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

 

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

 

 

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 $23,344,993,927.

 

The number of shares outstanding of the registrant’s common stock outstanding at February 19, 2009 was 579,213,365.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s 2009 Annual Meeting of Stockholders to be held on May 21, 2009, 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:

 

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.

 

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.

 

 

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 on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Code of Ethics, Board Committee Charters and 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 a 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, the 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.

 

In 2008, we used Economic Value Added^® (EVA^®)¹ as the basis for disciplined decision making around the use of capital. EVA^® is a tool that considers both financial earnings and a cost of capital in measuring performance. It is based on the idea that earning profits from an economic perspective requires that a company cover not only all of its operating expenses but also all of its capital costs. The two main components of EVA^® are net operating profit after taxes and a charge for the opportunity cost of capital. We derive these amounts by making various adjustments to our reported results and financial position, and by applying a cost of capital. We look for opportunities to improve EVA^® because we believe there is a strong correlation between EVA^® improvement and creation of shareholder value.

 

See “Item 8 — Financial Statements and Supplementary Data — Notes to Consolidated Financial Statements — Note 18” of our Notes to Consolidated Financial Statements for information with respect to each segment’s revenues, profits or losses and total assets.

 

 

¹ Economic Value Added^® (EVA^®) is a registered trademark of Stern, Stewart & Co.

 

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

 

 

This report is organized to reflect this structure.

 

Detailed discussion of each of our business segments follows.

 

Our Exploration & Production segment produces, develops, and manages natural gas reserves primarily located in the Rocky Mountain (primarily New Mexico, Wyoming and Colorado) and Mid-Continent (Oklahoma and Texas) regions of the United States. We specialize in natural gas production from tight-sands and shale formations and coal bed methane reserves in the Piceance, San Juan, Powder River, Arkoma, Green River and Fort Worth basins. Over 99 percent of Exploration & Production’s domestic reserves are natural gas. Our Exploration & Production segment also has international oil and gas interests, which include a 69 percent equity interest in Apco Argentina Inc., an oil and gas exploration and production company with operations in Argentina, and a 4 percent equity interest in Petrowayu S.A., a Venezuelan corporation that is the operator of a 100 percent interest in the La Concepcion block located in western Venezuela.

 

Exploration & Production’s current proved undeveloped and probable reserves provide us with strong capital investment opportunities for several years into the future. Exploration & Production’s goal is to drill its existing proved undeveloped reserves, which is comprised of approximately 43 percent of proved reserves, and to drill in areas of probable reserves adding to our proved reserves. In addition, Exploration & Production provides a significant amount of equity production that is gathered and/or processed by our Midstream facilities in the San Juan basin.

 

Information for our Exploration & Production segment relates only to domestic activity unless otherwise noted. We use the terms “gross” to refer to all wells or acreage in which we have at least a partial working interest and “net” to refer to our ownership represented by that working interest.

Gas reserves and wells

 

The following table summarizes our U.S. natural gas reserves as of December 31 (using market prices on December 31 held constant) for the year indicated:

 

 

No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2008. 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 the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, although Exploration & Production has not yet been required to file any information with respect to its estimated total reserves at December 31, 2008 with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable to those reported here due to special DOE reporting requirements, such as the requirement to report gross operated reserves only. In 2007 and 2006, the underlying estimated reserves for the DOE did not differ by more than 5 percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC.

 

Approximately 99 percent of our year-end 2008 United States proved reserves estimates were audited in each separate basin by Netherland, Sewell & Associates, Inc. (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 by basin and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. NSAI is satisfied with our methods and procedures in preparing the December 31, 2008 reserve estimates and saw nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us. Reserve estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, which comprise approximately 1 percent of our total U.S. proved reserves, were prepared by Miller and Lents, LTD.

 

The SEC has revised its oil and gas reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited. These changes include:

 

 

Oil and gas properties and reserves by basin

 

The table below summarizes 2008 activity and reserves for each of our areas, with further discussion following the table.

 

 

Piceance basin

 

The Piceance basin is located in northwestern Colorado and is our largest area of concentrated development. During 2008 we operated an average of 26 drilling rigs in the basin. As of December 31, 2008, 15 of these rigs were the new high efficiency rigs designed to drill up to 22 wells from one location. This area has approximately 1,770 undrilled proved locations in inventory. Within this basin we own and operate natural gas gathering facilities including some 300 miles of gathering lines and associated field compression. Approximately 85 percent of the gas gathered is our own equity production. The gathering system also includes 7 processing plants and associated treating facilities with an eighth plant that came on-line in February 2009, for a total capacity of 1.25 Bcfd. During 2008, these plants recovered approximately 69 million gallons of natural gas liquids (NGLs) which were marketed separately from the residue natural gas.

 

San Juan basin

 

The San Juan basin is located in northwest New Mexico and southwest Colorado.

 

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. We have a significant inventory of undrilled locations, providing long-term drilling opportunities.

 

Mid-Continent properties

 

The Mid-Continent properties are located in the southeastern Oklahoma portion of the Arkoma basin and the Barnett Shale in the Fort Worth basin of Texas.

 

Other properties

 

Other properties are primarily comprised of interests in the Green River basin in southwestern Wyoming. Also included is exploration activity and other miscellaneous activity.

 

The following table summarizes our leased acreage as of December 31, 2008:

 

Operating statistics

 

We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in each of 2008, 2007 and 2006. The following table summarizes domestic drilling activity by number and type of well for the periods indicated:

 

 

We also successfully drilled four exploratory wells in 2008. In addition, two exploratory wells drilled in prior years were determined to be unsuccessful in 2008.

 

Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. Exploration & Production natural gas hedges for 2009 domestic natural gas production consist of NYMEX fixed price contracts of 106 MMcf/d (whole year) and approximately 490 MMcf/d in regional collars (whole year). Our natural gas production hedges in 2008 consisted of 70 MMcf/d in NYMEX fixed price hedges and 434 MMcf/d in regional collars. A collar is an option contract that sets a gas price floor and ceiling for a certain volume of natural gas. Hedging decisions are made considering the overall Williams commodity risk exposure and are not executed independently by Exploration & Production; there are expected future gas purchases for other Williams entities that when taken as a net position may offset price risk related to Exploration & Production’s expected future gas sales. In February 2007, we entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging with the banks and on natural gas reserves value. In June 2008, we amended this agreement to extend the facility through year end 2013.

 

The following table summarizes our domestic sales and cost information for the years indicated:

 

 

Acquisitions & divestitures

 

In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. As a result of the contract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We obtained these interests through our acquisition of Barrett Resources Corporation in 2001.

 

In May 2008, we acquired certain undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin for $285 million. In July 2008, a third party exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the acquired assets for $71 million. We received this $71 million in October 2008.

 

In September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties for $147 million subject to post-closing adjustments. This acquisition is

consistent with our growth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties in the Barnett Shale formation.

 

Through other transactions totaling approximately $111 million, Exploration & Production expanded its acreage position and producing properties in the Fort Worth basin in north-central Texas and also expanded its acreage position in the Highlands area of the Piceance basin and in the Paradox basin.

 

Other information

 

In 1993, Exploration & Production conveyed a net profits interest in certain of its properties to the Williams Coal Seam Gas Royalty Trust. Substantially all of the production attributable to the properties conveyed to the trust was from the Fruitland coal formation and constituted coal seam gas. We subsequently sold trust units to the public in an underwritten public offering and retained 3,568,791 trust units then representing 36.8 percent of outstanding trust units. We have previously sold trust units on the open market, with our last sales in June 2005. As of February 1, 2009, we own 789,291 trust units.

 

International exploration and production interests

 

We also have investments in international oil and gas interests. If combined with our domestic proved reserves, our international interests would make up approximately 3 percent of our total proved reserves.

 

We own and operate, a combined total of approximately 14,000 miles of pipelines with a total annual throughput of approximately 2,700 trillion British Thermal Units of natural gas and peak-day delivery capacity of approximately 12 MMdt of gas. Gas Pipeline consists of Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline GP (Northwest Pipeline). Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System, L.L.C. Gas Pipeline also includes WMZ.

 

Transco

 

Transco is an interstate natural gas transportation company that owns and operates a 10,100-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, 2008, Transco’s system had a mainline delivery capacity of approximately 4.7 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 3.8 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.5 MMdt of natural gas per day. Transco’s system includes 45 compressor stations, four underground storage fields, and a liquefied natural gas (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. One customer accounted for approximately 11 percent and another customer accounted for approximately 10 percent of Transco’s total revenues in 2008. 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 and operates the facility. 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 204 billion cubic feet of gas. In October 2008, the FERC approved Transco’s request to abandon its Hester storage facility, which is not in operation. Hester is not included in the capacity described above. 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 are future pipeline projects for which we have customer commitments.

 

Sentinel Expansion Project

 

The Sentinel Expansion Project involves an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $200 million. Phase I was placed into service in December 2008. Phase II is expected to be placed into service by November 2009.

 

Mobile Bay South Expansion Project

 

The Mobile Bay South Expansion Project involves 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. The capital cost of the project is estimated to be up to approximately $37 million. Transco plans to place the project into service by May 2010.

 

85 North Expansion Project

 

The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. The capital cost of the project is estimated to be $248 million. Transco plans to place the project into service in phases, in July 2010 and May 2011.

 

Operating statistics

 

The following table summarizes transportation data for the Transco system for the periods indicated:

 

 

Transco’s facilities are divided into eight rate zones. Five are located in the production area, and three are located in the market area. Long-haul transportation involves gas that Transco receives in one of the production-area zones and delivers to a market-area zone. Market-area transportation involves gas that Transco both receives and

delivers within the market-area zones. Production-area transportation involves gas that Transco both receives and delivers within the production-area zones.

 

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, 2008, Northwest Pipeline’s system, having long-term firm transportation agreements including peaking service of approximately 3.6 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 473,000 horsepower.

 

In 2008, Northwest Pipeline served a total of 136 transportation and storage customers. We transport and store 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. The largest customer of Northwest Pipeline in 2008 accounted for approximately 20.7 percent of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2008. 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.

 

As a part of its transportation services, Northwest Pipeline utilizes underground storage facilities in Utah and Washington enabling it to balance daily receipts and deliveries. Northwest Pipeline also owns and operates an LNG storage facility in Washington that provides service for customers during a few days of extreme demands. These storage facilities have an aggregate firm delivery capacity of approximately 700 MMcf of gas per day.

 

Northwest Pipeline expansion projects

 

The pipeline projects listed below were completed during 2008 or are future pipeline projects for which we have customer commitments.

 

Colorado Hub Connection Project

 

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

 

In addition to providing greater opportunity for contract extensions for the short-term firm and Pan-Alberta capacity, the CHC Project provides direct access to additional natural gas supplies at the Meeker/White River Hub for Northwest Pipeline’s on-system and off-system markets. Northwest Pipeline has entered into precedent agreements with terms ranging between eight and fifteen years at maximum rates for all of the short-term firm and Pan-Alberta capacity resulting in the successful re-contracting of the capacity out to 2018 and beyond. In September 2008, Northwest Pipeline filed an application for FERC certification and is awaiting necessary regulatory approvals. If Northwest Pipeline does not proceed with the CHC Project, Northwest

Pipeline will seek recovery of any shortfall in annual capacity reservation revenues from our remaining customers in a future rate proceeding. Northwest Pipeline does expect to collect maximum rates for the new CHC Project capacity commitments and seek approval to recover the CHC Project costs in any future rate case filed with the FERC.

 

Sundance Trail Expansion

 

In February 2008, Northwest Pipeline initiated an open season for the proposed Sundance Trail Expansion project that resulted in the execution of an agreement for 150 MDth per day of firm transportation service from the Meeker/White River Hub in Colorado for delivery to the Opal Hub in Wyoming. The project will include construction of approximately 16 miles of 30-inch loop between Northwest Pipeline’s existing Green River and Muddy Creek compressor stations in Wyoming as well as an upgrade to Northwest Pipeline’s existing Vernal compressor station, with service targeted to commence in November 2010. The total project is estimated to cost up to $65 million, including the cost of replacing existing compression at the Vernal compressor station which will enhance the efficiency of Northwest Pipeline’s system. The Sundance Trail Expansion will utilize available capacity on the CHC lateral and the existing Piceance lateral in conjunction with available and expanded mainline capacity. The Sundance Trail Expansion remains subject to certain conditions, including receiving the necessary regulatory approvals. Northwest Pipeline expects to collect maximum system rates, and will seek approval to roll-in the Sundance Trail Expansion costs in any future rate case filed with the FERC.

 

Operating statistics

 

The following table summarizes volume and capacity data for the Northwest Pipeline system for the periods indicated:

 

 

 

 

Gulfstream Natural Gas System, L.L.C. (Gulfstream)

 

Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. Gas Pipeline and Spectra Energy, through their respective subsidiaries, each holds a 50 percent ownership interest in Gulfstream and provides operating services for Gulfstream. At December 31, 2008, our equity investment in Gulfstream was $525 million.

 

Gulfstream expansion projects

 

Gulfstream placed the Phase III expansion project in service on September 1, 2008. The project extended the pipeline system into South Florida and fully subscribed the remaining 345 Mdt/d of firm capacity on the existing pipeline system on a long-term basis. The estimated capital cost of this project is $118 million, with Gas Pipeline’s share being 50 percent of such costs. Service under the Gulfstream Phase IV expansion project began during the fourth quarter of 2008. The project is fully subscribed on a long-term basis and is the first incremental expansion of Gulfstream’s mainline capacity. The estimated capital cost of this expansion is $192 million, with Gas Pipeline’s share being 50 percent of such costs.

WMZ

 

WMZ was formed to own and operate natural gas transportation and storage assets. We currently own an approximate 45.7 percent limited partnership interest and a 2 percent general partner interest in WMZ. WMZ provides us with lower cost of capital that is expected to enable growth of our Gas Pipeline business. WMZ also creates a vehicle to monetize our qualifying assets. Such transactions, which are subject to approval by the boards of directors of Williams and WMZ’s general partner, allow us to retain control of the assets through our ownership interest in WMZ. A subsidiary of ours, Williams Pipeline GP LLC, serves as the general partner of WMZ. The initial asset of WMZ is a 35 percent interest in Northwest Pipeline.

 

Our Midstream segment, 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, Venezuela and western Canada. Midstream’s 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 natural gas and crude oil from the wellhead to the consumer. NGLs, ethylene and propylene are extracted/produced at our plants, including our Canadian and Gulf Coast olefins plants. These products are used primarily for the manufacture of petrochemicals, home heating fuels and refinery feedstock.

 

Some of our assets are owned through our interest in WPZ.

 

Key variables for our business will continue to be:

 

 

Domestic gathering, processing and treating

 

Our domestic 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. Our processing and treating plants remove water vapor, carbon dioxide and other contaminants and our processing plants extract the NGLs. NGL products include:

 

 

Although a significant portion of our 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 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 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.

 

Our domestic gas gathering and processing customers are generally natural gas producers who have proved and/or producing natural gas fields in the areas surrounding our infrastructure. During 2008, these operations gathered and processed gas for approximately 230 gas gathering and processing customers. Our top six gathering and processing customers accounted for about 50 percent of our domestic gathering and processing revenue.

 

In addition to our natural gas assets, we own and operate three deepwater crude oil pipelines and a deepwater floating production platform in the Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a substantial portion of our marketing revenues are recognized from purchase and sale arrangements whereby we purchase oil from producers at the receipt points of our crude oil pipelines for an index-based price and sell the oil back to the producers at delivery points at the same index-based price. Our offshore floating production platform provides 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, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of our offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Also, our gathering and processing facilities in the San Juan Basin handle about 87 percent of our Exploration & Production group’s wellhead production in this basin. Both our San Juan Basin and Southwest Wyoming systems deliver residue gas volumes into Northwest Pipeline’s interstate system in addition to third party interstate systems.

 

West Region domestic gathering, processing and treating

 

We own and/or operate domestic gas gathering, processing and treating assets within the western states of Wyoming, Colorado and New Mexico.

 

In the Rocky Mountain area, our assets include:

 

 

In the Four Corners area, our assets include:

 

 

As we enter the Piceance Basin in Colorado, our initial infrastructure includes:

 

 

 

West region expansion projects

 

Our two major expansion projects include the new Willow Creek facility and additional capacity at our Echo Springs facility.

 

 

Gulf region domestic gathering, processing and treating

 

We own and/or operate domestic 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. We own:

 

 

 

 

 

 

Gulf region expansion projects

 

The deepwater Gulf continues to be an attractive growth area for our Midstream business. Since 1997, we have invested over $1.5 billion in new midstream assets in the Gulf of Mexico. These facilities provide both onshore and offshore services through pipelines, platforms and processing plants. The new facilities could also attract incremental gas volumes to Transco’s pipeline system in the southeastern United States.

 

Our current major expansion projects in the Gulf region include:

 

 

Venezuela

 

Our Venezuelan investments involve gas compression and an equity interest in a gas processing and NGL fractionation operation. We own controlling interests and operate three gas compressor facilities which provide roughly 65 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas at high pressures. The three gas compressor facilities, owned within two of our Venezuelan subsidiaries, had a net book value of $324 million at December 31, 2008 and are held as security on $177 million of non-recourse debt at December 31, 2008. We own controlling interests of 70% and 66.67% in these two subsidiaries.

 

Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of the Venezuelan state-owned oil company, Petróleos de Venezuela S.A. under long-term contracts. These significant contracts have a remaining term between 9 and 12 years and our revenues are based on a combination of fixed capital payments, throughput volumes and, in the case of one of the gas compression facilities, a minimum throughput guarantee. The Venezuelan government continues its public criticism of U.S. economic and political policy, has implemented unilateral changes to existing energy related contracts, and has expropriated privately held assets within the energy and telecommunications sector. The continued threat of nationalization of certain energy-related assets in Venezuela could have a material negative impact on our results of operations. The economic situation resulting from lower commodity prices could jeopardize the Venezuelan oil industry and may further exacerbate political tension in Venezuela. We may not receive adequate compensation, or any compensation, if our assets in Venezuela are nationalized.

 

We also own a 49.25 percent interest in Accroven SRL which includes two 400 MMcf/d NGL extraction plants, a 50 Mbbls/d NGL fractionation plant and associated storage and refrigeration facilities. Our equity investment had a book value of $69 million at December 31, 2008.

 

Olefins

 

In the Gulf of Mexico region, we own a 10/12 interest in and are the operator of an ethane cracker at Geismar, Louisiana, with a total production capacity of 1.3 billion pounds of ethylene and 90 million pounds of propylene per year. Our feedstock for the ethane cracker is ethane and propane; as a result, we are exposed to the price spread between ethane and propane, and ethylene and propylene. We also own ethane and propane pipeline systems and a refinery grade propylene splitter with a production capacity of approximately 500 million pounds per year of propylene and its related pipeline system in Louisiana. 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.

Our Canadian operations include an olefin liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. Our facilities extract olefinic liquids from the off-gas produced by a third party oil sands bitumen upgrading process. Our arrangement with the third-party upgrade 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 to the third party in the form of natural gas. We then fractionate, treat, store, terminal and sell the propane, propylene, butane, butylenes 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 olefins fractionator in western Canada and the only treater/processor of oil sands upgrader off-gas. These operations extract petrochemical feedstocks from upgrader off-gas streams allowing the upgraders to burn cleaner natural gas streams and reduce overall air emissions. The extraction plant has processing capacity in excess of 100 MMcf/d with the ability to recover in excess of 15 Mbbls/d of olefin and NGL products.

 

NGL and olefin marketing services

 

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

 

Other

 

We own interests in and/or operate NGL fractionation and storage assets. These assets include two partially owned NGL fractionation facilities: one near Conway, Kansas and the other in Baton Rouge, Louisiana that have a combined capacity in excess of 167 Mbbls/d. We also own approximately 20 million barrels of NGL storage capacity in central Kansas near Conway.

 

We own an equity interest in and operate the facilities of Discovery Producer Services LLC and its subsidiary Discovery Gas Transmission Services LLC (collectively, Discovery) through our interest in WPZ. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbl/NGL fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system in the Gulf of Mexico.

 

We also own 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 87 Mbbls/d of extracted liquids into NGL products.

 

Operating statistics

 

The following table summarizes our significant operating statistics for Midstream:

 

 

 

 

WPZ

 

WPZ was formed in 2005 to engage in gathering, transporting, processing and treating natural gas and fractionating and storing NGLs. We currently own approximately a 23.6 percent limited partnership interest including the interests of the general partner, Williams Partners GP LLC, which is wholly owned by us, and incentive distribution rights. WPZ provides us with an alternative source of equity capital. WPZ also creates a vehicle to monetize our qualifying assets. Such transactions, which are subject to approval by the boards of directors of both Williams and WPZ’s general partner, allow us to retain control of the assets through our ownership interest in WPZ and operation of the assets. WPZ’s asset portfolio includes Williams Four Corners LLC, certain ownership interests in Wamsutter LLC, a 60 percent interest in Discovery, three integrated NGL storage facilities near Conway, Kansas, a 50 percent interest in an NGL fractionator near Conway, Kansas and the Carbonate Trend sour gas gathering pipeline off the coast of Alabama.

 

Gas Marketing Services (Gas Marketing) primarily supports our natural gas businesses by providing marketing and risk management services, which includes marketing and hedging the gas produced by Exploration & Production, and procuring fuel and shrink gas and hedging natural gas liquids sales for Midstream. Gas Marketing also provides similar services to third parties, such as producers. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, related hedges and proprietary trading positions, including certain legacy natural gas contracts and positions.

 

Gas Marketing’s 2008 natural gas purchase volumes include 1.4Bcf/d of gas produced by Exploration & Production and another 1.0 Bcf/d from third party/other sources. This natural gas was in turn marketed and sold to third parties (2.0 Bcf/d) and to Midstream (.4 Bcf/d).

 

Our Exploration & Production and Midstream segments may execute commodity hedges with Gas Marketing. In turn, Gas Marketing may execute offsetting derivative contracts with unrelated third parties.

 

As a result of the sale of a substantial portion of our Power business in the fourth quarter of 2007, Gas Marketing is also responsible for certain remaining legacy natural gas contracts and positions. During 2008, we substantially reduced the overall legacy positions remaining.

 

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 limit the transfer of funds to us.

 

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, 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.

 

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.

 

Gas Pipeline.  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 demand and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

 

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

 

Midstream also owns interests in and operates two offshore transmission pipelines that are regulated by the FERC because they are deemed to transport gas in interstate commerce. Black Marlin Pipeline Company provides transportation service for offshore Texas production in the High Island area and redelivers that gas to intrastate pipeline interconnects near Texas City. Discovery provides transportation service for offshore Louisiana production from the South Timbalier, Grand Isle, Ewing Bank and Green Canyon (deepwater) areas to an onshore processing facility and downstream interconnect points with major interstate pipelines. FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. In 2007, Black Marlin filed and settled a major rate change application before the FERC, resulting in increased rates for service. In November 2007, Discovery filed a settlement in lieu of a rate change filing, which the FERC approved effective January 1, 2008, for all parties, except one protestor, Exxon Mobil Gas

and Power Marketing Company. Among other things, the settlement increases Discovery’s rates for service, although most volumes flowing before the settlement became effective are not affected by the rate change due to life of lease rates and commitments.

 

Our Midstream 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 non-compliance with the applicable regulations is at issue, the ERCB and Alberta Environment have implemented an enforcement process with escalating consequences.

 

Gas Marketing Services.  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. We are also subject to various federal and state actions and investigations regarding, among other things, market structure, behavior of market participants, market prices, and reporting to trade publications. We may be liable for refunds and other damages and penalties as a result of ongoing actions and investigations. The outcome of these matters could affect our creditworthiness and ability to perform contractual obligations as well as other market participants’ creditworthiness and ability to perform contractual obligations to us.

 

See Note 16 of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

 

Our generation facilities, processing facilities, natural gas pipelines, and exploration and production 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 oil, gas or other pollutants into the air, soil, or water, as well as liability for clean up 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.

 

Exploration & Production.  Our Exploration & Production segment 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.

 

Gas Pipeline.  The natural gas industry has undergone significant change over the past two decades. A highly-liquid competitive commodity market in natural gas and increasingly competitive markets for natural gas services, including competitive secondary markets in pipeline capacity, have developed. 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, many of which are utilizing master limited partnership structures with a lower cost of capital, and on growth of natural gas demand.

 

Midstream Gas & Liquids.  In our Midstream segment, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, timeliness of services to be provided, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees. In 2005, we formed WPZ to help compete against other master limited partnerships for midstream projects. By virtue of the master limited partnership structure, WPZ provides us with an alternative source of equity capital.

 

Gas Marketing Services.  In our Gas Marketing Services segment, 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.

 

At February 1, 2009, we had approximately 4,704 full-time employees including 924 at the corporate level, 798 at Exploration & Production, 1,726 at Gas Pipeline, 1,232 at Midstream Gas & Liquids, and 24 at Gas Marketing Services. 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/RISK FACTORS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

 

Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

 

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements 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 project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

 

 

 

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.

 

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

 

Risks Inherent to our Industry and Business

 

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

 

The development of the additional natural gas reserves that are essential for our gas transportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, 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 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 our pipeline and cash flows associated with the 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, or if natural gas supplies are diverted to

serve other markets, the overall volume of natural gas transported 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 our system.

 

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

 

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 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 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 prices increase, our costs for additional reserves would also increase, conversely if natural gas 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, including related goodwill.

 

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 non-cash charge to earnings. The revisions could also possibly affect the evaluation of Exploration & Production’s goodwill for impairment purposes. At December 31, 2008, we had approximately $1 billion of goodwill on our balance sheet.

 

Certain of our 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 natural gas transportation and midstream businesses 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 we collect for our services. Although most of the services provided by our interstate gas pipelines 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 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 Pipelines rely on a limited number of customers for a significant portion of their revenues. The loss of even a portion of our contracted volumes, 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.

 

We are exposed to the credit risk of our customers.

 

We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade, are otherwise considered credit worthy, are required to make pre-payments, or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. While

we monitor these situations carefully and attempt to take appropriate measures to protect ourselves, it is possible that we may have to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our operating results and financial condition.

 

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

 

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

 

Our drilling, production, gathering, processing, storage and transporting activities involve numerous risks that might result in accidents, and other operating risks and hazards.

 

Our operations are subject to all the risks and hazards typically associated with the development and exploration for, and the production and transportation of oil and gas. These operating risks include, but are not limited to:

 

 

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 pipelines 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. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on segments of our pipeline infrastructure. Potential customer impacts arising from service interruptions on segments of our pipeline infrastructure could include limitations on the pipeline’s ability to satisfy customer requirements, obligations to provide reservations charge credits to customers in times of constrained capacity, and solicitation of existing customers by others for potential new pipeline projects that would compete directly with existing services. Such circumstances could materially impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations and cash flows.

 

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

 

We are not fully insured against all risks inherent to our business, including environmental accidents that might occur. In addition, we do not maintain business interruption 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

aggregate annually and a deductible of $2 million per occurrence. This insurance covers us and our affiliates for legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability for full limits, with the first $135 million of insurance also providing gradual pollution liability coverage for natural gas and NGL operations. Pollution liability coverage excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition, and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of us or our affiliates.

 

We do not insure onshore underground pipelines for physical damage, except at river crossings and at certain locations such as compressor stations. We maintain coverage of $300 million per occurrence for physical damage to onshore assets and resulting business interruption caused by terrorist acts. We also maintain coverage of $100 million per occurrence for physical damage to offshore assets caused by terrorist acts, except for our Devils Tower spar where we maintain terrorism limits of $300 million per occurrence for property damage and $105 million per occurrence for resulting business interruption. Also, 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. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and hurricanes Katrina, Rita, Gustav and Ike have impacted the availability of certain types of coverage at reasonable rates, and we may elect to self insure a portion of our asset portfolio. We cannot assure you that we will in the future be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

In addition, certain insurance companies that provide coverage to us, including American International Group, Inc., have experienced negative developments that could impair their ability to pay any of our potential 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.

 

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

 

A significant portion of our growth in the gas pipeline and midstream business areas is accomplished through the construction of new pipelines, processing and storage facilities, as well as the expansion of existing facilities. Construction 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 results of operations, financial position or cash flows.

Our costs and funding obligations for our defined benefit pension plans and costs for our other post-retirement 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. The amount of expenses recorded for our defined benefit pension plans and other post-retirement benefit plans is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact our future results of operations.

 

Two of our subsidiaries act as the respective general partners of two different publicly-traded limited partnerships, Williams Partners L.P. and Williams Pipeline Partners L.P. As such, those subsidiaries’ operations may involve a greater risk of liability than ordinary business operations.

 

One of our subsidiaries acts as the general partner of WPZ and another subsidiary of ours acts as the general partner of WMZ. Each of these subsidiaries that act as the general partner of a publicly-traded limited partnership may be deemed to have undertaken fiduciary obligations with respect to the limited partnership of which it serves as the general partner and to the limited partners of such limited partnership. 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 partners of two different publicly traded partnerships 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 (i) between the two publicly-traded partnerships as well as (ii) between a publicly-traded partnership, 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, companies’ relationships with their independent registered public accounting firms, and retirement plan practices. We cannot predict the ultimate impact of any future changes in accounting regulations or practices in general with respect to public companies or the energy industry or in our operations specifically. In addition, the Financial Accounting Standards Board (FASB) or the SEC could enact new accounting standards that might impact how we are required to record revenues, expenses, assets, liabilities and equity.

 

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 into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used 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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) 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 Statement of Financial Accounting Standards (SFAS) 133, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to the Company has occurred during the applicable period.

 

The impact of changes in market prices for natural gas on the average gas prices received by us may be reduced based on the level of our hedging strategies. These hedging arrangements may limit our potential gains if the market prices for natural gas were to rise substantially over the price established by the hedge. In addition, our hedging arrangements expose us to the risk of financial loss in certain circumstances, including instances in which:

 

 

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 non-recourse 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. Recent events in certain South American countries, particularly the continued threat of nationalization of certain energy-related assets in Venezuela, could have a material negative impact on our results of operations. We may not receive adequate compensation, or any compensation, if our assets in Venezuela are nationalized.

 

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 business units, but disadvantage another. For example, our Exploration & Production business may benefit from higher natural gas prices, and Midstream, which uses gas as a feedstock, may not.

 

Risks Related to Strategy and Financing

 

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

 

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, 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. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.

 

Our failure to comply with the covenants in our debt agreements and other related transactional documents 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. An event of default 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.

 

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.

 

Events in the global credit markets created a shortage in the availability of credit and have led to credit market volatility.

 

In 2008, global credit markets experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. While we cannot predict the occurrence of future disruptions or the duration of the current volatility in the credit markets, we believe cash on hand and cash provided by operating activities, as well as availability under our existing financing agreements will provide us with adequate liquidity. However, our ability to borrow under our existing financing agreements, including our bank credit facilities, could be negatively impacted if one or more of our lenders fail to honor its contractual obligation to lend to us. Continuing volatility or additional disruptions, including the bankruptcy or restructuring of certain financial institutions, may adversely affect the availability of credit already arranged and the availability and cost of credit in the future.

 

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

 

The slowdown in the economy and the significant disruptions and volatility in global credit markets have 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 current credit ratings could impact our liquidity, access to capital and our costs of doing business, and maintaining current credit ratings is within the control of independent third parties.

 

A downgrade of our credit rating might increase our cost of borrowing and would require us to post additional collateral with third parties, negatively impacting our available liquidity. Our ability to access capital markets would 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. Our corporate family credit rating and the credit ratings of Transco and Northwest Pipeline were raised to investment grade in 2007 by Standard & Poor’s, Moody’s Corporation, and Fitch Ratings, Ltd., and our senior unsecured debt ratings were raised to investment grade by Moody’s and Fitch. No assurance can be given that the credit rating agencies will continue to assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios or that our senior unsecured debt rating will be raised to investment grade by all of the credit rating agencies.

 

Prices for natural gas liquids, natural gas and other commodities 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 we receive for NGLs, natural gas, 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.

 

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 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. A general downturn in the economy and tightening of global credit markets could cause more of our counterparties to fail to perform than we have expected.

 

Risks Related to Regulations that Affect our Industry

 

Our natural gas sales, transmission, and storage operations are subject to government regulations and rate proceedings that could have an adverse impact on our results of operations.

 

Our interstate natural gas sales, transportation, and storage operations conducted through our Gas Pipelines business are subject to the FERC’s rules and regulations in accordance with the NGA and the Natural Gas Policy Act of 1978. The FERC’s regulatory authority extends to:

 

 

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 business. Regulatory decisions could also affect our costs for compression, processing and dehydration of natural gas, which could have a negative effect on our results of operations.

 

The FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that have led to increased competition throughout the industry. In a number of key markets, interstate pipelines are now facing

competitive pressure from other major pipeline systems, enabling local distribution companies and end users to choose a transportation provider based on considerations other than location.

 

Costs of environmental liabilities and complying with existing and future environmental regulations, including those related to greenhouse gas emissions, could exceed our current expectations.

 

Our operations are subject to extensive environmental regulation pursuant to a variety of federal, provincial, state and municipal laws and regulations. Such laws and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, extraction, transportation, treatment and disposal of hazardous substances and wastes, in connection with spills, releases and emissions of various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.

 

Compliance with environmental laws requires significant expenditures, including for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. 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. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.

 

Legislative and regulatory responses related to climate change create financial risk. The United States Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. Increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate the emission of greenhouse gases. Numerous states have announced or adopted programs to stabilize and reduce greenhouse gases and similar federal legislation has been introduced in both houses of Congress. Our pipeline, exploration and production and gas processing facilities may be subject to regulation under climate change policies introduced at either the state or federal level within the next few years. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws. If we are unable to recover or pass through all costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could negatively impact our cost of and access to capital.

 

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. Our regulatory rate structure and our contracts with customers might not necessarily allow us to recover capital costs we incur to comply with the new environmental regulations. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for certain development projects. If there is a delay in obtaining any required environmental regulatory approvals or if we fail to obtain and comply with them, the operation of our facilities could be prevented or become subject to additional costs, resulting in potentially material adverse consequences to our results of operations.

 

Competition in the markets in which we operate may adversely affect our results of operations.

 

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. There can be no assurance that we will be able to compete successfully against current and future competitors and any failure to do so could have a material adverse effect on our businesses and results of operations.

 

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. Although none of our Gas Pipelines’ material contracts are terminable in 2009, 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.

 

If third-party pipelines and other facilities interconnected to our pipeline and facilities become unavailable to transport 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 natural gas pipeline and storage facilities. 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 unavailable due to repairs, damage to the facility, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or for any other reason, our ability to operate efficiently and continue shipping natural gas to end-use markets could be restricted, thereby reducing our revenues. Further, although there are laws and regulations designed to encourage competition in wholesale market transactions, some companies may fail to provide fair and equal access to their transportation systems or may not provide sufficient transportation capacity for other market participants. Any temporary or permanent interruption at any key pipeline interconnect causing a material reduction in volumes transported on our pipeline or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations 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 might have a detrimental effect on our business. Specifically, the Colorado Oil & Gas Conservation Commission has enacted new rules effective in April 2009 which will increase our costs of permitting and environmental compliance and may affect our ability to meet our anticipated drilling schedule and therefore may have a material effect on our results of operations.

 

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

 

Public and regulatory scrutiny of the energy industry and of the capital markets has resulted in increased regulation being either proposed or implemented. Such scrutiny has also resulted in various inquiries, investigations

and court proceedings in which 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 and continue to adversely affect our business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, 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 arising out of our ongoing and discontinued operations including environmental matters, disputes over gas measurement, royalty payments, shareholder class action 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.

 

Risks Related to Employees, Outsourcing of Non-Core 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 may be unable to obtain insurance on commercially reasonable terms, if 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.

In addition, there is a growing belief that emissions of greenhouse gases may be linked to global climate change. Climate change creates physical and financial risk. 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 to either 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, natural gas liquids 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 31 states plus the District of Columbia in the United States and in Argentina, Canada and Venezuela.

 

Gas Marketing’s primary assets are its term contracts, related systems and technological support. In our Gas Pipeline and Midstream segments, we generally own our facilities, although a substantial portion of our 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 in exploration and production properties is held as working interests in oil and gas leaseholds.

 

 

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.

 

 

None.

 

 

The name, age, period of service, and title of each of our executive officers as of February 1, 2009, 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 19, 2009, we had approximately 10,323 holders of record of our common stock. The high and low closing 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 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, 2004. The Bloomberg U.S. Pipeline Index is composed of Crosstex Energy, Inc., El Paso Corporation, Enbridge Inc., Kinder Morgan Management, LLC, National Fuel Gas Company, Oneok, Inc., Promigas S.A. E.S.P., Spectra Energy Corp, TransCanada Corporation, and The Williams Companies, Inc. 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, 2008 and 2007, and for each of the three years in the period ended December 31, 2008, should be read in conjunction with Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part II, Item 8, Financial Statements and Supplementary Data of this Form 10-K. The following financial data at December 31, 2006 and 2005, and for the years ended December 31, 2005 and 2004, should be read in conjunction with the financial information included in Exhibit 99.1 of our Form 8-K as filed on October 12, 2007, except for the adjustments described in footnote (1) below. The following financial data at December 31, 2004, has been prepared from our accounting records.

 

 

 

 

General

 

We are primarily a 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 reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Gas Marketing Services. (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.

 

Overview of 2008

 

Our plan for 2008 was focused on continued disciplined growth. Objectives and highlights of this plan included:

 

 

Our 2008 income from continuing operations increased to $1.3 billion, as compared to $847 million in 2007. Our net cash provided by operating activities was almost $3.4 billion in 2008 compared to $2.2 billion in 2007.

 

While these annual measures are favorable compared to the prior year, the overall trend of results was significantly different when considering the first three quarters of the year versus the last quarter. Through September 30, 2008, our Exploration & Production business benefited from increased levels of production and higher net realized average natural gas prices, while our Midstream business realized higher margins from a favorable energy commodity price environment. However, energy commodity prices declined sharply during the last months of 2008, contributing to significantly lower fourth quarter operating results for these segments. The impact of the declining energy commodity prices on our consolidated results was partially mitigated by:

 

 

See additional discussion in Results of Operations.

 

Other Significant 2008 Events

 

We completed our stock repurchase program by reaching the $1 billion limit authorized by our Board of Directors. (See Note 12 of Notes to Consolidated Financial Statements.)

 

Exploration & Production increased its positions by acquiring undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin and undeveloped leasehold acreage and producing properties in the Fort Worth basin. See additional discussion in Results of Operations — Segments, Exploration & Production.

 

We recognized pre-tax income of $183 million in income from discontinued operations related to our former Alaska operations. (See Note 2 of Notes to Consolidated Financial Statements.)

 

Exploration & Production recognized pre-tax income of $148 million related to the sale of a contractual right to a production payment on certain future international hydrocarbon production. See additional discussion in Results of Operations — Segments, Exploration & Production.

 

Williams Pipeline Partners L.P. completed its initial public offering. See additional discussion in Results of Operations — Segments, Gas Pipeline.

 

In September 2008, Hurricanes Gustav and Ike impacted our operations, primarily at Midstream. As a result, we estimate that our segment profit for 2008 was decreased by approximately $60 million to $85 million due to downtime and charges for repairs and property insurance deductibles. See additional discussion in Results of Operations — Segments, Gas Pipeline and Midstream Gas & Liquids.

 

The overall decline in equity markets in 2008 negatively impacted our employee benefit plan assets and will significantly increase our net periodic benefit expense in future periods. (See Note 7 of Notes to Consolidated Financial Statements.)

 

Outlook for 2009

 

We expect the overall economic recession and related lower energy commodity price environment as well as the challenging financial markets to continue throughout the year. This is expected to result in sharply lower results of operations and cash flow from operations compared to 2008 levels and could also result in a further reduction in capital expenditures. The impacts could include the future nonperformance of counterparties or impairments of goodwill and long-lived assets. Considering this environment, our plan for 2009 is built around the transition from significant growth to a focus on sustaining our current operations and reducing costs where appropriate. However, we believe we are well positioned to capture growth opportunities when commodity prices strengthen and as economic conditions improve. Although we expect a reduction in capital expenditures compared to the prior year, near-term investment in our businesses will remain significant and focused on completing major projects, meeting legal, regulatory, and/or contractual commitments, and maintaining a reduced level of natural gas production development.

 

We will continue to operate with a focus on EVA^® and invest in our businesses in a way that meets customer needs and enhances our competitive position by:

 

 

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, focused efforts to resolve regulatory issues and litigation claims, disciplined investment strategies, and maintaining at least $1 billion in liquidity from cash and cash equivalents and unused revolving credit facilities. In addition, we utilize master netting agreements and collateral requirements with our counterparties.

 

We have completed a review of potential changes to our company structure with a goal of enhancing shareholder value and determined to leave our company structure unchanged. Major factors in our decision were the sharp decline in energy commodity prices and a further deterioration in the macroeconomic environment since the initiation of the review in early November 2008. Our business mix and strong credit profile position us to weather the challenging economic and market conditions in 2009 and benefit as the economy recovers.

 

Accounting Pronouncements Issued But Not Yet Adopted

 

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

 

See Recent Accounting Standards in Note 1 of Notes to Consolidated Financial Statements for further information on recently issued accounting standards.

 

Modernization of Oil & Gas Reporting Requirements

 

The SEC has revised its oil and gas reserves reporting requirements effective for fiscal years ending on or after December 31, 2009, with early adoption prohibited. These changes include:

 

 

Historically, the reserves calculated based on the SEC’s reporting requirements were also used to calculate depletion on our producing properties, as required by SFAS 69, “Disclosures about Oil and Gas Producing Activities” (SFAS 69). However, the change in the SEC reporting requirements has not yet been adopted by the FASB. The SEC has announced its intent to discuss potential amendments to SFAS 69 with the FASB so that the reserves disclosed remain consistent with the reserves used to calculate depletion on our producing properties. Any such change would impact our future financial results. The SEC has indicated that it may delay the effective date of the revised reporting requirements if the FASB does not make conforming amendments by December 31, 2009.

Critical Accounting Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We have discussed the following accounting estimates and assumptions as well as related disclosures 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 Long-Lived Assets and Goodwill

 

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 may 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.

 

Based on our assessment of the undiscounted and discounted cash flows on natural gas-producing properties and associated unproved leasehold costs in the Arkoma basin, Exploration & Production recorded an impairment charge of $129 million in December 2008. Significant judgments and assumptions in this impairment analysis included year-end natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, capital costs, and a pre-tax discount rate of 15 percent. The recorded impairment was largely the result of lower forward pricing estimates at year-end and lower reserve estimates resulting from lower year-end prices.

 

In addition to those long-lived assets for which impairment charges were recorded (see Note 4 of Notes to Consolidated Financial Statements), certain others were reviewed for which no impairment was required. These reviews included Exploration & Production’s properties in other basins and utilized inputs consistent with those described above for the Arkoma basin. Certain assets within our Midstream segment were also evaluated for impairment utilizing judgments and assumptions including future fees, margins and volumes. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

 

We have goodwill of approximately $1 billion at Exploration & Production primarily resulting from a 2001 acquisition. We assess goodwill for impairment annually as of the end of the year. For purposes of our assessment, the reporting unit is Exploration & Production’s domestic operations. As of December 31, 2008, the estimated fair value of the reporting unit exceeds its carrying value, including goodwill, indicating no impairment of Exploration & Production’s goodwill.

 

We estimated the fair value of the reporting unit on a stand-alone basis primarily by valuing proved and unproved reserves. We used an income approach (discounted cash flows) for valuing reserves. The significant inputs into the valuation of proved reserves included reserve quantities, forward natural gas prices, anticipated drilling and operating costs, anticipated production curves and appropriate discount rates. Unproved reserves were valued using similar assumptions adjusted further for the uncertainty associated with these reserves.

 

In estimating the inputs, management must make assumptions that require judgments and are subject to change in response to changing market conditions and other future events. Significant assumptions in valuing proved reserves included reserve quantities of more than 4.3 Tcfe, natural gas prices, adjusted for locational differences, averaging approximately $5.80 per Mcfe and a pre-tax discount rate of 15 percent.

 

We further reviewed the estimated fair value of the stand-alone reporting unit by reconciling the sum of the fair values of all our businesses to our total market capitalization, including a control premium. In estimating the fair value of our businesses and a control premium, we considered a range of market comparables from historical sales transactions of energy companies. Market capitalization was based on our traded stock price for a reasonably short period of time before and after December 31, 2008. In evaluating these items in our reconciliation analysis, management considered a range of reasonable judgments. This reconciliation allowed management to consider market expectations in corroborating the reasonableness of the estimated stand-alone fair value of the Exploration & Production reporting unit.

We also perform interim assessments of goodwill if impairment triggering events or circumstances are present. Examples of impairment triggering events or circumstances include:

 

 

We cannot predict future market conditions and events that might adversely affect the estimated fair value of the Exploration & Production reporting unit and possibly the reported value of goodwill. The estimated fair value of the reporting unit is significantly affected by natural gas prices, reserve quantities and market expectations for required rates of return. Further declines in natural gas prices would lower our estimates of fair value. There are numerous uncertainties inherent in estimating quantities of reserves that could affect our reserve quantities. Low prices for natural gas, regulatory limitations, or the lack of available capital for projects could adversely affect the development and production of additional reserves. Given the significant challenges affecting our businesses and the energy industry in 2009, these factors could impact us and require us to assess goodwill for possible impairment more frequently during 2009.

 

Subsequent to December 31, 2008, as a result of overall market and energy commodity price declines, we have witnessed periodic reductions in our total market capitalization below our December 31, 2008, consolidated stockholders’ equity balance. If our total market capitalization is below our consolidated stockholders’ equity balance at a future reporting date, we consider this an indicator of potential impairment of goodwill under recent SEC communications and our accounting considerations. We utilize market capitalization in corroborating our assessment of the fair value of our Exploration & Production reporting unit. Considering this, it is reasonably possible that we may be required to conduct an interim goodwill impairment evaluation, which could result in a material impairment of our goodwill.

 

Accounting for Derivative Instruments and Hedging Activities

 

We review our energy contracts to determine whether they are, 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, 99 percent of our reserve estimates are either audited or prepared 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-producing properties and/or goodwill and have an impact on our depletion 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 $46 million and $56 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 and/or goodwill.

 

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. 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. At December 31, 2008, we have $639 million of deferred tax assets for which a $15 million valuation allowance has been established. 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.

 

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 as required by FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). 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 regarding FIN 48.

 

Pension and Postretirement Obligations

 

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. 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.

 

 

The expected long-term rates of return on plan assets are determined by combining a review of historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and capital market projections for the asset classifications in which the portfolio is invested as well as the weightings of each asset classification. The credit crisis and subsequent economic downturn have negatively impacted the markets and our 2008 investment returns largely mirror market performance. While the market downturn has impacted short-term investment performance, these expected rates of return are long-term in nature and are not significantly impacted by short-term market swings. 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 was 7.75 percent for 2006 through 2008 and 8.5 percent for 2003 through 2005. Over the past ten years, our actual average return on plan assets for our pension plans has been approximately 2.1 percent. The 2008 return on plan assets for our pension plans was a loss of approximately 34.1 percent, which significantly impacted the ten-year average rate of return on plan assets. The 2007 ten-year average rate of return on plan assets for the pension plans was approximately 7.7 percent. As described in Note 7 of Notes to Consolidated Financial Statements, the asset allocation is being changed during 2009 with a slightly higher percentage of plan assets being allocated to debt securities and cash and cash equivalents. Therefore, our 2009 expected long-term rate of return on plan assets assumption is expected to slightly decrease.

 

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 our actual historical cost rates that are adjusted for expected changes in the health care industry. An increase in this rate causes the other postretirement benefit obligation and expense to increase.

 

Fair Value Measurements

 

On January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), for our assets and liabilities that are measured at fair value on a recurring basis, primarily our energy derivatives. See Note 14 of Notes to Consolidated Financial Statements for disclosures regarding SFAS No. 157, including discussion of the fair value hierarchy levels and valuation methodologies.

Certain of our energy derivative assets and liabilities and other assets 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, 2008, 22 percent of the total assets measured at fair value and 2 percent of the total liabilities measured at fair value 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 also incorporates the time value of money and credit risk factors including the credit standing of the counterparties involved, the existence of master netting arrangements, the impact of credit enhancements (such as cash deposits and letters of credit) and our nonperformance risk on our liabilities. Currently, our approach is to 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 through 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, 2008, the credit reserve is $6 million on our net derivative assets and $15 million on our 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.

 

As of December 31, 2008, 77 percent of our derivatives portfolio expires in the next 12 months and 99 percent of our derivatives portfolio expires in the next 36 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 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, 2008, predominantly consist of options that hedge future sales of production from our Exploration & Production segment, are structured as costless collars and are financially settled. The options are valued using an industry standard Black-Scholes option pricing model. Certain inputs into the model are generally observable, such as commodity prices and interest rates, whereas a significant input, implied volatility by location, is unobservable. The impact of volatility on changes in the overall fair value of the options structured as collars is mitigated by the offsetting nature of the put and call positions. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices. The hedges are accounted for as cash flow hedges where net unrealized gains and losses from changes in fair value are recorded, to the extent effective, in other comprehensive income (loss) and subsequently impact earnings when the underlying hedged production is sold.

 

Exploration & Production has an unsecured credit agreement through December 2013 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.

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, 2008. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

 

 

 

2008 vs. 2007

 

Our consolidated results in 2008 have improved significantly compared to 2007. However, these results were considerably influenced by favorable results in the first three quarters of the year, followed by a sharp decline in the fourth quarter due to a rapid decline in energy commodity prices.

 

The increase in revenues is primarily due to higher production revenues at Exploration & Production resulting from both higher net realized average prices and increased production volumes sold. Midstream also experienced higher olefin production revenues primarily due to higher average prices and volumes as well as increased natural gas liquid (NGL) production revenues resulting from higher average prices, partially offset by lower volumes. Additionally, Gas Marketing Services revenues increased primarily due to favorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage and the absence of a loss recognized on a legacy derivative sales contract in 2007.

The increase in costs and operating expenses is primarily due to increased costs associated with our olefin and NGL production businesses at Midstream. Higher depreciation, depletion, and amortization and higher operating taxes at Exploration & Production also contributed to the increase in expenses.

 

The increase in selling, general and administrative expenses (SG&A) primarily includes the impact of higher staffing and compensation at our Exploration & Production and Midstream segments in support of increased operational activities.

 

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

 

 

Other (income) expense — net within operating income in 2007 includes:

 

 

The increase in operating income reflects improved operating results at Exploration & Production due to higher net realized average prices, natural gas production growth and a gain of $148 million on the sale of a contractual right to a production payment, partially offset by increased operating costs and $143 million of property impairments in 2008. The increase also reflects improved results at Gas Marketing Services primarily due to favorable price movements on derivative positions economically hedging the anticipated withdrawals of natural gas from storage and the absence of a loss recognized on a legacy derivative sales contract in 2007. Partially offsetting these increases is a decrease in operating income at Midstream primarily due to a sharp decline in energy commodity prices in the latter part of 2008.

 

Interest accrued — net decreased primarily due to increased capitalized interest resulting from an increased level of capital expenditures. The decrease was also a result of lower interest rates on debt issuances that occurred late in the fourth quarter of 2007 and in the first half of 2008 for which the proceeds were primarily used to retire existing debt bearing higher interest rates. While our overall debt balances have been relatively comparable, the net effect of these retirements and issuances has resulted in lower rates.

 

The decrease in investing income is primarily due to a decrease in interest income largely resulting from lower average interest rates in 2008 compared to 2007.

 

Minority interest in income of consolidated subsidiaries increased primarily reflecting the growth in the minority interest holdings of Williams Partners L.P. and Williams Pipeline Partners L.P. in late 2007 and early 2008, respectively.

Provision for income taxes increased primarily due to higher pre-tax income partially offset by a reduction in our estimate of the effective deferred state tax rate. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rate compared to the federal statutory rate for both periods.

 

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

 

2007 vs. 2006

 

The increase in revenues is due primarily to higher Midstream revenues associated with increased NGL and olefins marketing revenues and increased production of olefins and NGLs. Exploration & Production experienced higher revenues also due to increases in production volumes and net realized average prices. Additionally, Gas Pipeline revenues increased primarily due to increased rates in effect since the first quarter of 2007. These increases are partially offset by a mark-to-market loss recognized at Gas Marketing Services on a legacy derivative natural gas sales contract that we expect to assign to another party in 2008 under an asset transfer agreement that we executed in December 2007.

 

The increase in costs and operating expenses is due primarily to increased NGL and olefins marketing purchases and increased costs associated with our olefins production business at Midstream. Additionally, Exploration & Production experienced higher depreciation, depletion and amortization and lease operating expenses due primarily to higher production volumes.

 

The increase in SG&A is primarily due to increased staffing in support of increased drilling and operational activity at Exploration & Production, the absence of a $25 million gain in 2006 related to the sale of certain receivables at Gas Marketing Services, and a $9 million charge related to certain international receivables at Midstream.

 

Other (income) expense — net within operating income in 2006 includes:

 

 

The increase in general corporate expenses is attributable to various factors, including higher employee-related costs, increased levels of charitable contributions and information technology expenses. The higher employee-related costs are primarily the result of higher stock compensation expense. (See Note 1 of Notes to Consolidated Financial Statements.)

 

The securities litigation settlement and related costs is primarily the result of our 2006 settlement related to class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002. (See Note 16 of Notes to Consolidated Financial Statements.)

 

The increase in operating income reflects record high NGL margins at Midstream, continued strong natural gas production growth at Exploration & Production, the positive effect of new rates at Gas Pipeline, and the absence of 2006 litigation expenses associated with shareholder lawsuits and Gulf Liquids litigation.

 

Interest accrued — net includes a decrease of $19 million in interest expense associated with our Gulf Liquids litigation contingency, offset by changes in our debt portfolio, most significantly the issuance of new debt in December 2006 by Williams Partners L.P.

 

The increase in investing income is due to:

 

 

 

These increases are partially offset by the absence of a $7 million gain on the sale of an international investment in 2006.

 

Early debt retirement costs in 2007 includes $19 million of premiums and fees related to the December 2007 repurchase of senior unsecured notes. Early debt retirement costs in 2006 includes $27 million in premiums and fees related to the January 2006 debt conversion and $4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.

 

Minority interest in income of consolidated subsidiaries increased primarily due to the growth in the minority interest holdings of Williams Partners L.P.

 

Provision for income taxes was significantly higher in 2007 due primarily to higher pre-tax earnings. See Note 5 of Notes to Consolidated Financial Statements for a reconciliation of the effective tax rate compared to the federal statutory rate for both periods.

 

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

 

Results of Operations — Segments

 

We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Gas Marketing Services, and Other. Other primarily consists of corporate operations. Our management currently evaluates performance based on segment profit (loss) from operations. (See Note 18 of Notes to Consolidated Financial Statements.)

 

Exploration & Production

 

Overview of 2008

 

In 2008, segment revenues and segment profit for Exploration & Production improved significantly compared to 2007. The 2008 results benefited from higher production levels coupled with higher natural gas prices through the first three quarters of the year. However, the results were negatively impacted by a significant decline in natural gas prices in the fourth quarter. The potential impact of sustained lower natural gas prices is discussed further in the following Outlook for 2009 section.

 

We’ve remained focused on continuing our domestic development drilling program in our growth basins. Accordingly, we:

 

 

The benefits of higher net realized average prices and higher production volumes were partially offset by increased operating costs. The increase in operating costs was primarily due to the impact of increased production volumes and prices on operating taxes and higher well service and lease service costs. In addition, higher production volumes coupled with higher capitalized drilling costs increased depreciation, depletion, and amortization expense.

 

Significant events

 

In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for $148 million. As a result of the contract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We had obtained these interests through our acquisition of Barrett Resources Corporation in 2001.

 

In May 2008, we acquired certain undeveloped leasehold acreage, producing properties and gathering facilities in the Piceance basin for $285 million. A third party subsequently exercised its contractual option to purchase, on the same terms and conditions, an interest in a portion of the acquired assets for $71 million.

 

In September 2008, we increased our position in the Fort Worth basin by acquiring certain undeveloped leasehold acreage and producing properties for $147 million. This acquisition is consistent with our growth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties.

 

Based on our assessment of undiscounted and discounted future cash flows, which considered year-end natural gas reserve quantities, we recorded an impairment of $129 million in December 2008 related to our properties in the Arkoma basin. In September 2008, we recorded a $14 million impairment due to unfavorable drilling results, also in the Arkoma basin.

 

In December 2008, the Wyoming Supreme Court ruled against us on our appeal of the Wyoming State Board of Equalization’s decision to uphold an assessment by the Wyoming Department of Audit related to severance and ad valorem taxes for the years 2000 through 2002. Related to this decision, we adjusted our estimated liability for the periods from 2000 through 2008, which resulted in a charge of $34 million. (See Note 4 of Notes to Consolidated Financial Statements.)

 

Outlook for 2009

 

Considering the previously discussed significant decline in natural gas prices, we expect segment revenues and segment profit in 2009 to be significantly lower than in 2008. As a result, we plan to reduce capital expenditures and deploy fewer drilling rigs in 2009 compared to 2008 which will reduce the number of wells drilled. We have the following expectations and objectives for 2009:

 

 

Risks to achieving our expectations include unfavorable natural gas market price movements which are impacted by numerous factors, including weather conditions, domestic natural gas production levels and demand, and the downturn in the global economy. A further significant decline in natural gas prices would impact these expectations for 2009.

 

In addition, changes in laws and regulations may impact our development drilling program. For example, the Colorado Oil & Gas Conservation Commission has enacted new rules effective in April 2009 which will increase our costs of permitting and environmental compliance and potentially delay drilling permits. The new rules include

additional environmental and operational requirements before permit approvals are granted, tracking of certain chemicals brought on location, increased wildlife stipulations, new pit and waste management procedures and increased notifications and approvals from surface landowners.

 

Commodity Price Risk Strategy

 

To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative forward sales contracts that fix the sales price relating to a portion of our future production using NYMEX and basis fixed-price contracts and collar agreements.

 

For 2009, we have the following agreements and contracts for our daily domestic production, shown at weighted average volumes and basin-level weighted average prices:

 

 

The following is a summary of our agreements and contracts for daily production for the years ended December 31, 2008, 2007 and 2006:

 

 

Additionally, we utilize contracted pipeline capacity through Gas Marketing to move our production from the Rockies to other locations when pricing differentials are favorable to Rockies pricing. We also expect additional pipeline capacity to be put into service in 2009.

 

Year-Over-Year Operating Results

 

 

2008 vs. 2007

 

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