 billion of available credit capacity under our credit facilities. Our $900 million credit facility does not expire until May 2012, and WPZ's $1.75 billion credit facility does not expire until February 2013. Additionally, Exploration & Production has an unsecured credit agreement that serves to reduce our margin requirements related to our hedging activities. (See additional discussion in the following Available Liquidity section.)

	•	Our credit exposure to derivative counterparties is partially mitigated by master netting agreements and collateral support. (See Note 15 of Notes to Consolidated Financial Statements.)

Outlook

For 2011, we expect operating cash flows to be stronger than 2010 levels. Lower-than-expected energy commodity prices would be somewhat mitigated by certain of our cash flow streams that are substantially insulated from short-term changes in commodity prices as follows:


	•	Firm demand and capacity reservation transportation revenues under long-term contracts from our gas pipelines;

	•	Hedged natural gas sales at Exploration & Production related to a significant portion of its production;

	•	Fee-based revenues from certain gathering and processing services in our midstream businesses.

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, and tax and debt payments while maintaining a sufficient level of liquidity. In particular, we note the following assumptions for the year:


	•	We expect to maintain consolidated liquidity (which includes liquidity at WPZ) of at least $1 billion from cash and cash equivalents and unused revolving credit facilities;

	•	We expect to fund capital and investment expenditures, debt payments, dividends, and working capital requirements primarily through cash flow from operations, cash and cash equivalents on hand, utilization of our revolving credit facilities, and proceeds from debt issuances and sales of equity securities as needed. Based on a range of market assumptions, we currently estimate our cash flow from operations will be between $2.5 billion and $3.3 billion in 2011;

	•	We expect capital and investment expenditures to total between $3.125 billion and $4.125 billion in 2011. Of this total, a significant portion of Williams Partners' expected expenditures of $1.58 billion to

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		$1.905 billion are considered nondiscretionary to meet legal, regulatory, and/or contractual requirements or to fund committed growth projects. Exploration & Production's expected expenditures of $1.15 billion to $1.75 billion are considered primarily discretionary. See Results of Operations - Segments, Williams Partners and Exploration & Production for discussions describing the general nature of these expenditures.

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


	•	Sustained reductions in energy commodity prices from the range of current expectations;

	•	Lower than expected distributions, including incentive distribution rights, from WPZ. WPZ's liquidity could also be impacted by a lack of adequate access to capital markets to fund its growth;

	•	Lower than expected levels of cash flow from operations from Exploration & Production and our other businesses.

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 2011. Our internal and external sources of consolidated liquidity include cash generated from our operations, cash and cash equivalents on hand, and our credit facilities. Additional sources of liquidity, if needed, include bank financings, proceeds from the issuance of long-term debt and equity securities, and proceeds from asset sales. These sources are available to us at the parent level and are expected to be available to certain of our subsidiaries, particularly equity and debt issuances from WPZ. WPZ is expected to be self-funding through its cash flows from operations, use of its credit facility, and its access to capital markets. Cash held by WPZ is available to us through distributions in accordance with the partnership agreement, which considers our level of ownership and incentive distribution rights. Our ability to raise funds in the capital markets will be impacted by our financial condition, interest rates, market conditions, and industry conditions.

Available Liquidity


			December 31, 2010
	Expiration		WPZ		WMB			Total
			(Millions)

Cash and cash equivalents			$	187	$	608	(1)	$	795
Available capacity under our $900 million unsecured revolving and letter of credit facility(2)		May 1, 2012				900			900
Capacity available to Williams Partners L.P. under its $1.75 billion senior unsecured credit facility(2)		February 17, 2013		1,750					1,750

			$	1,937	$	1,508		$	3,445


(1)		Cash and cash equivalents includes $25 million of funds received from third parties as collateral. The obligation for these amounts is reported as accrued liabilities on the Consolidated Balance Sheet. Also included is $518 million of cash and cash equivalents that is being utilized by certain subsidiary and international operations. The remainder of our cash and cash equivalents is primarily held in government-backed instruments.

(2)		At December 31, 2010, we are in compliance with the financial covenants associated with these credit facilities. See Note 11 of Notes to Consolidated Financial Statements.

In addition to the credit facilities listed above, we have issued letters of credit totaling $90 million as of December 31, 2010, under certain bilateral bank agreements.

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WPZ filed a shelf registration statement as a well-known, seasoned issuer in October 2009 that allows it to issue an unlimited amount of registered debt and limited partnership unit securities.

At the parent-company level, we filed a shelf registration statement as a well-known, seasoned issuer in May 2009 that allows us to issue an unlimited amount of registered debt and equity securities.

Exploration & Production has an unsecured credit agreement with certain banks that, so long as certain conditions are met, serves to reduce our use of cash and other credit facilities for margin requirements related to our hedging activities as well as lower transaction fees. In July 2010, the agreement term was extended from December 2013 to December 2015. The impairments of goodwill, natural gas producing properties and acquired unproved reserves recorded by our Exploration & Production segment in the third quarter of 2010 (see Notes 4 and 14 of Notes to Consolidated Financial Statements) did not impact our ability to utilize Exploration & Production's credit agreement to facilitate hedging our future natural gas production.

Credit Ratings

Our ability to borrow money is impacted by our credit ratings and the credit ratings of WPZ. The current ratings are as follows:


	WMB	WPZ

Standard and Poor's(1)
Corporate Credit Rating	BBB−	BBB−
Senior Unsecured Debt Rating	BB+	BBB−
Outlook	Positive	Positive
Moody's Investors Service(2)
Senior Unsecured Debt Rating	Baa3	Baa3
Outlook	Stable	Stable
Fitch Ratings(3)
Senior Unsecured Debt Rating	BBB−	BBB−
Outlook	Stable	Stable


(1)		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 & 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 & Poor's may modify its ratings with a "+" or a "-" sign to show the obligor's relative standing within a major rating category.

(2)		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 the lower end of the category.

(3)		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, 2010, we estimate that a downgrade to a rating below investment grade for WMB or WPZ would require us to post up to $453 million or $53 million, respectively, in additional collateral with third parties.

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Sources (Uses) of Cash


	Years Ended December 31,
	2010			2009			2008
	(Millions)

Net cash provided (used) by:
Operating activities	$	2,651		$	2,572		$	3,355
Financing activities		573			166			(432	)
Investing activities		(4,296	)		(2,310	)		(3,183	)

Increase (decrease) in cash and cash equivalents	$	(1,072	)	$	428		$	(260	)

Operating activities

Our net cash provided by operating activities in 2010 increased slightly from 2009 primarily due to the improvement in the energy commodity price environment during the year.

The decrease in net cash provided by operating activities from 2009 to 2008 was primarily due to the decrease in our operating results.

Financing activities

Significant transactions include:

2010


	•	$369 million received from WPZ's December 2010 equity offering used primarily to reduce revolver borrowings mentioned below and to fund a portion of WPZ's acquisition of a midstream business in Pennsylvania's Marcellus Shale in December 2010;

	•	$200 million received in revolver borrowings from WPZ's $1.75 billion unsecured credit facility primarily used for WPZ's general partnership purposes and to fund a portion of the cash consideration paid for WPZ's acquisition of certain gathering and processing assets in Colorado's Piceance basin in November 2010;

	•	$600 million received from WPZ's public offering of 4.125 percent senior unsecured notes in November 2010 primarily used to fund a portion of the cash consideration paid to Exploration & Production for WPZ's Piceance acquisition (see Note 1 of Notes to Consolidated Financial Statements);

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

	•	$437 million received from a WPZ equity offering used to reduce WPZ's revolver borrowings mentioned above;

	•	$3.491 billion received by WPZ in February 2010 from the issuance of $3.5 billion of senior unsecured notes related to our previously discussed restructuring (see Note 11 of Notes to Consolidated Financial Statements);

	•	$3 billion of senior unsecured notes retired in February 2010 and $574 million paid in associated premiums utilizing proceeds from the $3.5 billion debt issuance (see Note 11 of Notes to Consolidated Financial Statements);

	•	$250 million received from revolver borrowings on WPZ's $1.75 billion unsecured credit facility in February 2010 to repay a term loan;

	•	We paid $284 million of quarterly dividends on common stock for the year ended December 31, 2010.

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2009


	•	We received $595 million net cash from the issuance of $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to fund general corporate expenses and capital expenditures. (See Note 11 of Notes to Consolidated Financial Statements.);

	•	We paid $256 million of quarterly dividends on common stock for the year ended December 31, 2009.

2008


	•	We received $362 million from the completion of the WMZ initial public offering;

	•	We paid $474 million for the repurchase of our common stock. (See Note 12 of Notes to Consolidated Financial Statements.);

	•	WPZ received $75 million net proceeds from debt transactions;

	•	We paid $250 million of quarterly dividends on common stock for the year ended December 31, 2008.

Investing activities

Significant transactions include:

2010


	•	Capital expenditures totaled $2.8 billion in 2010. Included is approximately $599 million, including closing adjustments, related to Exploration & Production's acquisition in the Marcellus Shale in July 2010 (see Results of Operations - Segments, Exploration & Production);

	•	We paid approximately $949 million, including closing adjustments, for Exploration & Production's December 2010 business purchase, consisting primarily of oil and gas properties in the Bakken Shale (see Results of Operations - Segments, Exploration & Production);

	•	We contributed $488 million to our investments, including a $424 million cash payment for WPZ's September 2010 acquisition of an increased interest in OPPL (see Results of Operations - Segments, Williams Partners);

	•	We paid $150 million for WPZ's December 2010 business purchase, consisting primarily of certain midstream assets in the Marcellus Shale.

2009


	•	Capital expenditures totaled $2.4 billion, more than half of which related to Exploration & Production. Included was a $253 million payment by Exploration & Production for the purchase of additional properties in the Piceance basin. (See Results of Operations - Segments, Exploration & Production.);

	•	We received $148 million as a distribution from Gulfstream following its debt offering;

	•	We contributed $142 million to our investments, including $106 million related to our Laurel Mountain equity investment and $20 million related to our Gulfstream equity investment.

2008


	•	Capital expenditures totaled $3.4 billion and were primarily related to Exploration & Production's drilling activity. This total includes Exploration & Production's acquisitions of certain interests in the Piceance and Fort Worth basins;

	•	We received $148 million of cash from Exploration & Production's sale of a contractual right to a production payment;

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	•	We contributed $111 million to our investments, including $90 million related to our Gulfstream equity investment.

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

We have various other guarantees and commitments which are disclosed in Notes 9, 11, 15 and 16 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.

Contractual Obligations

The table below summarizes the maturity dates of our contractual obligations at December 31, 2010, including obligations related to discontinued operations.


			2012-		2014-
	2011		2013		2015		Thereafter		Total
	(Millions)

Long-term debt, including current portion:
Principal	$	507	$	352	$	750	$	7,532	$	9,141
Interest		580		1,071		1,017		5,046		7,714
Capital leases		1		3		-		-		4
Operating leases		89		84		59		182		414
Purchase obligations(1)		1,068		1,446		1,233		2,674		6,421
Other long-term liabilities, including current portion:
Physical and financial derivatives(2)(3)		489		1,058		870		3,634		6,051
Other(4)(5)		165		-		-		-		165

Total	$	2,899	$	4,014	$	3,929	$	19,068	$	29,910


(1)		Includes $2.3 billion of natural gas purchase obligations at market prices at our Exploration & Production segment. The purchased natural gas can be sold at market prices.

(2)		Includes $5.4 billion of physical natural gas derivatives related to purchases at market prices in our Exploration & Production segment. The natural gas expected to be purchased under these contracts can be sold at market prices. The obligations for physical and financial derivatives are based on market information as of December 31, 2010, and assumes contracts remain outstanding for their full contractual duration. Because market information changes daily and has the potential to be volatile, significant changes to the values in this category may occur.

(3)		Expected offsetting cash inflows of $2.1 billion at December 31, 2010, resulting from product sales or net positive settlements, are not reflected in these amounts. In addition, product sales may require additional purchase obligations to fulfill sales obligations that are not reflected in these amounts.

(4)		Does not include estimated contributions to our pension and other postretirement benefit plans. We made contributions to our pension and other postretirement benefit plans of $76 million in 2010 and $77 million in 2009. In 2011, we expect to contribute approximately $83 million to these plans (see Note 7 of Notes to Consolidated Financial Statements). During 2010, we contributed $60 million to our tax-qualified pension plans which was greater than the minimum required contributions. We expect to contribute approximately $60 million to these pension plans again in 2011, which is expected to be greater than the minimum required contributions. In the past, we have contributed amounts in excess of the minimum required contribution. These excess amounts can be used to offset future minimum contribution requirements. In the future, we may elect to use some of these excess amounts to satisfy the minimum contribution requirement in order to maintain cash contributions at the current level. Additionally, estimated future minimum funding requirements may vary significantly from historical requirements if actual results differ significantly from estimated results for

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		assumptions such as returns on plan assets, interest rates, retirement rates, mortality, and other significant assumptions or by changes to current legislation and regulations.

(5)		Includes $165 million reflecting our estimate of an income tax settlement to be paid in 2011. We have not included other income tax liabilities in the table above. See Note 5 of Notes to Consolidated Financial Statements for a discussion of income taxes, including our unrecognized tax benefits.

Effects of Inflation

Our operations have benefited from relatively low inflation rates. Approximately 35 percent of our gross property, plant, and equipment is comprised of our interstate gas pipelines. These assets are 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 regulation, along with competition and other market factors, may limit our ability to recover such increased costs. For the remainder of our business, 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 16 of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Current estimates of the most likely costs of such activities are approximately $49 million, all of which are included in accrued liabilities and other liabilities and deferred income on the Consolidated Balance Sheet at December 31, 2010. We will seek recovery of approximately $12 million of these accrued costs through future natural gas transmission rates. The remainder of these costs will be funded from operations. During 2010, we paid approximately $8 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $11 million in 2011 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, 2010, certain assessment studies were still in process for which the ultimate outcome may yield significantly different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.

In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA currently anticipates finalization of the new ground-level ozone standard in the third quarter of 2011. Designation of new eight-hour ozone non-attainment areas

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are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment-net on the Consolidated Balance Sheet. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

Additionally, in August 2010, the EPA promulgated National Emission Standards for Hazardous Air Pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the NESHAP regulations are estimated to include costs in the range of $31 million to $39 million through 2013, the compliance date.

Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide (CO 2 ) equivalent per year from stationary fossil fuel combustion sources to report GHG emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more CO 2 equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012, for calendar year 2011. Compliance with this reporting obligation is estimated to cost a total of $10 million to $14 million over the next four to five years.

In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO 2 ) NAAQS. The effective date of the new NO 2 standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.

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

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Item 7A.	*Quantitative and Qualitative Disclosures About Market Risk*

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. The majority of our debt portfolio is comprised of fixed rate debt in order to mitigate 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.

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2010 and 2009. 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.


																					Fair Value
																					December 31,
	2011			2012			2013			2014			2015			Thereafter(1)			Total		2010
	(Millions)

Long-term debt, including
current portion(2):
Fixed rate	$	507		$	352		$	-		$	-		$	750		$	7,495		$	9,104	$	9,990
Interest rate		6.4	%		6.4	%		6.3	%		6.3	%		6.4	%		6.9	%


																					Fair Value
																					December 31,
	2010			2011			2012			2013			2014			Thereafter(1)			Total		2009
	(Millions)

Long-term debt, including
current portion(2):
Fixed rate	$	15		$	936		$	953		$	-		$	-		$	6,119		$	8,023	$	8,905
Interest rate		7.7	%		7.7	%		7.7	%		7.7	%		7.7	%		8.0	%
Variable rate	$	-		$	-		$	250		$	-		$	-		$	-		$	250	$	237
Interest rate(3)


(1)		Includes unamortized discount and premium.

(2)		Excludes capital leases.

(3)		The interest rate at December 31, 2009 was LIBOR plus 1 percent.

Commodity Price Risk

We are exposed to the impact of fluctuations in the market price of natural gas, NGL and crude, 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 our proprietary trading activities. We manage the risks associated with these market fluctuations 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 15 of Notes to Consolidated Financial Statements.)

We measure the risk in our portfolios using a value-at-risk methodology to estimate the potential one-day loss from adverse changes in the fair value of the portfolios. 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 portfolios. 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 portfolios will not exceed the value at risk. The simulation method uses historical correlations and

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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 portfolios 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 trading portfolio consists of derivative contracts entered into for purposes other than economically hedging our commodity price-risk exposure. The fair value of our trading derivatives was a net asset of $2 million at December 31, 2010. The value at risk for contracts held for trading purposes was less than $1 million at December 31, 2010 and December 31, 2009.

Nontrading

Our nontrading portfolio consists of derivative contracts that hedge or could potentially hedge the price risk exposure from the following activities:


Segment		Commodity Price Risk Exposure

Williams Partners		• Natural gas purchases
		• NGL sales
Exploration & Production		• Natural gas purchases and sales
Other		• NGL purchases

The fair value of our nontrading derivatives was a net asset of $282 million at December 31, 2010.

The value at risk for derivative contracts held for nontrading purposes was $24 million at December 31, 2010, and $34 million at December 31, 2009. During the year ended December 31, 2010, our value at risk for these contracts ranged from a high of $33 million to a low of $21 million. The decrease in value at risk primarily reflects the realization of certain derivative positions and the market price impact, partially offset by new derivative contracts.

Certain of the derivative contracts held for nontrading purposes are accounted for as cash flow hedges. Of the total fair value of nontrading derivatives, cash flow hedges had a net asset value of $266 million as of December 31, 2010. Though these contracts are included in our value-at-risk calculation, any changes in the fair value of the effective portion of these hedge contracts would generally not be reflected in earnings until the associated hedged item affects earnings.

Trading Policy

We have policies and procedures that govern our trading and risk management activities. These policies cover authority and delegation thereof in addition to control requirements, authorized commodities and term and exposure limitations. Value-at-risk is limited in aggregate and calculated at a 95 percent confidence level.

Foreign Currency Risk

Net assets of our consolidated foreign operations, whose functional currency is the local currency, are located primarily in Canada and approximate 8 percent and 6 percent of our net assets at December 31, 2010 and 2009, respectively. These foreign operations do not have significant transactions or financial instruments denominated in currencies other than their functional currency. However, these investments do have the potential to impact our financial position, due to fluctuations in these local currencies arising from the process of translating the local functional currency into the U.S. dollar. As an example, a 20 percent change in the respective functional currencies against the U.S. dollar would have changed stockholders' equity by approximately $117 million at December 31, 2010.

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Item 8.	*Financial Statements and Supplementary Data*

MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING

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

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

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2010, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, we concluded that, as of December 31, 2010, our internal control over financial reporting was effective.

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

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

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited The Williams Companies, Inc.'s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Williams Companies, Inc.'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 Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, The Williams Companies, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, 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 sheet of The Williams Companies, Inc. as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2010 of The Williams Companies, Inc. and our report dated February 24, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 24, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

The Williams Companies, Inc.

We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. The 2010 financial statements of Gulfstream Natural Gas System, L.L.C. ("Gulfstream") (a limited liability corporation in which the Company has a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the 2010 consolidated financial statements, insofar as it relates to the amounts included for Gulfstream, is based solely on the report of the other auditors. In the consolidated financial statements, the Company's investment in Gulfstream is stated at $378 million at December 31, 2010 and the Company's equity earnings in the net income of Gulfstream is stated at $66 million for the year then ended.

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 The Williams Companies, Inc. at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 9 to the consolidated financial statements, beginning in the fourth quarter of 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Williams Companies, Inc.'s internal control over financial reporting as of December 31, 2010, 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 24, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 24, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the balance sheet of Gulfstream Natural Gas System, L.L.C., (the "Company"), as of December 31, 2010, and the related statements of operations, cash flows, and members' equity and comprehensive income for the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2010, and the results of its operations and its cash flows for the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 23, 2011

Table of Contents

THE WILLIAMS COMPANIES, INC.

CONSOLIDATED STATEMENT OF OPERATIONS

Williams Companies Inc (WMB) SEC Annual Report (10-K) for 2010

Form 10-K

The Williams Companies, Inc.