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.  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o

 

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 $13,912,313,182.

 

The number of shares outstanding of the registrant’s common stock outstanding at February 22, 2007 was 597,861,925.

 

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.

 

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.

 

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.

 

Today, we primarily find, produce, gather, process and transport natural gas. We also manage a wholesale power business. Our operations are concentrated in the Pacific Northwest, Rocky Mountains, Gulf Coast, Southern California and Eastern Seaboard.

 

In 2006 we focused on continued disciplined growth. During 2006 we:

 

 

 

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.          

 

In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.

 

In April 2006, Transcontinental Gas Pipe Line Corporation (Transco) issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

 

In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.

 

In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)

 

In May 2006, our Board of Directors approved a regular quarterly dividend of 9 cents per share of common stock, which reflects an increase of 20 percent compared with the 7.5 cents per share paid in each of the three prior quarters.

 

In June 2006, Northwest Pipeline Corporation (Northwest Pipeline) issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Northwest Pipeline Corporation completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

 

In June 2006, we reached an agreement-in-principle to settle class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000, and July 22, 2002, for a total payment of $290 million to plaintiffs. We funded our $145 million portion of the settlement with cash-on-hand in November 2006, with the balance funded through insurance proceeds. We recorded a pre-tax charge for approximately $161 million in second-quarter 2006. This settlement did not have a material effect on our liquidity position. (See Note 15 of Notes to Consolidated Financial Statements.)

 

In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. 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. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.

 

On July 31, 2006, and August 1, 2006, we received a verdict in civil litigation related to a contractual dispute surrounding certain natural gas processing facilities known as Gulf Liquids. We recorded a pre-tax charge for approximately $88 million in second quarter 2006 related to this loss contingency. (See Note 15 of Notes to Consolidated Financial Statements.)

 

Northwest Pipeline and Transco have each filed a general rate case with the Federal Energy Regulatory Commission (FERC). Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. The new transportation and storage rates for both pipelines will be effective, subject to refund, in the first quarter of 2007.

 

In December 2006, Northwest Pipeline completed and placed into service its capacity replacement project in the state of Washington. The project involved abandoning 268 miles of 26-inch pipeline and replacing it with approximately 80 miles of 36-inch pipeline constructed in four sections along the same pipeline corridor. Additionally, Northwest Pipeline modified five existing compressor stations which created additional net horsepower.

 

Our property insurance coverage levels and premiums were revised during the second quarter of 2006. In general, our coverage levels have decreased while our premiums have increased. These changes reflect general trends in our industry due to hurricane-related damages in recent years.

 

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 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 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 over 47 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 prices at December 31 held constant) for the year indicated:

 

The following table summarizes our proved natural gas reserves by basin as of December 31, 2006:

 

 

No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2006. 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, 2006, 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. 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 2006 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, 2006 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. Reserves estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust which comprise another approximately two percent of our total U.S. proved reserves were prepared by Miller and Lents, LTD.

 

Oil and gas properties

 

Following is a discussion of our oil and gas properties for our significant areas.

 

Piceance basin

 

The Piceance basin is located in northwestern Colorado. In 2006, we drilled 494 gross wells of which we operate 477, and owned working interests in a total of 1,889 gross producing wells at year-end. We produced a net of approximately 152 Bcfe of natural gas from the Piceance basin during 2006. Our estimated proved reserves in this basin at year-end 2006 were 2,469 Bcfe. The Piceance basin is our largest area of concentrated development comprising approximately 67 percent of our proved reserves at December 31, 2006. This area has approximately 1,500 undrilled proved locations in inventory. Within this basin, we are also the owner and operator of a natural gas gathering and processing system. In March 2005 we entered into a contract with Helmerich & Payne for the operation of 10 new FlexRig^® drilling rigs, each for a term of three years. By December 2006, all 10 of these rigs were operating in the Piceance basin. We also have 15 rigs operating in the Piceance basin under contract with other vendors, for a total of 25 rigs operating in the Piceance basin by December 2006.

 

San Juan basin

 

The San Juan basin is located in northwest New Mexico and southwest Colorado. In 2006, we participated in the drilling of 214 gross wells, of which we operate 56 and owned working interests in a total of 2,864 gross producing wells at year-end. We produced a net of approximately 56 Bcfe of natural gas from the San Juan basin during 2006. Our estimated proved reserves in the San Juan basin at year-end 2006 were 614 Bcfe.

 

Powder River basin

 

The Powder River basin is located in northeast Wyoming. In 2006, we drilled 858 gross wells of which we operate 449, and owned working interests in a total of 4,454 gross producing wells at year-end. We produced a net of approximately 52 Bcfe of natural gas from the Powder River basin during 2006. Our estimated proved reserves in this basin at year-end 2006 were 372 Bcfe. The Powder River basin comprises approximately 10 percent of our proved reserves at December 31, 2006. 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. In 2006, we drilled 112 gross wells, of which we operate 61 and owned working interests in a total of 475 gross producing wells at year-end. We produced a net of approximately 11 Bcfe of natural gas from the Mid-Continent in 2006. Our estimated proved reserves in the Arkoma and Fort Worth basins at year-end 2006 were 167 Bcfe.

 

The following table summarizes our leased acreage as of December 31, 2006:

 

 

At December 31, 2006, we owned working interests in 9,965 gross wells producing hydrocarbons (4,890 net).

 

Operating statistics

 

We focus on lower-risk development drilling. Our drilling success rate was 99 percent in 2006, 2005 and 2004. The following tables summarize domestic drilling activity by number and type of well for the periods indicated:

 

 

Substantially all our natural gas production is currently being sold to Power at prevailing market prices. Power then resells the majority of our production to unrelated third parties. Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. We have recently 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 2007 consist of derivative contracts with Power that hedge 172 BBtud in fixed price hedges (whole year) and approximately 270 BBtud in NYMEX and regional collars (whole year) for projected 2007 domestic natural gas production. Power then enters into offsetting derivative contracts with unrelated third parties. Our natural gas production hedges in 2006 consisted of 299 BBtud in fixed price hedges and 64 BBtud in NYMEX collars and an additional 50 BBtud in regional collars. A collar is a financial instrument 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 gas purchase hedging contracts executed on behalf of other Williams entities which taken as a net position may counteract Exploration & Production gas sales hedging derivatives.

 

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

 

 

Acquisitions & divestitures

 

Exploration & Production expanded its acreage position and purchased producing properties in the Fort Worth basin in north-central Texas through transactions totaling approximately $64 million.

 

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, 2007, we own 789,291 trust units. We sold no additional trust units during 2006.

 

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 4.2 percent of our total proved reserves.

 

We own and operate, through Williams Gas Pipeline Company, LLC and its subsidiaries, a combined total of approximately 14,400 miles of pipelines with a total annual throughput of approximately 2,500 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 Corporation. 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.

 

Transcontinental Gas Pipe Line Corporation (Transco)

 

Transco is an interstate natural gas transportation company that owns and operates a 10,500-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, 2006, 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 3.5 MMdt of natural gas per day for a system-wide delivery capacity total of approximately 8.2 MMdt of natural gas per day. Transco’s system includes 44 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 10 percent of Transco’s total revenues in 2006. 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

 

Leidy to Long Island Expansion Project

 

The Leidy to Long Island Expansion Project will involve an expansion of Transco’s existing natural gas transmission system in Zone 6 from the Leidy Hub in Pennsylvania to Long Island, New York. The project will provide 100 Mdt/d of incremental firm transportation capacity, which has been fully subscribed by one shipper for a 20-year primary term. The project facilities will include pipeline looping in Pennsylvania, pipeline looping, replacement and a natural gas compressor facility in New Jersey and appurtenant facilities in New York. Transco expects that over three-quarters of the project expenditures will occur in 2007. Transco filed an application for FERC authorization of the project in December 2005, which the FERC approved by order issued on May 18, 2006. On October 20, 2006, Transco filed an application to amend the FERC authorizations to reflect Transco’s ownership of certain appurtenant facilities as part of the project and to adjust the cost of facilities and rates, which the FERC approved on January 11, 2007. The estimated capital cost of the project is approximately $141 million. The target in-service date for the project is November 1, 2007.

 

Potomac Expansion Project

 

The Potomac Expansion Project will involve an expansion of Transco’s 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 project will provide 165 Mdt/d of incremental firm transportation capacity, which has been fully subscribed by shippers under long-term firm arrangements. The estimated capital cost of the project is approximately $74 million. On July 17, 2006, Transco filed an application for FERC approval of the project. The target in-service date for the project is November 1, 2007.

 

Sentinel Expansion Project

 

The Sentinel Expansion Project will involve an expansion of Transco’s 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 project will provide 142 Mdt/d of incremental firm transportation capacity, which has been fully subscribed by the shippers under long-term firm arrangements. The project facilities will include pipeline looping in Pennsylvania and New Jersey and minor compressor station modifications. The estimated capital cost of the project excluding any customer meter station upgrades is approximately $140 million. In order to accommodate certain shippers, Transco is planning to place the incremental firm transportation capacity into service in two phases, the first phase commencing on November 1, 2008 for 67 Mdt/d of service and the second phase commencing on November 1, 2009 for an additional 75 Mdt/d of service. The FERC has granted our request for a pre-application environmental review of the project, soliciting early input from citizens, governmental entities and other interested parties. Transco expects to file a formal application with the FERC in the second quarter of 2007.

 

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 Corporation (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, 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, 2006, 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.

 

In 2003, we experienced two breaks in a segment of one of our natural gas pipelines in western Washington. In response to these breaks, we received Corrective Action Orders from the Office of Pipeline Safety, elected to idle the pipeline segment until its integrity could be assured, and began the process of replacing the capacity served by the pipeline segment.

 

In September 2005 we received a FERC certificate authorizing us to construct and operate the “Capacity Replacement Project.” This project entailed the abandonment of approximately 268 miles of the existing 26-inch pipeline, and the construction of approximately 80 miles of new 36-inch pipeline and an additional 10,760 net horsepower of compression at two existing compressor stations. As of December 2006, all of the facilities were placed in service, and abandonment of the 26-inch pipeline was completed.

 

The rate case we filed on June 30, 2006 seeks to recover, among other things, the capitalized costs relating to the Capacity Replacement Project.

 

In 2006, Northwest Pipeline served a total of 141 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 2006 accounted for approximately 19.9 percent and 10.9 percent, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2006. 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

 

Parachute Lateral Project

 

In January 2006, we filed an application with the FERC to construct a 38-mile lateral that would provide additional transportation capacity from the Parachute area to the Greasewood area in northwest Colorado. The planned lateral would increase capacity by 450 Mdt/d through a 30-inch diameter line and is estimated to cost $86 million. We anticipate beginning service on the expansion in March 2007.

 

Greasewood Lateral Project

 

In March 2006, we executed an agreement with a shipper for 200 Mdt/d of capacity on a proposed new lateral to be constructed from the vicinity of Greasewood, Colorado, to our mainline system near Sands Springs, Colorado. On February 20, 2007, following a meeting with representatives of the shipper, we decided to postpone applying with the FERC for a certificate to construct the proposed Greasewood Lateral Project. We will be continuing to work with potential shippers to determine whether to proceed with the project at a future date.

 

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. In December 2001, Gulfstream filed an application with the FERC to allow Gulfstream to complete the construction of its approved facilities in phases. In May 2002, the first phase of the project was placed into service at a cost of approximately $1.5 billion. The second phase of the project was placed into service on February 1, 2005. The total capital cost of both phases of the project is approximately $1.7 billion. At December 31, 2006, our equity investment in Gulfstream was $387 million. Gas Pipeline and Spectra Energy (formerly known as Duke Energy), through their respective subsidiaries, each hold a 50 percent ownership interest in Gulfstream and provide operating services for Gulfstream.

 

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, we intend 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 approximately $135 million. 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, we intend 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 project will include the construction of additional pipeline in Florida and the installation of new compression in Alabama and Florida. The estimated capital cost of this expansion is anticipated to be approximately $117 million. No significant increase in operations personnel is expected as a result of these two projects.

 

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; natural gas liquids (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 NGLs extracted and 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 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:

 

 

Domestic 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 8,200 miles of gathering pipelines, nine processing plants (one partially owned) and five natural gas treating plants with a combined daily inlet capacity of nearly 6.2 billion cubic feet per day. Some of these assets are owned through our interest in Williams Partners L.P. (see Williams 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 these natural gas assets, we own and operate three crude oil pipelines totaling approximately 270 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 Kerr-McGee-operated Boomvang and Nansen field areas in the western Gulf of Mexico. These pipelines were placed in service on January 28, 2002.

 

Our 18 inch oil pipeline, Alpine, which became operational on December 14, 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 Kerr-McGee.

 

Our Devils Tower floating production system and associated pipelines were placed in service on May 5, 2004. Initially built to serve Dominion Exploration & Production’s 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. Located in 5,610 feet of water, it is the world’s deepest dry tree spar. The platform, which is operated by Dominion 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 102-mile Canyon Chief gas pipeline consists of 18-inch diameter pipe. The 118-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.

 

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). We own a partial interest in Discovery and 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.

 

Gulf Coast petrochemical and olefins

 

We own a 5/12 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. We also own an ethane pipeline system in Louisiana. Our Gulf Liquids New River LLC (Gulf Liquids) business consists of a propylene splitter and its related pipeline system.

 

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 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 Williams Partners L.P.

 

Williams Partners L.P.

 

Williams Partners L.P. (Williams Partners) was formed to engage in the business of gathering, transporting and processing natural gas and fractionating and storing NGLs. We own approximately 22.5 percent of Williams Partners. Williams Partners provides us with an acquisition currency that is expected to enable growth of our Midstream business. Williams Partners also creates a vehicle to monetize our qualifying assets. Such transactions, which are subject to approval by both our and Williams Partners’ general partner’s board of directors, allow us to retain control of the assets through our ownership interest in Williams Partners.

 

During 2006, Williams Partners L.P. acquired Williams Four Corners, LLC which includes a 3,500-mile natural gas gathering system in the San Juan Basin in New Mexico and Colorado with capacity of nearly 2 billion cubic feet per day; 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 million cubic feet per day; and the Milagro and Esperanza natural gas treating plants in New Mexico, which are designed to remove carbon dioxide from up to 750 million cubic feet of natural gas per day.

 

In addition, Williams Partners owns a 40 percent equity investment in the Discovery gathering, transportation, processing and NGL fractionation system; the Carbonate Trend sour gas gathering pipeline; three integrated NGL storage facilities near Conway, Kansas; and a 50 percent interest in an NGL fractionator near Conway, Kansas.

 

Expansion projects

 

Gathering and processing

 

In May 2006, we entered into an agreement to develop new pipeline capacity for transporting natural gas liquids from production areas in southwestern Wyoming to central Kansas. The other party to the agreement reimbursed us for the development costs we incurred to date for the proposed pipeline and initially will own 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 early 2008. Additionally, we have agreed to dedicate our equity NGL volumes from our two Wyoming plants for transport under a long-term shipping agreement. The terms represent significant savings compared with the existing tariff and other alternatives considered.

 

We are constructing a fifth cryogenic processing train at our existing gas plant in Opal, Wyoming, which is scheduled for start-up in the first quarter of 2007. The expansion is designed to boost the plant’s processing capacity by more than 30 percent to 1.45 billion cubic feet per day. Opal also will be able to recover a total of approximately 67,000 barrels per day of natural gas liquids.

 

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 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.

 

Chevron and Kerr-McGee 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 second quarter 2008. The approximately $200 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 natural gas liquids from Blind Faith also could be fractionated at our facilities in Baton Rouge or Paradis, Louisana.

 

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 2006, these operations gathered and processed gas for approximately 220 gas gathering and processing customers. Our top three gathering and processing customers accounted for about 44 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. The significant contracts have a remaining term between 11 and 15 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, indicating that a level of political risk still remains.

 

Operating statistics

 

The following table summarizes our significant operating statistics for Midstream:

 

 

 

 

Our Power business buys, sells, stores and transports energy and energy-related commodities, primarily power and natural gas. Power’s focus is not only on its objective of maximizing expected cash flows, but also on executing new contracts to hedge its portfolio and providing services that support our natural gas businesses across Williams. Our contracts include physical forward purchases and sales, various financial instruments and structured transactions. Our financial instruments include exchange-traded futures, as well as exchange-traded and over-the-counter options and swaps. Structured transactions include tolling contracts, full requirements contracts, tolling resales and heat rate options.

 

Tolling contracts represent the most significant portion of our portfolio. Under the tolling contracts, we have the right to request a plant owner to convert our fuel (usually natural gas) to electricity in exchange for a fixed fee. We have the right to request approximately 7,700 megawatts of electricity under six tolling agreements. The table below lists the locations and available capacity of each of our tolling agreements. These capacity numbers are subject to change, and our contractual rights to capacity may not reflect actual availability at the plants.

 

 

We use portions of the electricity produced under the tolling agreements to supply obligations under various arrangements such as power sales, tolling resales, and full requirements contracts. Under full requirements contracts, we supply the electricity required by our counterparties to serve their customers. Through full requirements contracts, we supply approximately 600 to 1,500 megawatts of electricity to our customers in Georgia and approximately 515 to 600 megawatts of electricity to our customers in Pennsylvania. The amount of electricity we supply under these contracts varies year to year but is expected to grow annually. Each year, the amount of electricity we supply is subject to a growth cap.

 

Through tolling resale agreements, we enter into transactions that mirror, to varying degrees, some or all of our rights under our underlying tolling arrangements, which remain in place with our tolling counterparties. We have resold part of our rights (1,934 to 3,875 megawatts) under the California tolling arrangement to two counterparties for periods through 2011. These volumes include amounts sold under contracts executed in 2007.

 

We also own two natural gas-fired electric generating plants located near Bloomfield, New Mexico (60 megawatts, Milagro facility) and in Hazleton, Pennsylvania (147 megawatts).

 

In 2006, we managed natural gas throughout North America with total physical volumes averaging 2.3 billion cubic feet per day. We use approximately 10 percent of this natural gas to fuel electric generating plants we own or in which we have contractual rights. We sell approximately 70 percent of this natural gas to customers including local distribution companies, utilities, producers, industrials and other gas marketers. With the remaining 20 percent, we procure gas supply for our Midstream operations.

 

In 2004, we substantially exited our crude oil and refined products activities.

 

Operating statistics

 

The following table summarizes marketing and trading gross sales volumes, including sales volumes to other segments, for the periods indicated:

 

 

In 2006, Power managed 2.3 billion cubic feet per day of natural gas. The natural gas volumes managed include the following (in billion cubic feet per day):

 

 

As of December 31, 2006, Power had approximately 350 customers compared with approximately 300 customers at the end of 2005.

 

At December 31, 2004, we owned approximately 94.7 percent of the Class B Interests and 21.3 percent of the Common 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.

 

During the first quarter of 2005, Longhorn became fully operational as deliveries commenced through both the Odessa and El Paso terminals. However, the pipeline’s throughput fell significantly short of management expectations. The primary driver behind this volume shortfall was the narrowing of the refined product pricing differentials between the Gulf Coast and El Paso markets. During the second quarter of 2005, Longhorn management indicated the shortfall was likely to continue and that the original business model was no longer feasible.

 

As a result of the other-than-temporary decline in fair value identified in the second quarter of 2005, we impaired the Common Interests by $16.2 million and the Class B shares by $32.7 million. After these adjustments, the book value of our investment in Longhorn (as of June 30, 2005) totaled $51.6 million, comprised of $25.0 million of Common Interests and $26.6 million of Class B shares.

 

During the third quarter of 2005, we provided $10 million of a $50 million fully collateralized bridge loan to fund operations of Longhorn until an economically feasible operational alternative was developed. In the fourth quarter of 2005, management of Longhorn concluded that its best alternative would be to sell the Longhorn assets. Accordingly, they directed a financial advisor to solicit offers from several entities. After reviewing the terms and conditions of bids received, our management determined that a full impairment of our investment in the Class B and Common Interests was appropriate. This decision resulted in a December 31, 2005 write-down of the remaining $38.1 million in book value which had been further reduced by additional equity losses during the third and fourth quarters.

 

The management of Longhorn completed an installment sale of the pipeline during the third quarter of 2006, and as a result we received full payment of the $10 million secured bridge loan that we provided to Longhorn during 2005. 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 fully impaired interests 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 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” sold in 2003 and 2004 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, 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, 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 Power, 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, 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 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 Gas Transmission LLC 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 Commission before any changes can go into effect. Currently, Black Marlin has a major rate change application pending before the Commission to 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.

 

Power.  Our Power business is subject to a variety of laws and regulations at the local, state and federal levels, including FERC and the Commodity Futures Trading Commission regulation. In addition, electricity and natural gas markets in California and elsewhere 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, 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, imposing limitations on generation facility availability, 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 (which we believe would be granted).

 

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.  Our Gas Pipeline segment faces increased competition as a result of various actions taken by the FERC and several states in which we operate to strengthen market forces in the natural gas pipeline industry. In a number of key markets, interstate pipelines are now facing competitive pressures from other major pipeline systems, enabling local distribution companies and end users to choose a supplier or switch suppliers based on the short-term price of gas and the cost of transportation. We expect competition for natural gas transportation to continue to intensify in future years due to increased customer access to other pipelines, rates, competitiveness among pipelines, customers’ desire to have more than one transporter, shorter contract terms, regulatory developments, and development of LNG facilities particularly in our market areas. Future utilization of pipeline capacity will depend on competition from other pipelines and LNG facilities, use of alternative fuels, the general level of natural gas demand, and weather conditions.

 

Suppliers of natural gas are able to compete for any gas markets capable of being served by pipelines using nondiscriminatory transportation services provided by the pipeline companies. As the regulated environment has matured, many pipeline companies have faced reduced levels of subscribed capacity as contractual terms expire and customers opt to reduce firm capacity under contract in favor of alternative sources of transmission and related services. This situation, known in the industry as “capacity turnback,” is forcing the pipeline companies to evaluate the consequences of major demand reductions in traditional long-term contracts. It could also result in significant shifts in system utilization, and possible realignment of cost structure for remaining customers because all interstate natural gas pipeline companies continue to be authorized to charge maximum rates approved by the FERC on a cost of service basis. Gas Pipeline does not anticipate any significant financial impact from “capacity turnback.” We anticipate that we will be able to remarket most future capacity subject to future capacity turnback, although competition may cause some of the remarketed capacity to be sold at lower rates or for shorter terms.

 

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, master limited partnerships (MLP), 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 well connections, pressure obligations and contract structure. We also compete in recruiting and retaining skilled employees. In 2005 we formed Williams Partners to help compete against other master limited partnerships for midstream projects. By virtue of the master limited partnership structure, Williams Partners provides us with an alternative and low-cost source of capital. We expect the alternative, low-cost capital will allow Williams Partners to compete with other MLPs when pursuing acquisition opportunities of gathering and processing assets.

 

Power.  In our Power 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, 2007, we had approximately 4,313 full-time employees including 972 at the corporate level, 584 at Exploration & Production, 1,694 at Gas Pipeline, 928 at Midstream, and 135 at Power. 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, other than financial instruments, long-term customer relationships of a financial institution, mortgage and other servicing rights and deferred policy acquisition costs, located in the United States and all foreign countries.

 

Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These 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 additions 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 transmission 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 transmission 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 transmission and import and export of natural gas supplies, adversely impacting our ability to fill the capacities of our gathering, transmission and processing facilities. Additionally, in some cases, new LNG import facilities built near our markets could result in less demand for our gathering and transmission 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.

 

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. Lower oil and gas prices 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 2006 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 and results of operations, particularly if the event is not fully covered by insurance. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances 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.

 

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, including gas transmission and the sale of electric power, can have seasonal characteristics. In many parts of the country, demand for power peaks during the summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. In addition, 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 power sale agreements and natural gas transmission 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 Power, which uses gas as a fuel source, 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 proposed 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. Foreign currency risk can also arise when the revenues received by our foreign subsidiaries are not in U.S. dollars. In such cases, a strengthening of the U.S. dollar or a weakening of the foreign currency could reduce the amount of

cash and income we receive from these foreign subsidiaries. We have put contracts in place designed to mitigate our most significant 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.

 

Our lack of investment grade credit ratings increases our costs of doing business in certain ways and attainment of an investment grade rating is within the control of independent third parties.

 

Because we do not have an investment grade credit rating, our transactions in each of our businesses require greater credit assurances, both to be given from, and received by, us to satisfy credit support requirements. In addition, we are more vulnerable to the impact of market disruptions or a further downgrade of our credit rating that might further increase our cost of borrowing or further impair our ability to access capital markets. 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 goal is to attain investment grade ratios. However, there is no guarantee that the credit rating agencies will assign us investment grade ratings even if we meet or exceed their criteria for investment grade ratios.

 

Long-term power generation purchase contracts without corresponding long-term purchase sale contracts might expose us to fluctuations in the wholesale power markets and negatively affect our results of operations.

 

We have entered into agreements with certain power generation facilities to purchase all or a substantial portion of their generation capacity. These facilities operate as “merchant” facilities, many without corresponding long-term power sales agreements, and therefore are exposed to market fluctuations. Without the benefit of such

long-term power sales agreements, we cannot be sure that we will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these power generation relationships will be profitable.

 

We sell all or a portion of the energy, capacity and other products from certain generation facilities to wholesale power markets, including energy markets operated by independent system operators, or ISOs, or regional transmission organizations, or RTOs, as well as wholesale purchasers. We are not subject to traditional cost-based regulation, therefore we sell electric generation capacity, power and ancillary services to wholesale purchasers at prices determined by the market. As a result, we are not guaranteed any rate of return on our capital investments through mandated rates, and our revenues and results of operations depend upon current and forward market prices for power.

 

Prices for electricity, 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 our power and gas businesses depend primarily upon the prices we receive for electricity, 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. In particular, market prices for power, generation capacity and ancillary services tend to fluctuate substantially. Unlike other commodities, electricity can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, market prices for electricity are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets.

 

The markets for electricity, natural gas liquids, and natural gas 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 electricity, 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 financing 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, transmission, 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.

 

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 transmission 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 transmission and distribution assets due to regulation by the FERC and regional authorities of wholesale market transactions for electricity and natural gas.

 

We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity and natural gas we buy and sell in the wholesale market. If transmission 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. The FERC has issued power transmission regulations that require wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, some companies may fail to provide fair and equal access to their transmission systems or may not provide sufficient transmission capacity to enable other companies to transmit electric power.

 

In addition, the independent system operators who oversee the transmission systems in regional power markets, such as California, have in the past been authorized to impose, and might continue to impose, price limitations and other mechanisms to address volatility in the power markets. These types of price limitations and other mechanisms might adversely impact the profitability of our wholesale power marketing and trading. Given the extreme volatility and lack of meaningful long-term price history in many of these markets and the imposition of price limitations by regulators, ISOs, RTOs or other marker operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets or that our results of operations will not be adversely affected by the actions of these parties.

 

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.

 

Existing regulations might be revised or reinterpreted, new laws and regulations might be adopted or become applicable to us or our facilities, 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 pending rate cases to set the rates we can charge customers on certain of our pipelines might result in rates that do not provide an adequate return on the capital we have invested in those pipelines.

 

We have filed rate cases with the FERC to request changes to the rates we charge on Northwest Pipeline and Transco. Although we have a pending settlement of our Northwest Pipeline rate case, we must still obtain approval of the settlement. Therefore, the outcome of both rate cases remains uncertain. There is a risk that rates set by the FERC will be lower than is necessary to provide us with an adequate return on the capital we have invested in these

assets. 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.

 

Accounting irregularities discovered in the past few years across various industries have forced regulators and legislators 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.

 

We manage our commodity price risk for our unregulated businesses as a whole. Although we have systems in place that use various methodologies to quantify risk, 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, including our long-term tolling agreements. 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, as well as long-term structured transactions when feasible. 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 tolling 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 and could also result in reported cash flows in future years not reflecting the realization of increases in the fair value of derivatives that have already been reflected in our income statements. 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 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. During the period from 2002 to 2004 when our Power business was for sale, most changes in the fair value of derivatives used in our Power business were reflected in our earnings as net forward unrealized mark-to-market gains. As a result, in future periods if the cash benefits associated with those hedges are actually realized, the value will not be reflected as earnings on our income statement, having already been recorded as earnings in prior years.

 

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 the 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.

 

Our ability to receive services from outsourcing provider locations outside of the United States might be impacted by cultural differences, political instability, or unanticipated regulatory requirements in jurisdictions outside the United States.

 

Certain of our accounting, information technology, application development, and helpdesk 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.

 

Our current information technology infrastructure is aging and may adversely affect our ability to conduct our business.

 

Limited capital spending for information technology infrastructure during 2001-2003 resulted in an aging server environment that may be less efficient, may require more personnel and capital resources to maintain and upgrade than more current systems, and may not be adequate for our current business needs. While efforts are ongoing to update the environment, the current age and condition of equipment could result in loss of internal and external communications, loss of data, inability to access data when needed, excessive software downtime (including downtime for critical software applications), and other disruptions that could have a material adverse impact on our business and results of operations.

 

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 generate, produce, process, transmit, transport or distribute electricity, natural gas or natural gas liquids. Acts of terrorism as well as events occurring in response to or in connection with acts of terrorism could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our financial condition, results of operations and cash flows.

 

None.

 

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

 

Power’s primary assets are its term contracts, related systems and technological support. In addition, affiliates of Power own the Hazelton and Milagro generating facilities described above. 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 22, 2007, are listed below.

 

 

 

Our common stock is listed on the New York Stock Exchange and NYSE Arca Equities Exchanges under the symbol “WMB.” At the close of business on February 22, 2007, we had approximately 11,875 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. However, until January 20, 2005, the credit agreements underlying our two unsecured revolving credit facilities totaling $500 million prohibited us from paying quarterly cash dividends on our common stock in excess of $0.05 per share. On January 20, 2005, these facilities were terminated and replaced with two new facilities. As part of the transaction, the dividend restriction, along with most of the other restrictive covenants, was removed from the new credit agreements.

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, 2002. The Bloomberg U.S. Pipeline Index is composed of El Paso, Equitable Resources, Questar, Kinder Morgan, 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 as of December 31, 2006 and 2005, and for the three years ended December 31, 2006, are an integral part of, and should be read in conjunction with, the consolidated financial statements and related notes. All other amounts have been prepared from our financial records. Certain amounts below have been restated or reclassified. See Note 1 of Notes to Consolidated Financial Statements in Part II Item 8 for discussion of changes in 2006, 2005 and 2004. Information concerning significant trends in the financial condition and results of operations is contained in Management’s Discussion & Analysis of Financial Condition and Results of Operations of this report.

 

 

 

 

General

 

We are primarily a natural gas company, engaged in finding, producing, gathering, processing, and transporting natural gas. We also manage a wholesale power business. 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 Power. (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 2006

 

Our plan for 2006 was focused on continued disciplined growth. Objectives and highlights of this plan included:

 

 

Our 2006 income from continuing operations increased to $332.8 million, as compared to $317.4 million in 2005. Our net cash provided by operating activities was $1,889.6 million in 2006 compared to $1,449.9 million in 2005. These comparative results reflect the benefit of strong natural gas liquid margins partially offset with resolution of certain legacy litigation issues. In addition to achieving these results, the following represent significant actions or events that occurred during the year:

 

Recent Events

 

In June 2006, Williams Partners L.P. acquired 25.1 percent of our interest in Williams Four Corners LLC for $360 million. The acquisition was completed after Williams Partners L.P. successfully closed a $150 million private debt offering of senior unsecured notes due 2011 and an equity offering of approximately $225 million in net proceeds. In December 2006, Williams Partners L.P. acquired the remaining 74.9 percent interest in Williams Four Corners LLC for $1.223 billion. The acquisition was completed after Williams Partners L.P. successfully closed a $600 million private debt offering of senior unsecured notes due 2017, a private equity offering of approximately $350 million of common and Class B units, and a public equity offering of approximately $294 million in net proceeds. 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. Williams Four Corners LLC owns certain gathering, processing and treating assets in the San Juan Basin in Colorado and New Mexico.

 

In December 2006, Northwest Pipeline completed and placed into service its capacity replacement project in the state of Washington. The project involved abandoning 268 miles of 26-inch pipeline and replacing it with approximately 80 miles of 36-inch pipeline constructed in four sections along the same pipeline corridor. Additionally, Northwest Pipeline modified five existing compressor stations and created additional net horsepower.

 

Northwest Pipeline and Transco have each filed a general rate case with the FERC. Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007. The new rates for Northwest Pipeline are effective in January 2007, subject to refund. The new rates for Transco are expected to be effective in March 2007, subject to refund.

 

In April 2006, Transco issued $200 million aggregate principal amount of 6.4 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Transco completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

 

In April 2006, we retired a secured floating-rate term loan for $488.9 million, including outstanding principal and accrued interest. The loan was due in 2008 and secured by substantially all of the assets of Williams Production RMT Company. The loan was retired using a combination of cash and revolving credit borrowings.

 

In May 2006, we replaced our $1.275 billion secured revolving credit facility with a $1.5 billion unsecured revolving credit facility. The new facility contains similar terms and financial covenants as the secured facility, but contains certain additional restrictions. (See Note 11 of Notes to Consolidated Financial Statements.)

 

In May 2006, our Board of Directors approved a regular quarterly dividend of 9 cents per share of common stock, which reflects an increase of 20 percent compared with the 7.5 cents per share paid in each of the three prior quarters.

 

In June 2006, Northwest Pipeline issued $175 million aggregate principal amount of 7 percent senior unsecured notes due 2016 to certain institutional investors in a private debt placement. In October 2006, Northwest

Pipeline completed an offer to exchange all of these notes for substantially identical notes registered under the Securities Act of 1933, as amended.

 

In June 2006, we reached an agreement-in-principle to settle class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000, and July 22, 2002, for a total payment of $290 million to plaintiffs. We funded our $145 million portion of the settlement with cash-on-hand in November 2006, with the balance funded directly by our insurers. We recorded a pre-tax charge for approximately $161 million in second quarter 2006. This settlement did not have a material effect on our liquidity position. (See Note 15 of Notes to Consolidated Financial Statements.)

 

On July 31, 2006, and August 1, 2006, we received a verdict in civil litigation related to a contractual dispute surrounding certain natural gas processing facilities known as Gulf Liquids. We recorded a pre-tax charge for approximately $88 million in second quarter 2006 related to this loss contingency. (See Note 15 of Notes to Consolidated Financial Statements.)

 

Our property insurance coverage levels and premiums were revised during the second quarter of 2006. In general, our coverage levels have decreased while our premiums have increased. These changes reflect general trends in our industry due to hurricane-related damages in recent years.

 

In November 2005, we initiated an offer to convert our 5.5 percent junior subordinated convertible debentures into our common stock. In January 2006, we converted approximately $220.2 million of the debentures in exchange for 20.2 million shares of common stock, a $25.8 million cash premium, and $1.5 million of accrued interest.

 

Outlook for 2007

 

Our plan for 2007 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 revolving credit facilities.

 

New Accounting Standards and Emerging Issues

 

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

 

 

FIN 48 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, the enterprise determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. A tax position that meets the more likely than not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit, determined on a cumulative probability basis, that is greater than 50 percent likely of being realized upon ultimate settlement.

 

We adopted FIN 48 as of January 1, 2007. The cumulative effect of applying the Interpretation will be reported as an adjustment to the opening balance of retained earnings. The net impact of the cumulative effect of adopting FIN 48 is expected to be in the range of a $10 million to $20 million decrease in retained earnings.

 

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 substantial portfolio of energy trading and nontrading contracts for a variety of purposes. 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 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 must also 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, 99.9 percent of our reserve estimates are either audited or prepared by independent experts. 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 $25 million and $31 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 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, 2006, we have approximately $926 million of deferred tax assets for which a $36 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. Based on our projections, we believe that it is probable that we can utilize our year-end 2006 federal tax net operating losses carryovers and charitable contribution carryovers prior to their expiration. We do not expect to be able to utilize $36 million of foreign deferred tax assets related to carryovers. See Note 5 of Notes to Consolidated Financial Statements for additional information regarding the tax carryovers. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by potential changes in jurisdictional income tax laws and the circumstances surrounding the actual realization of related tax assets.

 

We regularly face challenges from domestic and foreign tax authorities regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we record a liability for probable tax contingencies. 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.

 

Pension and Postretirement Obligations

 

We have employee benefit plans that include pension and other postretirement benefits. Pension and other postretirement benefit plan expense and obligations are calculated by a third-party actuary and 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 pension and other postretirement 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 the capital market projections provided by our independent investment consultant 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 2006 and was 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 7.9 percent.

 

The discount rates are used to discount future benefit cash flows to today’s dollars. Decreases in these rates increase the obligation and, generally, increase 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 corporate bonds.

 

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.

 

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, 2006. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

 

 

 

 

2006 vs. 2005

 

The decrease in revenues is primarily due to lower power and natural gas realized revenues at Power. These revenues declined due to lower sales volumes associated with reducing the scope of our trading activities and lower natural gas sales prices. Partially offsetting these decreases are increased crude, olefin and natural gas liquid (NGL) marketing revenues and higher NGL production revenue at Midstream and increased production revenue at Exploration & Production.

 

The decrease in costs and operating expenses is largely due to decreased power purchase volumes and reduced natural gas purchase prices at Power. 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 selling, general and administrative (SG&A) expenses is primarily due to increased personnel costs, insurance expense, higher information systems support costs and the absence of a $17.1 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 2006 includes:

 

 

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

 

 

General corporate expenses decreased primarily due to the absence of $13.8 million of insurance settlement charges in 2005 associated with certain insurance coverage allocation issues.

 

The securities litigation settlement and related costs is the result of settling class-action securities litigation filed on behalf of purchasers of our securities between July 24, 2000 and July 22, 2002.

 

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:

 

 

Early debt retirement costs in 2006 includes $25.8 million in premiums and $1.2 million in fees related to the January 2006 debt conversion and $4.4 million of accelerated amortization of debt expenses related to the retirement of the debt secured by assets of Williams Production RMT Company.

 

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

 

Provision for income taxes changed favorably during the year. 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, the effect of taxes on foreign operations 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 2006 includes:

 

 

Cumulative effect of change in accounting principle in 2005 is due to the implementation of FIN 47. (See Note 9 of Notes to Consolidated Financial Statements.)

 

2005 vs. 2004

 

The increase in revenues is due primarily to increased revenues at Exploration & Production due to higher natural gas prices and production volumes sold and gas management income, and at Midstream due primarily to increased NGL prices and crude marketing revenue. Partially offsetting these increases is decreased revenue at Power due primarily to the absence of crude and refined products activity and reduced net forward unrealized mark-to-market gains.

 

The increase in costs and operating expenses is due primarily to increased crude marketing costs and increased NGL costs at Midstream in addition to increased depreciation, depletion and amortization and gas management expense at Exploration & Production. Partially offsetting these increases are decreased costs at Power primarily due to the absence of crude and refined products activity.

 

The decrease in SG&A expenses is primarily due to the $17.1 million reduction in expenses at Gas Pipeline to record the cumulative impact of a correction to pension expense attributable to the periods 2003 and 2004 and a $9.7 reduction of bad debt expense at Power resulting from the sale of certain receivables to a third party. Partially offsetting these items is increased staffing costs at Exploration & Production in support of increased operational drilling activity.

 

Other (income) expense — net, within operating income, in 2004 includes:

 

 

The increase in general corporate expenses is due primarily to the $13.8 million of expense related to the settlement of certain insurance coverage issues and a $16 million increase in outside legal costs associated primarily with securities class action matters.

 

The decrease in interest accrued — net is due primarily to lower average borrowing levels in 2005 as compared to 2004.

 

The decrease in investing income is due primarily to a $76.4 increase in impairment charges on our investment in Longhorn, a $13.9 million increase in Longhorn equity losses, and the $23 million impairment of our Aux Sable equity investment. Partially offsetting these decreases are the following increases:

 

 

Early debt retirement costs include premiums, fees and expenses related to the retirement of debt.

 

Provision for income taxes changed unfavorably primarily due to increased pre-tax income in 2005 as compared to 2004. The effective income tax rate for 2005 is higher than the federal statutory rate due primarily to state income taxes, nondeductible expenses, the effect of taxes on foreign operations and the inability to utilize charitable contribution carryovers. The 2005 effective income tax rate has been reduced by an adjustment to reduce the overall deferred income tax liabilities and favorable settlements on federal and state income tax matters. The effective income tax rate for 2004 is higher than the federal statutory rate due primarily to state income taxes, a charge associated with charitable contribution carryovers and the effect of taxes on foreign operations. A 2004 accrual for income tax contingencies was offset by favorable settlements of certain federal and state income tax matters. (See Note 5 of Notes to Consolidated Financial Statements.)

 

Income (loss) from discontinued operations in 2004 is comprised of gains on the sales of the Canadian straddle plants and the Alaska refinery of $189.8 million and $3.6 million, respectively, as well as $22 million in income from our Canadian straddles discontinued operation. Partially offsetting these are $153 million of charges to increase our accrued liability associated with certain Quality Bank litigation matters.

Results of Operations — Segments

 

We are currently organized into the following segments: Exploration & Production, Gas Pipeline, Midstream, Power, 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 2006

 

In 2006, we focused on our objective to rapidly expand development of our drilling inventory. This resulted in significant growth as evidenced by the following accomplishments:

 

 

Domestic Production

 

 

2006 domestic production grew 23 percent or 140 MMcfe per day over 2005

 

 

The benefit of higher production volumes to operating results was more than offset by the downward trending of natural gas market prices during the year and increased operating costs. The increase in operating costs reflects an increase in our production volumes combined with a general industry condition of greater demand for services and products as production activities increase in our key basins.

 

Significant events

 

At December 31, 2006, all ten new state-of-the-art FlexRig4^® drilling rigs have been placed into service pursuant to our lease agreement with Helmerich & Payne. The March 2005 contract provided for the operation of the drilling rigs, each for a primary lease term of three years. This arrangement supports our continuing objective to

accelerate the pace of natural gas development in the Piceance basin through both deployment of the additional rigs and through the drilling and operational efficiencies of the new rigs.

 

In 2006, we increased our position in the Fort Worth basin by acquiring producing properties and undeveloped leasehold interests for approximately $64 million. These acquisitions increased our diversification into the Mid-Continent region and will allow us to use our horizontal drilling expertise to develop wells in the Barnett Shale formation.

 

Outlook for 2007

 

Our expectations and objectives for 2007 include:

 

 

Approximately 172 MMcfe, or 18 percent, of our forecasted 2007 daily production is hedged by NYMEX and basis fixed price contracts at prices that average $3.90 per Mcfe at a basin level. In addition, we have collar agreements for each month in 2007 as follows:

 

 

We have recently 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.

 

Additional risks to achieving our expectations include weather conditions at certain of our locations during the first and fourth quarters of 2007, drilling rig availability, obtaining permits as planned for drilling, and market price movements.

 

Year-Over-Year Operating Results

 

 

2006 vs. 2005

 

Total segment revenues increased $218.5 million, or 17 percent, primarily due to the following:

 

 

 

To manage the commodity price risk and volatility of owning producing gas properties, we enter into derivative sales contracts that fix the sales price relating to a portion of our future production. Approximately 40 percent of domestic production in 2006 was hedged by NYMEX and basis fixed price contracts at a weighted average price of $3.82 per Mcfe at a basin level compared to 47 percent hedged at a weighted average price of $3.99 per Mcfe in 2005. In addition, approximately 15 percent of domestic production was hedged by the following collar agreements in 2006:

 

 

In 2005, approximately 10 percent of domestic production was hedged by a NYMEX collar agreement for approximately 50 MMcfe per day at a floor price of $7.50 per Mcfe and a ceiling price of $10.49 per Mcfe in the first quarter and at a floor price of $6.75 per Mcfe and a ceiling price of $8.50 per Mcfe in the second, third, and fourth quarters, and a Northwest Pipeline/Rockies collar agreement for approximately 50 MMcfe per day in the fourth quarter at a floor price of $6.10 per Mcfe and a ceiling price of $7.70 per Mcfe.

 

Our hedges are executed with our Power segment, which, in turn, executes offsetting derivative contracts with unrelated third parties. Generally, Power bears the counterparty performance risks associated with unrelated third parties. Hedging decisions are made considering our overall commodity risk exposure and are not executed independently by Exploration & Production.

 

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

 

 

The $35.7 million decrease in segment profit is primarily due to lower net realized average prices and higher costs and expenses as discussed previously, and the absence in 2006 of $29.6 million of gains on the sales of properties in 2005. Partially offsetting these decreases are a 23 percent increase in domestic production volumes sold and an increase in income from ineffectiveness and forward mark-to-market gains. Segment profit also includes an $8 million increase in our international operations primarily due to higher revenue and equity earnings as a result of increases in net realized average prices for crude oil production volumes sold.

 

2005 vs. 2004

 

The $491.5 million, or 63 percent increase in segment revenues is primarily due to an increase in domestic production revenues of $434 million during 2005 reflecting higher net realized average prices and higher production volumes sold. Also contributing to the increase is a $58 million increase in revenues from gas management activities, offset in costs and expenses, and $13 million increased production revenues from our international operations. Partially offsetting these increases is $10 million in net unrealized losses attributable to NYMEX collars from hedge ineffectiveness.

 

The increase in domestic production revenues primarily results from $319 million higher revenues associated with a 42 percent increase in net realized average prices for production sold as well as a $115 million increase associated with an 18 percent increase in average daily production volumes. The higher net realized average prices reflect the benefit of the lower volumes hedged in 2005 as compared to 2004 coupled with higher market prices for natural gas in 2005. The increase in production volumes primarily reflects an increase in the number of producing wells resulting from our successful 2005 drilling program.

 

Approximately 77 percent of domestic production in 2004 was hedged at a weighted average price of $3.65 per Mcfe at a basin level.

 

Total costs and expenses increased $147 million, primarily due to the following:

 

 

These increased costs and expenses are partially offset by the absence in 2005 of a $15.4 million loss provision related to an ownership dispute on prior period production in 2004, a $7.9 million gain on the sale of an undeveloped leasehold position in Colorado in the first quarter of 2005, and a $21.7 million gain on the sale of certain outside operated properties in the Powder River basin area of Wyoming in the third quarter of 2005.

 

The $351.4 million increase in segment profit is primarily due to increased revenues from higher volumes and higher net realized average prices, as well as the gains on sales of assets, partially offset by higher expenses as discussed above. Segment profit also includes a $19 million increase in our international operations reflecting higher revenue and equity earnings resulting from higher net realized oil and gas prices.

 

Gas Pipeline

 

Overview

 

We operate, through our Northwest Pipeline and Transco subsidiaries, approximately 14,400 miles of pipeline from the Gulf Coast to the northeast United States and from northern New Mexico to the Pacific Northwest with a total annual throughput of approximately 2,500 trillion BTUs. Additionally, we hold a 50 percent interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). This asset, which extends from the Mobile Bay area in Alabama to markets in Florida, has current transportation capacity of 1.1 MMdt/d.

 

Our strategy to create value for our shareholders focuses on maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets.

 

Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have little impact on revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

 

Significant events of 2006 include:

 

Filing of rate cases

 

During 2006, Northwest Pipeline and Transco each filed general rate cases with the FERC for increases in rates due to higher costs in recent years. The new rates are effective, subject to refund, in January 2007 for Northwest Pipeline and in March 2007 for Transco. We expect the new rates to result in significantly higher revenues.

 

In January 2007, Northwest Pipeline reached a settlement in its pending rate case. The settlement is subject to FERC approval, which is expected by mid-2007.

 

Gulfstream

 

In March 2006, our equity method investee, Gulfstream, announced a new long-term agreement with a Florida utility company, which fully subscribed the pipeline’s mainline capacity on a long-term basis. Under the agreement, Gulfstream will extend its existing pipeline approximately 35 miles within Florida. The agreement is subject to the approval of various authorities. Construction of the extension is anticipated to begin in early 2008 with a targeted completion of summer 2008.

 

In May 2006, Gulfstream announced a new agreement to provide 155 Mdt/d of natural gas to a Florida utility. In December 2006, Gulfstream filed an application with the FERC seeking approval to expand its pipeline system to provide the additional capacity. Under this agreement, Gulfstream will construct approximately 17.5 miles of 20 inch pipeline and the installation of a new compressor facility. If approved, all of the facilities will be placed into service by January 2009.

 

Parachute Lateral project

 

In August 2006, we received FERC approval to construct a 37.6-mile expansion that will provide additional natural gas transportation capacity in northwest Colorado. The planned expansion will increase capacity by 450 Mdt/d through the 30-inch diameter line and is estimated to cost approximately $86 million. The expansion is expected to be in service in March 2007.

 

Grays Harbor

 

Effective January 2005, Duke Energy Trading and Marketing, LLC (Duke) terminated its firm transportation agreement related to Northwest Pipeline’s Grays Harbor lateral. In January 2005, Duke paid Northwest Pipeline $94 million for the remaining book value of the asset and the related income taxes. We and Duke have not agreed on the amount of the income taxes due Northwest Pipeline as a result of the contract termination. We have deferred the $6 million difference between the proceeds and net book value of the lateral pending resolution of the disputed early termination obligation.

 

On June 16, 2005, we filed a Petition for a Declaratory Order with the FERC requesting that it rule on our interpretation of our tariff to aid in resolving the dispute with Duke. On July 15, 2005, Duke filed a motion to intervene and provided comments supporting its position concerning the issues in dispute.

 

On October 4, 2006, the FERC issued its Order on Petition for Declaratory Order, providing clarification on issues relating to Duke’s obligation to reimburse us for future tax expenses. We reviewed the Order and filed a request for rehearing requesting further clarification of certain items. Based upon the order, as written, we do not anticipate any adverse impact to our results of operations or financial position.

 

Northwest Pipeline capacity replacement project

 

In September 2005, we received FERC approval to construct and operate approximately 80 miles of 36-inch pipeline loop as a replacement for most of the capacity previously served by 268 miles of 26-inch pipeline in the Washington state area. The capacity replacement as well as the abandonment of the old capacity was completed in December 2006. In addition to the capacity replacement, five existing compressor stations were modified, and we increased net horsepower.

 

Outlook for 2007

 

Leidy to Long Island expansion project

 

In May 2006, we received FERC approval to expand Transco’s natural gas pipeline in the northeast United States. The estimated cost of the project is approximately $141 million with three-quarters of that spending expected to occur in 2007. The expansion will provide 100 Mdt/d of incremental firm capacity and is expected to be in service by November 2007.

 

Potomac expansion project

 

In July 2006, we filed an application with the FERC to expand Transco’s existing facilities in the Mid-Atlantic region of the United States by constructing 16.5 miles of 42-inch pipeline. The project will provide 165 Mdt/d of incremental firm capacity. The estimated cost of the project is approximately $74 million, with an anticipated in-service date of November 2007.

 

Year-Over-Year Operating Results

 

 

Significant 2005 adjustments

 

Operating results for 2005 included:

 

 

Our management concluded that the effects of these adjustments were not material to our consolidated results for 2005 or prior periods, or to our trend of earnings.

 

2006 vs. 2005

 

Revenues decreased $65.1 million, or 5 percent, due primarily to $75 million lower revenues associated with exchange imbalance settlements (offset in costs and operating expenses). Partially offsetting this decrease is a $9 million increase in revenue due to an adjustment for the recovery of state income tax rate changes (offset in provision for income taxes).

 

Costs and operating expenses decreased $17 million, or 2 percent, due primarily to:

 

 

Partially offsetting these decreases are:

 

 

SG&A expenses increased $77 million, or 92 percent, due primarily to:

 

 

The $118.4 million, or 20 percent, decrease in segment profit is due primarily to the absence of significant 2005 adjustments as previously discussed, increases in costs and operating expenses and SG&A expenses as previously discussed, and the absence of a $4.6 million construction completion fee recognized in 2005 related to our investment in Gulfstream.

 

2005 vs. 2004

 

The $50.5 million, or 4 percent, increase in Gas Pipeline revenues is due primarily to $86 million higher revenues associated with exchange imbalance cash-out settlements (offset in costs and operating expenses). Partially offsetting this increase is $24 million lower transportation revenues due primarily to the termination of the Grays Harbor contract, and $11 million lower revenues associated with reimbursable costs, which are passed through to customers (offset in costs and operating expenses and SG&A expenses).

 

Costs and operating expenses increased $109 million, or 16 percent, due primarily to:

 

 

Partially offsetting these increases are decreases due to:

 

 

SG&A expenses decreased approximately $38 million, or 31 percent, due to the $17.1 million reduction in pension costs to correct a prior period error, $6 million lower reimbursable costs (offset in revenues), and the reversal of $5.6 million of prior period accruals.

 

Comparative segment profit is unchanged from 2004. The following are significant components of 2005 segment profit: