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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 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 an accelerated filer (as defined in Exchange Act Rule 12b-2).     Yes þ          No o

      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 $6,216,391,365.

      The number of shares outstanding of the registrant’s common stock held by non-affiliates outstanding at February 28, 2005 was 570,051,442.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the registrant’s Proxy Statement being prepared for the solicitation of proxies in connection with the Annual Meeting of Stockholders of the registrant for 2005 are incorporated by reference in Part III of this Form 10-K.

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THE WILLIAMS COMPANIES, INC.

FORM 10-K

TABLE OF CONTENTS

DEFINITIONS

      We use the following oil and gas measurements in this report:

PART I

      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.”

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

      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.

GENERAL

      We are a natural gas company originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. We were founded in 1908 when two Williams brothers began a construction company in Fort Smith, Arkansas.

      Today, we primarily find, produce, gather, process and transport natural gas. 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 February 2003, we announced our business strategy focused on migrating to an integrated natural gas business comprised of a smaller portfolio of natural gas businesses, reducing debt and increasing our liquidity through asset sales, strategic levels of financing and reductions in operating costs. During 2003, we made substantial progress in executing the announced plan. In 2004, we continued to execute certain components, and completed the plan (see Recent Developments for details on the steps of the plan we completed in 2004). In 2004, we continued to focus on disciplined growth, cash management and cost efficiencies.

      With the completion of the 2003 plan and our decision to retain the Power business, we have turned our attention to the creation of superior, sustainable growth through Economic Value Added® (EVA®)¹-based disciplined investments in natural gas businesses. Our strategy going forward is to sustain the strategic and financial discipline followed during the implementation of the 2003 business strategy.

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

RECENT DEVELOPMENTS

      In 2004, we completed key components of our previously announced business strategy through further planned asset sales, additional reductions in costs, and certain debt restructuring objectives. We also continued efforts to pursue growth projects and to address issues surrounding our Power business which we decided in 2004 to continue to operate. An overview of our efforts and progress in these areas and other events follows.

Asset sales

      Planned asset sales during 2004 were expected to generate proceeds of approximately $800 million. On March 31, 2004, we sold our Alaska refinery, and related assets including the retail stores and pipeline for approximately $304 million. In addition, on July 28, 2004, we sold three straddle plants in western Canada for approximately $544 million.

Cost reduction efforts

      In 2004 our selling, general and administrative and general corporate expenses decreased by approximately $33 million. On June 1, 2004, we selected International Business Machines Corporation (IBM) to aid us in transforming and managing certain areas of our accounting, finance and human resources processes. In addition, IBM will manage key aspects of our information technology. As a result of our seven and one-half year agreement, approximately 455 of our former employees were transferred to IBM beginning July 1, 2004.

Debt retirement and restructuring

      In 2004 we continued to reduce debt through scheduled maturities and early redemptions, eliminating approximately $4 billion of indebtedness in 2004. In April 2004, we also replaced our cash-collateralized letter of credit and revolver facility with unsecured facilities that do not encumber cash. In January 2005, these facilities were terminated and replaced with two new facilities that contain similar economic terms but fewer restrictions. For further information about debt retirement and restructuring matters, please see Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 11 of our Notes to Consolidated Financial Statements.

Addressing Power issues

      In September 2004, we announced that we would continue operating our wholesale power business and cease efforts to exit that business. During 2004, we reduced risk from this business through the sale, termination or expiration of certain contracts and through entering into new contracts that economically hedge existing positions. We will continue our current program of managing this business to minimize financial risk, generate cash and manage existing contractual commitments.

      In 2004 we also continued efforts to resolve various legal and regulatory proceedings, challenges and investigations regarding various aspects of the energy marketing and trading business. These matters include refund proceedings, pipeline storage data investigations, California Independent System Operator fines, contract challenges and alleged market manipulation investigations and proceedings. The market manipulation claims include withholding of generating capacity, reporting of inaccurate data to a trade periodical developer of natural gas indices and other alleged market gaming. Certain of these matters are also the subject of civil litigation. During the year, we entered into a settlement with major California utilities and others that resolved issues related to refunds for wholesale power sales in California. However, many challenges, legal actions and investigations are ongoing and could have a material negative effect on us. For further information about investigations and proceedings involving energy trading practices, see Note 15 of our Notes to Consolidated Financial Statements.

Disciplined growth

      Since February 2004, we continued to focus on disciplined growth. Our growth achievements in 2004 included, among others:

Other events

      On May 26, 2004, we announced an agreement to effectively release us from certain historical indemnities related to our previous ownership of operations, such as the Williams Pipe Line system, that are now owned by Magellan Midstream Partners, L.P. (Magellan). In June 2003 we divested interests in Magellan but retained certain environmental and other indemnification obligations. Under the terms of the agreement, we will pay a total of $117.5 million to Magellan through four structured annual payments beginning July 1, 2004 and ending July  1, 2007. In exchange, Magellan released us from certain historical indemnities, primarily related to environmental remediation.

FINANCIAL INFORMATION ABOUT SEGMENTS

      See Note 18 of our Notes to Consolidated Financial Statements for information with respect to each segment’s revenues, profits or losses and total assets.

BUSINESS SEGMENTS

General overview

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

      This report is organized to reflect this structure.

      An overview and detailed discussion of each of our business segments follows.

Power

      From June 2002 to September 2004, we pursued a strategy to exit the power business and substantially reduce our financial commitment to our Power segment. During this period, we continued to operate and manage the risk associated with our remaining contracts and our assets in order to maximize cash flow and, where possible, reduce risk within the portfolio. However, in September 2004, we announced our decision to continue operating the power business and cease efforts to exit that business. As a result, Power now focuses not only on its objective of maximizing expected cash flows, but also on executing new contracts to hedge its portfolio and providing functions that support our natural gas businesses. 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 and tolling resales, which are explained in the next three paragraphs. Through our contracts, we buy, sell, store and transport energy and energy-related commodities, primarily power and natural gas.

      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 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 counterparty-tailored arrangements known as 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 1,869 megawatts of electricity to our customers in Georgia and Pennsylvania.

      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 (1,045 to 1,175 megawatts) under the California tolling arrangement to the California Department of Water Resources through 2010.

      Additionally, we have rights to sell energy and capacity from two natural gas-fired electric generating plants owned by affiliated companies and located near Bloomfield, New Mexico (60 megawatts, Milagro facility) and in Hazleton, Pennsylvania (147 megawatts).

      In 2004, we marketed natural gas throughout North America with total physical volumes averaging 2.5 billion cubic feet per day. With approximately 10 percent of this natural gas, we 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, sell gas produced by Exploration & Production and manage firm service contracts for Gas Pipeline.

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

      In 2003, we substantially exited our European activities, which had been conducted through our London office.

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

      In 2004, Power managed 2.5 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, 2004, our Power segment had approximately 284 customers compared with 234 customers at the end of 2003.

      Our Power business is subject to a variety of laws and regulations at the local, state and federal levels. The Federal Energy Regulatory Commission (FERC) and the Commodity Futures Trading Commission regulate

us. 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. On December 17, 2004, a former trader with Power pled guilty to manipulation of gas prices through misreporting to an industry periodical. The Department of Justice’s (DOJ) investigation of us in this matter is continuing and it is reasonably possible that material penalties could result. However, a reasonable estimate of such amount cannot be determined at this time. Power has also been named as a defendant in class-action lawsuits related to reporting to natural gas trade periodicals. Discussions in California and other states have ranged from threats of re-regulation to suspension of plans to move forward with deregulation. Allegations have also been made that wholesale price increases resulted from the exercise of market power and collusion of the power generators and sellers, such as Power. These allegations have resulted in multiple state and federal investigations as well as the filing of class-action lawsuits in which we are named a defendant. Our long-term power contract with the California Department of Water Resources has also been challenged both at the FERC and in civil suits. On November 11, 2002, we executed a settlement agreement that resolved many of these disputes with the State of California with respect to non-criminal matters. This settlement agreement includes renegotiated long-term energy contracts. The settlement also resolved complaints brought by the California Attorney General against us and the State of California’s refund claims. In addition, the settlement resolved ongoing investigations by the States of California, Oregon, and Washington. The settlement closed December 31, 2002, although aspects of the settlement regarding certain class-action lawsuits are on appeal. Notwithstanding this settlement, numerous investigations and actions related to the Power segment remain. We may be liable for refunds and other damages and penalties as a result of the above actions and investigations. We discuss each of these matters as well as other regulatory and legal matters in more detail in Note 15 of our Notes to Consolidated Financial Statements. 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.

      We compete directly with large independent energy marketers, marketing affiliates of regulated pipelines and utilities and natural gas producers. We also compete with both brokerage houses and other energy-based companies offering similar services. Since 2002, we have fewer competitors due to the exit of independent energy marketers from the marketplace and the exit of utilities from financial merchant activities. We anticipate more competition in the future from brokerage houses, which are increasing their trading activity.

      Due to our current credit rating, certain counterparties request adequate assurance or prepayment in support of business transactions. In addition, we fund normal margin requirements with cash, letters of credit or other negotiable instruments as called for under standard industry agreements. As our credit and liquidity continue to improve, we are able to negotiate lower collateral requirements with certain counterparties.

      Certain of our counterparties have experienced significant declines in their financial stability and creditworthiness, which may adversely impact their ability to perform under contracts. Revenues from one counterparty, which has a credit rating below investment grade, constitutes approximately five percent of Power’s gross revenues. Our exposure to this counterparty is mitigated by the existence of a netting arrangement. In conjunction with our previous efforts to sell or liquidate all or portions of our portfolio, we closed out or sold positions with a number of counterparties in 2004. Credit constraints and financial instability of market participants are expected to continue in 2005. These factors may also significantly impact our ability to manage market risk.

      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. As discussed further in Note 1 of our Notes to Consolidated Financial Statements, derivative contracts in our portfolio have been recognized at their estimated fair value. According to generally accepted accounting principles (GAAP), fair

value is the amount at which an instrument could be exchanged in a current transaction between willing parties other than in a forced liquidation or sale. Non-derivative contracts are not recognized until revenue is earned or expenses have been incurred. With our September 2004 decision to continue operating the Power business, Power became eligible for hedge accounting under Statement of Financial Accounting Standard (SFAS) 133 on October 1, 2004. Under hedge accounting, future changes in fair value are reported as changes in other comprehensive income within the stockholders equity section of the balance sheet. Upon adoption of hedge accounting on October 1, 2004, certain existing derivative contracts, which already had significant fair value which had been previously recognized in earnings as unrealized gains or losses, were designated as hedges. Because the derivative contracts qualifying for hedge accounting already had significant fair value which had been recognized as unrealized gains or losses prior to October 1, 2004, the amounts recognized in future earnings under hedge accounting with respect to these derivatives will not equal the amount of cash flows realized from the settlement of those derivatives. Therefore, while future earnings will reflect any losses from transactions that have been hedged by the derivatives, such future earnings will not reflect the amounts realized from hedges that were previously recognized as mark-to-market unrealized gains or losses prior to the adoption of hedge accounting. However, cash flows from Power’s portfolio will reflect the net amount from both the hedged transactions and the hedges.

      Our generation facilities are subject to various environmental laws and regulations, including those regarding emissions. We believe compliance with various environmental laws and regulations will not have a material adverse effect on capital expenditures, earnings or competitive position. However, these laws and regulations may affect facility availability from time to time.

Gas pipeline

      We also own a 50 percent interest in the Gulfstream Natural Gas System, L.L.C. (Gulfstream).

      We own and operate, through Williams Gas Pipeline Company, LLC and its subsidiaries (Gas Pipeline), a combined total of approximately 14,700 miles of pipelines with a total annual throughput of approximately 2,600 trillion British Thermal Units of natural gas and peak-day delivery capacity of approximately 12 MMdt of gas. Gas Pipeline consists of Transco and Northwest Pipeline. Gas Pipeline also holds interests in joint venture interstate and intrastate natural gas pipeline systems including a 50 percent interest in Gulfstream.

      Construction of the Gulfstream gas pipeline project which consists of a natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, commenced in June 2001. 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 estimated capital cost of both phases of the project is approximately $1.7 billion. At December 31, 2004, our investment in Gulfstream was $726 million.

      Gas Pipeline jointly pursued a project known as the Georgia Strait Crossing Pipeline Project (GSX) with BC Hydro, in part to meet the needs of the Vancouver Island Generation Plant. On April 24, 2001 Gas Pipeline and BC Hydro filed separate applications with the FERC and Canada’s National Energy Board (NEB) to construct and operate a new pipeline to provide firm transportation capacity from Sumas,

Washington to Vancouver Island, British Columbia. On September 20, 2002, the FERC issued an order approving the construction and operation of the U.S. portion of the project. A NEB certificate approving the project in Canada was issued on December 15, 2003. In December 2004, Gas Pipeline and BC Hydro mutually agreed to discontinue development of the project. Under terms of the agreement with Gas Pipeline, BC Hydro assumes full responsibility for all project costs.

      Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC 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, the extension, enlargement or abandonment of jurisdictional facilities and accounting, 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 by Title I of the Pipeline Safety Act of 1979 and the Pipeline Safety Improvement Act of 2002, which regulate safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. Cardinal Pipeline Company, LLC, an intrastate natural gas pipeline company that is operated and 45 percent owned by Gas Pipeline, is subject to the jurisdiction of the North Carolina Utilities Commission.

      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 (1) costs of providing service, including depreciation expense, (2) allowed rate of return, including the equity component of the capital structure and related income taxes and (3) volume throughput assumptions. 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. See Note 15 of our Notes to Consolidated Financial Statements for the amounts accrued for potential refund at December 31, 2004.

      The FERC has taken various actions to strengthen market forces in the natural gas pipeline industry which has led to increased competition throughout the 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, and regulatory developments. Future utilization of pipeline capacity will depend on competition from other pipelines, use of alternative fuels, the general level of natural gas demand, and weather conditions. Electricity and distillate fuel oil are the primary competitive forms of energy for residential and commercial markets. Coal and residual fuel oil compete for industrial and electric generation markets. Nuclear and hydroelectric power and power purchased from electric transmission grid arrangements among electric utilities also compete with gas-fired electric generation in certain markets.

      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 since 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 capacity turnback, although competition may cause some of the remarketed capacity to be sold at lower rates or for shorter terms.

      Several state jurisdictions have been involved in implementing changes similar to the changes that have occurred at the federal level. New York, New Jersey, Pennsylvania, Maryland, Georgia, Delaware, Virginia, California, Wyoming, and the District of Columbia are currently at various points in the process of unbundling services at local distribution companies. We expect the implementation of these changes to encourage greater competition in the natural gas marketplace.

      Each of our interstate natural gas pipeline companies generally owns its facilities, although some facilities are held jointly with third parties. However, a substantial portion of each pipeline company’s facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses or consents on and across properties owned by others. Our compressor stations and appurtenant facilities are located on lands owned by us or on sites leased from or permitted by public authorities. The storage facilities are either owned or held under long-term leases or easements.

      Each of our interstate natural gas pipelines is subject to the National Environmental Policy Act and federal, state and local laws and regulations relating to environmental protection. We believe that, with respect to any capital expenditures and operation and maintenance expenses required to meet applicable environmental standards and regulations, the FERC would grant the requisite rate relief so that our pipeline companies could recover most of the cost of these expenditures in their rates. For this reason, we believe that compliance with applicable environmental requirements by the interstate pipeline companies is not likely to have a material adverse effect upon our earnings or competitive position.

      For a discussion of specific environmental issues involving the interstate pipelines, including estimated cleanup costs associated with certain pipeline activities, 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.

      A business description of the principal companies in the interstate natural gas pipeline group follows.

      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 eleven southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, New York, New Jersey, and Pennsylvania. Effective May 1, 1995, Transco transferred the operation of certain production area facilities to Williams Field Services Group, Inc. (Williams Field Services), an affiliated company and part of the Midstream segment. Effective June 1, 2004 and due in part to FERC Order No. 2004, the operation of the production area facilities was transferred back to Transco.

      At December 31, 2004, 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 that originates at the Canadian border in western New York along with market-area storage capacity, Transco can deliver an additional 3.4 MMdt of natural gas per day for a system-wide delivery capacity total of approximately

8.1 MMdt of natural gas per day. Transco’s system includes 44 compressor stations, five underground storage fields, two liquefied natural gas (LNG) storage facilities and four processing plants. 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 11 percent of Transco’s total revenues in 2004. 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 a 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, an LNG storage facility with four 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.

      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 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.

      At December 31, 2004, 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 4,200 miles of mainline and lateral transmission pipelines and 42 compressor stations having sea level-rated capacity of approximately 462,000 horsepower.

      In December 2003, we received an Amended Corrective Action Order (ACAO) from the U.S. Department of Transportation’s Office of Pipeline Safety (OPS) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003, and we subsequently idled the pipeline segment until its integrity could be assured.

      By June 2004, we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 Mdt/d of the 360 Mdt/d of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

      The restored facilities will be monitored and tested as necessary until they are ultimately replaced. Through December 31, 2004 approximately $40 million had been spent on testing and remediation, including approximately $9 million related to one segment of pipe that we recently determined not to return to service and was therefore written off in the second quarter of 2004. We estimate the total testing and remediation costs will be between $40 million to $45 million.

      On October 4, 2004, we received a notice of probable violation (NOPV) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on

one of the segments covered under the original CAO. This penalty was accrued in the third quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to prevent similar occurrences in the future. We requested a hearing on the proposed OPS civil penalty, which was held in Denver, Colorado on December 15, 2004. OPS will issue its decision in the near future.

      As required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 Mdt/d of capacity being relinquished and incorporated into the replacement project. On November 29, 2004, we filed with the FERC a certificate application for the “Capacity Replacement Project” including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

      In 2004, Northwest Pipeline served a total of 175 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 2004 accounted for approximately 13.9 percent and 11.3 percent, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2004. 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 a 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.

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

Exploration & production

      We also own and manage certain international oil and gas investments, including a 69 percent equity investment in APCO Argentina Inc., an oil and gas exploration and production company whose securities are traded on the NASDAQ under symbol APAGF.

      Our Exploration & Production segment, which is comprised of several wholly 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 and Mid-Continent 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 and Arkoma 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, an oil and gas exploration and production company with operations in Argentina, and a 10 percent interest in the La Concepcion area located in western Venezuela.

      Exploration & Production’s primary strategy is to utilize its expertise in the development of tight-sands 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 nearly 55 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.

      Certain exploration and production assets managed through RMT serve as collateral for a $500 million term loan facility established in May 2003 and amended in February 2004. This facility, as amended in February 2004, matures May 30, 2008 and represents a first priority lien on substantially all our Piceance and Powder River basin assets and any future assets in these basins.

      Exploration & Production’s properties are located primarily in the Rocky Mountain and Mid-Continent regions of the United States. Rocky Mountain properties are located primarily in New Mexico, Wyoming and Colorado. All our Mid-Continent properties are located in Oklahoma. 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.

      The Piceance Basin is located in northwestern Colorado, where we primarily target the tight sands contained within the Williams Fork Mesaverde formation. The Piceance Basin is our largest area of concentrated development comprising approximately 61 percent of our proved reserves. This area has approximately 1,200 undrilled proved locations in inventory. Within this basin, we are the owner and operator of a natural gas gathering system and, thus, have the ability to gather, process and deliver to one intrastate and four interstate pipelines. In 2004, we drilled 270 gross wells and produced a net of approximately 81 billion cubic feet equivalent (Bcfe) of natural gas from the Piceance Basin. Our estimated proved reserves in the Piceance Basin at year-end 2004 were 1,830 Bcfe. During 2004 we began drilling in Trail Ridge and Ryan Gulch, two new areas within the Piceance Basin. In addition to the 270 gross wells drilled in the basin as previously referenced, we drilled four wells at Trail Ridge and three wells at Ryan Gulch for a total of 277 gross wells drilled in the Piceance Basin.

      The San Juan Basin is a large gas producing area, located in northwest New Mexico and southwest Colorado. We produce natural gas primarily from the Fruitland Coal, Mesaverde, Pictured Cliffs and Dakota formations. In 2004, we participated in the drilling of 241 gross wells, of which we operate 35, and produced a net of approximately 55 Bcfe from the San Juan Basin. Our estimated proved reserves in the San Juan Basin at year-end 2004 were 671 Bcfe.

      Located in northeast Wyoming, the Powder River Basin includes large areas with multiple coal seam potential, targeting thick coal bed methane formations at shallow depths. We are one of the largest natural gas producers in the Powder River Basin and operate approximately half of our large leasehold position in the basin, where we own an interest in approximately 1,000,000 gross acres. We operate approximately 2,300 wells in the basin and have an interest in approximately 2,400 additional wells. We have a significant inventory of undrilled locations, providing long-term drilling opportunities. In 2004, we drilled 723 gross wells from this basin, of which we operate 387, and produced a net of approximately 43 Bcfe of natural gas. Our estimated proved reserves in the Powder River Basin at year-end 2004 were 304 Bcfe, which includes approximately 5 Bcfe of reserves from conventional properties.

      Our Arkoma Basin properties are located in southeastern Oklahoma. Our production from the Arkoma Basin is primarily from the Hartshorne coal bed methane formation. We utilize horizontal drilling technology to develop the coal seams. We own and operate a natural gas gathering system, which enables us to move our natural gas production out of the basin. In 2004, we drilled 99 gross wells, of which we operate 49, and produced a net of approximately 7 Bcfe of natural gas. Our estimated proved reserves in the Arkoma Basin at year-end 2004 were 121 Bcfe.

      We have production in other areas including the Green River in southwest Wyoming and in the Gulf Coast region. These properties represent approximately two percent of our estimated proved reserves.

