PART I

Items 1 and 2.      Business and Properties

      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. 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.

      We make available free of charge on or through our Internet website at http://www.williams.com , 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 Principles, 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. Our operations stretch across the country and serve the Northwest, California, Rocky Mountains, Gulf Coast and Eastern Seaboard markets.

      The energy industry has substantially changed over the last two years. Those changes have significantly impacted our operations and will continue to impact future operations. In light of the changed environment, on February 20, 2003, we outlined our planned business strategy for the next few years. Our refocused strategy is to become a smaller integrated natural gas company focusing on key growth markets. We also focused on bolstering our liquidity through asset sales, strategic levels of financing and reductions in operating costs to develop a balance sheet capable of supporting and ultimately growing our remaining businesses.

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

RECENT DEVELOPMENTS

Implementing Our Strategy

      We expended considerable effort in 2003 implementing our refocused business strategy and have successfully completed a number of the components of that strategy including asset sales, cost reductions, improving our financial position through a series of financial transactions, and addressing issues surrounding our Power segment. Each of those components is discussed in more detail below.

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Asset sales

      In 2003, consistent with the strategy outlined above, we generated proceeds of approximately $3 billion from the sale of assets. In addition, we realized proceeds from the sale, termination and liquidation of Power contracts during the year. We have completed the sale of or announced our intention to sell the following:

	•	February 3, 2003 — We sold our 170-megawatt power facility in Worthington, Indiana, to Hoosier Energy and terminated our power load serving contract with Hoosier Energy for cash totaling $67 million.
	•	May 15, 2003 — We sold certain crude gathering contracts and assets to Seminole Transportation and Gathering, L.P. for $13.9 million. The sale included the assignment of certain purchase and sales contracts with average annual throughput of 40,000 barrels per day, a four-mile pipeline in Louisiana, and a two percent interest in the High Island Pipeline System located offshore, Gulf Coast. The sale relieved us of a fixed-lease obligation totaling $32 million over the next eight years related to the lease of a terminal in Louisiana.
	•	May 30, 2003 — We sold our full-requirements power agreement with Jackson Electric Membership Corporation in Jefferson, Georgia, to Progress Energy for $188 million in cash with $175 million received in second quarter 2003 and $13 million received in third quarter 2003.
	•	August 1, 2003 — We announced an agreement to terminate a long-term power contract with a subsidiary of Allegheny Energy, Inc. for $100 million in cash and a $28 million note receivable. On the same date, we also announced the sale of or agreements to sell distributed-generation units and an associated third-party contract for approximately $31 million.

	•	May 16, 2003 — We sold our Texas Gas Transmission pipeline to a subsidiary of Loews Corporation for approximately $1.045 billion, which included approximately $795 million in cash and assumption of $250 million in existing Texas Gas Transmission debt.

	•	May 30, 2003 — We sold certain exploration and production assets, on properties located in Kansas, Colorado, and New Mexico for net proceeds of $383 million.
	•	June 2003 — We sold natural gas exploration and production properties in the Green River basin in southwest Wyoming and the Denver-Julesberg basin in northeastern Colorado for net proceeds of $34 million.
	•	August 28, 2003 — We sold oil and gas properties in Brundage Canyon, Utah, to Berry Petroleum Company for net proceeds of $44 million.

	•	May 2, 2003 — We mutually agreed to terminate an agreement for the sale of certain of our South Texas natural gas transmission lines to Enbridge Energy Partners, L.P. because the parties were unable to obtain regulatory approvals from the Federal Energy Regulatory Commission (FERC). We intend to pursue an alternative transaction with another buyer under a structure that is responsive to the FERC’s concerns.
	•	June 30, 2003 — We sold our 45 percent ownership interest in the 223-mile Rio Grande Pipeline that transports natural gas liquids from Hobbs, New Mexico to Ciudad Juarez, Chihuahua. Navajo Southern Inc., a wholly-owned subsidiary of Holly Corporation, purchased our interest for $27.5 million, subject to certain closing adjustments.

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	•	August 1, 2003 — We sold our West Stoddart natural gas processing plant located near Fort St. John, British Columbia.
	•	August 8, 2003 — We sold our 20 percent aggregate ownership interest in the 3,000-mile West Texas LPG Pipeline Limited Partnership to Buckeye Partners, L.P. for approximately $28.5 million.
	•	September 30, 2003 — We sold our natural gas fractionation system and a portion of our storage and distribution system at a plant in Redwater, Alberta for $246 million in U.S. funds to Provident Energy Trust.
	•	October 2, 2003 — We sold our interests in Wilprise Pipeline Co. and Tri-States NGL Pipeline LLC to affiliates of Enterprise Products Partners L.P. for $26.5 million plus an earn-out provision that entitles us to receive up to an additional $8.3 million based on transportation volumes for Wilprise and Tri-States through 2006.
	•	December 2003 — We sold our Dry Trail gas processing plant located in the Oklahoma panhandle, and certain wholesale propane assets, including seven propane distribution terminals.

	•	February 27, 2003 — We sold our retail travel center operations for approximately $189 million in cash to Pilot Travel Centers LLC.
	•	March 4, 2003 — We sold our Memphis, Tennessee refinery and other related operations to Premcor Inc. for approximately $455 million in cash. In April 2003 we sold an earnout agreement we retained in the sale of the refinery.
	•	May 30, 2003 — We sold our interest in Williams Bio-Energy L.L.C. to a new company formed by Morgan Stanley Capital Partners for $59 million in cash. The sale included ethanol production plants in Pekin, Illinois, and Aurora, Nebraska.
	•	June 17, 2003 — We sold our 54.6 percent ownership interest in Williams Energy Partners L.P. (now known as Magellan Midstream Partners, L.P.). The buyer, a limited partnership formed by the private equity firms Madison Dearborn Partners, LLC and Carlyle/ Riverstone Global Energy and Power Fund II, L.P., paid approximately $512 million in cash at closing for our interests in the partnership. In addition, the transaction had the effect of removing $570 million of the partnership’s debt from our consolidated balance sheet. In the fourth quarter 2003 we received an additional $20 million associated with the terms of this sale.
	•	September 10, 2003 — We sold all of our investment in a soda ash and sodium bicarbonate mining operation to a wholly-owned affiliate of Solvay America, Inc.
	•	November 17, 2003 — We announced definitive agreements to sell for approximately $265 million in cash our refinery at North Pole, two petroleum terminals in Anchorage and Fairbanks, and related crude oil and refined products inventories, our 3.0845 percent interest in the Trans Alaska Pipeline System, and 26 convenience stores. The sales price is subject to closing adjustments for items such as the value of petroleum inventories. In addition to anticipated cash proceeds, the transaction will eliminate two cash-collateralized letters of credit that we have with the state of Alaska, releasing $90.9 million back to us.
	•	December 2003 — We announced the closing of an agreement for the structured sale of our 20 percent investment in Brazil-based Algar Telecom Leste (ATL).

Cost reductions

      Our selling, general and administrative costs from continuing operations decreased 28 percent and our general corporate expenses decreased 39 percent. We are continuing our efforts to reduce costs through internal initiatives in which we are working to find more efficient and cost effective means of providing internal

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Other efforts to improve our financial position

      In addition to asset sales and cost reductions, we pursued other transactions to improve our financial position, which included the following:

	•	March 4, 2003 — Our wholly-owned subsidiary, Northwest Pipeline Corporation, completed a $175 million offering of senior notes due 2010.
	•	May 28, 2003 — We closed a $300 million private offering of junior subordinated convertible debentures due 2033. We used substantially all of the approximately $290 million of net proceeds from the offering to fund our repurchase of our 9.875 percent cumulative-convertible preferred stock held by a subsidiary of MidAmerican Energy Holdings Company on June 10, 2003.
	•	May 30, 2003 — We retired a $1.15 billion obligation to a group of investors led by a subsidiary of Berkshire Hathaway Inc. secured by substantially all of our exploration and production interests in the U.S. Rocky Mountains. We retired the obligation with funds from the proceeds of recent asset sales and funds from a new $500 million, secured, subsidiary-level financing. The new loan, which closed on May 30, 2003, is also secured by substantially all of our exploration and production interests in the U.S. Rocky Mountains and the terms of the new loan reflect market rates. The loan was amended on February 25, 2004 to reduce the floating interest rate 125 basis points from 3.75 percent over the London InterBank Offered Rate (LIBOR) to 2.5 percent over LIBOR and extends the maturity by one year from May 30, 2007, to May 30, 2008.
	•	June 6, 2003 — We obtained a new $800 million cash-collateralized letter of credit and revolver facility, primarily for the purpose of issuing letters of credit. The new facility replaced a $1.1 billion credit line. The majority of our Midstream assets were security for the previous agreement.
	•	June 10, 2003 — We issued 8.625 percent senior unsecured notes due 2010 in an $800 million public offering.
	•	November 6, 2003 — We issued tender offers relating to approximately $1.641 billion aggregate outstanding principal of debt securities. As of the expiration of the offers, we received tenders for approximately $721 million aggregate principal amount of our 9.25 percent notes due March 15, 2004, $24 million aggregate principal amount of 9.875 percent debentures due 2020 that were originally issued by Transco Energy Company, approximately $105.5 million aggregate principal amount of various tranches of Series B Medium Notes due 2003-2022 that were originally issued by MAPCO, Inc., and approximately $100 million aggregate principal amount of three series of debentures due 2012-2021 that we issued under a 1990 indenture.

Addressing power issues

      In 2003 we continued to pursue a strategy of exiting the Power business. We sold, terminated or liquidated certain Power contracts and assets. We have continued to manage the activities of this business unit to reduce risk, to generate cash, and to fulfill contractual commitments. We have also expended considerable effort addressing civil litigation and challenges and investigations by state and federal regulators and attorneys general regarding the trading practices of subsidiaries of our Power unit in California and other western states in 2000 and 2001. These challenges include refund proceedings, investigations of market manipulation, challenges to long-term power sales to the State of California, and civil litigation relating to each of these issues.

      On November 11, 2002, we executed a settlement agreement that resulted in renegotiated long-term energy contracts with the State of California, resolution of civil complaints brought by the California Attorney General, resolution of refund claims by the State of California, and resolution of ongoing investigations by the states of California, Oregon, and Washington. The settlement did not extend to criminal matters or matters of

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      On Oct. 25, 2002, we disclosed that our internal review of our trading activities revealed that a few non-managerial employees had engaged in inaccurate reporting of natural gas trades to energy publications that compile and report index prices. We voluntarily reported these findings to the Commodity Futures Trading Commission (CFTC) and other relevant federal agencies. On July 29, 2003, we announced that we and our subsidiary, Williams Power Company, Inc., reached a settlement with the Commodity Futures Trading Commission on the matter pursuant to which we paid a civil penalty of $20 million, the CFTC closed its investigation and we did not admit or deny allegations of false reporting or attempted manipulation. The U.S. Department of Justice (DOJ) is continuing to investigate the matter. Civil suits based on allegations of manipulating gas indexes have been brought against us and others in federal and state courts.

      On March 26, 2003, the FERC issued a report on an investigation by the agency into price manipulation in the western energy markets in 2000 and 2001. The report cleared us of an allegation that we attempted to corner the gas market. On January 22, 2004, the FERC approved a settlement between us and the FERC trial staff of all Enron trading practices for $45,000. The agency is continuing its investigation of physical and economic withholding.

      On February 25, 2004, we announced that we had reached agreement on terms to settle with two California utilities, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company, resolving outstanding disputes, including refund liability related to natural gas and power markets in 2000 and 2001. The settlement will be subject to approval of the FERC, the California Public Utilities Commission and the U.S. Bankruptcy Court administering PG&E’s bankruptcy proceedings.

      See Note 16 of our Notes to Consolidated Financial Statement for more information about investigations and proceedings involving energy trading practices, including our continued involvement in FERC and related refund proceedings.

Other events

      On March 17, 2003, the FERC approved a settlement of issues raised during a joint investigation of Transcontinental Gas Pipe Line Corporation’s (Transco) and Williams Power Company’s compliance with regulations governing the relationship between interstate gas pipelines and marketing affiliates. Pursuant to the settlement, we will pay a $20 million civil penalty to the FERC over the next four years and Transco will discontinue firm sales services by April 1, 2005. The settlement also places restrictions on Power’s ability to transport gas on affiliated pipelines. We also agreed to implement a compliance program to ensure future compliance with the settlement agreement and FERC’s marketing affiliate rules. See Note 16 of our Notes to Consolidated Financial Statements for further information on the settlement.

      On May 15, 2003, our shareholders approved a stock option exchange program. Under this exchange program, eligible employees were given a one-time opportunity to exchange certain outstanding options for a proportionately lesser number of options at an exercise price which was based on the market value of our common stock on the grant date of the new options. Surrendered options for 10.4 million shares were cancelled June 26, 2003, and replacement options for 3.9 million shares were granted on December 29, 2003.

FINANCIAL INFORMATION ABOUT SEGMENTS

      See Note 19 of our Notes to Consolidated Financial Statements for information with respect to each segment’s revenues, profits or losses and total assets.

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BUSINESS SEGMENTS

General

      Substantially all of our operations are conducted through our subsidiaries. To achieve organizational and operating efficiencies, our activities are primarily operated through our wholly-owned subsidiary, Williams Power Company; our interstate natural gas pipelines and pipeline joint venture investments are organized under our wholly-owned subsidiary, Williams Gas Pipeline Company, LLC; our Exploration & Production business is operated through several wholly-owned subsidiaries including Williams Production Company LLC and Williams Production RMT Company; our Midstream business is operated primarily through wholly-owned subsidiaries including Williams Field Services Group, Inc. and Williams Natural Gas Liquids, Inc.; and our previously reported Petroleum Services and International segments are now reported under our Other segment. This report is organized to reflect this structure.

      Our business segments include Power, Gas Pipeline, Exploration & Production, Midstream, and Other. An overview and detailed discussion of each of our business segments follows.

Power

	•	Our Power segment, formerly known as Energy Marketing & Trading, is an energy services provider that buys, sells and transports a full suite of energy and energy-related commodities, including power, natural gas, refined products, crude oil and emissions credits, primarily on a wholesale level.
	•	We have sold certain portions of the Power portfolio, liquidated certain positions and are negotiating with various parties for a joint venture or sale of all or a portion of the remainder of our trading portfolio.

      In June 2002, we announced our intent to exit the power business and reduce our financial commitment to our Power segment. Until the portfolio is completely sold or liquidated, we continue 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. Our contracts include various financial instruments and structured transactions. Our financial instruments include exchange-traded futures, over-the-counter forwards, options and swaps. Structured transactions include tolling contracts and full requirements contracts, which are explained in the next two paragraphs. Through our contracts, we buy, sell, store and transport energy and energy-related commodities. These energy and energy-related commodities include power, natural gas, refined products, crude oil, and emission credits.

      Tolling contracts represent the most significant portion of our remaining 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:

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      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 1,146 megawatts of electricity in Georgia and Pennsylvania.

      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.

      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) and in Hazleton, Pennsylvania (147 megawatts).

      In 2003, we marketed natural gas throughout North America with total physical volumes averaging 2.7 billion cubic feet per day. With approximately 20 percent of this natural gas, we fuel electric generating plants we own or have contractual rights to. We sell approximately 28 percent of this natural gas to customers including local distribution companies, utilities, producers, industrials and other gas marketers. With the remaining 52 percent, we procure gas supply for our Midstream operations, sell gas produced by Exploration & Production and manage firm service contracts for Gas Pipeline.

      In 2003, we marketed on average approximately 77,000 barrels per day of physical crude oil and petroleum products to petroleum producers, refiners and end-users in the United States and various international regions.

      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 for the periods indicated:

      As of December 31, 2003, our Power segment had approximately 234 customers compared with 287 customers at the end of 2002.

      Our Power business is subject to a variety of laws and regulations at the local, state and federal levels. The 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. They are also subject to civil actions regarding, among other things, market

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      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.

      As a result of the credit rating downgrades to below investment grade levels in 2002, certain of our counterparties require adequate assurance or alternate credit support. In addition, under our industry standard derivative agreements, we are required to fund margin requirements with cash, letters of credit or other negotiable instruments. In 2003, however, due to improvements in our credit and liquidity, we were able to negotiate lower collateral requirements with certain brokers and 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 two counterparties, which have credit ratings below investment grade, constitute approximately 12 percent of Power’s gross revenues. Our exposure to these counterparties may be mitigated by the existence of netting arrangements. In conjunction with efforts to sell or liquidate all or portions of our portfolio, we closed out or sold positions with a number of counterparties in 2003. Credit constraints and financial instability of market participants are expected to continue in 2004. 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. As mentioned, we intend to sell or liquidate all or portions of our portfolio. No assurances can be made regarding the ultimate consummation of any sale or liquidation. 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. Certain of our tolling agreements have a negative fair value, which is not reflected in our financial statements since these agreements are non-derivatives. These tolling agreements may result in future accrual losses. See Note 1 of our Notes to Consolidated Financial Statements and our Management’s Discussion and

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      Amounts ultimately received in any portfolio sale, contract liquidation or realization may be significantly different than the estimated economic value or the carrying values presented in the financial statements. It is possible that we may sell contracts for less than their carrying value or enter into agreements to terminate certain obligations, either of which could result in future loss recognition or reductions of future cash flows.

      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 own one of the nation’s largest interstate natural gas pipeline systems with 14,600 miles of interstate natural gas pipelines for transportation of natural gas across the country to utilities and industrial customers.
	•	Our pipelines include Transco, Northwest Pipeline Corporation (Northwest Pipeline) and several pipeline joint ventures.
	•	We also own a 50 percent interest in the Gulfstream Pipeline.

      We own and operate, through Williams Gas Pipeline Company, LLC and its subsidiaries (Gas Pipeline), a combined total of approximately 14,600 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 11 billion cubic feet 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 the Gulfstream Natural Gas System, L.L.C.

      In February 2001, one of our subsidiaries and a subsidiary of Duke Energy completed a joint acquisition of The Coastal Corporation’s 100 percent ownership interest in Gulfstream Natural Gas System, L.L.C., and announced that they were proceeding with the development of the Gulfstream gas pipeline project. In June, 2001 construction commenced on the project, which consists of a new natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida. On December 28, 2001, Gulfstream filed an application with the FERC to allow Gulfstream to complete the construction of its approved facilities in phases. On May 28, 2002, the first phase of the project was placed into service at a cost of approximately $1.5 billion. The scheduled in-service date for the second phase of the project is May 1, 2005. The total estimated capital cost of both phases of the project is approximately $1.7 billion. At December 31, 2003, our investment in Gulfstream was $731 million.

      On April 24, 2001 the respective general partners of U.S. and Canadian general partnerships that are pursuing the Georgia Strait Crossing Pipeline Project (GSX), filed separate applications with the FERC and Canada’s National Energy Board (NEB) to construct and operate a new pipeline that will provide firm transportation capacity from Sumas, Washington to Vancouver Island, British Columbia. GSX is a project being pursued jointly between Gas Pipeline and BC Hydro, in part to meet the needs of the Vancouver Island Generation Plant (VIGP). On September 20, 2002, the FERC issued an order approving the construction and operation of the U.S. portion of the project. An NEB certificate approving the project in Canada was issued on December 15, 2003. Construction of the GSX project is contingent upon a favorable outcome of a British Columbia Utilities Commission mandated call for tenders process which is being pursued by BC Hydro to

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      Gas Pipeline’s interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938 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 Natural Gas Act of 1938. 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, a North Carolina 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 FERC determines the allowed rate of return 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 16 of our Notes to Consolidated Financial Statements for the amounts accrued for potential refund at December 31, 2003.

      On March 17, 2003, we entered into a settlement with FERC regarding its investigation of the relationship between Transco and Power whereby Transco will pay a civil penalty in the amount of $20 million payable over a five-year period. In addition, we agreed to certain operational restrictions and agreed to implement a compliance program to ensure future compliance with the settlement agreement and FERC’s marketing affiliate rules. See Note 16 of our Notes to Consolidated Financial Statements for further information on the settlement.

      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, rate , 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

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      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. Management expects 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, with certain portions being 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 16 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.

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      At December 31, 2003, 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 and 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 12 percent of Transco’s total revenues in 2003. 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.

      In 2003 and early 2004, Transco completed construction of, and placed into service, two major projects, the Momentum Expansion Project and the Trenton-Woodbury Expansion Project.

Pursuant to a FERC certificate, Transco placed into service the Momentum Expansion Project, an expansion of its pipeline system from Station 65 in Louisiana to Station 165 in Virginia. The first phase, consisting of approximately 269 Mdt/d, was placed into service on May 1, 2003. On February 1, 2004, Transco placed into service the second phase of the project consisting of 54 Mdt/d. All of the expansion capacity is fully subscribed by shippers under long-term firm arrangements. The project facilities include approximately 50 miles of pipeline looping and 45,000 horsepower of compression. The revised capital cost of the project is estimated to be approximately $189 million.

On November 1, 2003, Transco placed into service a 51 Mdt/d expansion of its Trenton-Woodbury Line, which runs from its mainline at Station 200 in eastern Pennsylvania, around the metropolitan Philadelphia area and southern New Jersey area, to its mainline near Station 205. All of the expansion capacity is fully subscribed by shippers under long-term firm arrangements. The project facilities include approximately seven miles of pipeline looping at an estimated capital cost of approximately $22 million.

On January 14, 2004, Transco announced that it was holding an open season from January 14, 2004 to February 13, 2004 to receive requests for incremental firm transportation service to be made available through its Central New Jersey Expansion Project, a proposed expansion of Transco’s pipeline system in Transco’s Zone 6 from Station 210 to locations along Transco’s Trenton-Woodbury Line. As a result of the open season, the expansion has been designed to create approximately 105 Mdt/d of new firm

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	transportation capacity, which will be fully subscribed under a long-term arrangement with one shipper. The project facilities will include approximately 3.5 miles of pipeline loop at an estimated capital cost of $13 million. Transco plans to file for FERC approval of the project in the second quarter of 2004. The target in-service date for the project is November 1, 2005.

      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, 2003, Northwest Pipeline’s system, having long term firm transportation agreements with peaking capacity of approximately 3.4 billion cubic feet of natural gas per day, was composed of approximately 4,100 miles of mainline and lateral transmission pipelines and 42 compressor stations having sea level-rated capacity of approximately 462,000 horsepower.

      On May 1, 2003, a line break occurred on our 26-inch gas transmission pipeline near Lake Tapps in Pierce County, Washington. The line break did not result in ignition and there were no injuries. On May 2, 2003, the Office of Pipeline Safety (OPS) initiated an investigation and issued a Corrective Action Order (CAO) requiring us to reduce the pressure in our 26-inch line from Sumas to Washougal, Washington to 80 percent of Maximum Allowable Operating Pressure (MAOP), determine the cause, and work to remedy the cause of the line break. We subsequently determined that the line break was caused by stress corrosion cracking (SCC) and implemented a variety of processes to ensure the integrity of our pipeline. Specifically, we completed surface and in-line inspection of certain segments of the line and were developing and executing plans to return the line to service prior to an additional line break occurring in December 2003.

      On December 13, 2003, we experienced another line break on the same line seventy miles south near Toledo, Washington. This line break occurred during pendency of the OPS CAO referred to above and the

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      In 2003, Northwest Pipeline transported natural gas for a total of 175 customers. Transportation customers include distribution companies, municipalities, interstate and intrastate pipelines, gas marketers and direct industrial users. The three largest customers of Northwest Pipeline in 2003 accounted for approximately 12.4 percent, 11.7 percent and 10.3 percent, respectively, of its total operating revenues. No other customer accounted for more than 10 percent of Northwest Pipeline’s total operating revenues in 2003. 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.

On November 1, 2003, Northwest Pipeline placed into service most of the facilities associated with its Rockies Expansion Project, an expansion of its pipeline system designed to provide an additional 175 MDt/d of capacity to its transmission system in Wyoming and Idaho in order to reduce reliance on displacement capacity. The remaining facilities were placed into service on November 30, 2003. The project included the installation of 91 miles of pipeline loop and the upgrading or modification of six compressor stations for a total increase of 26,057 horsepower. A majority of Northwest Pipeline’s firm shippers agreed to support roll-in of the expansion costs into its existing rates. The estimated cost of the expansion project is approximately $140 million, of which approximately $16 million has been offset by settlement funds received from a former customer in connection with a contract restructuring.

On October 1, 2003, Northwest Pipeline placed into service its Evergreen Expansion Project, an expansion of its pipeline system designed to provide 277 Mdt/d of firm transportation service from Sumas, Washington to Chehalis, Washington to serve new power generation demand in western Washington. The project included installation of 28 miles of pipeline loop, upgrading, replacing or modifying five compressor stations and adding a net total of 64,160 horsepower of compression. The estimated cost of the expansion project is approximately $198 million including the allocated portion of the Columbia Gorge Project discussed below. The Evergreen Expansion customers have agreed to pay for the cost of service of this expansion on an incremental basis.

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On October 1, 2003 Northwest Pipeline placed into service its Columbia Gorge project, an expansion of its pipeline system designed to replace 56 Mdt/d of northflow design displacement capacity from Stanfield, Oregon to Washougal, Washington. The project includes upgrading, replacing or modifying five existing compressor stations and adding a net total of 23,900 horsepower of compression. A majority of Northwest Pipeline’s firm shippers have agreed to support roll-in of approximately 84 percent of the expansion costs into the existing rates with the remainder to be allocated to the incremental Evergreen Expansion customers. The estimated cost of the expansion project is approximately $43 million.

      The following table summarizes transportation data for the Northwest Pipeline System for the periods indicated:

(1)	Consists primarily of additional capacity created from time to time through the installation of new receipt or delivery points or the segmentation of existing mainline capacity. Such capacity is generally marketed on a short-term firm basis, because it does not involve the construction of additional mainline capacity.

Exploration & production

	•	We produce, develop, explore for and manage natural gas reserves primarily located in the Rocky Mountain and Mid-Continent regions of the United States.
	•	We produce natural gas predominately from tight-sand formations and coal bed methane reserves.
	•	We own 2.7 trillion cubic feet equivalent of proved natural gas reserves in the United States as of December 31, 2003.

      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, explores for 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 is also comprised of 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 coalbed methane reserves. Exploration & Production’s current proved undeveloped and probable reserves

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      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 of 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 of 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 58 percent of our proved reserves. This area has approximately 1,075 undrilled proved locations in inventory. Probable reserves in this basin provide significant potential beyond our existing proved reserves. 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 four interstate and one intrastate pipelines. In 2003, we drilled 76 gross wells and produced a net of approximately 64 billion cubic feet equivalent (Bcfe) of natural gas from the Piceance Basin. Our estimated proved reserves in the Piceance Basin at year-end 2003 were 1,560 Bcfe.

      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 2003, we participated in the drilling of 173 gross wells, of which we operate 19, and produced a net of approximately 51 Bcfe from the San Juan Basin. Our estimated proved reserves in the San Juan Basin at year-end 2003 were 702 Bcfe.

      Located in northeast Wyoming, the Powder River Basin includes large areas with multiple coal seam potential, targeting thick coalbed 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 2,300 wells in the basin and have an interest in an additional 2,500 wells. We have a significant inventory of undrilled locations, providing long-term drilling opportunities. In 2003, we drilled 560 gross wells from this basin, of which we operate 410, and produced a net of approximately 47 Bcfe of natural gas. Our estimated proved reserves in the

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      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 2003, we drilled 53 gross wells, of which we operate 33, and produced a net of approximately five Bcfe of natural gas. Our estimated proved reserves in the Arkoma Basin at year-end 2003 were 122 Bcfe.

      We have production in other areas, including the Green River Basin, located in southwest Wyoming and 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 natural gas reserves by basin as of December 31, 2003:

      No major discovery or other favorable or adverse event has caused a significant change in estimated gas reserves since year-end 2003. 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, 2003, with the DOE. Certain estimates filed with the DOE may not necessarily be directly comparable due to special DOE reporting requirements, such as requirements to report in some instances on a gross, net or total operator basis, and requirements to report in terms of smaller units. The underlying estimated reserves for the DOE did not differ by more than five percent from the underlying estimated reserves utilized in preparing the estimated reserves reported to the SEC.

      Approximately 98 percent of our year-end 2003 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.

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      The following table summarizes our leased acreage as of December 31, 2003:

      At December 31, 2003, we owned interests in 7,923 gross producing wells (3,649 net) on our leasehold lands.

      We focus on lower-risk development drilling. Our drilling success rate was nearly 99 percent in 2003 and 98 percent in 2002. The following tables summarize domestic drilling activity by number and type of well for the periods indicated:

      The majority of our natural gas production is currently being sold to Power generally 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 approximately 80 percent of projected 2004 domestic natural gas production. Power then enters into offsetting derivative contracts with unrelated third parties. Approximately 86 percent of our natural gas production in 2003 was hedged. Hedging decisions are made considering the overall Williams commodity risk exposure and are not executed independently by Exploration & Production, thus 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:

      On December 30, 2003, Williams Production Mid-Continent Company purchased various incremental ownership interests in certain Arkoma Basin properties located in Oklahoma. The acquisition, for which we paid cash of $11 million, added 33 Bcfe in proved reserves and 4.6 MMcf/d of production. We operate the majority of these properties.

      Effective April 1, 2003, RMT sold its interest in the Raton Basin located in south central Colorado and its interest in the Hugoton Embayment located in southwest Kansas, and Williams Production Company LLC sold its interest in a small portion of its outside-operated properties in the San Juan Basin located in northwest New Mexico and southwest Colorado. This divestiture comprised nearly 303 Bcfe in year-end 2002 reserves

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      Effective April 1, 2003, RMT sold its interest in the Uinta Basin in Brundage Canyon, Utah, which consisted of nearly 53 Bcfe in year-end 2002 reserves and 13 MMcfe per day in production.

      Effective April 1, 2003, RMT sold its interest in the West Side Canal properties located in the Green River Basin in southwest Wyoming and its interest in the Denver-Julesberg Basin properties in northeastern Colorado, which together represent approximately 26 Bcfe in year-end 2002 reserves and around 7.5 MMcfe per day in production.

      Our Exploration & Production business is subject to various federal, state and local laws and regulations on taxation, the exploration for and 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:

	•	from a well or drilling equipment at a drill site;
	•	leakage from gathering systems, pipelines, transportation facilities and storage tanks;
	•	damage to oil and gas wells resulting from accidents during normal operations; and
	•	blowouts, cratering and explosions.

      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 in the areas of property acquisitions and the development, production and marketing of, and exploration for, natural gas with major oil companies, other independent oil and natural gas concerns and individual producers and operators. We also compete with major and independent oil and gas concerns in recruiting and retaining qualified employees.

      The majority of our ownership interest in exploration and production properties are 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. Williams 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

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      In March 2001, Williams Production Company LLC transferred certain interests in coal seam gas properties located in the San Juan Basin of New Mexico and Colorado to a third party. These properties are burdened by net profits interests held by the Williams Coal Seam Gas Royalty Trust. Williams Production Company exercised its right to repurchase the underlying properties pursuant to the original purchase and sale agreement. This repurchase of the underlying properties by Williams Production Company LLC was completed in May 2003 and effective January 1, 2003.

      In May 2000, Williams Production Company LLC transferred certain interests in coal seam gas properties located in the San Juan Basin of New Mexico to a third party. Williams exercised its right to repurchase these certain interests pursuant to the original purchase and sale agreement. The repurchase of these interests by Williams Production Company LLC was effective January 1, 2003.

      We also have investments in international oil and gas interests. We own approximately a 69 percent interest in APCO Argentina Inc., an oil and gas exploration and production company with operations in Argentina, whose securities are traded on the NASDAQ stock market. APCO Argentina’s principal business is its 52.9 percent interest in the Entre Lomas concession in southwest Argentina. It also owns a 82.0 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 7.3 percent of our total proved reserves.

Midstream

	•	We own and operate gas gathering, treating and processing facilities 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, Alabama, Mississippi, and Louisiana including ownership and operation of approximately 8,500 miles of gathering lines, nine natural gas processing plants (one of which is partially owned), and eight natural gas treating plants within the United States. In addition to these natural gas assets, we own and operate two crude oil pipelines totaling over 150 miles of pipeline.
	•	We own interests in and/or operate natural gas liquids fractionation and storage assets in central Kansas and southern Louisiana.
	•	We own a 41.67 percent interest and operate an ethylene production, storage and transportation complex and a 100 percent interest and operate olefin extraction assets within Louisiana.
	•	We own and/or operate three natural gas processing plants (one partially owned), a liquid extraction plant, and an olefin fractionation facility within Alberta, Canada. We intend to sell certain of our Canadian assets.
	•	We have ownership interests in various Venezuelan midstream energy assets.

      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 Coast, Venezuela and Canada. Our businesses — gathering, treating, processing, fractionation, storage and transportation — fall

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      Although much 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 receive the liquids 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.

      Key variables for our business will continue to be (1) the revenue growth associated with additional infrastructure recently completed in late 2003 and planned for 2004 in the deepwater portion of the Gulf of Mexico, (2) the execution of our remaining planned asset sales, and (3) the commodity prices impacting our commodity-based processing activities. With increased fee-based business in the deepwater and the planned sale of our Canadian liquids extraction plants, our exposure to commodity prices is expected to decline in future periods.

      Geographically, our natural gas assets are positioned to maximize commercial and operational synergies. For example, most of our offshore gathering and processing assets attach and condition natural gas supplies to the Williams’ 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 Williams’ Northwest Pipeline customers. We gather the largest volume of gas in the San Juan Basin. We produce approximately one-half of the natural gas liquids coming out of Wyoming and we gather 40 percent of the gas produced in the western Gulf of Mexico.

      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 8,500 miles of gathering pipelines with a capacity in excess of 7.9 billion cubic feet per day (including certain gathering lines owned by Transco but operated by Midstream), 9 processing plants (one partially owned) and 8 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 two crude oil pipelines totaling over 150 miles with a capacity of more than 160,000 barrels per day. This includes our recently completed Alpine crude oil pipeline in the deepwater Gulf of Mexico that serves the Kerr McGee-operated Gunnison field.

      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.

      In southern Louisiana, we provide customers in the petrochemical industry a full suite of products and services. These operations include a 42 percent interest in a 1.3 billion pound per year ethylene production, storage and transportation complex in Geismar, Louisiana. Also, our Gulf Liquids New River LLC (Gulf Liquids) business consists of two refinery off-gas processing facilities, an olefinic fractionator and propylene splitter and connecting pipeline system. During 2003, we announced our intention to sell Gulf Liquids and we continue to market for sale certain of the petrochemical pipeline and storage assets located in Geismar, Louisiana with the expectation that these assets will be sold in the first half of 2004.

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      Our Venezuelan investments involve gas compression recovery and gas gathering and processing operations. We own controlling interests in three gas compressor facilities. 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.

      Our compression facilities provide roughly 70 percent of the gas injections in eastern Venezuela. These injections allow our sole customer, Petroleos de Venezuela S.A. (PDVSA) to freely produce approximately 500,000 barrels of oil per day, which is roughly 50 percent of PDVSA’s eastern crude oil production.

      Prior to 2003, our Venezuelan operations included an operations contract for an oil loading and storage facility. We operated these facilities on behalf of PDVSA, 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 three natural gas straddle plants (one partially owned) in Alberta, Canada, a liquids extraction plant located near Ft. McMurray, Alberta and an olefin fractionation facility near Edmonton, Alberta. Our interests in these straddle plants are capable of processing more than 5.5 billion cubic feet of gas per day. The facilities located at Ft. McMurray and near Edmonton, extract olefin liquids from the off-gas produced from oil sands and then fractionate, treat, store and terminal the propane and propylene recovered from this process. We continue to be the largest gas processor and ethane producer in Canada, the only olefins fractionator in Western Canada, and the only processor of oil sands off-gas.

      During 2003, we announced two separate sales related to our Canadian assets. We closed the sale of our West Stoddart natural gas processing plant to Canadian Natural Resources Limited on August 1, 2003. On September 30, 2003, we closed on the sale of our natural gas liquids fractionation, storage and distribution system in Redwater, Alberta to Provident Energy Trust. We continue to market for sale our natural gas straddle plants with the expectation of selling these assets before the end of 2004 and intend to retain our Ft. McMurray liquids extraction plant and our olefin fractionation, storage and distribution facility in Redwater, Alberta.

      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.

