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

Form 10-K

 

 

Commission file number 1-4174

The Williams Companies, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

 

918-573-2000

 

(Registrant’s Telephone Number, Including Area Code)

 

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

 

 

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 þ     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 þ

 

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

 

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

 

 

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

 

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

TABLE OF CONTENTS

 

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.

 

 

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.”

 

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.

 

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.

 

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.

 

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.

 

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:

 

 

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.

 

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.

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.

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

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:

 

 

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

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

 

 

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:

 

 

 

In the Four Corners area, the assets include:

 

 

In the Piceance basin in Colorado, the assets include:

 

 

In the Appalachian basin in Pennsylvania, the assets include:

 

 

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:

 

 

 

 

 

 

 

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

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:

 

 

 

 

 

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:

 

 

 

 

 

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.

 

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:

 

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:

 

 

 

 

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:*

 

 

 

 

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

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:*

 

 

 

 

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:

 

 

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.

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.

 

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

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:

 

 

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.

 

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.

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:

 

 

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.

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.

 

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:

 

 

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.

 

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

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.

 

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.

 

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.

 

 

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:

 

 

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

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

 

 

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

 

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

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

 

RISK FACTORS

 

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

 

Risks 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

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:

 

 

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:

 

 

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:

 

 

 

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:

 

 

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

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.

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:

 

 

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.

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:

 

 

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.

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

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.

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:

 

 

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

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:

 

 

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.”

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:

 

 

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

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.

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.

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.

 

 

None.

 

 

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

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.

 

 

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.

 

 

 

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:

 

 

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

 

 

 

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.

 

 

 

 

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

 

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.

 

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

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

 

 

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

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:

 

 

 

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.

 

 

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

 

 

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

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:

 

 

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:

 

 

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.

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:

 

 

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.

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.

 

 

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

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.

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.

 

 

 

 

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.

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:

 

 

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