      The following table summarizes our 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, 2004:

      No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2004. 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, 2004, 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 99 percent of our year-end 2004 United States proved reserves estimates were either audited by Netherland, Sewell & Associates, Inc., or, in the case of reserves estimates related to properties underlying the Williams Coal Seam Gas Royalty Trust, were prepared by Miller and Lents, LTD.

      The following table summarizes our leased acreage as of December 31, 2004:

      At December 31, 2004, we owned interests in 10,001 gross producing wells (4,616 net) on our leasehold lands.

      We focus on lower-risk development drilling. Our drilling success rate was over 99 percent in 2004 and 99 percent in 2003. 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. Because we currently have a low-risk drilling program in proven basins, the main component of risk that we manage is price risk. Exploration & Production has entered into derivative contracts with Power that hedge 286 BBtud in fixed price hedges (whole year) and 50 Bbtud in collars for January through March for projected 2005 domestic natural gas production. Power then enters into offsetting derivative contracts with unrelated third parties. 400 BBtud of our natural gas production in 2004 was hedged. 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 sales and cost information for the year indicated:

      Exploration & Production purchased additional producing properties and acreage positions in our existing basins for a total cash price of $21 million. The $21 million includes 1.4 MMcf/d of net production and 24.4 Bcfe in proved reserves, along with new acreage for future drilling opportunities on probable and possible reserve locations.

      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.

      Our operations are subject to complex environmental laws and regulations adopted by the various 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, including responsibility for remedial costs. We could potentially discharge such materials into the environment in many ways including:

      Because the requirements imposed by such 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, because we acquire properties that have been operated in the past by others, we may be liable for environmental damage caused by such former operators.

      The natural gas industry is highly competitive. We compete 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 the acquisition of oil and gas properties and obtaining necessary equipment, supplies and services. We also compete in recruiting and retaining skilled employees.

      The majority of our ownership interest in exploration and production properties is held as working interests in oil and gas leaseholds.

      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 representing 36.8 percent of outstanding trust units. During 2000, we sold all of our trust units as part of a Section 29 tax credit transaction, in which we retained an option to repurchase the units. We registered the units with the SEC and had been repurchasing the units and reselling the units on the open market from time to time. In June 2003, we repurchased the remaining 2,408,791 trust units covered by the repurchase option. As of March 1, 2005, we own 995,791 trust units.

      We also have investments in international oil and gas interests. We own approximately a 69 percent interest in APCO Argentina Inc. (APCO Argentina), an oil and gas exploration and production company with operations in Argentina. APCO Argentina’s principal business is its 52.9 percent interest in the Entre Lomas concession in southwest Argentina. It also owns an 82 percent interest in the Canadon Ramirez concession, a 50 percent interest in the Capricorn Exploration Permit and a 1.5 percent interest in the Acambuco concession. We also own a direct 1.5 percent interest in Acambuco through our Northwest Argentina subsidiary. In Venezuela, we own a 10 percent interest in the La Concepcion area, located in Western Venezuela, near Lake Maracaibo. If combined with our domestic proved reserves, these interests would make up 6.7 percent of our total proved reserves.

Midstream

      Our Midstream segment, one of the nation’s largest natural gas gatherers and processors, has primary service areas concentrated in the major producing basins of San Juan, Wyoming, the Gulf of Mexico, Venezuela and Western Canada. Our 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. 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 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 an exposure similar to our “Keep Whole” contracts. We are exposed to the spread between the price for natural gas and the 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.

      Key variables for our business will continue to be (1) the revenue growth associated with additional infrastructure completed in late 2003 and 2004 in the deepwater portion of the Gulf of Mexico, (2) disciplined growth in our core service areas, and (3) the prices impacting our commodity-based processing and olefin activities.

      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 80 percent of our Exploration & Production group’s wellhead production in this basin. Several of our western gathering systems serve as critical sources of supply for Northwest Pipeline customers.

      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 8,100 miles of gathering pipelines, nine processing plants (one partially owned) and six natural

gas treating plants with a combined daily inlet capacity in excess of 5.3 billion cubic feet per day. 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 recently completed Mountaineer crude oil pipeline in the deepwater Gulf of Mexico that serves the Dominion Exploration & Production-operated Devils Tower field. See Gathering and processing — deepwater projects below.

      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 50 percent 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.

      Effective June 1, 2004, and due in part to our response to FERC Order 2004, management, operations and decision-making control of certain regulated gathering assets in the Midstream segment was transferred to the Gas Pipeline segment. These assets were owned by Transco, but were commercially and physically operated by Midstream. We also requested and were granted a partial waiver allowing us to continue to manage and operate the Discovery Gas Transmission and Black Marlin assets. In order to comply with the remaining provisions of the FERC order, we determined it was necessary to transfer the management of our equity investment in the Aux Sable processing plant to Power. This transfer was effective September 21, 2004.

      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. During the fourth quarter of 2004, we closed on the sale of our interest in an associated ethane/ ethylene storage and transportation complex located in Choctaw, Louisiana. We continue to own a major ethane pipeline system in Louisiana.

      Our Gulf Liquids New River LLC (Gulf Liquids) business consists of two refinery off-gas processing facilities, an olefins fractionator and propylene splitter and connecting pipeline system in Louisiana. We continue to market Gulf Liquids with the expectation that these assets will be sold by the end of the second quarter 2005.

      Our Venezuelan investments involve gas compression and gas processing and natural gas liquids fractionation operations. We own controlling interests in three gas compressor facilities which provide roughly 65 percent of the gas injections in eastern Venezuela. These facilities help stabilize the reservoir and enhance the recovery of crude oil by re-injecting natural gas at high pressures. 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.

      Prior to 2003, our Venezuelan operations included an operations contract for an oil loading and storage facility. We operated these facilities on behalf of Petróleos de Venezuela, S.A. (PDVSA), the state owned petroleum corporation of Venezuela, the owner of these facilities. In December 2002, we were removed as operator of these facilities in connection with the nationwide strike within Venezuela. We are presently in arbitration with PDVSA regarding the termination of this contract.

      Our Canadian operations include an olefin liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. These facilities extract olefin liquids from the off-gas produced from oil sands bitumen upgrading and then fractionate, treat, store and terminal the propane and propylene recovered from this process. During 2004, approximately 1.9 million barrels of propane and 129 million pounds of polymer grade propylene were produced. We continue to be the only olefins fractionator in Western Canada and the only treater/processor of oil sands off-gas. These operations extract valuable

petrochemical feedstocks from tar sands refinery off-gas streams allowing our customers to burn cleaner natural gas streams and reduce overall air emissions.

      We sold our three straddle plants in Western Canada to Inter Pipeline Fund of Calgary on July 28, 2004. The sale included our 100 percent ownership interest in the Cochrane and Empress II plants, and our 50 percent interest in the Empress V facility.

      We own interests in and/or operate natural gas liquid fractionation and storage assets. These assets include two partially owned natural gas liquid fractionation facilities near McPherson, Kansas and Baton Rouge, Louisiana that have a combined capacity in excess of 160,000 barrels per day. We also own approximately 20 million barrels of natural gas liquid storage capacity in central Kansas.

      In the first quarter of 2004, we began processing additional gas volumes at our Opal processing plant following an expansion completed by Willbros Mt. West, Inc., a business unit of Willbros Group, Inc. The new volumes are being produced by affiliates of Shell Exploration & Production Company in southwestern Wyoming’s Pinedale Anticline and other area producers. This expansion involved the construction of a fourth cryogenic processing train at our existing gas plant in Opal, Wyoming.

      We operate the new unit under a long-term agreement with Willbros Mt. West. The terms of the agreement provide for revenue opportunities to both parties. This project boosts Opal’s overall processing capacity from 750 MMcf/d to more than 1.1 billion cubic feet per day, with the ability to recover in excess of 50 Mbbls/d of NGL products. At the end of 2004, the gas volumes processed at the Opal plant were over 1.1 billion cubic feet per day.

      From the Opal plant, gas can be delivered to markets throughout the West Coast and in the Rockies via connections to three interstate pipelines — Colorado Interstate Pipeline, Kern River Pipeline and our own Northwest Pipeline.

      The deepwater Gulf continues to be an attractive growth area for our Midstream business. Investments like our Alpine pipeline and Devils Tower production facilities continue to increase our fee-based business and our scale in the Gulf.

      Our new floating production system and associated pipelines, Devils Tower, became operational 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. 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 110 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 line consists of 18-inch diameter pipe. The 117-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 natural gas liquids. The oil is transported to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana.

      Our 18-inch oil pipeline, Alpine, which became operational on December 14, 2003 is averaging approximately 17.6 Mbbls/d for the fourth quarter of 2004. 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 Oil & Gas Corporation, a wholly-owned subsidiary of Kerr-McGee Corporation.

      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.

      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 2004, these operations gathered and processed gas for approximately 200 gas gathering customers and 100 processing customers. Our top three gathering and processing customers accounted for about thirty percent (30%) of our domestic gathering revenue and processing gross margin. Our gathering and processing agreements are generally long-term agreements.

      In addition to our gathering and processing operations, we also 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 PDVSA. The significant contracts have a remaining term between 13 and 17 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. During 2004, Venezuelan President Hugo Chavez successfully defeated a referendum vote calling for his removal from office. The internal political situation has enjoyed relative calm since the conclusion of the referendum. However, President Chavez has confirmed his public criticism of U.S. policy and has implemented unilateral changes to existing energy related contracts, indicating that a level of political risk still remains.

      The following table summarizes our significant operating statistics for Midstream (as restated, see Note 1 of our Notes to Consolidated Financial Statements):

      Under the NGA, gathering and processing facilities and services are generally not subject to the regulatory authority of the FERC. Onshore gathering is reserved to the states and offshore gathering is subject to the Outer Continental Shelf Lands Act (OCSLA).

      Of the states where Midstream operates, currently only Kansas and Texas actively regulate gathering activities. Those states regulate 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, 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’s business operations are subject to various federal, state, and local environmental and safety laws and regulations. The Discovery and Black Marlin pipeline systems are subject to FERC regulation common to interstate gas transmission. Midstream’s liquid pipeline operations are subject to the provisions of the Hazardous Liquid Pipeline Safety Act. Certain of our pipelines also file tariff rates covering intrastate movements with various state commissions. The United States Department of Transportation has prescribed safety regulations for common carrier pipelines. The pipeline systems are subject to various state laws and regulations concerning safety standards, exercise of eminent domain, and similar matters. The Kansas Department of Health and Environment has adopted new regulations to govern underground storage in Kansas, which will require additional equipment and testing for Midstream’s storage operations in Kansas.

      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.

      The gathering and processing business is a regional business 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. Our focus is to provide our customers with the most reliable and consistent service at a competitive price.

      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 the willingness of the provider to process for either a fee or for liquids taken in-kind. Our gathering and processing services are generally covered by long-term contracts with applicable acreage or reserve dedications. The active drilling programs near our relatively large positions in the San Juan Basin, Wyoming area and Gulf Coast Region indicate that demand for future gathering and processing infrastructure and services should continue.