      We also own a 14.6 percent interest in Aux Sable Liquid Products LP, which owns and operates a natural gas liquids extraction and fractionation facility located in the Village of Channahon, Illinois. Natural gas delivered from the Alliance Pipeline System is processed at the plant before it is redelivered to the Alliance shippers at downstream interconnecting pipelines. The recovered liquids are sold in the U.S. Midwest and Canada.

      We have been selected by Shell Exploration & Production Company affiliates to process their incremental natural gas production from the Pinedale Anticline in southwestern Wyoming. To accommodate the projected volumes, a fourth cryogenic processing train is being added to our existing gas plant in Opal, Wyoming. The new train has a processing capacity of 350 MMcf/d and is capable of extracting more than 7,000 barrels of natural gas liquids.

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      Willbros Mt. West, a business unit of Willbros Group, Inc., an unaffiliated third party, funded the new train, which will be commissioned in the first quarter of 2004. Willbros will own the new train and we will operate it under an operating and processing agreement. This project will boost 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 50,000 barrels per day of NGL products.

      As our scale increases at Opal, our per unit operating and capital costs will go down, which should increase the value of these operations. The fourth train also allows us to provide the most reliable and flexible services available to producers in the area.

      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 Devils Tower project, a floating production system and associated pipelines built to initially serve Dominion Exploration and Production’s Devils Tower discovery in Mississippi Canyon Block 773, is scheduled to be in service in the second quarter of 2004. The facility is located about 180 miles southeast of New Orleans in a water depth of 5,610 feet. This project required us to construct and own a floating production facility, a 90-mile gas pipeline and a 120-mile oil pipeline to handle the production from the Devils Tower discovery. The oil will be transported to ChevronTexaco’s Empire Terminal in Plaquemines Parish, Louisiana. The gas will be delivered into Transco’s pipeline, and processed at our Mobile Bay Plant to recover the natural gas liquids. The estimated capital costs including capitalized interest for this project is approximately $512 million.

      Our new 18-inch oil pipeline, Alpine, became operational on December 14, 2003 and has a capacity of transporting an estimated 84,000 barrels of oil per day. 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 the platform, the oil is delivered onshore through ExxonMobil’s Hoover Offshore Oil Pipeline System under a joint tariff agreement. The initial oil production is coming from the Gunnison field, which is located in 3,150 feet of water and operated by Kerr-McGee Oil & Gas Corp., a wholly owned affiliate of Kerr-McGee Corporation.

      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 2003, these operations gathered gas for over 200 customers and processed gas for approximately 100 customers. Our top four gathering and processing customers accounted for about one-third (1/3) 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 natural gas liquids 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. Our Canadian operations sell the ethane produced from the Canadian facilities to third party end users and the plant operator markets the remainder of the products. Our Canadian ethane sales contracts are typically long-term in nature.

      Our Venezuelan assets were constructed and are currently operated for the exclusive benefit of PDVSA, the state owned petroleum corporation of Venezuela. The significant contracts are 20 years in duration with revenues 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 December 2002 and early 2003, a countrywide strike took place within Venezuela that resulted in significant political instability and a volatile economic environment. The Venezuelan economic and political environment remains fluid and volatile, but

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      The following table summarizes our significant operating statistics for Midstream:

(1)	Excludes volumes associated with partially owned assets that are not consolidated for financial reporting purposes.
(2)	Annual Average mbbls/d (thousand barrels per day).
(3)	Deepwater volumes are included in the Domestic Gathering volumes listed above.
(4)	2001 and 2002 NGL Production volumes have been restated to reflect asset sales.

      Under the Natural Gas Act (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, Oklahoma and Texas actively regulate gathering activities. Those states regulate gathering 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 and appellate courts. 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 other 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 (KDHE) 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.

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      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 reliable 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 are indicators 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 are 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 year end, we owned approximately 32% of Longhorn Partners Pipeline, L.P. (Longhorn) which owns a refined petroleum products pipeline form 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 22.7% 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 are expected to commence by mid-year 2004. 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.

      Our ongoing business segments are accounted for as continuing operations in the accompanying financial statements and notes to financial statements included in Part II. Assets announced to be sold are also included in continuing operations until such time that they qualify for treatment as “discontinued operations” under GAAP.

      Our Petroleum Services segment is now reported within Other as a result of the Alaska refinery and related assets being reflected as discontinued operations. Our Other segment consists of corporate operations and certain continuing operations previously reported with the International and Petroleum Services segments.

      Other assets sold in 2003 or subject to an approved sale have also been reclassified in accordance with GAAP, from their traditional business segment to “Discontinued Operations” in the accompanying financial statements and notes to financial statements included in Part II.

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      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 us.

      We believe that we have adequate sources and availability of raw materials and commodities for existing and anticipated business needs. With the deterioration of our credit ratings, we now must provide additional margin, adequate assurance and pre-pay for gas supplies to support our energy commodity operations. 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 16 of our Notes to Consolidated Financial Statements and is incorporated herein by reference.

EMPLOYEES

      At March 1, 2004, we had approximately 4,800 full-time employees including 1,819 at the corporate level, 250 at Power, 1,449 at Gas Pipeline, 317 at Exploration & Production, and 965 at Midstream. None of our employees are represented by unions or covered by collective bargaining agreements. We expect further workforce reductions in 2004 as a result of further cost reduction efforts and asset sales.

FORWARD LOOKING STATEMENTS/ RISK FACTORS AND CAUTIONARY STATEMENT

      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:

	•	amounts and nature of future capital expenditures;
	•	expansion and growth of our business and operations;
	•	business strategy;
	•	estimates of proved gas and oil reserves;
	•	reserve potential;

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	•	development drilling potential; and
	•	power and gas prices and demand.

      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:

	•	general economic and market conditions;
	•	changes in laws or regulations;
	•	continued availability of capital and financing; and
	•	other factors, most of which are beyond our control.

      Events in 2002 significantly impacted the risk environment all businesses face and raised a level of uncertainty in the capital markets that has approached that which lead to the general market collapse of 1929. Beliefs and assumptions as to what constitutes appropriate levels of capitalization and fundamental value have changed abruptly. The collapse of Enron and the energy industry is a new reality that has had and will likely continue to have specific impacts on all companies, including us.

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 management 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 deterioration of our credit, 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

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      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:

	•	production is less than expected;
	•	a change in the difference between published price indexes established by pipelines in which our hedged production is delivered and the reference price established in the hedging arrangements is such that we are required to make payments to our counterparties; or
	•	the counterparties to our hedging arrangements fail to honor their financial commitments.

      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:

	•	worldwide and domestic supplies of electricity, natural gas, petroleum, and related commodities;
	•	turmoil in the Middle East and other producing regions;
	•	weather conditions;
	•	the level of consumer demand;
	•	the price and availability of alternative fuels;
	•	the availability of pipeline capacity;
	•	the price and level of foreign imports;
	•	domestic and foreign governmental regulations and taxes;
	•	increased volatility in the natural gas markets in light of continuing uncertainty surrounding regulatory proceedings and proposed regulations;
	•	the overall economic environment; and
	•	the credit of participants in the markets where products are bought and sold.

      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.

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      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. The pattern of this fluctuation might change depending on the nature and location of our facilities and pipeline systems and the terms of our power sale agreements and gas transmission arrangements.

      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

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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.

      Such inquiries, investigations and court proceedings are ongoing and continue to adversely affect our business as well as the energy trading business as a whole. We might see these adverse effects continue as a result of the uncertainty of these ongoing inquiries or additional inquiries by federal or state regulatory agencies. 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.

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. Our ability to do so in a timely manner may be subject to circumstances outside of our control, such as our ability to attract a creditworthy buyer for the portfolio, reduced market activity, market conditions and creditworthiness of counterparties to the contracts in the trading portfolio. Liquidation or divestiture of all or parts of our wholesale power and energy trading business may require that we liquidate contracts or assets at a value that is less than our carrying value or the value we would expect to receive if we retained the benefits of those contracts.

      As a result of the 2000-2001 energy crisis in California, the resulting collapse in energy merchant credit, the recent 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, companies generally in the regulated and so-called unregulated utility businesses have been adversely affected.

      These market factors have led to industry-wide downturns that have resulted in some companies being forced to exit from the energy trading markets, leading to a reduction in the number of trading partners and in market liquidity and announcements by us, other energy suppliers and gas pipeline companies of plans to sell large numbers of assets in order to boost liquidity and strengthen their balance sheets. Proposed and completed sales by other energy suppliers and gas pipeline companies could increase the supply of the type of assets we are attempting to sell and potentially lead either to our failing to execute such asset sales or our obtaining lower prices on completed asset sales.

      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

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	•	further economic downturns;
	•	capital market conditions generally;
	•	market prices for electricity and natural gas;
	•	terrorist attacks or threatened attacks on our facilities or those of other energy companies; or
	•	the overall health of the energy industry, including the bankruptcy or insolvency of other energy companies.

      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. Our goal is to attain investment grade ratings. However, there is no guarantee that the credit rating agencies will assign us investment grade ratings once we meet or exceed their criteria for investment grade ratings.

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. Certain restructured markets have recently experienced supply problems and price volatility. These supply problems and volatility have been the subject of a significant amount of press coverage, much of which has been critical of the restructuring initiatives. 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. 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.

      On November 25, 2003, the FERC issued a final rule, Order No. 2004, that adopted new standards of conduct for transmission providers to follow when dealing with their energy affiliates. Order No. 2004 may require substantial changes to our internal leadership structure that may have an adverse impact on our ability to effectively run our business. Our transmission providers must comply with the new standards of conduct and post procedures on the internet indicating how they will do so by June 1, 2004. The precise scope of the new rule is unclear and clarification has been requested from FERC. That clarification may not be received until after the June 1 deadline, and so the new procedures we implement to meet the standards of Order No. 2004 may not be adequate in spite of our efforts to comply with the new rule.

      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

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      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 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.

      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:

	•	transportation and sale for resale of natural gas in interstate commerce;
	•	rates and charges;
	•	construction;
	•	acquisition, extension or abandonment of services or facilities;
	•	accounts and records;
	•	depreciation and amortization policies; and
	•	operating terms and conditions of service.

      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.

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

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      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.

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Risks relating to accounting standards

      Recently discovered accounting irregularities 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 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:

	•	blowouts, cratering and explosions;
	•	uncontrollable flows of oil, natural gas or well fluids;
	•	fires;
	•	formations with abnormal pressures;
	•	pollution and other environmental risks; and
	•	natural disasters.

      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 occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations. 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.

      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). Efforts are underway to determine

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      Potential customer impact arising from the 2003 line break on Northwest Pipeline in particular may include potential shortages in Northwest Pipeline’s ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of existing Northwest Pipeline customers by others for potential new pipeline projects that would compete directly with Northwest Pipeline. The size of reservation charge credits in particular is sensitive to actual market requirements and difficult to predict. From a market and rate recovery standpoint, it will be critical for Northwest Pipeline to expedite its response to the diminished capacity arising out of the 2003 line break. Critical to the ability to respond will be regulatory approval of any such response plan by the Department of Transportation — Office of Pipeline Safety and the Washington Utilities and Transportation Commission. Such approvals will be subject to the same uncertainty inherent in any government approval process.

      Implementation of new Pipeline Safety Improvement Act (PSIA) regulations requires us to implement an Integrity Management Plan (IMP) for our gas transmission pipelines by December 2004. As part of the IMP, we must identify High Consequence Areas (HCA) through which our pipelines run. Although our investigations are ongoing, we believe that certain segments of our pipelines will be determined to run through HCAs. An HCA is defined by the rule as an area where the potential consequence of a gas pipeline accident may be significant or do considerable harm to people or property. Designing and implementing the IMP and identifying HCA’s could result in significant additional costs. There is always the possibility that the assessments related to the IMP would reveal an unexpected condition for which remedial action would be required.

      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.

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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:

	•	regulations and regulatory approvals;
	•	availability of capital for drilling projects which may be affected by other risk factors discussed in this report;
	•	cost-effective availability of drilling rigs and necessary equipment;
	•	availability of cost-effective transportation for products; or
	•	market risks already discussed in this report.

      Our success rate for drilling projects in 2003 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.

FINANCIAL INFORMATION ABOUT GEOGRAPHIC AREAS

      See Note 19 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 19 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.