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

Form 10-K

 

 

Commission file number 1-4174

The Williams Companies, Inc.

(Exact name of Registrant as Specified in Its Charter)

 

 

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

 

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

 

 

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

5.50% Junior Subordinated Convertible Debentures due 2033

 

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

 

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

 

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

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) 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 $9,096,736,726.

 

The number of shares outstanding of the registrant’s common stock outstanding at February 19, 2010 was 583,598,142.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s 2010 Annual Meeting of Stockholders to be held on May 20, 2010, 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, 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 2009, 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.

 

On February 17, 2010, we completed a strategic restructuring, which involved contributing a substantial majority of our domestic midstream and gas pipeline businesses, including our limited- and general-partner interests in Williams Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ). As consideration for the asset contributions, we received proceeds from WPZ’s debt issuance of approximately $3.5 billion, less WPZ’s transaction fees and expenses, as well as 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution. We also maintained our 2 percent general-partner interest. WPZ assumed

 

 

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

approximately $2 billion of existing debt associated with the gas pipeline assets. In connection with the restructuring, we retired $3 billion of our debt and paid $574 million in related premiums. These amounts, as well as other transaction costs, were primarily funded with the cash consideration received from WPZ. As a result of our restructuring, we are better positioned to drive additional growth and pursue value-adding growth strategies. Our new structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. (See Note 19 of Notes to Consolidated Financial Statements.)

 

In conjunction with the restructuring, WPZ has announced its intention to launch an exchange offer for the publicly traded common units of WMZ at a future date. WPZ will offer a fixed exchange ratio of 0.7584 of its common units for each WMZ common unit. The ratio is based on closing prices on the New York Stock Exchange on Friday, January 15, 2010, the business day before WPZ’s intention to make the exchange offer was announced, of $23.35 for WMZ and $30.79 for WPZ. The exact timing of the launch will be based upon the filing of necessary offering documents with the SEC and upon market conditions. If WPZ acquires ownership of more than 75% of WMZ’s outstanding common units pursuant to this offer, WPZ will consider causing the general partner of WMZ to (i) deregister WMZ under the Exchange Act or cause its common units to no longer be traded on the New York Stock Exchange, if these options are available, (ii) exercise its right under the WMZ’s limited partnership agreement to purchase all of the remaining common units or (iii) exercise any other available options.

 

Beginning with reporting of first-quarter 2010 results, we will change our segment reporting structure to align with the new parent-level focus, resource allocation management and related governance provisions resulting from the restructuring. Our reporting segments will be Williams Partners, Exploration & Production, and Other. Exploration & Production will include our current Gas Marketing Services (Gas Marketing) segment and Other will include certain midstream and gas pipeline businesses that were not contributed to WPZ, such as our Canadian and olefins midstream businesses and the remaining 25.5 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream), as well as corporate operations.

 

Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statements in Part II, Item 8 of this document, which reflects our segment reporting structure prior to the restructuring. These segments are discussed in further detail in the following sections.

 

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.

 

Substantially all our operations are conducted through our subsidiaries. To achieve organizational and operating efficiencies, our activities in 2009 were 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 Colorado, New Mexico, and Wyoming), Mid-Continent (Oklahoma and Texas), and Appalachian 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, Fort Worth, and Appalachian basins. Over 99 percent of our domestic reserves are natural gas. We also have international oil and gas interests, which include a 69 percent equity interest in Apco Oil and Gas International Inc. (formerly Apco Argentina Inc., NASDAQ listed: APAGF), an oil and gas exploration and production company with operations in South America. If combined with our domestic proved reserves, our international interests would make up approximately 4 percent of our total proved reserves. Considering this, the reserves information included in this section relates only to our domestic activity.

 

Our goal is to continue to drill our existing proved undeveloped reserves, which comprise approximately 44 percent of proved reserves, and to drill in areas of probable and possible reserves in order to add to our proved reserves. Our current proved, probable, and possible reserves inventory provides us with strong capital investment opportunities for many years into the future.

 

On January 14, 2009, the SEC issued the Final Rule for Modernization of Oil and Gas Reporting which modifies how oil and gas companies report reserves estimates. We have adopted the revised SEC oil and gas reporting requirements, effective as of December 31, 2009, with the following effects:

 

 

Oil and Gas Reserves

 

Reserves information is reported as gas equivalents, since oil volumes are insignificant. Reserves are more than 99 percent natural gas for all periods indicated.

 

Summary of oil and gas reserves:

 

 

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

Proved reserves sensitivities price scenario

 

The new SEC rules allow for reserves sensitivity analysis using alternate price and cost criteria as shown below. The SEC case was derived using the 12-month average, first-of-the-month Henry Hub spot price of $3.87 per MMbtu, adjusted for locational price differentials. Neither of the sensitivity scenarios was audited by a third party. All three cases assume that proved undeveloped reserves are drilled within five years. No changes were made to capital expenditures or operating costs in the sensitivity scenarios.

 

 

Sensitivity 1: Reflects proved reserves estimated by adding $1.00 to each of the basin prices from the SEC case.

 

Sensitivity 2: Reflects proved reserves estimated using prices from the prior year-end, which were calculated using the December 31, 2008, NYMEX Henry Hub posted price of $5.71 per MMbtu, adjusted for locational price differentials.

 

The chart below shows the year-end 2009 SEC case compared to the two alternate price scenarios. Also shown is the impact the new SEC reserves rules had on 2009 proved reserves.

 

Proved U.S. Reserves Reconciliation

 

 

The new SEC reporting rules require that year-end proved reserve volumes are calculated using an average price for the full-year 2009, rather than the year-end price. This resulted in utilization of a basin price approximately 33 percent lower than the previous year which resulted in a downward price revision of 336 Bcfe.

 

Under the new rules, reserves generally cannot be classified as proved if they have not or will not be developed within five years according to planned drilling activity and taking into account anticipated proved undeveloped conversion rates for wells drilled. This rule change resulted in reclassification of 496 Bcfe of reserves from proved undeveloped to probable.

 

Additionally, the new rules now allow adding undeveloped proved reserves locations that are more than one offset away from currently producing wells where there is reasonable certainty of production. This rule change resulted in the addition of 454 Bcfe of proved reserves.

 

Also shown on the chart is 570 Bcfe of net additions/revisions to our proved reserves through drilling 882 gross wells in 2009 at a capital cost of approximately $878 million.

 

Reserves estimation process

 

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

 

The preparation of our year-end reserves report is a formal process. We begin with a review of the existing process to identify where improvements can be made. Our internal processes and controls, as they relate to the year-end reserves, are reviewed and updated. Each asset teams’ reserves engineering and geological technical staffs, the reserves analysis team, and the third-party engineering consultants meet to begin the year-end process and audit. The asset teams’ reserves staff, the reserves analysis team and the third-party engineering consultants exchange data and interpretations in furtherance of the completion of the year-end reserves estimates. The reserves analysis team met twice with the Audit Committee of our Board of Directors to report on the progress of its analysis of our 2009 reserves, allowing the Audit Committee the opportunity to review and comment on management’s processes and conclusions.

 

Approximately 99 percent of our total year-end 2009 domestic proved reserves estimates were audited 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 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 Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is satisfied with our methods and procedures in preparing the December 31, 2009, reserves estimates and noted nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us. The report of NSAI is included as Exhibit 99.1 to this Form 10-K.

 

In addition, reserves estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, of which our ownership in the Trust represents approximately 1 percent of our total domestic proved reserves estimates, were prepared by Miller and Lents, LTD. The report of Miller and Lents is included as Exhibit 99.2 to this Form 10-K.

 

The reserves estimates resulting from the above process are subjected to both internal and external checks and controls to promote transparency and accuracy of the year-end reserves estimates. Our internal control documentation provides further confirmation on the checks and controls. Our internal reserves analysis team is independent and does not work within an asset team or report directly to anyone on the asset teams. The compensation of our reserves analysis team is not linked to reserves additions or revisions.

The technical person primarily responsible for overseeing preparation of the reserves estimates and the third- party reserves audit is the Director of Reserves and Production Services. The Director’s qualifications include 27 years of reserves evaluation experience, a B.S. in geology from the University of Texas at Austin, an M.S. in physical sciences from the University of Houston, and membership in the American Association of Petroleum Geologists, and The Society of Petroleum Engineers.

 

Proved undeveloped reserves

 

Our proved undeveloped reserves as of December 31, 2009, are 1,868 Bcfe and 1,883 Bcfe as of December 31, 2008, a net decrease of approximately 15 Bcfe. See additional discussion of proved undeveloped reserves in our sensitivity analysis.

 

The vast majority of our reserves is concentrated in unconventional tight gas sands, shale gas and coal bed gas reservoirs. We use available geoscience and engineering data to establish drainage areas and continuity of reservoir beyond one direct offset from a producing well, which provides additional proved undeveloped bookings in fields where the evidence supported the methodology. Inherent in the methodology was a requirement for significant well density of economically producing wells to establish those bookings with reasonable certainty. In fields where producing wells were less dense, only direct offsets from proved producing wells were assigned the proved undeveloped reserves classification.

 

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

 

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

 

 

 

 

Drilling and Exploratory Activities

 

We focus on lower-risk development drilling. Our development drilling success rate was approximately 99 percent in each of 2009, 2008, and 2007.

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

 

 

 

 

In 2009, there were two gross nonproductive exploratory wells and one net nonproductive exploratory well. Total gross operated wells drilled were 472 in 2009, 1,125 in 2008, and 1,112 in 2007.

 

Present Activities

 

At December 31, 2009, we had 42 gross (14 net) wells in the process of being drilled.

 

Delivery Commitments

 

We hold a long-term obligation, through our Gas Marketing segment, to deliver on a firm basis 200,000 MMBtu/d of gas to a buyer at the White River Hub (Greasewood-Meeker, Colorado), which is the major market hub exiting the Piceance basin. The Piceance, being our largest producing basin, holds ample reserves to fulfill this obligation without risk of nonperformance during periods of normal infrastructure and market operations. While the daily volume of gas is large and represents a significant percentage of our daily production, this transaction does not represent a material exposure.

 

Oil and Gas Properties, Wells, Operations, and Acreage

 

The table below summarizes 2009 producing wells and production by area:*

 

 

 

 

At December 31, 2009, there were 181 gross and 106 net producing wells with multiple completions.

 

The following table summarizes our leased acreage as of December 31, 2009:

 

 

Piceance basin

 

The Piceance basin is located in northwestern Colorado and is our largest area of concentrated development. During 2009 we operated an average of 10.3 drilling rigs in the basin. This area has approximately 1972 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 5 processing plants and associated treating facilities for a total capacity of 1.15 Bcf/d. During 2009, these plants recovered approximately 6.3 million gallons of natural gas liquids (NGLs) each month, which were marketed separately from the residue natural gas.

 

In addition to our own operated facilities, Midstream owns and operates a new cryogenic processing plant, Willow Creek, which currently has a capacity of 450 MMcf/d and reprocesses that amount of gas, recovering an average of 12.6 million additional gallons of NGLs per month, 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. We provide a significant amount of equity production that is gathered and/or processed by Midstream’s facilities in the San Juan basin.

 

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 and the Appalachian basin (Marcellus Shale) in Pennsylvania. Also included is exploration activity and other miscellaneous activity.

 

Hedging Activity

 

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

Acquisitions & Divestitures

 

In June 2009, we entered into an agreement that allows us to acquire, through a “drill to earn” structure, a 50 percent interest in approximately 44,000 net acres in Pennsylvania’s Marcellus Shale in the Appalachian basin. This agreement requires us to fund $33 million of drilling and completion costs on behalf of our partner and $41 million of our own costs and expenses prior to the end of 2011 to earn our 50 percent interest. This growth opportunity leverages our experience in developing nonconventional natural gas reserves. Through December 2009, we have funded $14 million of the $33 million.

 

In September 2009, we completed the purchase of additional unproved leasehold acreage and proved properties in the Piceance basin for $253 million. In December 2009, we increased our working interest in these properties through a $22 million acquisition.

 

Through other transactions totaling approximately $36 million, Exploration & Production expanded its acreage position and producing properties in the Fort Worth basin (Barnett Shale), the Appalachian basin (Marcellus Shale), the Arkoma basin (Woodford Shale), as well as exploration leaseholds 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 (“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 March 1, 2010, we expect to own 789,291 trust units. Based on certain provisions of the Trust agreement, the Trust is expected to terminate on March 1, 2010. Upon termination, the net profits interest will be placed for sale and we will receive proceeds from the sale less applicable expenses in direct proportion to the Trust units owned. This transaction is expected to have a minimal impact to our financial statements.

 

We own and operate a combined total of approximately 13,900 miles of pipelines with a total annual throughput of approximately 2,700 TBtu 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. Gas Pipeline also includes WMZ.

 

Transco

 

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

 

Pipeline system and customers

 

At December 31, 2009, 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 3.9 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.6 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 2009. Transco’s firm transportation agreements are generally long-term agreements with various expiration dates and account for the major portion of Transco’s business. Additionally, Transco offers storage services and interruptible transportation services under short-term agreements.

 

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that they own and operate. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 204 billion cubic feet of gas. In addition, wholly owned subsidiaries of Transco operate and hold a 35 percent ownership interest in Pine Needle LNG Company, LLC, a LNG storage facility with 4 billion cubic feet of storage capacity. Storage capacity permits Transco’s customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

 

Transco expansion projects

 

The pipeline projects listed below were completed during 2009 or are significant future pipeline projects for which we have customer commitments.

 

Sentinel Expansion Project

 

The Sentinel Expansion Project is a recently completed 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 $229 million. Phase I was placed into service in December 2008. Phase II was placed into service in 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. In May 2009, Transco received approval from the Federal Energy Regulatory Commission (FERC). The capital cost of the project is estimated to be approximately $37 million. Transco plans to place the project into service by May 2010.

 

Mobile Bay South II Expansion Project

 

The Mobile Bay South II Expansion Project involves the addition of compression at Transco’s Station 85 in Choctaw County, Alabama, and modifications to existing facilities at Transco’s Station 83 in Mobile County, Alabama, to allow Transco to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In November 2009, Transco filed an application with the FERC. The capital cost of the project is estimated to be approximately $36 million. Transco plans to place the project into service by May 2011.

 

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. In September 2009, Transco received approval from the FERC. The capital cost of the project is estimated to be $241 million. Transco plans to place the project into service in phases, in July 2010 and May 2011.

 

Mid-South Expansion Project

 

The Mid-South Expansion Project involves an expansion of Transco’s mainline from Station 85 in Choctaw County, Alabama, to markets as far downstream as North Carolina. Transco anticipates filing an

application with the FERC in the fourth quarter of 2010. The capital cost of the project is estimated to be approximately $200 million. Transco plans to place the project into service in September 2012.

 

Mid-Atlantic Connector Project

 

The Mid-Atlantic Connector Project involves an expansion of Transco’s mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. Transco anticipates filing an application with the FERC in the first quarter of 2011. The capital cost of the project is estimated to be approximately $55 million. Transco plans to place the project into service in November 2012.

 

Rockaway Delivery Lateral Project

 

The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. Transco anticipates filing an application with the FERC in the third quarter of 2010. The capital cost of the project is estimated to be approximately $120 million. Transco plans to place the project into service in November 2013.

 

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, 2009, Northwest Pipeline’s system, having long-term firm transportation agreements including peaking service of approximately 3.7 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 2009, Northwest Pipeline served a total of 127 transportation and storage customers. Northwest Pipeline transports and stores natural gas for a broad mix of customers, including local natural gas distribution companies, municipal utilities, direct industrial users, electric power generators and natural gas marketers and producers. The two largest customers of Northwest Pipeline in 2009 accounted for approximately 22 percent and 12 percent, respectively, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2009. 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 2009 or are significant future pipeline projects for which we have customer commitments.

 

Colorado Hub Connection Project

 

In November 2009, Northwest Pipeline placed into service the new 27-mile, 24-inch diameter lateral referred to as the Colorado Hub Project (CHC Project). The new lateral connects the Meeker/White River Hub near Meeker, Colorado to its mainline south of Rangely, Colorado, and is estimated to cost up to $60 million. The CHC Project combined the new lateral capacity with existing mainline capacity to provide approximately 363 Mdth per day of firm transportation from various receipt points to delivery points on the mainline as far south as Ignacio, Colorado. In April 2009, the FERC issued a certificate approving the CHC Project, including the presumption of rolling in the costs of the project in any future rate case filed with the FERC.

 

Sundance Trail Expansion

 

In November 2009, Northwest Pipeline received approval from the FERC to construct 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 the existing compression at Vernal, which will enhance the efficiency of Northwest Pipeline’s system. Northwest Pipeline executed a precedent agreement to provide 150 Mdth per day of firm transportation service from the Greasewood and Meeker Hubs in Colorado for delivery to the Opal Hub in Wyoming. Northwest Pipeline has proposed to collect its maximum system rates, and has received approval from the FERC to roll-in the Sundance Trail Expansion costs in any future rate cases.

 

Operating statistics

 

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

 

 

 

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, 2009, our equity investment in Gulfstream was $383 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 capital cost of this project was $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 capital cost of this expansion was $190 million, with Gas Pipeline’s share being 50 percent of such costs. The Phase V expansion involves the addition of compression to provide 35 Mdt/d of firm capacity by July 2011. The estimated capital cost of this expansion is approximately $54 million with Gas Pipeline’s share being 50 percent of such cost.

 

WMZ

 

WMZ was formed to own and operate natural gas transportation and storage assets. As of December 31, 2009, we own an approximate 45.7 percent limited partnership interest and a 2 percent general partner interest in WMZ. A subsidiary of ours, Williams Pipeline GP LLC, serves as the general partner of WMZ. WMZ owns a 35 percent interest in Northwest Pipeline.

 

As previously discussed, our overall ownership in WMZ was affected by our restructuring transactions in 2010. WPZ intends to make an exchange offer for the publicly held units of WMZ at a future date. See “Strategic Restructuring” in Part I, Item 1 of this Form 10-K for further discussion of this potential exchange offer.

 

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, Pennsylvania, 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 raw natural gas and crude oil from the producing fields 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.

 

Key variables for the Midstream 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 and olefins. 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 both of these types of processing agreements are referred to as our equity NGL production. Our gathering and processing agreements have terms ranging from month-to-month to the life of the producing lease. Generally, our gathering and processing agreements are long-term agreements.

 

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 2009, these operations gathered and processed gas for approximately 230 gas gathering and processing customers. Our top 7 gathering and processing customers accounted for approximately 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 own two production platforms serving the deepwater Gulf of Mexico. Our crude oil transportation revenues are typically volumetric-based fee arrangements. However, a portion of our marketing revenues are recognized from purchase and sale arrangements whereby we purchase oil from producers at the receipt points of our crude oil pipelines for an index-based price and resell the oil 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 approximately 87 percent of our Exploration & Production segment’s equity production in this basin. Our Willow Creek plant, completed in 2009, is currently processing Exploration & Production segment’s wellhead production in the Piceance basin. Our San Juan basin, southwest Wyoming, and Willow Creek systems deliver residue gas volumes into Northwest Pipeline’s interstate system in addition to third-party interstate systems.

 

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:

 

 

In the Piceance basin in Colorado, our infrastructure includes:

 

 

West region expansion projects

 

Our major capital and expansion projects include additional capacity at our Echo Springs facility and related gathering system expansions in the Wamsutter basin. We expect to significantly increase the processing and NGL production capacities at our Echo Springs cryogenic natural gas processing plant in Wyoming. The addition of a fourth cryogenic processing train will add approximately 350 MMcf/d of processing capacity and 30 Mbbls/d of NGL production capacity, nearly doubling Echo Spring’s capacities in both cases. We began construction on the fourth train at Echo Springs during the second half of 2009 and expect to bring the additional capacity online during late 2010.

 

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

 

Our current major expansion project in the Gulf region is our Perdido Norte project located in the western deepwater of the Gulf of Mexico. The investment expands our existing infrastructure and includes a total of 184 miles of deepwater oil and gas pipeline and a 200 MMcf/d expansion of our onshore Markham gas processing facility. We expect the project to begin start-up operations in the first quarter of 2010.

 

Olefins

 

Gulf Coast region 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, respectively. 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.

 

Canadian region olefins

 

Our Canadian operations include an oil sands off-gas processing plant located near Ft. McMurray, Alberta and an NGL/olefin fractionation facility near Edmonton, Alberta. Our facilities extract liquids from the off-gas produced by a third-party oil sands bitumen upgrading process. Our arrangement with the third-party upgrader is a “keep-whole” type where we remove a mix of NGLs and olefins from the off-gas and return the equivalent heating value back 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 NGL/olefins fractionator in western Canada and the only treater/processor of oil sands upgrader off-gas. Our extraction of liquids from upgrader off-gas streams allows the upgraders to burn cleaner natural gas streams and reduce their overall air emissions. The Ft. McMurray 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.

 

Canadian olefin expansion projects

 

In Canada, we expect to begin construction in 2010 on a 261-mile, 12-inch pipeline which will transport recovered NGLs and olefins from our processing plant in Ft. McMurray to our fractionation facility near Edmonton, Alberta. The pipeline will have sufficient capacity to transport additional NGLs and olefins from the current arrangement with the third-party oil sands producer, as well as from other oil-sands producers’ off-gas in the Ft. McMurray area. The project will be constructed using cash previously generated from Canadian and other international projects. We anticipate an in-service date in 2012.

 

In addition, a project to upgrade the value of one of the products produced at the fractionators near Edmonton, Alberta, is expected to be completed in the latter part of 2010. The new splitter and hydrotreating facilities will take the butane/butlyene mix product currently produced and further fractionate the mix product into two higher value products that are in greater demand in the market place. These new facilities are also being constructed using cash generated from Canadian and other international projects.

 

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 LLC. 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 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 Mbbls/d 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 LP 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.

 

In June 2009, we completed the formation of a new joint venture, Laurel Mountain Midstream, LLC (Laurel Mountain), in the Marcellus Shale located in southwest Pennsylvania. Our partner in the venture contributed its existing Appalachian basin gathering system, which currently has an average throughput of approximately 100 MMcf/d. In exchange for a 51 percent interest in the venture, we contributed $100 million and issued a

$26 million note payable. In 2010, we expect to significantly increase our investment in our Laurel Mountain joint venture through new gathering system infrastructure construction.

 

In conjunction with a long-term agreement with a major producer, we will construct a 28-mile natural gas gathering pipeline in the Marcellus Shale region that will deliver to the Transco pipeline. Construction is expected to begin on the 20-inch pipeline in the latter part of 2010, and it is expected to be placed into service during 2011. We will operate the pipeline, which represents our second significant midstream expansion in the Marcellus Shale.

 

We 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. Accroven owns and operates gas processing facilities and an NGL fractionation plant for the exclusive benefit of the state-owned oil company, Petróleos de Venezuela S.A. (PDVSA). As a result of deteriorating circumstances for our Venezuelan operations (see Note 2 of Notes to Consolidated Financial Statements), we fully impaired and recognized a $75 million charge related to an other-than-temporary loss in value of our Accroven investment. (See Note 3 of Notes to Consolidated Financial Statements.) Accroven was not part of the operations that were expropriated by the Venezuelan government in May 2009. We are currently engaged in discussions regarding the eventual disposition of Accroven.

 

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. As of December 31, 2009, we 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. As of December 31, 2009, 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.

 

As previously discussed, our ownership in WPZ, WPZ’s asset portfolio, and our future segment reporting structure were affected by our 2010 restructuring transactions.

 

Gas Marketing primarily supports our natural gas businesses by providing marketing and risk management services, which include marketing and hedging the gas produced by Exploration & Production and procuring the

majority of fuel and shrink gas and hedging natural gas liquids sales for Midstream. Gas Marketing also provides similar services to third parties, such as producers and natural gas processors. In addition, Gas Marketing manages various natural gas-related contracts such as transportation and storage along with the related hedges, including certain legacy natural gas contracts and positions.

 

Gas Marketing’s 2009 natural gas purchase volumes include 1.4 Bcf/d of gas produced by Exploration & Production and another 1.0 Bcf/d from other sources. This natural gas was in turn marketed and sold to third parties (2.1 Bcf/d) and to Midstream (0.3 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.

 

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.

 

Pipeline Integrity Regulations

 

Transco and Northwest Pipeline have developed Integrity Management Plans that meet the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, Transco and Northwest Pipeline have identified high-consequence areas, completed baseline assessment plans, and are on schedule to complete the required assessments within specified timeframes. Currently, Transco and Northwest Pipeline estimate that the cost to perform required assessments and remediation will be primarily capital and range between $150 million and $220 million and between $65 million and $85 million, respectively, over the remaining assessment period of 2010 through 2012. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through rates.

 

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 nonowner 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.

 

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 noncompliance 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 cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

 

 

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

 

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

 

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

 

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. By virtue of the master limited partnership structure, WPZ provides us with an alternative source of capital, which helps us compete against other master limited partnerships for midstream projects.

 

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, 2010, we had approximately 4,801 full-time employees. None of our employees are represented by unions or covered by collective bargaining agreements.

 

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

 

 

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

 

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,”

“goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

 

 

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

 

 

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking

statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

 

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

 

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

 

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

 

Risks Related to the Restructuring

 

We did not seek a vote of our shareholders in connection with the restructuring. If there is a determination that such a vote was required, the resulting consequences could impact us.

 

Section 271 of the Delaware General Corporation Law (the “DGCL”) generally requires a corporation to obtain authorization from the holders of a majority of its outstanding shares if the corporation intends to sell all or substantially all of its assets. We do not believe the restructuring constituted a sale of “all or substantially all” of our assets because of, among other things, the portion of our assets involved, the significance of our assets and businesses that were not transferred and the facts that we retain control of all of the assets involved and over an 80% interest in the cash flows therefrom. As such, we did not seek a vote of our shareholders in connection with the restructuring. There is a limited body of Delaware case law interpreting the phrase “all or substantially all,” and there is no precise established definition. We cannot assure you that the restructuring did not constitute a sale of “all or substantially all” of our assets and, therefore, that a shareholder vote was not required. If such a shareholder vote were determined to be required, the resulting consequences could impact us and could include (among other consequences) our shareholders asserting claims against us, some or all of which could ultimately be successful.

 

We may not realize the anticipated benefits from the restructuring.

 

We may not realize the benefits that we anticipate from the Dropdown for a number of reasons, including, but not limited to, if any of the matters identified as risks in this Risk Factors section were to occur. If we do not realize the anticipated benefits from the restructuring for any reason, our business may be materially adversely affected.

 

Risks Inherent to our Industry and Business

 

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

 

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

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

 

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

 

Prices for NGLs, 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 of NGLs, natural gas, or other commodities, and the differences between prices of these commodities. Price volatility and relative price levels may 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.

 

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 noncash charge to earnings. The revisions could also possibly affect the evaluation of Exploration & Production’s goodwill for impairment purposes. At December 31, 2009, 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 Gas Pipeline 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 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 2010, upon expiration of the terms we may not be able to extend contracts with existing customers to obtain replacement contracts at favorable rates or on a long-term basis. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

 

 

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

 

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

 

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

 

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered 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 GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.

 

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

 

 

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

 

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

 

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

 

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

 

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.

 

The failure of new sources of natural gas production or 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 U.S. 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:

 

 

 

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses, and only at levels we believe to be appropriate. The location of certain segments of our 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, our subsidiaries and certain of 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, our subsidiaries and certain of 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 limits of $300 million per occurrence for property damage caused by terrorist acts 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 hurricane losses in recent years have impacted named windstorm insurance coverage, rates and availability for Gulf of Mexico area exposures, 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 any growth in our Gas Pipeline and Midstream businesses 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 and 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. Any significant change in accounting standards or disclosure requirements could have a material adverse effect on our business, results of operations, and financial condition.

 

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

 

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

 

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

 

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

 

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

Additionally, changes in the price of natural gas could benefit one of our 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, merge, sell substantially all of our 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. These covenants could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities and prevent us from engaging in certain transactions that might otherwise be considered beneficial to us. Our ability to comply with these covenants may be affected by many events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our current assumptions about future economic conditions turn out to be incorrect or unexpected events occur, our ability to comply with these covenants may be significantly impaired. 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 could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. Certain payment defaults or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

 

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

 

Future disruptions in the global credit markets may make equity and debt markets less accessible, create a shortage in the availability of credit and lead to credit market volatility.

 

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

 

Adverse economic conditions could adversely affect our results of operations.

 

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

A downgrade of our credit ratings could impact our liquidity, access to capital and our costs of doing business, and maintaining current credit ratings is under 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 are rated investment grade by Standard & Poor’s, Moody’s Corporation, and Fitch Ratings, Ltd., and our senior unsecured debt ratings are rated investment grade by Moody’s and Fitch. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the ratings agencies, and no assurance can be given that 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.

 

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.

 

We are subject to risks associated with climate change.

 

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

 

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

 

Compliance with environmental laws requires significant expenditures, including clean up costs and damages arising out of contaminated properties. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with spills or releases of natural gas and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations.

 

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

 

Several bills have been introduced in the United States Congress that would compel GHG emission reductions. In June of 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act” which is intended to decrease annual GHG emissions through a variety of measures, including a “cap and trade” system

which limits the amount of GHGs that may be emitted and incentives to reduce the nation’s dependence on traditional energy sources. The U.S. Senate is currently considering similar legislation, and numerous states have also announced or adopted programs to stabilize and reduce GHGs. In addition, on December 7, 2009, the EPA issued a final determination that six GHGs are a threat to public safety and welfare. This determination is the latest in a series of EPA actions in 2009 which could ultimately lead to the direct regulation of GHG emissions in our industry by the EPA under the Clean Air Act. While it is not clear whether or when any federal or state climate change laws or regulations will be passed, any of these actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations. To the extent financial markets view climate change and emissions of GHGs 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.

 

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

 

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipeline and facilities for the benefit of our customers. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipelines or other facilities were to become unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to the pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. 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 or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated or stored at our facilities could have a material adverse effect on our business, 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 in 2009 which increased our costs of permitting and environmental compliance and the time required to obtain permits, which 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, 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 Noncore Support Activities, and Technology

 

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

 

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

 

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

 

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

 

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

 

Risks Related to Weather, other Natural Phenomena and Business Disruption

 

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

 

Our assets and operations, including those located offshore, can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures, making it more difficult for us to realize the historic rates of return associated with these assets and operations. Insurance may be inadequate, and in some instances, we have been unable to obtain insurance on commercially

reasonable terms, or insurance may not be available. A significant disruption in operations or a significant liability for which we were not fully insured could have a material adverse effect on our business, results of operations and financial condition.

 

Our customers’ energy needs vary with weather conditions. To the extent weather conditions are affected by climate change or demand is impacted by regulations associated with climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, leading 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 32 states plus the District of Columbia in the United States and in Argentina, Canada, Venezuela, and Colombia.

 

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 17, 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, 2010, we had approximately 10,445 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, 2005. The Bloomberg U.S. Pipeline Index is composed of Enbridge Inc., 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, 2009 and 2008, and for each of the three years in the period ended December 31, 2009, 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, 2007, 2006, and 2005, and for the years ended December 31, 2006 and 2005, has been prepared from our accounting records.

 

 

 

 

Strategic Restructuring

 

On February 17, 2010, we completed a strategic restructuring, which involved contributing a substantial majority of our domestic midstream and gas pipeline businesses, including our limited- and general-partner interests in Williams Pipeline Partners L.P. (WMZ), into Williams Partners L.P. (WPZ). As consideration for the asset contributions, we received proceeds from WPZ’s debt issuance of approximately $3.5 billion, less WPZ’s transaction fees and expenses, as well as 203 million WPZ Class C units, which are identical to common units, except for a prorated initial distribution. We also maintained our 2 percent general-partner interest. WPZ assumed approximately $2 billion of existing debt associated with the gas pipeline assets. In connection with the restructuring, we retired $3 billion of our debt and paid $574 million in related premiums. These amounts, as well as other transaction costs, were primarily funded with the cash consideration received from WPZ. The premiums paid and certain other transaction costs will be recorded as expense in the first quarter of 2010. As a result of our restructuring, we are better positioned to drive additional growth and pursue value-adding growth strategies. Our new structure is designed to lower capital costs, enhance reliable access to capital markets, and create a greater ability to pursue development projects and acquisitions. (See Note 19 of Notes to Consolidated Financial Statements.)

 

In conjunction with the restructuring, WPZ intends to make an exchange offer for the publicly held units of WMZ at a future date. See “Strategic Restructuring” in Part I, Item 1 of this Form 10-K for further discussion of this potential exchange offer.

 

Beginning with reporting of first-quarter 2010 results, we will change our segment reporting structure to align with the new parent-level focus, resource allocation management and related governance provisions resulting from the restructuring. Our reporting segments will be Williams Partners, Exploration & Production, and Other. Exploration & Production will include our current Gas Marketing segment and Other will include certain midstream and gas pipeline businesses that were not contributed to WPZ, such as our Canadian and olefins midstream businesses and the remaining 25.5 percent interest in Gulfstream, as well as corporate operations.

 

Information in this report has generally been prepared to be consistent with the reportable segment presentation in our consolidated financial statements in Part II, Item 8 of this document, which reflects our segment reporting structure prior to the restructuring.

 

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 as of December 31, 2009: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids, 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 2009

 

The overall economic recession, related lower energy commodity price environment, and challenging financial markets during the past year had a significant impact on our business. While we began to see improvement in the second half of the year, these conditions have resulted in sharply lower results of operations, cash flow from operations and capital expenditures in 2009 compared to 2008. Anticipating these circumstances, our plan for 2009 was built around the transition from significant growth to a focus on sustaining our current operations and reducing costs where appropriate. Although capital expenditures were reduced compared to the prior year, we continued to invest in our businesses with a focus on completing major projects, meeting legal, regulatory, and/or contractual

commitments, and maintaining a reduced level of natural gas production development. Objectives and highlights of this plan included:

 

 

Our 2009 income from continuing operations attributable to The Williams Companies, Inc., decreased by $868 million compared to 2008. This decrease is primarily reflective of the overall unfavorable commodity price environment for the full year of 2009 as compared to 2008. Commodity prices declined sharply in the fourth quarter of 2008, but have improved in the latter half of 2009. See additional discussion in Results of Operations.

 

Our net cash provided by operating activities for 2009 decreased $783 million compared to 2008, primarily due to the decrease in our operating results. See additional discussion in Management’s Discussion and Analysis of Financial Condition and Liquidity.

 

Other Significant 2009 Events

 

In March 2009, we issued $600 million aggregate principal amount of 8.75 percent senior unsecured notes due 2020 to certain institutional investors in a private debt placement. In August 2009, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

 

In April 2009, Midstream announced its plan to build a 261-mile natural gas liquids pipeline in Canada at an estimated cost of $283 million. Construction is expected to begin in 2010 with completion expected in 2012.

 

In May 2009, certain of Midstream’s Venezuela operations were expropriated by the Venezuelan government. As a result, these operations are now reflected as discontinued operations and have been deconsolidated. (See Note 2 of Notes to Consolidated Financial Statements.)

 

In June 2009, Midstream finalized the formation of a new joint venture in the Marcellus Shale located in southwest Pennsylvania. (See Results of Operations — Segments, Midstream Gas & Liquids.)

 

In June 2009, Exploration & Production entered into an agreement to develop properties in the Marcellus Shale. (See Results of Operations — Segments, Exploration & Production.)

 

In September 2009, Exploration & Production completed the purchase of additional properties in the Piceance basin of Colorado for $253 million. (See Results of Operations — Segments, Exploration & Production.)

 

In September 2009, Gas Pipeline received approval from the FERC to begin construction of the 85 North expansion project at an estimated cost of $241 million. (See Results of Operations — Segments, Gas Pipeline.)

Outlook for 2010

 

We believe we are well positioned to execute on our 2010 business plan and to capture attractive growth opportunities. The economic environment in the latter half of 2009 has improved compared to conditions earlier in the year. In addition, economic and commodity price indicators for 2010 and beyond reflect continued improvement in the economic environment. However, given the potential volatility of these measures, it is reasonably possible that the economy could worsen and/or commodity prices could decline, negatively impacting future operating results and increasing the risk of nonperformance of counterparties or impairments of goodwill and long-lived assets.

 

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

 

We continue to operate with a focus on 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, 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 to reduce credit risk and liquidity requirements.

 

Accounting Pronouncements Issued But Not Yet Adopted

 

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

 

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

 

Critical Accounting Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. 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.

 

We assess our natural gas-producing properties and associated unproved leasehold costs for impairment using estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of natural gas reserves quantities, estimates of future natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs, and an applicable discount rate commensurate with risk of the underlying cash flow estimates. Considering market-based pricing at December 31, 2009, we are not currently aware of any significant properties that are approaching impairment thresholds.

 

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 and utilized inputs consistent with those described above. Certain assets within our Midstream segment were also evaluated for impairment utilizing judgments and assumptions including future fees, margins, and volumes. These underlying variables are subjective and susceptible to change. The use of alternate judgments and 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 related to its domestic operations (the reporting unit) primarily resulting from a 2001 acquisition. We assess goodwill for impairment annually as of the end of the year. Because quoted market prices are not available for the reporting unit, management applies a range of reasonable judgments (including market supported assumptions when available) in estimating a range of fair values for the reporting unit.

 

We estimate the fair value of the reporting unit on a stand-alone basis and also consider our market capitalization in corroborating our estimate of the fair value of the reporting unit. As of December 31, 2009, 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. We corroborated our fair value estimates with recent market transactions where possible.

 

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 reserves quantities of more than 4.7 Tcfe, forward natural gas prices, adjusted for locational differences, averaging approximately $5.97 per Mcfe, and an after-tax discount rate of 11 percent.

 

At December 31, 2009, we believe that an overall 20 percent or greater reduction to our estimates of future revenues, which are a component of our estimates of future cash flows, could result in an impairment of goodwill. Future revenue estimates are largely impacted by estimated prices and reserves. This sensitivity does not include any related changes in operating taxes or production costs. We currently do not consider such a decrease in future revenues across all future periods to be likely.

 

We further reviewed the fair value of the reporting unit estimated on a stand-alone basis, by considering our market capitalization in a reconciliation of the fair values of all our businesses, including the reporting unit. In this

reconciliation, we determined our market capitalization, including a control premium, and estimated the fair values of all our businesses considering certain financial performance metrics. The range of control premiums that we considered were consistent with historical market sales transactions and also considered the current market environment. Market capitalization was based on our traded stock price for a reasonably short period of time before and after December 31, 2009. In evaluating the items in our reconciliation analysis, management considered a range of reasonable judgments. This analysis allowed management to consider market expectations in corroborating the reasonableness of the estimated fair value of the 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. 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 challenges affecting our businesses and the energy industry in 2010, these factors could impact us and require us to perform interim assessments of goodwill for possible impairment during 2010, 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, approximately 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 properties and/or goodwill and have an impact on our depreciation, depletion and amortization expense prospectively. For example, a change of approximately 10 percent in our total oil and gas reserves could change our annual depreciation, depletion and amortization expense between approximately $72 million and $87 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, 2009, we have $681 million of deferred tax assets for which a $4 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. The ultimate disposition of these contingencies could have a significant impact on operating results and net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.

 

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

 

Pension and Postretirement Obligations

 

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

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

 

 

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

 

The capital markets improved in 2009 and the benefit plans’ assets reflect this improvement. While the 2009 investment performance was greater than our expected rates of return, the expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance. Changes to our asset allocation would also impact these expected rates of return. Our expected long-term rate of return on plan assets used for our pension plans has been 7.75 percent since 2006. The 2009 actual return on plan assets for our pension plans was a gain of approximately 21.8 percent. The ten-year average rate of return on pension plan assets through December 2009 was approximately 2.2 percent and is largely affected by the approximately 34.1 percent loss experienced in 2008.

 

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

 

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

 

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

Fair Value Measurements

 

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, 2009, less than 1 percent of the total assets and total liabilities measured at fair value on a recurring basis are included in Level 3. For Level 2 transactions, we do not make significant adjustments to observable prices in measuring fair value as we do not generally trade in inactive markets.

 

The determination of fair value for our assets and liabilities also incorporates the time value of money and various credit risk factors which can include the credit standing of the counterparties involved, master netting arrangements, the impact of credit enhancements (such as cash collateral posted and letters of credit) and our nonperformance risk on our liabilities. The determination of the fair value of our liabilities does not consider noncash collateral credit enhancements. For net derivative assets, we apply a credit spread, based on the credit rating of the counterparty, against the net derivative asset with that counterparty. For net derivative liabilities we apply our own credit rating. We derive the credit spreads by using the corporate industrial credit curves for each rating category and building a curve based on certain points in time for each rating category. The spread comes from the discount factor of the individual corporate curves versus the discount factor of the LIBOR curve. At December 31, 2009, the credit reserve is less than $1 million on our net derivative assets and $3 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.

 

At December 31, 2009, 82 percent of our derivatives portfolio expires in the next 12 months and more than 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 relatively short tenure of our derivatives portfolio, we do not believe it is necessary to make an adjustment for illiquidity. We regularly analyze the liquidity of the markets based on the prevalence of broker pricing and exchange pricing for products in our derivatives portfolio.

 

At December 31, 2009, Level 2 includes option contracts that hedge future sales of production from our Exploration & Production segment; these options are structured as costless collars and are financially settled. They are valued using an industry standard Black-Scholes option pricing model. Prior to the third quarter of 2009, these options were included in Level 3 because a significant input to the model, implied volatility by location, was considered unobservable. However, due to the increased transparency, we now consider this input to be observable and have included these options in Level 2.

 

The instruments included in Level 3 at December 31, 2009, consist of natural gas liquids swaps for our Midstream segment as well as natural gas index transactions that are used to manage the physical requirements of our Exploration & Production and Midstream segments. The change in the overall fair value of instruments included in Level 3 primarily results from changes in commodity prices.

 

Exploration & Production has an unsecured credit agreement through December 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.

 

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

Results of Operations

 

Consolidated Overview

 

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2009. The results of operations by segment are discussed in further detail following this consolidated overview discussion.