      We typically own our gathering and processing facilities. We construct and maintain gathering pipeline systems pursuant to rights-of-way, easements, permits, licenses, and consents on and across properties owned by others. Some portion of the compression equipment used to lower field pressures to the natural gas wells that we gather is leased. The compressor stations and gas processing and treating facilities are located in whole or in part on lands owned by our subsidiaries or on sites held under leases or permits issued or approved by public authorities.

Other

      At December 31, 2003, we owned approximately 32% of Longhorn which owns a refined petroleum products pipeline from Houston, Texas to El Paso, Texas. During February 2004, we participated in a recapitalization plan completed by Longhorn, following which our subsidiaries, Longhorn Enterprises of Texas, Inc. (LETI) and Williams Petroleum Services, LLC (WPS), together own, directly or indirectly, approximately 94.7% of the Class B Interests in Longhorn Pipeline Investors, LLC (Pipeline Investors) and

approximately 21.3% of the Common Interests therein. Pipeline Investors now indirectly owns Longhorn. The recapitalization provided the funds necessary to complete final construction and start-up of the pipeline, and operations commenced in January 2005. As part of the recapitalization, LETI sold a portion of its limited partner interests in Longhorn for $11.4 million, and LETI and WPS sold a portion of the debt owed to them individually by Longhorn for approximately $58 million. In addition, in exchange for the Common Interests described above, LETI contributed the remaining balance of its limited partnership interests, and WPS contributed all of its general partnership interests in the general partner of Longhorn. LETI and WPS also exchanged the remaining debt owed by Longhorn for the Class B Interests described above. The Class B Interests are preferred interests but subordinate to the new investors’ preferred interests, and the Common Interests are subordinate to both.

Additional business segment information

      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 2002, 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 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 many 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, we are required by counterparties 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.

ENVIRONMENTAL MATTERS

      In addition to the environmental matters included in the business segment discussions above, a description of environmental claims is included in Note 15 of our Notes to Consolidated Financial Statements and is incorporated herein by reference.

EMPLOYEES

      At February 28, 2005, we had approximately 3,656 full-time employees including 728 at the corporate level, 141 at Power, 1,562 at Gas Pipeline, 411 at Exploration & Production, and 814 at Midstream. None of our employees are represented by unions or covered by collective bargaining agreements.

FORWARD LOOKING STATEMENTS/ RISK FACTORS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

      Certain matters discussed in this annual report, excluding historical information, include forward-looking statements — statements that discuss our expected future results based on current and pending business

operations. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

      All statements, other than statements of historical facts, included in this Form 10-K which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. Forward-looking statements can be identified by words such as “anticipates,” “believes,” “could,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, such things as:

      These statements are based on certain assumptions and analysis made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

      These risks and uncertainties include:

See the “Risk Factors” section of this report for a more detailed discussion of these risks and uncertainties. When considering forward-looking statements, one should keep in mind the risk factors described in “Risk Factors” below. The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

RISK FACTORS

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

Risks related to our business

      Although we have risk measurement systems in place that use various methodologies to quantify risk, these systems might not always be followed or might not always work as planned. Further, such risk measurement systems do not in themselves manage risk, and adverse changes in energy commodity market

prices, volatility, adverse correlation of commodity prices, the liquidity of markets, and changes in interest rates might still adversely affect our earnings and cash flows and our balance sheet under applicable accounting rules, even if risks have been identified.

      To lower 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. Substantial declines in market liquidity, however, as well as our current credit rating, and termination of existing positions (due for example to credit concerns) have greatly limited our ability to hedge risks identified and have caused previously hedged positions to become unhedged. To the extent we have unhedged positions, fluctuating commodity prices could cause our net revenues and net income to be volatile.

      Some of the hedges of our tolling contracts are more effective than others in reducing economic risk and creating future cash flow certainty. For example, we may resell our rights under a tolling contract through a forward contract, which has terms that match those of the tolling contract. This type of forward contract would be very effective at hedging not only the commodity price risk but also the volatility risk inherent in the tolling contract. However, this forward contract would not hedge the tolling contract’s counterparty credit or performance risk. A default by the tolling contract counterparty could result in a future loss of economic value and a change in future cash flows. Other economic hedges of the tolling contract, including full requirements contracts, forward physical commodity contracts and financial swaps and futures, could also effectively hedge the commodity price risk of a tolling contract. However, these types of contracts would be less effective or ineffective in hedging the volatility risk associated with the tolling contract because they do not possess the same optionality characteristics as the tolling contract. These other contracts would also be ineffective in hedging counterparty credit or performance risk.

      We manage counterparty credit risk at the enterprise level for our unregulated businesses and at the business unit level for our regulated business. Risk is managed within the guidelines established by our Credit Policy. We believe that the application of the requirements under the credit policy and the associated control framework, along with our analytical capabilities inherent in our credit system, will enhance our ability to manage counterparty credit risk. However, we might not be able to successfully manage all credit risk and as such, future cash flows could be impacted by counterparty default.

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

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

      Historically, the markets for these commodities have been volatile and they 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:

      These factors and the volatility of the energy markets make it extremely difficult to predict future electricity and gas price movements with any certainty. Further, electricity and gas prices do not necessarily move in tandem.

      Our portfolios consist 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, we could realize material losses from our marketing. 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. In such event, 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 lose money.

      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.

      Revenues from our businesses, 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 hot summer months, with market prices also peaking at that time. In other areas, demand for power peaks during the winter. In addition, demand for 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 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 gas transmission arrangements relative to demand created by unusual weather patterns.

      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 or other financing on suitable terms, could adversely affect the ability of certain customers to honor their obligations with respect to such projects or investments and could impair our ability to enforce our rights under agreements relating to such projects or investments.

      Operations in foreign countries also can present currency exchange rate and convertibility, inflation and repatriation risk. In certain conditions under which we develop or acquire projects, or make investments, economic and monetary conditions and other factors could affect our ability to convert 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 could reduce the amount of cash and income we receive from these foreign subsidiaries. While we believe we have hedges and contracts in place to mitigate our most significant foreign currency exchange risks, our hedges might not be sufficient or we might have some exposures that are not hedged which could result in losses or volatility in our revenues.

      Our debt agreements contain covenants that 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.

      Although we are currently in compliance with our financial and other covenants in our debt agreements, our failure to comply with such financial or other covenants could result in events of default. Upon the occurrence of an event of default under our debt agreements, 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. By reason of cross-default or cross-acceleration provisions in certain of our debt agreements, such a default or 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, and the lenders under the affected debt agreement 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.

Risks related to the regulation of our businesses

      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, including California, 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. We cannot assure you that other proposals to re-regulate will not be made or that legislative or other attention to the electric power restructuring process will not cause the deregulation process to be delayed or reversed.

      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 have failed to provide fair and equal access to their transmission systems or have not provided sufficient transmission capacity to enable other companies to transmit electric power. We cannot predict whether and to what extent the industry will comply with these initiatives, or whether the regulations will fully accomplish the FERC’s objectives.

      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, independent system operators or other marker operators, we can offer no assurance that we will be able to operate profitably in all wholesale power markets.

      Our interstate 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:

      The FERC has taken certain actions to strengthen market forces in the natural gas pipeline industry that has 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 economic and other considerations.

      Our results are likely to be affected by differences in the market and transmission regulatory structures in various regional power markets. Problems or delays that might arise in the formation and operation of new regional transmission organizations (RTOs) might restrict our ability to sell power produced by our generating capacity to certain markets if there is insufficient transmission capacity otherwise available. The rules governing the various regional power markets might also change from time to time which could affect our costs or revenues. Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will develop and evolve or what regions they will cover, we are unable to assess fully the impact that these power markets might have on our business.

Risks related to legal proceedings and governmental investigations

      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, including a DOJ investigation and private class actions and shareholder lawsuits in which we are a named defendant.

      Such 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 against us arising out of the operation of our Power business, our former telecommunications subsidiary, or other matters related to our ongoing business include environmental matters, disputes over gas measurement and royalty payments, ERISA litigation, shareholder class action suits, regulatory appeals and similar matters. Any or all of these 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 affecting our strategy and financing needs

      In June 2002, we announced our intention to exit the wholesale power and energy trading business and divest our trading portfolio. We have since decided to maintain our wholesale power and energy trading business and trading portfolio.

      Therefore, the legacy issues arising out of the 2000-2001 energy crisis in California, the resulting collapse in energy merchant credit and volatility in natural gas prices, the Enron Corporation bankruptcy filing, and investigations by governmental authorities into energy trading activities and increased litigation related to such inquiries, could continue to affect us in the future.

      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. Additionally, certain market disruptions or a further downgrade of our credit rating might further increase our cost of borrowing or further impair our ability to access one or any of the 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.

Risks related to outsourcing of non-core support services

      Due to the large number of our former employees who migrated to an outsourcing provider, access to significant amounts of internal historical knowledge and expertise could become unavailable to us, particularly if knowledge transfer initiatives are delayed or ineffective.

      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, a failure of all or part of these relationships could lead to loss of institutional knowledge and interruption of services necessary for us to be able to conduct our business.

      Certain information technology application development, human resources, and helpdesk services that are currently provided by an outsourcer will be relocated to service centers operated by our outsourcing provider outside of the United States during 2005. 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, including risks of interruption of business, war, expropriation, nationalization, renegotiation, trade sanctions or nullification of existing contracts and changes in law or tax policy, that are greater than in the United States.

Risks related to environmental matters

      We are generally responsible for all on-site liabilities associated with the environmental condition of our facilities and assets, which we have acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In addition, in connection with certain acquisitions and sales of assets, we might obtain, or be required to provide, indemnification against certain environmental liabilities. If we incur a material liability, or the other party to a transaction fails to meet its indemnification obligations to us, we could suffer material losses. If a purchaser of one of our divested assets incurs a liability due to the environmental condition of the divested asset, we may have a contractual obligation to indemnify that purchaser or otherwise retain responsibility for the environmental condition of the divested asset. We may also have liability for the environmental condition of divested assets under applicable federal or state laws and regulations. Changes to applicable laws and regulations, or changes to their interpretation, may increase our liability. Environmental conditions of divested assets may not be covered by insurance. Even if environmental conditions could be covered by insurance, policy conditions may not be met.

      We make assumptions and develop expectations about possible liability 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 assumptions and expectations are also based on available information. If more information becomes available to us, our assumptions may change. Any of these changes may result in not only increased risk related to one or more of our assets, but material losses in excess of current estimates.

      Our operations are subject to extensive environmental regulation pursuant to a variety of federal, provincial, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. The federal government and several states recently have proposed increased environmental regulation of many industrial activities, including increased regulation of air quality, water quality and solid waste management.

      Compliance with environmental legislation will require significant expenditures, including expenditures for compliance with the Clean Air Act and similar legislation, for clean up costs and damages arising out of contaminated properties, and for failure to comply with environmental legislation and regulations which might result in the imposition of fines and penalties. The steps we take to bring certain of our 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.

      Further, our regulatory rate structure and our contracts with clients might not necessarily allow us to recover capital costs we incur to comply with 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. Should we fail to comply with all applicable environmental laws, we might be subject to penalties and fines imposed against us by regulatory authorities. Although we do not expect that the costs of complying with current environmental legislation will have a material adverse effect on our financial condition or results of

operations, no assurance can be made that the costs of complying with environmental legislation in the future will not have such an effect.

Risks relating to accounting standards

      Accounting irregularities discovered in the past few years in various industries have forced regulators and legislators to take a renewed look at accounting practices, financial disclosures, companies’ relationships with their independent auditors and retirement plan practices. Because it is still unclear what laws or regulations will ultimately develop, 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 and liabilities.

Risks relating to our industry

      The development of additional natural gas reserves 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 of additional reserves and production, gathering, storage and pipeline transmission and import and export of natural gas supplies. Additional natural gas reserves might not be developed in commercial quantities and in sufficient amounts to fill the capacities of our gathering and processing pipeline facilities.

      Our operations are subject to all of the risks and hazards typically associated with the exploitation, 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, 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. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. We implemented an Integrity Management Plan (IMP) for our gas transmission pipelines in December 2004, as required by the Pipeline Safety Improvement Act. As part of the IMP, we identified High Consequence Areas (HCA) through which our pipelines run. An HCA is an area where the potential consequence of a gas pipeline accident may be

significant or do considerable harm to people or property. Certain segments of our pipelines run through HCAs. An event such as those described above in a HCA not only could cause considerable harm to people or property, but could have a material adverse effect on our financial position 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 adversely impact our ability to meet contractual obligations and retain customers. For example, the 26 inch segment of Northwest Pipeline from Sumas to Washougal, Washington was idled in 2003 after a line break associated with stress corrosion cracking (SCC). SCC is caused by a specific combination of stress and exposure to environmental factors such as soil acidity, moisture, and electro chemical properties that occurs in older pipelines. This type of corrosion cracking is a very complex technical phenomenon and, while the industry is making progress in developing methods to predict and identify SCC, there are still many unknowns.

      In December 2003, we received an Amended Corrective Action Order (ACAO) from the U.S. Department of Transportation’s Office of Pipeline Safety (OPS) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured.

      By June 2004 we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 Mdt/d of the 360 Mdt/d of idled capacity and is anticipated to be adequate to meet most market conditions. To date our ability to serve the market demand has not been significantly impacted.

      As required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities. That resulted in 13 Mdt/d of capacity being relinquished and incorporated into the replacement project. On November 29, 2004 we filed with the FERC a certificate application for the “Capacity Replacement Project” including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

      Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. 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 Form 10-K 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. Although unlikely, the revisions could also affect the evaluation of Exploration & Production’s goodwill for impairment purposes.

Other risks

      The continued threat of terrorism and the impact of continued military and other action by the United States and its allies might lead to increased political, economic and financial market instability and volatility in prices for natural gas, which could affect the market for our gas operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and it has been reported that terrorists might be targeting domestic energy facilities. While we are taking steps that we believe are appropriate to increase the security at locations where our energy assets are located, there is no assurance that we can completely secure our locations or to completely protect them against a terrorist attack. These developments have subjected our operations to increased risks and, depending on their ultimate magnitude, could have a material adverse effect on our business. In particular, we might experience increased capital or operating costs to implement increased security for our energy assets.

      Performance of our exploration and production business is affected in part by factors beyond our control, such as:

      Our success rate for drilling projects in 2004 should not be considered a predictor of future performance. Reserves that are “proven reserves” are those estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty are recoverable in future years form known reservoirs under existing economic and operating conditions, but should not be considered as a guarantee of results for future drilling projects.

      Our assets and operations, especially 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.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

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

      The information called for by this item is provided in Note 15 Contingent liabilities and commitments included in the Notes to Consolidated Financial Statements of this report, which information is incorporated by reference into this item.

      None.

Item 4A. Executive Officers of the Registrant

      The name, age, period of service, and title of each of our executive officers as of February 28, 2005, are listed below.

PART II

      Our common stock is listed on the New York Stock Exchange and Pacific Stock Exchanges under the symbol “WMB.” At the close of business on February  28, 2005, we had approximately 13,234 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.

      The following financial data as of December 31, 2004 and 2003 and for the three years ended December 31, 2004 are an integral part of, and should be read in conjunction with, the consolidated financial statements and notes thereto. 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 Item 8 for discussion of changes in 2004, 2003 and 2002. Results for the years 2001 and 2000 also include amounts related to the discontinued operations of Williams Communications Group, our previously owned communications subsidiary (WilTel). 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.

      In February 2003, we outlined our planned business strategy in response to the events that significantly impacted the energy sector and our company during late 2001 and 2002. The plan focused upon migrating to an integrated natural gas business comprised of a strong, but smaller, portfolio of natural gas businesses, reducing debt and increasing our liquidity through asset sales, strategic levels of financing and reductions in operating costs. The plan provided us with a clear strategy to address near-term and medium-term debt and liquidity issues, to de-leverage the company with the objective of returning to investment grade status and to develop a balance sheet capable of supporting and ultimately growing our remaining businesses. A component of our plan was to reduce the risk and liquidity requirements of the Power segment while realizing the value of Power’s portfolio.

      In 2004, we continued to execute certain components of the plan and substantially completed our plan as outlined in February 2003. Our results for 2004 include the following.

      As a result of the accomplishments noted above, we enter 2005 with improved financial condition and liquidity. To manage our operations and meet unforeseen or extraordinary calls on cash, we expect to maintain liquidity from cash and revolving credit facilities of at least $1 billion.

      In September 2004, our Board of Directors approved the decision to retain Power and end our efforts to exit that business. Several factors affected our decision to retain the business, including:

Our strategy is to continue managing this business to minimize financial risk, maximize cash flow and meet contractual commitments. In the fourth quarter of 2004, we elected to begin applying hedge accounting to qualifying derivative contracts, which is expected to reduce Power’s mark-to-market earnings volatility.

      Having successfully completed the key components of our February 2003 plan to strengthen our finances, we are now in a position to shift from restructuring to disciplined growth.

      Our plan for 2005 includes the following objectives:

      As a result of the strategy to grow our natural gas asset base, we estimate capital and investment expenditures will increase to approximately $1.0 to $1.2 billion in 2005 compared to $787.4 million in 2004. We expect to fund capital and investment expenditures, debt payments and working-capital requirements through cash and cash equivalents on hand and cash generated from operations, which is currently estimated to be between $1.3 billion and $1.6 billion in 2005.

      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.

Critical accounting policies & estimates

      Our financial statements reflect the selection and application of accounting policies that require management to make significant estimates and assumptions. The selection of these has been discussed with our Audit Committee. We believe that the following are the more critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations.

      We hold a substantial portfolio of derivative contracts for a variety of purposes. Many of these are designated as hedge positions meaning changes in their fair value are not reflected in earnings until the associated hedged item impacts earnings. Others have not been designated as hedges or do not qualify for hedge accounting. The net change in fair value of these non-hedge contracts represents unrealized gains and losses and is recognized in income currently (marked-to-market). The fair value for each of these 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 fair value. Certain contracts are executed in exchange traded or over-the-counter markets where quoted prices in active markets may exist. Transactions are also executed in exchange-traded or over-the-counter markets for which market prices may exist, but which may be relatively inactive with limited price transparency. As a result, the ability to determine the fair value of the contract is

more subjective than if an independent third party quote were available. A limited number of transactions are also executed for which quoted market prices are not available. Determining fair value for these contracts involves assumptions and judgments when estimating prices at which market participants would transact if a market existed for the contract or transaction. We estimate the fair value of these various derivative contracts by incorporating information about commodity prices in actively quoted markets, quoted prices in less active markets, and other market fundamental analysis. The estimated fair value of all these derivative contracts is continually subject to change as the underlying energy commodity market changes and as management’s assumptions and judgments change.

      Additional discussion of the accounting for energy contracts at fair value is included in Note 1 of Notes to Consolidated Financial Statements, Energy Trading Activities, and Item 7A — Qualitative and Quantitative Disclosures About Market Risk.

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

      The process of estimating natural gas and oil reserves is very complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. After being estimated internally, 99 percent of our reserve estimates are either audited or prepared by independent experts. 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 reasonably likely revision of our reserve estimates 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 $16 million and $22 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 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 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. A reasonably likely unfavorable change in the forward price curve is not expected to result in an impairment of our oil and gas properties or goodwill.

      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 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, it is possible that our assumptions and estimates in these matters will 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.

      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 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, 2004, we have $780 million of deferred tax assets for which a $62 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 2004 federal tax net operating loss carryovers and capital loss carryovers prior to their expiration. We do not expect to be able to utilize $21 million, or approximately $8 million of tax benefit, of the charitable contribution carryovers expiring in 2005. The remaining $43 million of charitable contribution carryovers are expected to be utilized prior to their expiration. We also do not expect to be able to utilize $54 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 frequently 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 material 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.

      We evaluate our long-lived assets and investments for impairment when we believe events or changes in circumstances indicate that we may not be able to recover the carrying value of certain long-lived assets or the decline in carrying value of an investment is other-than-temporary. In addition to those long-lived assets and investments for which impairment charges were recorded (see Notes 2, 3 and 4 of Notes to Consolidated Financial Statements), certain others were reviewed for which no impairment was required. Our computations utilized judgments and assumptions in the following areas:

      An indicator of impairment relating to our Canadian olefins assets was identified during 2004. It is possible that our investment in these assets may not be recoverable without modifications to or a renegotiation of key terms in an off-gas processing agreement. Therefore, we performed recoverability tests that considered a possible sale of the assets versus successful renegotiation of the processing agreements. Our computations utilized judgments and assumptions in the following areas:

      After applying probability weightings to the various scenarios, we determined that the assets did not require impairment at December 31, 2004. A critical assumption in our impairment analysis was the valuation of future contract terms in the related processing agreement. Under the most likely scenario, a decrease of approximately 25 percent or more in our estimate of the contract valuation would likely result in an impairment.

      Our Gulf Liquids New River Project LLC (Gulf Liquids) operations are classified as “held for sale” at December 31, 2004. These assets were written down to the then estimated fair value less costs to sell at December 31, 2003. Additional analysis during 2004 resulted in an impairment of $2.5 million. We estimated fair value based on a probability-weighted analysis that considered sales price negotiations, salvage value estimates, and discounted future cash flows. This estimate involved significant judgment, including:

The estimated cash flows from the various scenarios ranged from approximately $4 million above to $8 million below our estimated fair value at December 31, 2004.

      We have employee benefit plans that include pension and other postretirement benefits. Pension and other postretirement benefit plan expense and obligations are determined 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. We review these assumptions annually and make adjustments as needed. The assumptions utilized to compute expense and the benefit obligations are shown in Note 7 of Notes to Consolidated Financial Statements. The table below presents the estimated increase (decrease) in pension and other postretirement benefit expense and obligations resulting from a one-percentage-point change in these assumptions.

      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.

      The discount rates are used to discount future benefit obligations to today’s dollars. Decreases in this rate cause the obligation and related expense to increase. 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 which 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 used by the actuaries are based on our actual historical cost rates and then adjusted for expected changes in the health care industry.

      One of our subsidiaries, Williams Alaska Petroleum, Inc. (WAPI) is actively engaged in administrative litigation being conducted jointly by the FERC and the Regulatory Commission of Alaska (RCA) concerning the Trans-Alaska Pipeline System (TAPS) Quality Bank. Primary issues being litigated include the appropriate valuation of the naphtha, heavy distillate, vacuum gas oil and residual product cuts within the

TAPS Quality Bank as well as the appropriate retroactive effects of the determinations. Due to the sale of WAPI’s interests on March 31, 2004, we are no longer responsible for paying into the Quality Bank. We are responsible for any liability that existed as of that date including potential liability for any retroactive payments that might be awarded in these proceedings for the period prior to March 31, 2004. The FERC and RCA presiding administrative law judges rendered their joint and individual initial decisions during the third quarter of 2004. The initial decisions set forth methodologies for determining the valuations of the product cuts under review and also approved the retroactive application of the approved methodologies for the heavy distillate and residual product cuts (see Note 15 in Notes to Consolidated Financial Statements).

      Based on our computation and assessment of the 2004 initial decisions by both the FERC and RCA, we recorded an increase to our accrual of approximately $134 million in the third quarter of 2004. Because the application of certain aspects of the initial decisions is subject to interpretation, the exercise of significant judgment is required to calculate the impact of the order. We have calculated the reasonably possible impact of the decisions, if fully adopted by the FERC and RCA, to result in additional exposure to us of approximately $32 million more than we have accrued at December 31, 2004. Therefore, the final outcome could potentially be materially different than we have estimated and accrued.

      In December 2004, the FASB issued revised SFAS No. 123, “Share-Based Payment.” The Statement requires that compensation cost for all share based awards to employees be recognized in the financial statements at fair value. The Statement is effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. We intend to adopt the revised Statement as of the interim reporting period beginning July 1, 2005.

      The Statement requires an option pricing model to estimate the fair value of employee stock awards. We are evaluating the appropriateness of several option pricing models, including a Black-Scholes model and a lattice model (such as a binomial model). Application of these two models could result in different estimates of fair value with resulting differences in compensation costs. Pro forma expense associated with options can be found in Note 1 of Notes to Consolidated Financial Statements. We have not determined the impact of the Statement on net income beyond the presentation of the pro forma disclosures.

General

      In accordance with the provisions related to discontinued operations within Statement of Financial Accounting Standard (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the consolidated financial statements and notes in Part II Item 8 reflect our results of operations, financial position and cash flows through the date of sale, as applicable, of certain components as discontinued operations (see Note 2 of Notes to Consolidated Financial Statements).

      Unless indicated otherwise, the following discussion and analysis of results of operations, 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.

Results of operations

      The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2004. The results of operations by segment are discussed in further detail following this Consolidated Overview discussion.

      The $4.2 billion decrease in revenues is due primarily to an approximately $3.9 billion decrease in revenues at Power resulting from lower realized revenues from power and crude and refined products. Partially offsetting the decrease was an increase in Midstream’s revenues of $97.8 million reflecting higher volumes and improved natural gas liquids (NGL) margins.

      The $4.3 billion decrease in costs and operating expenses is due primarily to lower costs and operating expenses at Power. This decrease is due primarily to lower purchase volumes of power and crude and refined products.

      The $65.8 million decrease in selling, general and administrative (SG&A) expenses is due primarily to a $36 million decrease in compensation expense at Power due to reduced staffing levels, combined with the absence of $13.6 million of expense related to the accelerated recognition of deferred compensation during 2003. In addition, Midstream’s SG&A expense declined $18 million largely due to asset sales and lower legal expense.

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

      Other (income) expense — net, within operating income, in 2003 includes:

      The $32.8 million increase in general corporate expenses is due primarily to efforts to evaluate and implement certain cost reduction strategies, and initial costs associated with outsourcing of certain services, increased legal costs due primarily to shareholder litigation and Employee Retirement Income Security Act (ERISA) matters, and increased third-party costs associated with certain mandated compliance activities.

      The $420.3 million decrease in interest accrued — net includes:

      The $25.2 million decrease in investing income includes $57.1 million lower interest income due primarily to higher net interest income at Power as a result of certain 2003 FERC proceedings. The decrease was partially offset by $29.6 million higher equity earnings. See Note 3 of Notes to Consolidated Financial Statements.

      Early debt retirement costs include payments in excess of the carrying value of the debt, dealer fees and the write-off of deferred debt issuance costs and discount/premium on the debt.

      The provision (benefit) for income taxes increased by $136.6 million due primarily to pre-tax income in 2004 compared to a pre-tax loss in 2003. 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 tax contingencies was offset by favorable settlements of certain Federal and state income tax matters. The effective income tax rate for 2003 is lower than the federal statutory rate due primarily to non-deductible impairment of goodwill, non-deductible expenses, an accrual for tax contingencies and the effect of state income taxes, somewhat offset by the tax benefit of capital losses.

      Income from discontinued operations decreased $256.1 million (see Note 2 of Notes to Consolidated Financial Statements). The decrease in the operating results from discontinued operations activities of $318.8 million is reflective of the following pre-tax items:

The 2004 net gain on sales of discontinued operations of $200.5 million includes a $189.8 million gain on the sale of three straddle plants in western Canada.

The 2003 net gain on sales of discontinued operations of $277.7 million includes the following pre-tax items:

See Note 2 of Notes to Consolidated Financial Statements for detail of the gains and losses on sales and asset impairments.

      The cumulative effect of change in accounting principles reduced net income for 2003 by $761.3 million due to a $762.5 million charge related to the adoption of EITF 02-3 (see Note 1 of Notes to Consolidated Financial Statements), slightly offset by $1.2 million related to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (see Note 9 of Notes to Consolidated Financial Statements).

      In June 2003, we redeemed all of our outstanding 9.875 percent cumulative-convertible preferred shares. Thus, no preferred dividends were paid in 2004.

      The $13.2 billion increase in revenues is due primarily to increased revenues at Power and Midstream as a result of the January 1, 2003 adoption of EITF 02-3, which requires that revenues and costs of sales from non-derivative contracts and certain physically settled derivative contracts be reported on a gross basis (see Note 1 of Notes to Consolidated Financial Statements). Prior to the adoption of EITF 02-3, revenues and costs of sales related to non-derivative contracts and certain physically settled derivative contracts were reported in revenues on a net basis. As permitted by EITF 02-3, 2002 amounts have not been restated. Power’s revenues increased $13.3 billion and Midstream’s revenues increased $1.6 billion due primarily to the effect of EITF 02-3. The increase in revenues also includes $210 million due primarily to higher natural gas liquids (NGL) revenues at Midstream’s gas processing plants as a result of moderate market price increases, partially offset by lower NGL production volumes.

      Results for 2003 include approximately $117 million of revenue related to the correction of the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001. This matter was initially disclosed in our Form 10-Q for the second quarter of 2003. Loss from continuing operations before income taxes and cumulative effect of change in accounting principles in 2003 was $62.8 million. Absent the corrections, we would have reported a larger pre-tax loss from continuing operations in 2003. Approximately $83 million of this revenue relates to a correction of net energy trading assets for certain derivative contract terminations occurring in 2001. The remaining $34 million relates to net gains on certain other derivative contracts entered into in 2002 and 2001 that we now believe should not have been deferred as a component of other comprehensive income due to the incorrect designation of these contracts as cash flow hedges. Our management, after consultation with our independent auditor, concluded that the effect of the previous accounting treatment was not material to 2003 and prior periods and the trend of earnings.

      The $13 billion increase in costs and operating expenses is due primarily to the effect of reporting certain costs on a gross basis at Power and Midstream, as discussed above. Costs increased $12.9 billion at Power and $1.9 billion at Midstream due primarily to the effect of EITF 02-3. Contributing to the increase at our Midstream segment is $113 million attributable to rising market prices for natural gas used to replace the heating value of NGLs extracted at their gas processing facilities. The cost increases at these operating units were partially offset by $1.5 billion higher intercompany eliminations resulting primarily from intercompany costs that were previously netted in revenues prior to the adoption of EITF 02-3.

      The $154.3 million decrease in SG&A expenses is due primarily to reduced staffing levels at Power reflective of our strategy to exit this business. Also contributing to the decrease was the absence of $22 million of costs related to an enhanced benefit early retirement option offered to certain employee groups in 2002.

      Other (income) expense — net, within operating income, in 2003 is included above in the 2004 vs. 2003 discussion. Other (income) expense — net, within operating income, in 2002 includes:

      The $55.8 million decrease in general corporate expenses is due primarily to the absence in 2003 of $24 million of various restructuring costs associated with the liquidity and business issues addressed beginning third-quarter 2002. We also incurred $19 million higher advertising and branding costs in 2002 (due primarily to golf events and other advertising campaigns that were not continued in 2003).

      The $106.1 million increase in interest accrued — net is primarily due to:

      In 2002, we began entering into interest rate swaps with external counterparties primarily in support of the energy-trading portfolio. The change in market value of these swaps was $122 million more favorable in 2003 than 2002, due largely to a reduction in overall swap positions during the second half of 2002. The total notional amount of these swaps is approximately $300 million at December 31, 2003.

      The $186.3 million increase in investing income in 2003 includes:

      Minority interest in income and preferred returns of consolidated subsidiaries in 2003 is lower than 2002 due primarily to the absence of preferred returns totaling $23 million on the preferred interests in Castle Associates L.P., Piceance Production Holdings L.L.C., and Williams Risk Holdings L.L.C., which were modified and reclassified as debt in third-quarter 2002, and Arctic Fox, L.L.C., which was modified and reclassified as debt in April 2002.

      Other income — net, below operating income, in 2003 includes $84.7 million of foreign currency transaction gains on a Canadian dollar denominated note receivable. Partially offsetting these gains were $79.8 million of derivative losses on a forward contract to fix the U.S. dollar principal cash flows from this note.

      The provision (benefit) for income taxes was unfavorable by $285 million due primarily to reduced pre-tax loss in 2003 compared to 2002. The effective income tax rate for 2003 is lower than the federal statutory rate due primarily to non-deductible impairment of goodwill, non-deductible expenses, an accrual for tax contingencies and the effect of state income taxes, somewhat offset by the tax benefit of capital losses. The effective income tax rate for 2002 is less than the federal statutory rate due primarily to the effect of taxes on foreign operations, non-deductible impairment of goodwill, an accrual for tax contingencies and income tax credits recapture that reduced the tax benefit of the pre-tax loss somewhat offset by the tax benefit of capital losses and the effect of state income taxes.

      The 2003 net gain on sales of discontinued operations of $277.7 million is included above in the 2004 vs. 2003 discussion.

      The 2002 net loss on sales of discontinued operations of $567.8 million includes:

      The cumulative effect of change in accounting principles reduces net income for 2003 by $761.3 million due to a $762.5 million charge related to the adoption of EITF 02-3 (see Note 1 of Notes to Consolidated Financial Statements), slightly offset by $1.2 million related to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (see Note 9 of Notes to Consolidated Financial Statements).

      In June 2003, we redeemed all of our outstanding 9.875 percent cumulative-convertible preferred shares for approximately $289 million, plus $5.3 million for accrued dividends (see Note 12 of Notes to Consolidated Financial Statements). Preferred stock dividends in 2002 reflects the first-quarter 2002 impact of recording a $69.4 million non-cash dividend associated with the accounting for a preferred security that contained a conversion option that was beneficial to the purchaser at the time the security was issued.

Results of operations — segments

      We are currently organized into the following segments: Power, Gas Pipeline, Exploration & Production, Midstream and Other. Other primarily consists of corporate operations and certain continuing operations formerly included in the previously reported International and Petroleum Services segments. Our management currently evaluates performance based on segment profit (loss) from operations (see Note 18 of Notes to Consolidated Financial Statements).

      Prior period amounts have been restated to reflect all segment changes. The following discussions relate to the results of operations of our segments.

Power

      Power’s 2004 operating results were significantly influenced by past efforts to exit from the Power business and the effect of price changes on derivative contracts.

      Prior to September 2004, Power continued to focus on 1) terminating or selling all or portions of its portfolio, 2) maximizing cash flow, 3) reducing risk, and 4) managing existing contractual commitments. These efforts were consistent with our 2002 decision to sell all or portions of Power’s portfolio. The decrease in revenues, costs and SG&A expenses in 2004 reflects our lower levels of business activity pursuant to our past efforts to exit the Power business.

      In September 2004, we announced our decision to continue operating the Power business and cease efforts to exit that business. As a result, subsequent to September 2004, Power continued to focus on its objectives of minimizing financial risk, maximizing cash flow, meeting contractual commitments and providing functions that support our natural gas businesses. In addition, Power began executing new contracts to hedge its portfolio.

      As a result of our past intent to exit the Power business, Power’s derivative contracts did not previously qualify for hedge accounting. Therefore, we reported changes in the forward fair value of our derivative contracts in earnings as unrealized gains or losses. However, with the decision to retain the business, Power’s derivative contracts became eligible for hedge accounting under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) and Power elected hedge accounting on a prospective basis beginning October 1, 2004 for certain qualifying derivative contracts. Under cash flow hedge accounting, to the extent that the hedges are effective, prospective changes in the forward fair value of the hedges are reported as changes in Accumulated other comprehensive income in the Stockholders’ equity section of the Consolidated Balance Sheet, and then reclassified to earnings when the underlying hedged transactions (i.e. power sales and gas purchases) affect earnings.

      Key factors that influence Power’s financial condition and operating performance include the following:

      In 2005, Power intends to service its customers’ needs while increasing the certainty of cash flows from its long-term contracts.

      As Power continues to apply hedge accounting in 2005, its future earnings may be less volatile. However, not all of Power’s derivative contracts qualify for hedge accounting. Power will continue to report changes in the fair value of those remaining non-hedge contracts in earnings as unrealized gains or losses. In addition, the ineffective portion of the change in the forward fair value of qualifying hedges will also continue to be reported in earnings. Because the derivative contracts qualifying for hedge accounting have significant fair value that has been recognized as unrealized gains or losses prior to October 1, 2004, the amounts recognized in future earnings under hedge accounting will not necessarily align with the expected cash flows to be realized from the settlement of those derivatives. Therefore, it is expected that future earnings will reflect losses from underlying transactions that have been hedged by the derivatives, but will not reflect the corresponding offsetting positive value from the hedges since such positive value has already been recognized in prior periods. However, cash flows from Power’s portfolio continue to reflect the net amount from both the hedged transactions and the hedges.

      Even with the adoption of hedge accounting, some variability in Power’s earnings will remain as a result of:

      The fair value of Power’s tolling, full requirements, transportation, storage and transmission contracts are not reflected in the balance sheet since these contracts are not derivatives. Some of these contracts have a significant negative estimated fair value and, therefore, could also result in future operating gains or losses as a result of the volatile nature of energy commodity markets. The inability of counterparties to perform under contractual obligations due to their own credit constraints could also affect future operations.

      The $3.9 billion decrease in revenues includes an approximately $4 billion decrease in realized revenues partially offset by a $41.9 million increase in forward unrealized mark-to-market gains.

      Realized revenues represent 1) revenue from the sale of commodities or completion of energy-related services, and 2) gains and losses from the net financial settlement of derivative contracts. The approximately $4 billion decrease in realized revenues is primarily due to an approximately $3.1 billion decrease in power and natural gas realized revenues and an $862 million decrease in crude and refined products realized revenues.

      Power and natural gas realized revenues decreased primarily due to a 47 percent decrease in power sales volumes, partially offset by a five percent increase in power sales prices. Sales volumes decreased because Power did not replace certain long-term physical contracts that expired or were terminated in 2003, primarily due to a lack of market liquidity and past efforts to reduce our commitment to the Power business. In addition, results for 2003 include a realized gain of $126.8 million based on the terms of an agreement to terminate a derivative contract. In addition, during 2003, revenues include the correction of the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001, resulting in the recognition of approximately $117 million in revenues attributable to prior periods. Refer to Note 1 of Notes to Consolidated Financial Statements for further information. Additionally, power and natural gas revenues in 2003 include a $37 million reduction for increased power rate refunds owed to the state of California as the result of FERC rulings. Crude and refined products revenues decreased primarily due to the sale of the crude gathering business in 2003, the sale of the refined products business in 2004 and the past efforts to exit this line of business.

      Net forward unrealized mark-to-market gains and losses represent changes in the fair values of derivative contracts with a future settlement or delivery date. In 2004, Power had net forward unrealized mark-to-market

gains of $304 million, an increase of $41.9 million from 2003. The increase in unrealized gains is due to a $75 million increase associated with power and gas contracts, partially offset by an $11 million decrease in crude and refined products and a $22 million decrease in the interest rate portfolio. The increase in power and gas primarily results from a greater increase associated with near-term natural gas forward prices in 2004 than in 2003. Also contributing to the increase was the absence in 2004 of unrealized losses of approximately $70 million recognized in first-quarter 2003 on contracts for which we elected the normal purchases and sales exception in second-quarter 2003. Another factor contributing to the increase was the impact of cash flow hedge accounting, which was prospectively applied to certain of Power’s forecasted transactions beginning October 1, 2004. A net loss of $15 million related to the effective portion of the hedges was reported in Accumulated other comprehensive income in 2004. The decrease in crude and refined products primarily results from the sale of the crude gathering business in 2003, the sale of the refined products business in 2004 and the past efforts to exit this line of business. These activities led to a significantly smaller derivative position in 2004 than in 2003 which resulted in lower unrealized mark-to-market gains. The decrease in the interest rate portfolio is due primarily to a decrease in forward interest rates in first-quarter 2004 compared to a slight increase in first-quarter 2003.

      The $3.9 billion decrease in Power’s costs is primarily due to a decrease in power and natural gas costs of approximately $3 billion and a decrease in crude and refined products costs of $904.5 million. Power and natural gas costs decreased primarily due to a 48 percent decrease in power purchase volumes, partially offset by a two percent increase in power prices. A $10.4 million reduction to certain contingent loss accruals in 2004 and a $13.8 million loss for other contingencies in 2003, both associated with power marketing activities in California during 2000 and 2001, contributed to the decrease in costs discussed above. Costs in 2004 also reflect a $13 million payment made to terminate a non-derivative power sales contract, which partially offsets the decrease in power and natural gas costs. Crude and refined products costs decreased primarily due to the sale of the crude gathering business in 2003, the sale of the refined products business in 2004, and other past efforts to exit this line of business.

      The $40.8 million decrease in SG&A expenses is largely due to a $36 million decline in compensation expense, primarily as a result of staff reductions in prior years combined with the accelerated recognition of $13.6 million in 2003 of certain deferred compensation arrangements. In addition, a $6.3 million reduction of allowance for bad debts resulting from the 2004 settlement with certain California utilities and the absence of a $6.5 million bad debt charge associated with a termination settlement in 2003 also contributed to the decrease.

      Other (income) expense — net in 2004 includes $6.1 million in fees related to the sale of certain receivables to a third party. Other (income) expense — net in 2003 includes a $188 million gain from the sale of an energy-trading contract and a $13.8 million gain from the sale of certain investments. These income items are partially offset by the effect of the following 2003 items:

      The $58.4 million decrease in segment profit is primarily due to lower sales volumes and the absence in 2004 of income from certain terminated contracts and prior period adjustments and the effect of the other income changes noted above, partially offset by lower SG&A.

      The $13.3 billion increase in revenues includes an approximately $13.2 billion increase in realized revenues and a $68.6 million increase in forward unrealized mark-to-market gains.

      Realized revenues increased primarily as a result of the implementation of EITF 02-3 on January 1, 2003. EITF 02-3 impacts how Power present revenues and costs from certain transactions in the statement of operations. The table below summarizes items included in revenues and costs before and after January  1, 2003:

      As illustrated in the table above, Power now reports certain purchases in costs instead of reporting them as reduction of revenues. Revenues for 2003 include a realized gain of $126.8 million based on the terms of an agreement to terminate a derivative contract. Additionally, during 2003, Power corrected the accounting treatment previously applied to certain third party derivative contracts during 2002 and 2001, resulting in the recognition in 2003 of approximately $117 million in revenues attributable to prior periods. This matter was initially disclosed in our Form 10-Q for the second quarter of 2003. Refer to Note 1 of Notes to Consolidated Financial Statements for further information. Realized revenues in 2003 also include a $37 million loss for increased power rate refunds owed to the state of California as the result of FERC rulings, which partially offsets the general increase discussed above. Increased power supply in the mid-continent and eastern regions contributed to lower prices received on power sales in 2003, which further offsets the general increase in realized revenues.

      EITF 02-3 also affects forward unrealized mark-to-market gains. Before the adoption of EITF 02-3, Power reported the fair value of all its energy contracts, energy-related contracts and inventory on the balance

sheet. Power reported changes in the fair value of the items, or forward unrealized mark-to-market gains, from period to period in revenues. Examples of derivative and non-derivative contracts are as follows:

      In 2003, Power continued to reflect the changes in fair value of derivative contracts in revenues and segment profit. However, for non-derivative contracts, Power does not recognize revenue until commodities are delivered or services are completed. The $68.6 million increase in forward unrealized mark-to-market gains includes a $44 million increase in the power and natural gas portfolios and a $71 million increase in the interest rate portfolio, partially offset by a $46 million decrease in the crude and refined products portfolio. Power and natural gas forward unrealized mark-to-market gains in 2003 reflect the impact of decreased forward power prices on net power sales contracts (derivative contracts) and increased forward gas prices on net gas purchase contracts (derivative contracts). Increased power supply in the mid-continent and eastern U.S. significantly contributed to the decrease in forward power prices. Unrealized mark-to-market gains in 2002 were lower primarily due to the impact of decreased margins between forward power prices and the estimated cost to produce the power on tolling contracts (non-derivative contracts). The decline in volatility of the power and natural gas markets in 2002 also contributed to a decrease in fair value of tolling contracts within certain of our tolling portfolios as it does other option contracts. Tolling contracts possess characteristics of options since we have the right but not the obligation to request the plant owner to convert natural gas to power. Results in 2002 also reflect an unfavorable $74.8 million valuation adjustment on certain non-derivative power sale contracts. Quotes received during sales efforts in 2002 resulted in the valuation adjustment. The effect of decreased interest rates on power and natural gas derivative and non-derivative contracts in 2002 partially offsets the general increase discussed above. As interest rates decreased in 2002, the overall fair value of these commodity contracts increased. Further offsetting the general increase is a lack of origination in 2003. In 2002, we recognized $85.1 million of power and natural gas revenues by originating new contracts, a portion of which realized during 2002. The favorable net effect of approximately $85 million resulting from a settlement with the state of California in 2002 also partially offsets the increase in power and natural gas forward unrealized mark-to-market gains. The $85 million reflects the increase in fair value on power sales contracts with the California Department of Water Resources, which resulted from a restructuring of the contracts and the improved credit standing of the counterparty. The increase in the interest rate portfolio reflects a lesser decrease in forward interest rates in 2003 than in 2002. The decrease in crude and refined products portfolios reflects a lack of origination in 2003. In 2002, Power recognized $118.8 million of forward unrealized mark-to-market gains within the petroleum products portfolio by originating new contracts, a portion of which realized in 2002.

      The $12.9 billion increase in costs is primarily due to the implementation of EITF 02-3 as discussed above. As a result of EITF 02-3, Power now reports certain purchases in costs instead of reporting them as reduction of revenues. The increase in costs caused by EITF 02-3 does not affect gross margin or segment profit. Also included in 2003 costs is a $13.8 million loss for other contingencies related to our power marketing activities in the state of California.

      The reduced focus on the Power business resulted in further employee reductions in 2003. We employed approximately 250 employees at the end of 2003 compared to approximately 410 at the end of 2002. This decrease in employees was a primary factor in the $85 million, or 41 percent, decrease in SG&A expenses.

      The $319.5 million variance in other income (expense) — net is primarily due to Power terminating or selling certain contracts and other assets, resulting in losses in 2002 and gains in 2003. In 2002, Power

terminated certain power — related capital projects, which resulted in $138.8 million of impairments. Power also recorded a $44.7 million impairment in 2002 from the January 2003 sale of the Worthington generation facility. In 2003, Power sold a non-derivative energy-trading contract resulting in a $188 million gain on sale. Power also sold an interest in certain investments accounted for under the equity method in 2003 for a gain of $13.8 million. A $45 million goodwill impairment in 2003 compared to a $61.1 million goodwill impairment in 2002 also contributed to the increase in Other (income) expense-net. See Note 4 of Notes to Consolidated Financial Statements. Other factors offset the increase in Other income (expense) — net. In 2003, Power recognized a $44.1 million impairment on a power generating facility (see Note 4 of Notes to Consolidated Financial Statements). Power also reached a settlement with the Commodity Futures Trading Commission as discussed in Note 16 of Notes to Consolidated Financial Statements, resulting in a charge of $20 million. In addition, Power recognized $14.1 million of impairment charges associated with the Aux Sable partnership investment. Finally, Power recorded accruals of $19.5 million for power marketing activities in California during 2000 and 2001 (see Note 15 of Notes to Consolidated Financial Statements).

      The $761.3 million increase in segment profit is primarily due to an increase in realized revenues and forward unrealized mark-to-market gains that were greater than the increase in costs. Further impacting this increase are the changes in other (income) expense — net and a decrease in selling, general and administrative expenses as discussed above.

Gas Pipeline

      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, enlargement 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.

      Effective June 1, 2004, and due in part to FERC Order 2004, management and decision-making control of certain regulated gas gathering assets was transferred from our Midstream segment to our Gas Pipeline segment. Consequently, the results of operations were similarly reclassified. All prior periods reflect these classifications.

      In December 2003, we received an Amended Corrective Action Order (ACAO) from the U.S. Department of Transportation’s Office of Pipeline Safety (OPS) regarding a segment of one of our natural gas pipelines in western Washington. The pipeline experienced two breaks in 2003 and we subsequently idled the pipeline segment until its integrity could be assured.

      By June 2004, we had successfully completed our hydrostatic testing program and returned to service 111 miles of the 268 miles of pipe affected by the ACAO. That effort has restored 131 thousand dekatherms per day (Mdt/d) of the 360 Mdt/d of idled capacity and is anticipated to be adequate to meet most market conditions. The decision to idle the pipeline has not had a significant impact on our ability to meet market demand to date.

      The restored facilities will be monitored and tested as necessary until they are ultimately replaced. As of December 31, 2004, approximately $40 million has been spent on testing and remediation, including approximately $9 million related to one segment of pipe that we determined not to return to service and therefore was written off in the second quarter of 2004. We estimate additional testing and remediation costs of up to $5 million.

      On October 4, 2004 we received a notice of probable violation (“NOPV”) from OPS. Under the provisions of the NOPV, OPS has issued a preliminary civil penalty of $100,000 for exceeding the pressure restriction on one of the segments covered under the original CAO. This penalty was accrued in the third

quarter of 2004. The incident occurred on July 15, 2003 and did not occur as part of normal operations, but in preparation for running an internal inspection tool to test the integrity of the line. The operating pressure dictated by the original CAO was exceeded for approximately three hours due to the mechanical failure of an overpressure device and we immediately reported the incident to the OPS. There was no impact on pipeline facilities, and no additional sections of the pipeline were affected. Following the incident, new protocols were adopted to ensure that a similar situation would not occur in the future. We requested a hearing on the proposed OPS civil penalty, which was held on December 15, 2004. We expect OPS to issue its decision in the near future.

      As required by OPS, we plan to replace the pipeline’s entire capacity by November 2006 to meet long-term demands. We conducted a reverse open season to determine whether any existing customers were willing to relinquish or reduce their capacity commitments to allow us to reduce the scope of pipeline replacement facilities, which resulted in 13 Mdt/d of capacity being relinquished and incorporated into the replacement project. On November 29, 2004, we filed with the FERC a certificate of application for the “Capacity Replacement Project,” including construction of approximately 79.5 miles of 36-inch pipeline and 10,760 net horsepower of additional compression at two existing compressor stations and abandonment of approximately 268 miles of the existing 26-inch pipeline. The estimated net cost of the Capacity Replacement Project included in the filing is approximately $333 million. The majority of these costs will be spent in 2005 and 2006. We anticipate filing a rate case to recover the capitalized costs relating to restoration and replacement facilities following the in-service date of the replacement facilities.

      In February 2004, Transco placed an expansion into service increasing capacity on its natural gas system by 54 Mdt/d. The expansion provides additional firm transportation capacity to serve Transco’s southeastern market area.

      In December 2004, we mutually agreed with British Columbia Hydro and Power Authority (BC Hydro) to end plans to construct a $209 million natural gas pipeline across the Strait of Georgia to serve electric generation facilities on Vancouver Island, B.C. Under the terms of the agreement, BC Hydro assumes full responsibility for all project costs.

      In February 2005, Gulfstream placed into service its 110-mile Phase II natural gas pipeline extension, expanding its reach across Florida and facilitating the increase of long-term firm service by 350 million cubic feet per day. Gulfstream now has the capacity of approximately 1.1 billion cubic feet per day. The cost for Phase II of the project is estimated at $200 million.

      In February 2005, Transco received authorization from the FERC to construct and operate the Central New Jersey Expansion Project on its natural gas pipeline system. The expansion will provide an additional 105 Mdt/d of firm natural gas transportation service in Transco’s northeastern market area. The estimated cost of the project is $13 million. The construction is scheduled to begin in the summer of 2005 and is expected to be placed into service in November 2005.

      Significant risk factors that could affect the profitability of our Gas Pipeline segment include:

      The following discussions relate to the current continuing businesses of our Gas Pipeline segment which includes Transco, Northwest Pipeline and various joint venture projects. Certain assets sold during 2002 are included in the 2002 results. In addition, any gains or losses on the sale and results of operations related to Texas Gas, Central and Kern River are excluded and are reported within discontinued operations.

      The $6 million decrease in Gas Pipeline revenues is due primarily to $25 million lower revenues associated with reimbursable costs, which are passed through to customers (offset in costs and operating expenses and general and administrative expenses) and $12 million lower revenues from the sale of environmental mitigation credits. These decreases were partially offset by $29 million higher transportation revenues and $7 million higher revenue from exchange imbalance settlements (offset in costs and operating expenses). The $29 million increase in transportation revenues is due primarily to $46 million higher revenue from expansion projects, partially offset by $17 million lower revenue from all other operations. The $17 million decrease is due primarily to $5 million lower commodity revenues at Transco and $9 million lower short-term firm revenues at Northwest Pipeline.

      Costs and operating expenses decreased $2 million due primarily to $18 million lower recovery of reimbursable costs which are passed through to customers (offset in revenues); an $8.5 million reduction of expense related to adjustments to depreciation recognized in a prior period; an $8 million reduction of depreciation, depletion and amortization expense related to capitalized environmental mitigation credits; and the absence of a $4 million write-off of certain receivables at Transco in 2003. These decreases were partially offset by $11 million higher maintenance expenses, $10 million higher fuel expense at Transco reflecting a reduction in pricing differentials on the volumes of gas used in operations as compared to 2003, $7 million higher gas exchange imbalance settlements (offset in revenues), and a $5 million increase in regulatory charges.

      General and administrative costs decreased $11 million, or nine percent, due primarily to $6 million lower reimbursable costs (offset in revenues) and $4 million lower rent resulting from the terms of a new office lease at Transco.

      Other (income) expense — net in 2004 includes an approximate $9 million charge for the write-off of previously-capitalized costs incurred on an idled segment of Northwest Pipeline’s system that we determined will not be returned to service. Other (income) expense — net in 2003 includes a $25.6 million charge at Northwest Pipeline to write-off capitalized software development costs for a service delivery system following a decision not to implement and $7.2 million of income at Transco resulting from a reduction of accrued liabilities for claims associated with certain producers as a result of settlements and court rulings (see Royalty indemnifications in Note 15 of Notes to Consolidated Financial Statements).

      The $30.3 million, or five percent, increase in segment profit, which includes equity earnings and income (loss) from investments is due to the following: