UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

Form 10-K

 

 

Commission file number 1-4174

The Williams Companies, Inc.

(Exact name of Registrant as Specified in Its Charter)

 

 

918-573-2000

(Registrant’s Telephone Number, Including Area Code)

 

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

 

 

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

5.50% Junior Subordinated Convertible Debentures due 2033

 

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

 

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

 

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

 

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

 

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

 

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, as of the last business day of the registrant’s most recently completed second quarter was approximately $18,963,794,420.

 

The number of shares outstanding of the registrant’s common stock outstanding at February 21, 2008 was 585,021,071.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

 

 

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.

 

 

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 450 Fifth Street, N.W., 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 Secretary at Williams, 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, and the Eastern Seaboard.

 

We continue to use 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.

 

Our goal is to create superior sustainable growth in EVA^® and shareholder value. In early 2006, we set some ambitious three-year goals referred to as our game plan for growth. Our success in achieving the game plan for growth contributed to our significant accomplishments in 2007 designed to increase shareholder value, including:

 

 

 

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

 

 

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

 

During third-quarter 2007, we formed Williams Pipeline Partners L.P. (WMZ) to own and operate natural gas transportation and storage assets. In January 2008, WMZ completed its initial public offering of 16.25 million common units at a price of $20.00 per unit. The underwriters also exercised their option to purchase an additional 1.65 million common units at the same price.

 

In December 2007, Williams Partners L.P. (WPZ) acquired certain of our membership interests in Wamsutter LLC, the limited liability company that owns the Wamsutter system, from us for $750 million.

 

In December 2007, we repurchased $213 million of 7.125 percent notes due September 2011 and $22 million of 8.125 percent notes due March 2012.

 

On November 28, 2007, Transcontinental Gas Pipe Line Corporation (Transco) filed a formal stipulation and agreement with the Federal Energy Regulatory Commission (FERC) resolving all substantive issues in Transco’s pending 2006 rate case. Final resolution of the rate case is subject to approval by the FERC.

 

On November 9, 2007, we closed on the sale of substantially all of our power business to Bear Energy, LP, a unit of The Bear Stearns Companies, Inc., for $496 million, subject to post-closing adjustments. The assets sold included tolling contracts, full requirements contracts, tolling resales, heat rate options, related hedges and other related assets including certain property and software. This sale reduces the risk and complexity of our overall business.

 

In November 2007, our credit ratings were raised to investment grade based on improvements in our credit outlook. As we continue to invest and grow our natural gas businesses, our improved credit rating is expected to provide greater access to capital and more favorable loan terms. See additional discussion of credit ratings in Management’s Discussion and Analysis of Financial Condition.

 

In July 2007, our Board of Directors authorized the repurchase of up to $1 billion of our common stock. We intend to purchase shares of our stock from time to time in open-market transactions or through privately negotiated or structured transactions at our discretion, subject to market conditions and other factors. This stock-repurchase program does not have an expiration date. During 2007, we repurchased approximately 16 million shares for $526 million (including transaction costs) at an average cost of $33.08 per share.

 

In April 2007, our Board of Directors approved a regular quarterly dividend of 10 cents per share, which reflects an increase of 11 percent compared to the 9 cents per share that we paid in each of the four prior quarters and marks the fourth increase in our dividend since late 2004.

 

On March 30, 2007, the FERC approved the stipulation and settlement agreement with respect to the rate case for Northwest Pipeline GP (Northwest Pipeline), formerly Northwest Pipeline Corporation.

 

See Note 17 of our Notes to Consolidated Financial Statements for information with respect to each segment’s revenues, profits or losses and total assets. See Note 9 for information with respect to property, plant and equipment for each segment.

 

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

 

 

This report is organized to reflect this structure.

 

Detailed discussion of each of our business segments follows.

 

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

 

Exploration & Production’s primary strategy is to utilize its expertise in the development of tight-sands, shale, and coal bed methane reserves. Exploration & Production’s current proved undeveloped and probable reserves provide us with strong capital investment opportunities for several years into the future. Exploration & Production’s goal is to drill its existing proved undeveloped reserves, which comprise approximately 46 percent of proved reserves and to drill in areas of probable reserves. In addition, Exploration & Production provides a significant amount of equity production that is gathered and/or processed by our Midstream facilities in the San Juan basin.

 

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

Gas reserves and wells

 

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

 

 

No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2007. We have not filed on a recurring basis estimates of our total proved net oil and gas reserves with any U.S. regulatory authority or agency other than the Department of Energy (DOE) and the SEC. The estimates furnished to the DOE have been consistent with those furnished to the SEC, although Exploration & Production has not yet filed any information with respect to its estimated total reserves at December 31, 2007, with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable due to special DOE reporting requirements, such as the requirement to report gross operated reserves only. In 2006 and 2005 the underlying estimated reserves for the DOE did not differ by more than five percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC.

 

Approximately 98 percent of our year-end 2007 United States proved reserves estimates were audited in each separate basin by Netherland, Sewell & Associates, Inc. (NSAI). When compared on a well-by-well basis, some of our estimates are greater and some are less than the estimates of NSAI. However, in the opinion of NSAI, the estimates of our proved reserves are in the aggregate reasonable by basin and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. NSAI is satisfied with our methods and procedures in preparing the December 31, 2007 reserve estimates and saw nothing of an unusual nature that would cause NSAI to take exception with the estimates, in the aggregate, as prepared by us. Reserve estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, which comprise approximately two percent of our total U.S. proved reserves, were prepared by Miller and Lents, LTD.

 

On December 12, 2007, the SEC issued a “Concept Release” to obtain information about the extent and nature of the public’s interest in revising oil and gas reserves disclosure requirements which exist in their current form in Regulation S-K and Regulation S-X under the Securities Act of 1933 and the Securities Exchange Act of 1934. The Commission adopted the current oil and gas reserves disclosure requirement between 1978 and 1982. The Concept Release is intended to address significant changes in the oil and gas industry. Some commentators have expressed concern that the Commission’s rules have not adapted to current practices and may not provide investors with the most useful picture of oil and gas reserves public companies hold. Comments were due to the Commission on February 19, 2008. At this time it is not possible to determine what effect changes the SEC may make, if any, will have on our reserve estimates and disclosures.

Oil and gas properties and reserves by basin

 

The table below summarizes 2007 activity and reserves for each of our areas, with further discussion following the table.

 

 

Piceance basin

 

The Piceance basin is located in northwestern Colorado and is our largest area of concentrated development. During 2007 we operated an average of 25 drilling rigs in the basin. As of December 2007, 14 of these rigs were the new high efficiency rigs designed to drill up to 22 wells from one location. This area has approximately 1,760 undrilled proved locations in inventory. Within this basin we own and operate natural gas gathering facilities including some 280 miles of gathering lines and associated field compression. Approximately 88% of the gas gathered is our own equity production. The gathering system also includes six processing plants and associated treating facilities with a total capacity of 900,000 Mcfd. During 2007, these plants recovered approximately 54 million gallons of natural gas liquids (NGL’s) which were marketed separately from the residue natural gas.

 

San Juan basin

 

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

 

Powder River basin

 

The Powder River basin is located in northeast Wyoming. The Powder River basin includes large areas with multiple coal seam potential, targeting thick coal bed methane formations at shallow depths. We have a significant inventory of undrilled locations, providing long-term drilling opportunities.

 

Mid-Continent properties

 

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

 

Other properties

 

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

 

The following table summarizes our leased acreage as of December 31, 2007:

 

Operating statistics

 

We focus on lower-risk development drilling. Our drilling success rate was 99 percent in 2007, 2006 and 2005. The following tables summarize domestic drilling activity by number and type of well for the periods indicated:

 

 

Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. In February 2007, we entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging with the banks and on natural gas reserves value. Exploration & Production natural gas hedges for 2008 domestic natural gas production consist of NYMEX fixed price contracts of 70 MMcf/d (whole year) and approximately 397 MMcf/d in regional collars (whole year). Our natural gas production hedges in 2007 consisted of 172 MMcf/d in NYMEX fixed price hedges and an additional 271 MMcf/d in NYMEX and basin level collars. A collar is an option contract that sets a gas price floor and ceiling for a certain volume of natural gas. Hedging decisions are made considering the overall Williams commodity risk exposure and are not executed independently by Exploration & Production; there are expected future gas purchases for other Williams entities which when taken as a net position may offset price risk related to Exploration & Production’s expected future gas sales.

 

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

 

 

Acquisitions & divestitures

 

Through transactions totaling approximately $77 million, Exploration & Production expanded its acreage position and purchased producing properties in the Fort Worth basin in north-central Texas and also expanded its acreage position in the Highlands area of the Piceance basin.

 

In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production in Peru for approximately $148 million. We have received $118 million in cash and $29 million has been placed in escrow subject to certain post-closing conditions and adjustments. We will recognize a pre-tax gain of approximately $118 million in the first quarter of 2008 related to the initial cash received. As a result of the contract termination, we have no further interests associated with the crude oil concession. We had obtained these interests through our acquisition of Barrett Resources Corporation in 2001.

Other information

 

In 1993, Exploration & Production conveyed a net profits interest in certain of its properties to the Williams Coal Seam Gas Royalty Trust. Substantially all of the production attributable to the properties conveyed to the trust was from the Fruitland coal formation and constituted coal seam gas. We subsequently sold trust units to the public in an underwritten public offering and retained 3,568,791 trust units then representing 36.8 percent of outstanding trust units. We have previously sold trust units on the open market, with our last sales in June 2005. As of February 1, 2008, we own 789,291 trust units.

 

International exploration and production interests

 

We also have investments in international oil and gas interests. If combined with our domestic proved reserves, our international interests would make up approximately 3.6 percent of our total proved reserves.

 

We own and operate, through Williams Gas Pipeline Company, LLC (WMZ) and its subsidiaries, a combined total of approximately 14,200 miles of pipelines with a total annual throughput of approximately 2,700 trillion British Thermal Units of natural gas and peak-day delivery capacity of approximately 12 MMdt of gas. Gas Pipeline consists of Transcontinental Gas Pipe Line Corporation and Northwest Pipeline GP. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream Natural Gas System, L.L.C. Gas Pipeline also includes our new master limited partnership, Williams Pipeline Partners, L.P.

 

Transcontinental Gas Pipe Line Corporation (Transco)

 

Transco is an interstate natural gas transportation company that owns and operates a 10,300-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, New York, New Jersey, and Pennsylvania.

 

Pipeline system and customers

 

At December 31, 2007, 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 3.7 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.4 MMdt of natural gas per day. Transco’s system includes 45 compressor stations, five underground storage fields, two liquefied natural gas (LNG) storage facilities. Compression facilities at a 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 12 percent of Transco’s total revenues in 2007. 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 five underground storage fields located on or near its pipeline system or market areas and operates three of these storage fields. Transco also has storage capacity in an LNG storage facility and operates the facility. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 216 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, an 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 2007 or are future pipeline projects for which we have customer commitments.

 

Potomac Expansion Project

 

In November 2007, we placed into service the Potomac Expansion Project, an expansion of our existing natural gas transmission system from receipt points in North Carolina to delivery points in the greater Baltimore and Washington, D.C. metropolitan areas. The second phase of the project involving installation of certain appurtenant facilities will be completed in fall 2008. The capital cost of the project is estimated to be approximately $88 million.

 

Leidy to Long Island Expansion Project

 

In December 2007, we placed into service the Leidy to Long Island Expansion Project, an expansion of our existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The capital cost of the project is estimated to be approximately $169 million.

 

Sentinel Expansion Project

 

The Sentinel Expansion Project will involve an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $169 million. Transco plans to place the project into service in phases, in late 2008 and late 2009.

 

Pascagoula Expansion Project

 

The Pascagoula Expansion Project will involve the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting Transco’s existing Mobile Bay Lateral to the outlet pipeline of a proposed liquefied natural gas import terminal in Mississippi. Transco’s share of the estimated capital cost of the project is up to $37 million. Transco plans to place the project into service in mid-2011.

 

Operating statistics

 

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

 

 

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

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

 

Northwest Pipeline GP (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, 2007, Northwest Pipeline’s system, having long-term firm transportation agreements with peaking capacity of approximately 3.4 MMdt 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.

 

Northwest implemented new rates effective January 1, 2007 that were approved by FERC. The rate case settlement established that general system firm transportation rates on Northwest’s system increased from $0.30760 to $0.40984 per Dth.

 

In 2007, Northwest Pipeline served a total of 132 transportation and storage customers. Transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. The two largest customers of Northwest Pipeline in 2007 accounted for approximately 20 percent and 11.5 percent, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2007. Northwest Pipeline’s firm transportation agreements are generally long-term agreements 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 600 million cubic feet of gas per day.

 

Northwest Pipeline expansion projects

 

The pipeline projects listed below were completed during 2007 or are future pipeline projects for which we have customer commitments.

 

Jackson Prairie Underground Expansion

 

The Jackson Prairie Storage Project, connected to Northwest’s transmission system near Chehalis, Washington, is operated by Puget Sound Energy and is jointly owned by Northwest, Puget Sound Energy and Avista Corporation. A phased capacity expansion is currently underway and a deliverability expansion is planned for 2008. Northwest’s one-third interest in the project includes 104 MMcf per day of planned 2008 deliverability expansion and approximately 1.2 Bcf of working natural gas storage capacity to be developed over approximately a four year period from 2007 through 2010. Northwest’s one-third share of the cost of the deliverability expansion is estimated to be $16 million. Northwest’s estimated capital cost for the capacity expansion component of the new storage service is $6.1 million, primarily for base natural gas.

 

Colorado Hub Connection Project

 

Northwest has proposed installing a new lateral to connect the White River Hub near Meeker, Colorado to Northwest’s mainline near Sand Springs, Colorado. This project is referred to as the Colorado Hub

Connection, or CHC Project. It is estimated that the construction of the CHC Project would cost up to $53 million and could begin service as early as November 2009.

 

Parachute Lateral

 

Northwest placed its Parachute Lateral facilities in service on May 16, 2007, and began collecting revenues of approximately $0.87 million per month. The expansion increased capacity by 450 Mdt/d at a cost of approximately $86 million.

 

On August 24, 2007, Northwest filed an application with FERC to amend its certificate of public convenience and necessity issued for the Parachute Lateral to allow the transfer of the ownership of its Parachute Lateral facilities to a newly created entity, Parachute Pipeline LLC (Parachute), which is owned by Midstream through one of its wholly-owned subsidiaries Williams Field Services Company, LLC (Williams Field Services). This application was approved by FERC on November 15, 2007, and Northwest sold the Parachute on December 31, 2007. The Parachute Lateral facilities are located in Rio Blanco and Garfield counties, Colorado.

 

As contemplated in the application for amendment, Parachute has leased the facilities back to Northwest, and as a result of the sale has become a Midstream subsidiary. Northwest will continue to operate the facilities under the FERC certificate. When Midstream completes its Willow Creek Processing Plant, the lease (subject to further regulatory approval) will terminate, and Parachute will assume full operational control and responsibility for the Parachute Lateral.

 

Operating statistics

 

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

 

 

 

 

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

 

Gulfstream is a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. Gas Pipeline and Spectra Energy (formerly known as Duke Energy), through their respective subsidiaries, each holds a 50 percent ownership interest in Gulfstream and provides operating services for Gulfstream. At December 31, 2007, our equity investment in Gulfstream was $439 million.

 

Gulfstream expansion projects

 

Gulfstream has entered into a precedent agreement and a related firm transportation service agreement pursuant to which, subject to the receipt of all necessary regulatory approvals and other conditions precedent therein, Gulfstream intends to extend the pipeline system into South Florida and fully subscribe the remaining 345 Mdt/d of firm capacity on the existing pipeline system on a long-term basis. The estimated capital cost of this project is anticipated to be up to approximately $130 million, with Gas Pipeline’s share being 50 percent of such costs. Gulfstream also has executed a precedent agreement and a related firm transportation service agreement pursuant to which, subject to the receipt of all necessary regulatory approvals and other conditions precedent therein, it intends to construct and fully subscribe on a long-term basis the first incremental expansion of

Gulfstream’s mainline capacity, increasing the current mainline capacity of 1.1 MMdt/d to 1.255 MMdt/d. The estimated capital cost of this expansion is anticipated to be up to approximately $153 million, with Gas Pipeline’s share being 50 percent of such costs. No significant increase in operations personnel is expected as a result of these two projects.

 

Williams Pipeline Partners L.P

 

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

 

 

Our Midstream segment, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in the major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, Venezuela and western Canada. Midstream’s primary businesses — natural gas gathering, treating, and processing; NGL fractionation, storage and transportation; and oil transportation — fall within the middle of the process of taking natural gas and crude oil from the wellhead to the consumer. NGLs, ethylene and propylene are extracted/produced at our plants, including our Canadian and Gulf Coast olefins plants. These products are used primarily for the manufacture of plastics, home heating and refinery feedstock.

 

Although most of our gas services are performed for a volumetric-based fee, a portion of our gas processing contracts are commodity-based and include two distinct types of commodity exposure. The first type includes “Keep Whole” processing contracts 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 contracts, we are exposed to the spread between NGLs and natural gas prices. The second type consists of “Percent of Liquids” contracts whereby we receive a portion of the extracted liquids with no direct exposure to the price of natural gas. Under these contracts, we are only exposed to NGL price movements.

 

Our Canadian and Gulf Liquids olefin facilities have commodity price exposure. In Canada, we are exposed to the spread between the price for natural gas and the olefinic products we produce. In the Gulf Coast, 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. In the Gulf Coast, we also 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.

 

Key variables for our business will continue to be:

 

 

Gathering and processing

 

We own and/or operate domestic gas gathering and processing assets primarily within the western states of Wyoming, Colorado and New Mexico, and the onshore and offshore shelf and deepwater areas in and around the Gulf Coast states of Texas, Louisiana, Mississippi and Alabama. These assets consist of approximately 8,700 miles of gathering pipelines, nine processing plants (one partially owned) and five natural gas treating plants with a combined daily inlet capacity of nearly 6.5 billion cubic feet per day. Some of these assets are owned through our interest in WPZ (see William Partners L.P. section below).

Geographically, our Midstream natural gas assets are positioned to maximize commercial and operational synergies with our other assets. For example, most of our offshore gathering and processing assets attach and process or condition natural gas supplies delivered to the Transco pipeline. Also, our gathering and processing facilities in the San Juan Basin handle about 85 percent of our Exploration & Production group’s wellhead production in this basin. Both our San Juan Basin and Southwest Wyoming systems deliver gas volumes into Northwest Pipeline’s interstate system in addition to third party interstate systems.

 

Included in the natural gas assets listed above are the assets of Discovery Producer Services LLC and its subsidiary Discovery Gas Transmission Services LLC (Discovery). WPZ owns a partial interest in Discovery and we operate its facilities. Discovery’s assets include a cryogenic natural gas processing plant near Larose, Louisiana, a natural gas liquids fractionator plant near Paradis, Louisiana and an offshore natural gas gathering and transportation system in the Gulf of Mexico.

 

In addition to these natural gas assets, we own and operate three crude oil pipelines totaling approximately 310 miles with a capacity of more than 300,000 barrels per day. This includes our Mountaineer, Alpine and BANJO crude oil pipeline systems in the deepwater Gulf of Mexico.

 

The BANJO oil pipeline and Seahawk gas pipeline run parallel and deliver production across two producer-owned spar-type floating production systems from the Anadarko Petroleum Corporation (Anadarko) operated Boomvang and Nansen field areas in the western Gulf of Mexico. These pipelines were placed in service in 2002.

 

Our 18 inch oil pipeline, Alpine, which became operational in 2003, is our second western gulf crude oil pipeline. The pipeline extends 96 miles from Garden Banks Block 668 in the central Gulf of Mexico to our shallow-water platform at Galveston Area Block A244. From this platform, the oil is delivered onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System under a joint tariff agreement. This production is coming from the Gunnison field, which is located in 3,150 feet of water and operated by Anadarko.

 

Our Devils Tower floating production system and associated pipelines were placed in service in 2004. Initially built to serve the Devils Tower field, the floating production system is located in Mississippi Canyon Block 773, approximately 150 miles south-southwest of Mobile, Alabama. During the fourth quarter of 2005, the platform’s service expanded to include tie-backs of production from the Triton and Goldfinger fields in addition to the host Devils Tower field. Construction is currently underway to add topside capacity for the recently dedicated Bass Lite gas discovery. Full field production from Bass Lite is expected mid-year 2008. Located in 5,610 feet of water, it is the world’s deepest dry tree spar. The platform, which is operated by ENI Petroleum on our behalf, is capable of producing 60 MMcf/d of natural gas and 60 Mbbls/d of oil.

 

The Devils Tower project includes gas and oil pipelines. The 139-mile Canyon Chief gas pipeline consists of 18-inch diameter pipe. The 155-mile Mountaineer oil pipeline is a combination of 18- and 20-inch diameter pipe. The gas is delivered into Transco’s pipeline, and processed at our Mobile Bay plant to recover the NGLs. The oil is transported to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana. These associated pipelines are significantly oversized relative to the Devils Tower spar top-side capacity.

 

Gulf Coast petrochemical and olefins

 

We own a 10/12 interest in and are the operator for an ethane cracker at Geismar, Louisiana, with a total production capacity of 1.3 billion pounds per year of ethylene. In July 2007, we exercised our right of first refusal to acquire BASF’s 5/12^th ownership interest in the Geismar olefins facility bringing our ownership position up to the current 10/12 interest. We also own an ethane pipeline system and a propylene splitter and its related pipeline system in Louisiana.

 

Canada

 

Our Canadian operations include an olefin liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. Our facilities extract olefinic liquids from the off-gas produced from third party oil sands bitumen upgrading and then fractionate, treat, store, terminal and sell the propane, propylene, butane and condensate recovered from this process. We continue to be the only olefins fractionator in Western Canada and the only treater-processor of oil sands upgrader off-gas. These operations extract valuable

petrochemical feedstocks from upgrader off-gas streams allowing the upgraders to burn cleaner natural gas streams and reduce overall air emissions. The extraction plant has processing capacity in excess of 100 MMcf/d with the ability to recover in excess of 15 Mbbls/d of olefin and NGL products.

 

Venezuela

 

Our Venezuelan investments involve gas compression and gas processing and natural gas liquids fractionation operations. We own controlling interests and operate three gas compressor facilities which provide roughly 70 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas at high pressures. We also own a 49.25 percent interest in two 400 MMcf/d natural gas liquids extraction plants, a 50,000 barrels per day natural gas liquids fractionation plant and associated storage and refrigeration facilities.

 

Other

 

We own interests in and/or operate NGL fractionation and storage assets. These assets include two partially owned NGL fractionation facilities near Conway, Kansas and Baton Rouge, Louisiana that have a combined capacity in excess of 167,000 barrels per day. We also own approximately 20 million barrels of NGL storage capacity in central Kansas. Some of these assets are owned through our interest in WPZ.

 

We also own a 14.6% interest in Aux Sable Liquid Products and its Channahon, Illinois gas processing and NGL fractionation facility near Chicago. The facility is capable of processing up to 2.1 Bcf/d of natural gas from the Alliance Pipeline system and fractionating approximately 87,000 barrels per day of extracted liquids into NGL products.

 

Williams Partners L.P (WPZ)

 

WPZ was formed to engage in the business of gathering, transporting and processing natural gas and fractionating and storing NGLs. We currently own approximately a 21.6 percent limited partnership interest and a 2 percent general partner interest in WPZ. WPZ provides us with lower cost of capital that is expected to enable growth of our Midstream business. 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.

 

WPZ’s asset portfolio at its initial public offering in 2005 consisted of a 40 percent interest in Discovery, the Carbonate Trend gathering pipeline, three integrated NGL storage facilities near Conway, Kansas and a 50 percent interest in an NGL fractionator near Conway, Kansas.

 

During 2006, WPZ acquired Williams Four Corners, LLC which owns a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with capacity of nearly 2 Bcf/d; the Ignacio natural gas processing plant in Colorado and the Kutz and Lybrook natural gas processing plants in New Mexico, which have a combined processing capacity of 760 MMcf/d; and the Milagro and Esperanza natural gas treating plants in New Mexico, which are designed to remove carbon dioxide from up to 750 MMcf of natural gas per day.

 

In June 2007, WPZ acquired an additional 20 percent interest in Discovery. WPZ now owns a 60 percent interest in the Discovery gathering, transportation, processing and NGL fractionation system, the remainder of which is owned by third parties.

 

In December 2007, WPZ acquired certain ownership interests in Wamsutter LLC from us for $750 million. Wamsutter LLC owns a 1,700 mile natural gas gathering system in the Washakie Basin in south-central Wyoming and the Echo Springs natural gas processing plant in Sweetwater County, Wyoming.

 

Expansion projects

 

Gathering and processing — west

 

During the first quarter of 2007, we completed construction at our existing gas processing complex located near Opal, Wyoming, to add a fifth cryogenic gas processing train capable of processing up to 350 MMcf/d,

bringing total Opal capacity to approximately 1.5 Bcf/d. This plant expansion increased Opal’s processing capacity by more than 30 percent and became operational during the first quarter.

 

In the first quarter of 2007, we also announced plans to construct and operate the Willow Creek facility a 450 MMcf/d natural gas processing plant in the Piceance Basin of western Colorado, where Exploration and Production has its most significant volume of natural gas production, reserves and development activity. Exploration and Production’s existing Piceance Basin processing plants are primarily designed to condition the natural gas to meet quality specifications for pipeline transmission, not to maximize the extraction of NGLs. We expect the new Willow Creek facility to recover 25,000 barrels per day of NGLs at startup, which is expected to be in the third quarter of 2009.

 

In December 2007, Midstream purchased the Parachute Lateral system from Gas Pipeline. The system is a 37.6-mile expansion, originally placed in service by Gas Pipelines in May 2007, and provides capacity of 450 Mdt/d through a 30-inch diameter line, transporting residue gas from the Piceance basin to the Greasewood Hub in northwest Colorado. The Willow Creek facility will straddle the Parachute Lateral pipeline and will process gas flowing through the pipeline. In an arrangement approved by the FERC, Midstream will lease the pipeline to Gas Pipeline, who will continue to operate the pipeline until completion of a planned FERC abandonment filing.

 

In addition, Midstream acquired an existing natural gas pipeline from Gas Pipeline, and has begun the process of converting it from natural gas to NGL service and constructing additional pipeline to create a pipeline alternative for NGLs currently being transported by truck from Exploration & Production’s existing Piceance basin processing plants to a major NGL transportation pipeline system.

 

In 2006, we entered into an agreement to develop new pipeline capacity for transporting NGLs from production areas in southwestern Wyoming to central Kansas. The other party to the agreement reimbursed us for the development costs we had incurred for the proposed pipeline and acquired 99 percent of the pipeline, known as Overland Pass Pipeline Company, LLC. We retained a 1 percent interest and have the option to increase our ownership to 50 percent and become the operator within two years of the pipeline becoming operational. Start-up is planned for mid-2008. Additionally, we have agreed to dedicate our equity NGL volumes from our two Wyoming plants and the new Willow Creek facility for transport under a long-term shipping agreement. The terms represent significant savings compared with the existing tariff and other alternatives considered.

 

Gathering and processing — deepwater projects

 

The deepwater Gulf continues to be an attractive growth area for our Midstream business. Since 1997, we have invested almost $1.3 billion in new midstream assets in the Gulf of Mexico. These facilities provide both onshore and offshore services through pipelines, platforms and processing plants. The new facilities could also attract incremental gas volumes to Transco’s pipeline system in the southeastern United States.

 

During 2007, we have continued construction activities on the Perdido Norte project which includes oil and gas lines that would expand the scale of our existing infrastructure in the western deepwater of the Gulf of Mexico. In addition, we completed agreements with certain producers to provide gathering, processing and transportation services over the life of the reserves. We also intend to expand our onshore Markham gas processing facility to adequately serve this new gas production. The scale of the project has increased to include additional pipeline and more efficient processing capacity and is now estimated to cost approximately $560 million and to be in service in the third quarter of 2009.

 

Chevron and Anadarko are dedicating to us the transport of production from their current and future ownership in a defined area surrounding the Blind Faith discovery in the deepwater Gulf of Mexico. To accommodate production from the Blind Faith acreage and the surrounding blocks, we have agreed to extend our Canyon Chief and Mountaineer pipelines to the producer-owned floating production facility. We expect to have the extensions ready for service in the second quarter of 2008. The approximately $250 million project will facilitate a 37-mile extension of each pipeline. The agreement also creates opportunities for us to move natural gas from the Blind Faith discovery through our Mobile Bay, Alabama, processing plant and our Transco and Gulfstream interstate pipeline systems. Recovered NGLs from Blind Faith also could be fractionated at our facilities in Baton Rouge or Paradis, Louisiana.

Customers and operations

 

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 2007, these operations gathered and processed gas for approximately 215 gas gathering and processing customers. Our top three gathering and processing customers accounted for about 45 percent of our domestic gathering and processing revenue. Our gathering and processing agreements are generally long-term agreements.

 

In addition to our gathering and processing operations, we market NGLs and petrochemical products to a wide range of users in the energy and petrochemical industries. We provide these products to third parties from the production at our domestic facilities. The majority of domestic sales are based on supply contracts of less than one year in duration. The production from our Canadian facilities is marketed in Canada and in the United States.

 

Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of Petróleos de Venezuela S.A under long-term contracts. These significant contracts have a remaining term between 10 and 14 years and our revenues are based on a combination of fixed capital payments, throughput volumes, and, in the case of one of the gas compression facilities, a minimum throughput guarantee. The Venezuelan government has continued its public criticism of U.S. economic and political policy, has implemented unilateral changes to existing energy related contracts, and continues to publicly declare that additional energy contracts will be unilaterally amended and privately held assets will be expropriated, escalating our concern regarding political risk in Venezuela.

 

Operating statistics

 

The following table summarizes our significant operating statistics for Midstream:

 

 

 

 

Gas Marketing Services 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 fuel and shrink gas and hedging natural gas liquids sales for Midstream. In addition, Gas Marketing manages various natural gas-related contracts such as transportation, storage, and related hedges, and provides services to third-parties, such as producers.

 

Gas Marketing Services’ natural gas sales volumes, including sales volumes to other segments, were 2.3 Bcf/d, 2.1 Bcf/d and 2.1 Bcf/d for the years ending December 31, 2007, 2006 and 2005, respectively. Gas Marketing Services’ natural gas purchase volumes, including purchases from other segments, were 2.4 Bcf/d, 2.3 Bcf/d and 2.2 Bcf/d for the same periods.

 

As of December 31, 2007, Gas Marketing Services has approximately 159 customers compared with approximately 163 customers at the end of 2006.

 

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

As a result of the sale of a substantial portion of our Power business in the fourth quarter of 2007, Gas Marketing Services also is responsible for certain remaining legacy natural gas contracts and positions. We intend to liquidate a substantial portion of these legacy contracts. During 2007, we substantially reduced the overall legacy positions remaining. Until such legacy positions are liquidated, segment results may experience mark- to-market volatility from commodity-based derivatives that represent economic hedges but are not designated as hedges for accounting purposes or do not qualify for hedge accounting. However, this mark-to-market volatility is expected to be significantly reduced compared to previous levels.

 

At December 31, 2007, we owned approximately 99.3 percent of the Class B Interests in Longhorn Partners Pipeline LP (Longhorn), which owned a refined petroleum products pipeline from Houston, Texas to El Paso, Texas. The Class B Interests are preferred interests but subordinate to other preferred interests, and the common interests are subordinate to both. It is uncertain whether we will ever receive any payments related to our Class B Interests or our common interests, however any such amounts related to these interests were fully impaired in 2005, and will only be recognized as income when received.

 

We continue to receive payments associated with the 2005 transfer of the First Amended and Restated Pipeline Operating Services Agreement to a third party. The management of Longhorn completed an installment sale of the pipeline during the third quarter of 2006. The sale of the pipeline did not impact these ongoing payments which are recognized as income when received.

 

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.

 

Our corporate parent company performs certain management, legal, financial, tax, consultative, information technology, administrative and other services for our subsidiaries.

 

Our corporate parent company’s principal sources of cash are from external financings, dividends and advances from our subsidiaries, investments, payments by subsidiaries for services rendered, sales of master partnership units to the public, interest payments from subsidiaries on cash advances 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 our corporate parent.

 

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, 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 their marketing affiliates. Among other things, the Standards of Conduct require that interstate pipelines not operate their systems to preferentially benefit their marketing affiliates.

 

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

 

 

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

 

Midstream.  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 gathering facilities located offshore are not subject to the NGA (although offshore transmission pipelines may be), some controversy exists as to how the FERC should determine whether offshore facilities function as gathering. These issues are currently before the FERC. Most gathering facilities offshore are subject to the OCSLA, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and non-owner shippers.”

 

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

 

Our remaining Midstream Canadian assets are regulated by the Alberta Energy & Utilities Board (AEUB) and Alberta Environment. The regulatory system for the Alberta oil and gas industry incorporates a large measure of self-regulation, providing that licensed operators are held responsible for ensuring that their operations are conducted in accordance with all provincial regulatory requirements. For situations in which non-compliance with the applicable regulations is at issue, the AEUB 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 15 of our Notes to Consolidated Financial Statements for further details on our regulatory matters.

 

Our generation facilities, processing facilities, natural gas pipelines, and exploration and production operations are subject to federal environmental laws and regulations as well as the state and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil, or water, as well as liability for clean up costs. Materials could be released into the environment in several ways including, but not limited to:

 

 

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

 

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

 

For a discussion of specific environmental issues, see “Environmental” under Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Environmental Matters” in Note 15 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.

 

Several states are considering re-regulation and extending price caps because many regulators and legislators believe that deregulation has not worked. 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.  In our Midstream segment, we face regional competition with varying competitive factors in each basin. Our gathering and processing business competes with other midstream companies, interstate and intrastate pipelines, producers and independent gatherers and processors. We primarily compete with five to ten companies across all basins in which we provide services. Numerous factors impact any given customer’s choice of a gathering or processing services provider, including rate, location, term, timeliness of services to be provided, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees. In 2005 we formed WPZ to help compete against other master limited partnerships for midstream projects. By virtue of the master limited partnership structure, WPZ provides us with an alternative and low-cost source of capital. We expect the alternative, low-cost capital will allow WPZ to compete favorably from a cost of capital perspective with other MLPs when pursuing acquisition opportunities of gathering and processing assets.

 

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, 2008, we had approximately 4,319 full-time employees including 898 at the corporate level, 681 at Exploration & Production, 1,732 at Gas Pipeline, 984 at Midstream, and 24 at Gas Marketing Services. None of our employees are represented by unions or covered by collective bargaining agreements.

 

See Note 17 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 17 of our Notes to Consolidated Financial Statements for information relating to long-lived assets during the last three fiscal years, located in the United States and all foreign countries.

 

 

FORWARD-LOOKING STATEMENTS/RISK FACTORS AND CAUTIONARY STATEMENT
FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

 

Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements discuss our expected future results based on current and pending business operations. We make those 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 which address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:

 

 

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

 

 

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list 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 include the following:

 

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

 

Risks Inherent to our Industry and Business

 

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

 

The development of the additional natural gas reserves that are essential for our gas transportation and midstream businesses to thrive requires significant capital expenditures by others for exploration and development drilling and the installation of production, gathering, storage, transportation and other facilities that permit natural gas to be produced and delivered to our pipeline systems. Low prices for natural gas, regulatory limitations, or the lack of available capital for these projects could adversely affect the development and production of additional reserves, as well as gathering, storage, pipeline transportation and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transportation and processing facilities. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our gathering and transportation facilities.

 

Estimating reserves and future net revenues involves uncertainties. Negative revisions to reserve estimates and oil and gas price declines 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 over time.

 

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. The revisions may also be sufficient to trigger impairment losses on certain properties which would result in a further non-cash charge to earnings. The revisions could also possibly affect the evaluation of Exploration & Production’s goodwill for impairment purposes.

Our past success rate for drilling projects and the historic performance of our exploration and production business is no predictor of future performance.

 

Our past success rate for drilling projects in 2007 should not be considered a predictor of future performance.

 

Performance of our exploration and production business is affected in part by factors beyond our control (any of which could cause the results of this business to decrease materially), such as:

 

 

Our drilling, production, gathering, processing 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:

 

 

In addition, there are inherent in our gas gathering, processing and transporting properties a variety of hazards and operating risks, such as leaks, spills, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, 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 could cause considerable harm to people or property, and could have a material adverse effect on our financial condition, 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 could materially impact our ability to meet contractual obligations and retain customers, with a resulting impact on our results of operations.

 

Costs of environmental liabilities and complying with existing and future environmental regulations could exceed our current expectations.

 

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

various substances into the environment, and in connection with the operation, maintenance, abandonment and reclamation of our facilities.

 

Compliance with environmental laws requires significant expenditures, including for clean up costs and damages arising out of contaminated properties. In addition, the possible failure to comply with environmental laws and regulations might result in the imposition of fines and penalties. We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses. Although we do not expect that the costs of complying with current environmental laws will have a material adverse effect on our financial condition or results of operations, no assurance can be given that the costs of complying with environmental laws in the future will not have such an effect.

 

Changes in federal laws or regulations could reduce the availability or increase the cost of our interstate pipeline capacity or gas supply, and thereby reduce our earnings. Congress and certain states have for some time been considering various forms of legislation related to greenhouse gas emissions. There is a possibility that, when and if enacted, the final form of such legislation could increase our costs of compliance with environmental laws.

 

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.

 

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 the Current Geopolitical Situation

 

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

 

We currently own and might acquire and/or dispose of material energy-related investments and projects outside the United States. The economic and political conditions in certain countries where we have interests or in which we might explore development, acquisition or investment opportunities present risks of delays in construction and interruption of business, as well as risks of war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States. The uncertainty of the legal environment in certain foreign countries in which we develop or acquire

projects or make investments could make it more difficult to obtain non-recourse project financing or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments. Recent events in certain South American countries, particularly the continued threat of nationalization of certain energy-related assets in Venezuela, could have a material negative impact on our results of operations. We may not receive adequate compensation, or any compensation, if our assets in Venezuela are nationalized.

 

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

 

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, sell assets, make certain distributions, repurchase equity and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.

 

Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.

 

A downgrade of our current credit ratings could impact our costs of doing business in certain ways and maintaining current credit ratings is within the control of independent third parties.

 

A downgrade of our credit rating might increase our cost of borrowing. Our ability to access capital markets could also be limited by a downgrade of our credit rating and other disruptions. Such disruptions could include:

 

 

Credit rating agencies perform independent analysis when assigning credit ratings. Given the significant changes in capital markets and the energy industry over the last few years, credit rating agencies continue to review the criteria for attaining investment grade ratings and make changes to those criteria from time to time. Our corporate family credit rating and the credit ratings of Transco and Northwest Pipeline were raised to investment

grade in 2007 by Standard & Poor’s, Moody’s Corporation, and Fitch Ratings, Ltd., and our senior unsecured debt ratings were raised to investment grade by Moody’s and Fitch. No assurance can be given that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios or that our senior unsecured debt rating will be raised to investment grade by all of the credit rating agencies.

 

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

 

Our revenues, operating results, future rate of growth and the value of certain segments of our businesses depend primarily upon the prices we receive for natural gas liquids, natural gas, or other commodities, and the differences between prices of these commodities. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.

 

The markets for natural gas liquids, 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 consists of wholesale contracts to buy and sell commodities, including contracts for natural gas, natural gas liquids 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.

 

If we are unable to perform under our energy agreements, we could be required to pay damages. These damages generally would be based on the difference between the market price to acquire replacement energy or energy services and the relevant contract price. Depending on price volatility in the wholesale energy markets, such damages could be significant.

 

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 Natural Gas Act of 1938 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.

 

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.

 

Expiration of firm transportation agreements.

 

A substantial portion of the operating revenues of our Gas Pipelines are generated through firm transportation agreements that expire periodically and must be renegotiated and extended or replaced. We cannot give any assurance as to whether any of these agreements will be extended or replaced or that the terms of any renegotiated agreements will be as favorable as the existing agreements. Upon the expiration of these agreements, should customers turn back or substantially reduce their commitments, we could experience a negative effect to our results of operations.

Our revenues might decrease if we are unable to gain adequate, reliable and affordable access to transportation and distribution assets.

 

We depend on transportation and distribution facilities owned and operated by utilities and other energy companies to deliver the commodities we buy and sell in the wholesale market. If transportation is disrupted, if capacity is inadequate, or if credit requirements or rates of such utilities or energy companies are increased, our ability to sell and deliver products might be hindered. 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.

 

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. Over the past few years, certain restructured energy markets have experienced supply problems and price volatility. In some of these markets, proposals have been made by governmental agencies and other interested parties to re-regulate areas of these markets which have previously been deregulated. Various forms of market controls and limitations including price caps and bid caps have already been implemented and new controls and market restructuring proposals are in various stages of development, consideration and implementation. We cannot assure you that changes in market structure and regulation will not adversely affect our business and results of operations. We also cannot assure you that other proposals to re-regulate will not be made or that legislative or other attention to these restructured energy markets will not cause the deregulation process to be delayed or reversed or otherwise adversely affect our business and results of operations.

 

The outcome of a pending rate case to set the rates we can charge customers on Transco’s pipeline might result in rates that do not provide an adequate return on the capital we have invested in the Transco pipeline.

 

We have a pending rate case with the FERC to request changes to the rates we charge on Transco. We have sought FERC approval of a settlement of the significant issues in the rate case but until FERC approves the settlement, the outcome of the rate case remains uncertain. There is a risk that rates set by the FERC will lower our return on the capital we have invested in our assets or might not be adequate to recover increases in operating costs. There is also the risk that higher rates will cause our customers to look for alternative ways to transport their natural gas.

 

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

 

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

 

Certain inquiries, investigations and court proceedings are ongoing and continue to adversely affect our business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries and proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our revenues and net income or increase our operating costs in other ways. Current legal proceedings or other matters against us arising out of our ongoing and discontinued operations including environmental matters, disputes over gas measurement, royalty payments, shareholder class action suits, regulatory appeals and similar matters might result in adverse decisions

against us. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

 

Risks Related to Accounting Standards

 

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.

 

Risks Related to Market Volatility and Risk Measurement and Hedging Activities

 

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

 

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

 

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used fixed-price, forward, physical purchase and sales contracts, futures, financial swaps and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default.

 

Our use of hedging arrangements through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under SFAS 133, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to the Company has occurred during the applicable period.

 

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

 

 

Risks Related to Employees, Outsourcing of Non-Core Support Activities, and Technology

 

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

 

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

 

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

 

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

 

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, 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.

 

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 30 states plus the District of Columbia in the United States and in Argentina, Canada and Venezuela.

 

Gas Marketing’s primary assets are its term contracts, related systems and technological support. In our Gas Pipeline and Midstream segments, we generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or

consents on and across properties owned by others. In our Exploration & Production segment, the majority of our ownership interest in exploration and production properties is held as working interests in oil and gas leaseholds.

 

 

The information called for by this item is provided in Note 15 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 21, 2008, are listed below.

 

 

 

 

Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 21, 2008, we had approximately 11,153 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.

 

ISSUER PURCHASES OF EQUITY SECURITIES

 

 

 

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, 2003. The Bloomberg U.S. Pipeline Index is composed of El Paso, Equitable Resources, Questar, Oneok, TransCanada, Spectra Energy, Enbridge and Williams. The graph below assumes an investment of $100 at the beginning of the period.

 

Cumulative Total Shareholder Return

 

 

 

 

The following financial data 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.

 

 

 

 

General

 

We are primarily a natural gas company, engaged in finding, producing, gathering, processing, and transporting natural gas. Our operations are located principally in the United States and are organized into the following reporting segments: Exploration & Production, Gas Pipeline, Midstream Gas & Liquids (Midstream), and Gas Marketing Services. (See Note 1 of Notes to Consolidated Financial Statements for further discussion of reporting segments.)

 

Unless indicated otherwise, the following discussion of critical accounting estimates, discussion and analysis of 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 2007

 

Our plan for 2007 was focused on continued disciplined growth. Objectives and highlights of this plan included:

 

 

Our 2007 income from continuing operations increased to $847 million, as compared to $347 million in 2006. Our net cash provided by operating activities was $2.2 billion in 2007 compared to $1.9 billion in 2006. These comparative results reflect:

 

 

 

Natural gas prices in the Rocky Mountain areas (Rockies) trended lower throughout 2007 due to strong drilling activities increasing third-party supplies while constrained by limited pipeline capacity. This trend has benefited Midstream as the lower regional gas prices contributed to increased NGL margins in the West region. Exploration & Production utilizes firm transportation contracts, which allow a substantial portion of their Rockies production to be sold at more advantageous market points, and basin-level collars and fixed-price hedges to reduce exposure to this trend.

 

See additional discussion in Results of Operations.

 

Recent Events

 

During third-quarter 2007, we formed Williams Pipeline Partners L.P. (WMZ) to own and operate natural gas transportation and storage assets. In January 2008, WMZ completed its initial public offering of 16.25 million common units at a price of $20.00 per unit. In February 2008, the underwriters also exercised their right to purchase an additional 1.65 million common units at the same price. A subsidiary of ours serves as the general partner of WMZ. The initial asset of the partnership is a 35 percent interest in Northwest Pipeline GP, formerly Northwest Pipeline Corporation. Upon completion of the transaction, we hold approximately 47.7 percent of the interests in WMZ, including the interests of the general partner.

 

In December 2007, Williams Partners L.P. acquired certain of our membership interests in Wamsutter LLC, the limited liability company that owns the Wamsutter system, from us for $750 million. Williams Partners L.P. completed the transaction after successfully closing a public equity offering of 9.25 million common units that yielded net proceeds of approximately $335 million. The partnership financed the remainder of the purchase price primarily through utilizing $250 million of term loan borrowings and issuing approximately $157 million of common units to us. Since Williams Partners L.P. is consolidated within our consolidated financial statements, the debt and equity issued by Williams Partners L.P. is reported as a component of our consolidated debt balance and minority interest balance, respectively. (See Note 1 of Notes to Consolidated Financial Statements.)

 

In December 2007, we repurchased $213 million of 7.125 percent notes due September 2011 and $22 million of 8.125 percent notes due March 2012. In conjunction with these early retirements, we paid premiums of approximately $19 million. These premiums, as well as related fees and expenses are recorded as early debt retirement costs in the Consolidated Statement of Income.

 

On November 9, 2007, we closed on the sale of substantially all of our power business to Bear Energy, LP, a unit of The Bear Stearns Companies, Inc., for $496 million, subject to post-closing adjustments. The assets sold included tolling contracts, full requirements contracts, tolling resales, heat rate options, related hedges and other related assets including certain property and software. This sale reduces the risk and complexity of our overall business model.

 

In November 2007, our credit ratings were raised to investment grade based on improvements in our credit outlook. As we continue to invest and grow our natural gas businesses, our improved credit rating is expected to provide greater access to capital and more favorable loan terms. See additional discussion of credit ratings in Management’s Discussion and Analysis of Financial Condition.

 

On November 28, 2007, Transco filed a formal stipulation and agreement with the FERC resolving all substantive issues in Transco’s pending 2006 rate case. Final resolution of the rate case is subject to approval by the FERC.

 

In July 2007, our Board of Directors authorized the repurchase of up to $1 billion of our common stock. We intend to purchase shares of our stock from time to time in open-market transactions or through privately negotiated

or structured transactions at our discretion, subject to market conditions and other factors. This stock-repurchase program does not have an expiration date. During 2007, we repurchased approximately 16 million shares for $526 million at an average cost of $33.08 per share. We are funding this program with cash on hand.

 

In April 2007, our Board of Directors approved a regular quarterly dividend of 10 cents per share, which reflected an increase of 11 percent compared to the 9 cents per share that we paid in each of the four prior quarters and marked the fourth increase in our dividend since late 2004.

 

On March 30, 2007, the FERC approved the stipulation and settlement agreement with respect to the rate case for Northwest Pipeline. The settlement establishes an increase in general system firm transportation rates on Northwest Pipeline’s system from $0.30760 to $0.40984 per Dth (dekatherm), effective January 1, 2007.

 

Outlook for 2008

 

Our plan for 2008 is focused on continued disciplined growth. Objectives of this plan include:

 

 

Potential risks and/or obstacles that could prevent us from achieving these objectives include:

 

 

We continue to address these risks through utilization of commodity hedging strategies, focused efforts to resolve regulatory issues and litigation claims, disciplined investment strategies, and maintaining our desired level of at least $1 billion in liquidity from cash and cash equivalents and unused revolving credit facilities.

 

New Accounting Standards and Emerging Issues

 

Accounting standards that have been issued and are not yet effective may have an effect on our Consolidated Financial Statements in the future. These include:

 

 

See Recent Accounting Standards in Note 1 of Notes to Consolidated Financial Statements for further information on these and other 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 that affect the reported amounts therein. 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.

 

Revenue Recognition — Derivative Instruments and Hedging Activities

 

We hold a portfolio of energy trading and nontrading contracts. We review these contracts to determine whether they are nonderivatives or derivatives. If they are derivatives, we further assess whether the contracts qualify for either cash flow hedge accounting or the normal purchases and normal sales exception.

 

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 achieving offsetting 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 that are designated as cash flow hedges, we do not reflect the effective portion of changes in their fair value in earnings until the associated hedged item affects earnings. For those that have not been designated as hedges or do not qualify for hedge accounting, we recognize the net change in their fair value in income currently (marked to market).

 

For derivatives that are designated as cash flow hedges, 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 reclass 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 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.

 

The fair value of derivative contracts is determined based on the nature of the transaction and the market in which transactions are executed. We also incorporate assumptions and judgments about counterparty performance and credit considerations in our determination of their fair value. Contracts are executed in the following environments:

 

 

The number of transactions executed without quoted market prices is limited. We estimate the fair value of these contracts by using readily available price quotes in similar markets and other market analyses. The fair value of all derivative contracts is continually subject to change as the underlying commodity market changes and our assumptions and judgments change.

 

Additional discussion of the accounting for energy contracts at fair value is included in Energy Trading Activities within Item 7 and Note 1 of Notes to Consolidated Financial Statements.

 

Oil- and Gas-Producing Activities

 

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

 

 

The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering, and economic data. After being estimated internally, 99 percent of our reserve estimates are either audited or prepared by independent experts. (See Part I Item 1 for further discussion.) The data may change substantially over time as a result of numerous factors, including additional development 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. A revision of our reserve estimates within reasonably likely parameters is not expected to result in an impairment of our oil and gas properties or goodwill. However, reserve estimate revisions would impact our depreciation and depletion expense prospectively. For example, a change of approximately 10 percent in oil and gas reserves for each basin would change our annual depreciation, depletion and amortization expense between approximately $33 million and $41 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. An unfavorable change in the forward price curve within reasonably likely parameters is not expected to result in an impairment of our oil and gas properties 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 in the period in which 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 15 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, 2007, we have $717 million of deferred tax assets for which a $57 million valuation allowance has been established. When assessing the need for a valuation allowance, we considered 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. We do not expect to be able to utilize $57 million of foreign deferred tax assets primarily related to 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. Beginning January 1, 2007, we evaluate the liability associated with our various filing positions by applying the two step process of recognition and measurement as required by Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109” (FIN 48). The ultimate disposition of these contingencies could have a significant impact on net cash flows. To the extent we were to prevail in matters for which accruals have been established or were required to pay amounts in excess of our accrued liability, our effective tax rate in a given financial statement period may be materially impacted.

 

See Note 5 of Notes to Consolidated Financial Statements for additional information regarding FIN 48 and tax carryovers.

 

Pension and Postretirement Obligations

 

We have employee benefit plans that include pension and other postretirement benefits. Net periodic benefit expense and obligations are impacted by various estimates and assumptions. These estimates and assumptions include the expected long-term rates of return on plan assets, discount rates, expected rate of compensation increase, health care cost trend rates, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements. The following table presents the estimated increase (decrease) in net periodic benefit expense and obligations resulting from a one-percentage-point change in the specified assumption.

 

 

The expected long-term rates of return on plan assets are determined by combining a review of historical returns realized within the portfolio, the investment strategy included in the plans’ Investment Policy Statement, and capital market projections for the asset classifications in which the portfolio is invested as well as the target

weightings of each asset classification. These rates are impacted by changes in general market conditions, but because they are long-term in nature, short-term market swings do not significantly impact the rates. Changes to our target asset allocation would also impact these rates. Our expected long-term rate of return on plan assets used for our pension plans is 7.75 percent for 2007. This rate was 7.75 percent in 2006 and 8.5 percent from 2002-2005. Over the past ten years, our actual average return on plan assets for our pension plans has been approximately 7.7 percent.

 

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 were 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 the duration of our plans’ liabilities.

 

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

 

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

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, 2007. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

 

 

 

2007 vs. 2006

 

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

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

 

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

 

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

 

 

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

 

 

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

 

The securities litigation settlement and related costs is primarily the result of our 2006 settlement related to class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002. (See Note 15 of Notes to Consolidated Financial Statements.)

 

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

 

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

 

The increase in investing income is due to:

 

 

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

 

Early debt retirement costs in 2007 includes $19 million of premiums and fees related to the December 2007 repurchase of senior unsecured notes. (See Note 11 of Notes to Consolidated Financial Statements.) Early debt retirement costs in 2006 includes $27 million in premiums and fees related to the January 2006 debt conversion and $4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.

 

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

 

Provision for income taxes was significantly higher in 2007 due primarily to higher pre-tax earnings. The effective income tax rate for 2007 is slightly higher than the federal statutory rate primarily due to the effect of taxes on foreign operations and an accrual for income tax contingencies, partially offset by the utilization of charitable contribution carryovers not previously benefited. The effective income tax rate for 2006 is slightly higher than the federal statutory rate primarily due to state income taxes, the effect of taxes on foreign operations, nondeductible convertible debenture expenses and an accrual for income tax contingencies, partially offset by the favorable resolution of federal income tax litigation and the utilization of charitable contribution carryovers not previously benefited. The 2006 effective income tax rate has been increased by an adjustment to increase overall deferred income tax liabilities. (See Note 5 of Notes to Consolidated Financial Statements.)

 

Income (loss) from discontinued operations in 2007 primarily includes the operating results of substantially all of our power business and the sale of that business, which was completed in November 2007. (See Note 2 of Notes to Consolidated Financial Statements.) These results include the following pre-tax items:

 

 

Income (loss) from discontinued operations in 2006 includes:

 

 

2006 vs. 2005

 

The decrease in revenues is primarily due to lower natural gas realized revenues at Gas Marketing Services associated with lower natural gas sales prices. Additionally, the effect of a change in forward prices on legacy natural gas derivative contracts not designated as cash flow hedges had an unfavorable impact on revenues. Partially

offsetting these decreases are increased crude, olefin and NGL marketing revenues, higher NGL production revenue at Midstream and increased production revenue at Exploration & Production.

 

The decrease in costs and operating expenses is largely due to reduced natural gas purchase prices at Gas Marketing Services. Partially offsetting these decreases are increased crude, olefin and NGL marketing purchases and operating expenses at Midstream and increased depreciation, depletion and amortization and lease operating expense at Exploration & Production.

 

The increase in SG&A expenses is primarily due to increased personnel costs, insurance expense, higher information systems support costs and the absence of a $17 million reduction of pension expense at Gas Pipeline in 2005. Additionally, Exploration & Production experienced higher costs due to increased staffing in support of increased drilling and operational activity.

 

Other (income) expense — net within operating income in 2005 includes:

 

 

General corporate expenses decreased primarily due to the absence of $14 million of insurance settlement charges in 2005 associated with certain insurance coverage allocation issues.

 

The decrease in operating income primarily reflects the negative effect of a change in forward prices on natural gas derivative contracts at Gas Marketing Services, higher operating and administrative costs at Gas Pipeline and 2006 litigation expenses associated with shareholder lawsuits and Gulf Liquids litigation. These decreases are partially offset by higher margins at Midstream and the absence a 2005 accrual for estimated litigation contingencies associated primarily with agreements reached to substantially resolve exposure related to natural gas price and volume reporting issues.

 

Interest accrued — net in 2006 includes $22 million in interest expense associated with our Gulf Liquids litigation contingency.

 

The increase in investing income is due to:

 

 

These increases are partially offset by:

 

 

The increase in minority interest in income of consolidated subsidiaries is primarily due to the growth of Williams Partners L.P.

Provision for income taxes was significantly lower in 2006 due primarily to lower pre-tax earnings. The effective income tax rate for 2006 is slightly higher than the federal statutory rate primarily due to state income taxes, the effect of taxes on foreign operations, nondeductible convertible debenture expenses and an accrual for income tax contingencies, partially offset by the favorable resolution of federal income tax litigation and the utilization of charitable contribution carryovers not previously benefited. The 2006 effective income tax rate has been increased by an adjustment to increase overall deferred income tax liabilities. The effective income tax rate for 2005 is higher than the federal statutory rate due primarily to state income taxes, nondeductible expenses and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate was reduced by an adjustment to reduce overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. (See Note 5 of Notes to Consolidated Financial Statements.)

 

Income (loss) from discontinued operations in 2005 includes a $155 million net-of-tax loss related to our discontinued power business. (See Note 2 of Notes to Consolidated Financial Statements.)

 

Cumulative effect of change in accounting principle in 2005 is due to the implementation of FIN 47.

Results of Operations — Segments

 

We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Gas Marketing Services, and Other. Other primarily consists of corporate operations. Our management currently evaluates performance based on segment profit (loss) from operations. (See Note 17 of Notes to Consolidated Financial Statements.)

 

Exploration & Production

 

Overview of 2007

 

In 2007, we continued our strategy of a rapid execution of our development drilling program in our growth basins. Accordingly, we:

 

 

2007 vs 2006 Domestic Production

 

 

Average daily domestic production grew 21 percent or 161 MMcfe per day

 

 

The benefits of higher production volumes and higher net realized average prices were partially offset by increased operating costs. The increase in operating costs was primarily due to increased production volumes and higher well service and industry costs. In addition, higher production volumes increased depletion, depreciation and amortization expense.

 

Significant events

 

In February 2007, we entered into a five-year unsecured credit agreement with certain banks in order to reduce margin requirements related to our hedging activities as well as lower transaction fees. Margin requirements, if any, under this new facility are dependent on the level of hedging and on natural gas reserves value. (See Note 11 of Notes to Consolidated Financial Statements.) We may also execute hedges with the Gas Marketing Services segment, which, in turn, executes offsetting derivative contracts with unrelated third parties. In this situation, Gas Marketing Services, generally, bears the counterparty performance risks associated with unrelated third parties. Hedging decisions primarily are made considering our overall commodity risk exposure and are not executed independently by Exploration & Production.

 

In May and July 2007, we increased our position in the Fort Worth basin by acquiring producing properties and leasehold acreage for approximately $41 million. These acquisitions are consistent with our growth strategy of leveraging our horizontal drilling expertise by acquiring and developing low-risk properties in the Barnett Shale formation. In July 2007, we increased our position in the Piceance basin by acquiring additional undeveloped leasehold acreage for approximately $36 million.

 

Outlook for 2008

 

Our expectations and objectives for 2008 include:

 

 

Natural gas prices in the Rocky Mountain areas trended lower throughout 2007 due to strong drilling activities increasing supplies while constrained by limited pipeline capacity. However, we will continue to utilize firm transportation contracts which allow a substantial portion of our Rockies production to be sold at more advantageous market points. Our continued use of basin-level collars and fixed-price hedges should also reduce our exposure to this trend. The construction of a new third-party pipeline that began transporting gas from the Rocky Mountain areas in the beginning of 2008 should lessen pipeline transportation capacity constraints and provided an additional alternative market for the sale of production.

 

Approximately 70 MMcf of our forecasted 2008 daily domestic production is hedged by NYMEX and basis fixed-price contracts at prices that average $3.97 per Mcf at a basin level. In addition, we have the following collar agreements for our forecasted 2008 daily domestic production, shown at basin-level weighted-average prices and weighted-average volumes:

 

 

Risks to achieving our expectations include unfavorable natural gas market price movements which are impacted by numerous factors including weather conditions and domestic natural gas production and consumption. Also, achievement of expectations can be affected by costs of services associated with drilling.

In January 2008, we sold a contractual right to a production payment on certain future international hydrocarbon production for approximately $148 million. We have received $118 million in cash and $29 million has been placed in escrow subject to certain post-closing conditions and adjustments. We will recognize a pre-tax gain of approximately $118 million in the first quarter of 2008 related to the initial cash received. As a result of the contract termination, we have no further interests associated with the crude oil concession, which is located in Peru. We had obtained these interests through our acquisition of Barrett Resources Corporation in 2001.

 

Year-Over-Year Operating Results

 

 

2007 vs. 2006

 

Total segment revenues increased $605 million, or 41 percent, primarily due to the following:

 

 

These increases were partially offset by a $30 million decrease relating to hedge ineffectiveness. In 2006, there were $14 million in net unrealized gains from hedge ineffectiveness as compared to $16 million in net unrealized losses in 2007.

 

To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative forward sales contracts that fix the sales price relating to a portion of our future production. Approximately 19 percent of domestic production in 2007 was hedged by NYMEX and basis fixed-price contracts at a weighted-average price of $3.90 per Mcf at a basin level compared to 40 percent hedged at a weighted-average price of $3.82 per Mcf for 2006. Also, approximately 30 percent and 15 percent of 2007 and 2006 domestic production was

hedged in the following collar agreements shown at basin-level weighted-average prices and weighted-average volumes:

 

 

Total segment costs and expenses increased $404 million, primarily due to the following:

 

 

The $204 million increase in segment profit is primarily due to the 21 percent increase in domestic production volumes sold as well as the 15 percent increase in net realized average prices, partially offset by the increase in segment costs and expenses.

 

2006 vs. 2005

 

Total segment revenues increased $219 million, or 17 percent, primarily due to the following:

 

 

In 2005, approximately 47 percent of domestic production was hedged by NYMEX and basis fixed-price contracts at a weighted-average price of $3.99 per Mcf. Approximately 10 percent of domestic production was hedged by a NYMEX collar agreement for approximately 50 MMcf per day at a floor price of $7.50 per Mcf and a

ceiling price of $10.49 per Mcf in the first quarter and at a floor price of $6.75 per Mcf and a ceiling price of $8.50 per Mcf in the second, third, and fourth quarters, and a Northwest Pipeline/Rockies collar agreement for approximately 50 MMcf per day in the fourth quarter at a floor price of $6.10 per Mcf and a ceiling price of $7.70 per Mcf.

 

Total segment costs and expenses increased $257 million, primarily due to the following: